|
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, 2015 |
| 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 and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 | [ X ] | |||
| 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, or a smaller reporting company. See definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
|
Large accelerated filer |
Accelerated filer |
Non-accelerated filer |
Smaller reporting 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 ] | [ ] |
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 30, 2015, PPL Corporation had 669,514,249 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 $19,730,584,918. As of January 31, 2016, PPL Corporation had 675,190,188 shares of its $0.01 par value Common Stock outstanding.
As of January 31, 2016, 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, 2016, 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, 2016, 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 2016 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, 2015. Such Statements will provide the information required by Part III of this Report.
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, 2015
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.
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 services 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, beginning in 2015, provides support services and corporate functions such as financial, supply chain, human resources and facilities management services primarily to PPL Electric and its affiliates.
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 WEM Limited - also referred to as PPL WEM is an indirect UK subsidiary of PPL Global which during a reorganization in October 2014 transferred WPD (East Midlands) and WPD (West Midlands) to a subsidiary of WPD plc.
PPL WPD Limited - an indirect U.K. subsidiary of PPL Global. PPL WPD Limited holds a liability for a closed defined benefit pension plan and a receivable with WPD plc. Following a reorganization in October 2015, PPL WPD Limited is now parent to WPD plc having previously been a sister company.
Registrant(s) - refers to the Registrants named on the cover of this Report (each a "Registrant" and collectively, the "Registrants").
Subsidiary Registrant(s) - Registrants that are direct or indirect wholly owned subsidiaries of PPL: PPL Electric, LKE, LG&E and KU.
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, formerly known as Western Power Distribution Limited, a direct 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).
i
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.
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-utility generating plants in western Kentucky until July 2009.
Other terms and abbreviations
£ - British pound sterling.
2001 Mortgage Indenture - PPL Electric's Indenture, dated as of August 1, 2001, to the Bank of New York Mellon (as successor to JPMorgan Chase Bank), as trustee, as supplemented.
2010 Equity Unit(s) - a PPL equity unit, issued in June 2010, consisting of a 2010 Purchase Contract and, initially, a 5.0% undivided beneficial ownership interest in $1,000 principal amount of PPL Capital Funding 4.625% Junior Subordinated Notes due 2018.
2010 Purchase Contract(s) - a contract that is a component of a 2010 Equity Unit requiring holders to purchase shares of PPL common stock on or prior to July 1, 2013.
2011 Equity Unit(s) - a PPL equity unit, issued in April 2011, consisting of a 2011 Purchase Contract and, initially, a 5.0% undivided beneficial ownership interest in $1,000 principal amount of PPL Capital Funding 4.32% Junior Subordinated Notes due 2019.
2011 Purchase Contract(s) - a contract that is a component of a 2011 Equity Unit requiring holders to purchase shares of PPL common stock on or prior to May 1, 2014.
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 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, a DSIC.
Act 129 - Act 129 of 2008 that became effective in October 2008. The law amends the Pennsylvania Public Utility Code and creates an energy efficiency and conservation program and smart metering technology requirements, adopts new PLR electricity supply procurement rules, provides remedies for market misconduct and changes to the Alternative Energy Portfolio Standard (AEPS).
AFUDC - Allowance for Funds Used During Construction. The cost of equity and debt funds used to finance construction projects of regulated businesses, which is capitalized as part of construction costs.
AOCI - accumulated other comprehensive income or loss.
ARO - asset retirement obligation.
ATM Program - At-the-Market stock offering program.
ii
BSER - Best System of Emission Reduction. The degree of emission reduction that EPA determines has been adequately demonstrated when taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements.
Cane Run Unit 7 - a natural gas combined-cycle generating unit in Kentucky, jointly owned by LG&E and KU, with a capacity of 642 MW (141 MW and 501 MW to LG&E and KU).
CCR(s) - Coal Combustion Residual(s). CCRs include fly ash, bottom ash and sulfur dioxide scrubber wastes.
Clean Air Act - federal legislation enacted to address certain environmental issues related to air emissions, including acid rain, ozone and toxic air emissions.
Clean Water Act - federal legislation enacted to address certain environmental issues relating to water quality including effluent discharges, cooling water intake, and dredge and fill activities.
COBRA - Consolidated Omnibus Budget Reconciliation Act, which provides individuals the option to temporarily continue employer group health insurance coverage after termination of employment.
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.
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.
DPCR4 - Distribution Price Control Review 4, the U.K. five-year rate review period applicable to WPD that commenced April 1, 2005.
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 - the 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 plans proposed by any utility under its jurisdiction. Proposed DSM mechanisms may seek full recovery of costs and revenues lost by implementing DSM programs and/or incentives designed to provide financial rewards to the utility for implementing cost-effective DSM programs. The cost of such programs shall be assigned only to the class or classes of customers which benefit from the programs.
DUoS - Distribution Use of System. This forms the majority of WPD's revenues and is the charge to electricity suppliers who are WPD's customers and use WPD's network to distribute electricity.
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). See "Non-GAAP Financial Measures" within the MD&A for additional details.
iii
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.
Equity Unit(s) - refers collectively to the 2011 and 2010 Equity Units.
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.
Fitch - Fitch, Inc., a credit rating agency.
GAAP - Generally Accepted Accounting Principles in the U.S.
GBP - British pound sterling.
GHG - greenhouse gas(es).
GLT - Gas Line Tracker. The KPSC approved mechanism for LG&E's recovery of costs associated with gas service lines, gas risers, leak mitigation, and gas main replacements. Rate recovery became effective January 1, 2013.
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). See "Non-GAAP Financial Measures" within the MD&A, for additional details.
GWh - gigawatt-hour, one million kilowatt hours.
Holdco - Talen Energy Holdings, Inc., a Delaware corporation, which was formed for the purposes of the June 1, 2015 spinoff of PPL Energy Supply, LLC.
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 the 2012 PPL 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.
If-Converted Method - A method applied to calculate diluted EPS for a company with outstanding convertible debt. The method is applied as follows: Interest charges (after-tax) applicable to the convertible debt are added back to net income and the convertible debt is assumed to have been converted to equity at the beginning of the period, and the resulting common shares are treated as outstanding shares. Both adjustments are made only for purposes of calculating diluted EPS. This method was applied to PPL's Equity Units prior to settlement.
IRS - Internal Revenue Service, a U.S. government agency.
KPSC - Kentucky Public Service Commission, the state agency that has jurisdiction over the regulation of rates and service of utilities in Kentucky.
iv
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.
LTIIP - Long Term Infrastructure Improvement Plan. A plan that must be approved by the PUC prior to requesting the DSIC mechanism. The plan must include identification of the types and age of property for which the company is requesting recovery, a schedule of replacement, general description of location and quantity, projected annual expenditures and the manner in which replacement will ensure and maintain adequate, efficient, safe, reliable and reasonable service.
MATS - Mercury and Air Toxics Standards, regulations promulgated by the EPA.
MMBtu - One million British Thermal Units.
MOD - A mechanism applied in the U.K. to adjust allowed base demand 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.
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.
NGCC - Natural gas-fired combined-cycle generating plant.
NorthWestern - NorthWestern Corporation, a Delaware corporation, and successor in interest to Montana Power's electricity delivery business, including Montana Power's rights and obligations under contracts with PPL Montana.
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.
NSR - The new source review provisions of the Clean Air Act that impose stringent emission control requirements on new and modified sources of air emissions that result in emission increases beyond thresholds allowed by the Clean Air Act.
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 related matters.
v
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 accounted for as a cost-method investment. OVEC owns and operates two coal-fired power plants, the Kyger Creek plant in Ohio and the Clifty Creek plant in Indiana, with combined summer rating capacities of 2,120 MW.
PEDFA - Pennsylvania Economic Development Financing Authority.
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, 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, LLC 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.
Purchase Contract(s) - refers collectively to the 2010 and 2011 Purchase Contracts, which are components of the 2010 and 2011 Equity Units.
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. Since the beginning of DPCR5 in April 2010, RAV additions have been based on a percentage of annual total expenditures which have continued from April 2015 under RIIO-ED1. RAV is intended to represent 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.
Regional Transmission Expansion Plan - PJM conducts a long-range Regional Transmission Expansion Planning process that identifies changes and additions to the PJM grid necessary to ensure future needs are met for both the reliability and the economic performance of the grid. Under PJM agreements, transmission owners are obligated to build transmission projects assigned to them by the PJM Board.
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-ED1 - RIIO represents "Revenues = Incentive + Innovation + Outputs." RIIO-ED1 refers to the initial eight-year rate review period applicable to WPD which commenced April 1, 2015.
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Riverstone - Riverstone Holdings LLC, a Delaware limited liability company and ultimate parent company of the entities that own the competitive power generation business contributed to Talen Energy other than the competitive power generation business contributed by virtue of the spinoff of a newly formed parent of PPL Energy Supply.
RJS Power - RJS Generation Holdings LLC, a Delaware limited liability company controlled by Riverstone, that owns the competitive power generation business contributed by its owners to Talen Energy other than the competitive power generation business contributed by virtue of the spinoff of a newly formed parent of PPL Energy Supply.
RPI - Retail Price Index, is a measure of inflation in the United Kingdom published monthly by the Office for National Statistics.
SCRs - selective catalytic reduction, a pollution control process for the removal of nitrogen oxide from exhaust gas.
SIP - PPL Corporation's 2012 Stock Incentive Plan.
S&P - Standard & Poor's Ratings Services, a credit rating agency.
Sarbanes-Oxley - Sarbanes-Oxley Act of 2002, which sets requirements for management's assessment of internal controls for financial reporting. It also requires an independent auditor to make its own assessment.
Scrubber - an air pollution control device that can remove particulates and/or gases (primarily sulfur dioxide) from exhaust gases.
SEC - the U.S. Securities and Exchange Commission, a U.S. government agency primarily responsible to protect investors and maintain the integrity of the securities markets.
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.
Smart meter - an electric meter that utilizes smart metering technology.
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.
Superfund - federal environmental statute that addresses remediation of contaminated sites; states also have similar statutes.
Talen Energy - Talen Energy Corporation, the Delaware corporation formed to be the publicly traded company and owner of the competitive generation assets of PPL Energy Supply and certain affiliates of Riverstone.
Talen Energy Marketing - PPL EnergyPlus' new name subsequent to the spinoff of PPL Energy Supply.
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.
TRA - Tennessee Regulatory Authority, the state agency that has jurisdiction over the regulation of rates and service of utilities in Tennessee.
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.
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TRU - a mechanism applied in the U.K. to true-up inflation estimates used in determining base demand revenue.
VEBA - Voluntary Employee Benefit Association Trust, accounts for health and welfare plans for future benefit payments for employees, retirees or their beneficiaries.
Volumetric risk - the risk that the actual load volumes provided under full-requirement sales contracts could vary significantly from forecasted volumes.
VSCC - Virginia State Corporation Commission, the state agency that has jurisdiction over the regulation of Virginia corporations, including utilities.
viii
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 from the forward-looking statements.
| · | challenges by intervenors to the return on equity granted in existing rate structures; |
| · | fuel supply, cost and availability; |
| · | continuing 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 conditions affecting generation, transmission and distribution operations and customer energy use; |
| · | availability and operating costs of existing generation facilities; |
| · | the duration of and cost associated with scheduled and unscheduled outages at our generating facilities; |
| · | generation, transmission and distribution system conditions and operating costs; |
| · | expansion of alternative and distributed sources of electricity generation and storage; |
| · | collective labor bargaining negotiations; |
| · | laws or regulations to reduce emissions of "greenhouse" gases or the physical effects of climate change; |
| · | the outcome of litigation against the Registrants and their subsidiaries; |
| · | potential effects of threatened or actual terrorism, war or other hostilities, cyber-based intrusions or natural disasters; |
| · | the commitments and liabilities of the Registrants and their subsidiaries; |
| · | the effectiveness of our risk management programs, including foreign currency and interest rate hedging; |
| · | our ability to attract and retain qualified employees; |
| · | volatility in demand for electricity; |
| · | market prices of commodity inputs for ongoing capital expenditures or key operational needs; |
| · | capital market conditions, including the availability of capital or credit, changes in interest rates and certain economic indices, and decisions regarding capital structure; |
| · | stock price performance of PPL; |
| · | defaults by counterparties or suppliers for energy, capacity, coal, natural gas or key commodities, goods or services; |
| · | volatility 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 and interest payable on certain debt securities; |
| · | volatility in or the impact of other changes in financial markets and economic conditions; |
| · | new accounting requirements or new interpretations or applications of existing requirements; |
| · | changes in securities and credit ratings; |
| · | changes in foreign currency exchange rates for British pound sterling; |
| · | the effect of changes in RPI on WPD's revenues; |
| · | current and future environmental conditions, regulations and other requirements and the related costs of compliance, including environmental capital expenditures, emission allowance costs and other expenses; |
| · | 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, approvals and rate relief; |
| · | new state, federal or foreign legislation or regulatory developments; |
| · | the outcome of any rate cases or other cost recovery or revenue filings by PPL Electric, LG&E, KU or WPD; |
| · | the achievement of performance targets set by regulators; |
| · | the impact of any state, federal or foreign investigations applicable to the Registrants and their subsidiaries and the energy industry; |
| · | the effect of any business or industry restructuring; |
| · | development of new projects, markets and technologies; |
| · | performance of new ventures; and |
| · | business dispositions or acquisitions and our ability to realize expected benefits from such business transactions. |
Any such forward-looking statements should be considered in light of such important factors and in conjunction with other documents of the Registrants on file with the SEC.
1
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 such statement to reflect subsequent developments or information.
2
PART I
General
(All Registrants)
PPL Corporation, headquartered in Allentown, Pennsylvania, is a utility holding company that was incorporated in 1994. PPL, through its regulated utility subsidiaries, delivers electricity to customers in the U.K., Pennsylvania, Kentucky, Virginia and Tennessee; delivers natural gas to customers in Kentucky; and generates electricity from power plants in Kentucky. In June 2014, PPL and PPL Energy Supply executed definitive agreements with affiliates of Riverstone to combine their competitive power generation businesses into a new, stand-alone, publicly traded company named Talen Energy. The transaction was completed on June 1, 2015. See "Spinoff of PPL Energy Supply" below for more information.
PPL's principal subsidiaries at December 31, 2015 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 |
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|
LG&E* ● Engages in the regulated generation, transmission, distribution and sale of electricity and 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 |
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In addition to PPL, the other Registrants included in this filing are as follows.
PPL Electric Utilities Corporation, headquartered in Allentown, Pennsylvania, is a direct wholly owned subsidiary of PPL incorporated 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 and in Tennessee under the KU name. LKE, formed in 2003, is the successor to a Kentucky entity incorporated in 1989.
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.
3
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, Virginia and Tennessee. KU is subject to regulation as a public utility by the KPSC, the VSCC and the TRA, 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 Virginia customers under the Old Dominion Power name and its Kentucky and Tennessee customers under the KU name. KU was incorporated in Kentucky in 1912 and in Virginia in 1991.
(PPL)
Spinoff of PPL Energy Supply
In recognition of the changes in recent years in the wholesale power markets, PPL performed an in-depth analysis of its business mix to determine the best available opportunities to maximize the value to shareowners of its competitive generation business. As a result, in June 2014, PPL and PPL Energy Supply executed definitive agreements with affiliates of Riverstone to spin off PPL Energy Supply and immediately combine it with Riverstone's competitive power generation businesses to form a new, stand-alone, publicly traded company named Talen Energy. The transaction was subject to customary closing conditions, including receipt of regulatory approvals from the NRC, FERC, DOJ and PUC, all of which were received by mid-April 2015. On April 29, 2015, PPL's Board of Directors declared the June 1, 2015 distribution to PPL's shareowners of record on May 20, 2015 of a newly formed entity, Holdco, which at closing owned all of the membership interests of PPL Energy Supply and all of the common stock of Talen Energy.
Immediately following the spinoff on June 1, 2015, Holdco merged with a special purpose subsidiary of Talen Energy, with Holdco continuing as the surviving company to the merger and as a wholly owned subsidiary of Talen Energy and the sole owner of PPL Energy Supply. Substantially contemporaneous with the spinoff and merger, RJS Power was contributed by its owners to become a subsidiary of Talen Energy. PPL's shareowners received approximately 0.1249 shares of Talen Energy common stock for each share of PPL common stock they owned on May 20, 2015. Following completion of these transactions, PPL shareowners owned 65% of Talen Energy and affiliates of Riverstone owned 35%. The spinoff had no effect on the number of PPL common shares owned by PPL shareowners or the number of shares of PPL common stock outstanding. The transaction is intended to be tax-free to PPL and its shareowners for U.S. federal income tax purposes.
PPL has no continuing ownership interest in, control of, or affiliation with Talen Energy and Talen Energy Supply (formerly PPL Energy Supply).
See Note 8 to the Financial Statements for additional information.
Acquisitions
On April 1, 2011, PPL, through an indirect, wholly owned subsidiary, PPL WEM Limited, acquired all of the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently defined herein as WPD Midlands), from subsidiaries of E.ON AG. WPD Midlands operates two regulated distribution networks in the Midlands area of England and is included in the U.K. Regulated segment.
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 primarily reflect the activities of its related Subsidiary Registrants, except that the reportable segments are also allocated certain corporate level financing and other costs that are not included in the results of the applicable Subsidiary Registrants. As a result of the June 1, 2015 spinoff of PPL Energy Supply, PPL no longer has a Supply segment.
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| A comparison of PPL's three regulated segments is shown below: | ||||||||||
| Kentucky | Pennsylvania | |||||||||
| U.K. Regulated | Regulated | Regulated | ||||||||
| For the year ended December 31, 2015: | ||||||||||
| Operating Revenues (in billions) | $ | 2.4 | $ | 3.1 | $ | 2.1 | ||||
| Net Income (in millions) | $ | 1,121 | $ | 326 | $ | 252 | ||||
| Electricity delivered (GWh) | 75,907 | 30,814 | 36,984 | |||||||
| At December 31, 2015: | ||||||||||
| Regulatory Asset Base (in billions) (a) | $ | 9.7 | $ | 8.7 | $ | 5.2 | ||||
| Service area (in square miles) | 21,600 | 9,400 | 10,000 | |||||||
| End-users (in millions) | 7.8 | 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 each operate within a single operating segment.
| · | 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 allocated financing costs. |
WPD, through indirect wholly owned subsidiaries, operates four of the 15 regulated distribution networks providing electricity service in the U.K. The number of network customers (end-users) served by WPD totals 7.8 million across 21,600 square miles in south Wales and southwest and central England.
Revenues for the years ended December 31 are shown below.
| 2015 | 2014 | 2013 | |||||||
| Operating Revenues | $ | 2,410 | $ | 2,621 | $ | 2,403 | |||
The majority of WPD's operating revenue is known as DUoS and is generated by providing regulated electricity distribution services to licensed third party energy suppliers who pay WPD for the use of WPD's distribution network to transfer electricity to the suppliers' customers, the end-users. Throughout the following discussion, the use of the term "customers" refers to the end-users of WPD's regulated distribution networks.
| Franchise and Licenses |
The operations of WPD's principal subsidiaries, WPD (South West), WPD (South Wales), WPD (East Midlands) and WPD (West Midlands), are regulated by Ofgem under the direction of the Gas and Electricity Markets Authority. The Electricity Act 1989 provides the fundamental framework of electricity companies and established licenses that require each of the DNOs to develop, maintain and operate efficient distribution networks. WPD operates under a regulatory year that begins April 1 and ends March 31 of each year.
WPD is authorized by Ofgem to provide electricity distribution services within its concession areas and service territories, subject to certain conditions and obligations. For instance, WPD is subject to Ofgem regulation with respect to the regulated revenue it can earn and the quality of service it must provide, and WPD can be fined or have its licenses revoked if it does not meet the mandated standard of service.
Ofgem has formal powers to propose modifications to each distribution license. In January 2014, Ofgem and WPD agreed to a reduction of £5 per residential end-user in the 2014/15 regulatory year to be recovered in the 2016/2017 regulatory year. See "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Distribution Revenue Reduction" for additional information. Ofgem has made license changes as part of the RIIO-ED1 process discussed below.
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| 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 distribution businesses are, therefore, regulated monopolies which operate under regulatory price controls.
| Revenue and Regulation |
Ofgem has adopted a price control mechanism that establishes the amount of base demand revenue WPD can earn, subject to certain true-ups, and provides for an increase or reduction in revenues based on incentives or penalties for exceeding or underperforming relative to pre-established targets. WPD's allowed revenue primarily includes base demand revenue, incentive adjustments, adjustments for over or under-recovery and adjustments related to the DPCR4 line loss close out.
WPD is currently operating under the eight-year price control period of RIIO-ED1, which commenced on April 1, 2015. The RIIO framework is intended to:
| · | encourage DNOs to deliver safe, reliable and sustainable network service at long-term value to customers; |
| · | enable DNOs to finance the required investment in a timely and efficient way; |
| · | remunerate DNOs according to their delivery for customers; |
| · | increase emphasis on outputs and incentives; |
| · | enhance stakeholder engagement including network customers; |
| · | provide a stronger incentive framework to encourage more efficient investment and innovation; and |
| · | replace the current Low Carbon Network Fund to continue to stimulate innovation. |
Additionally, from a financial perspective the RIIO framework:
| · | regulates revenues for the DNOs in real terms using 2012/2013 prices; |
| · | inflates RAV (therefore allowed revenues) and other revenue components using the RPI since March 31, 2013; |
| · | splits the recovery of Totex between immediate recovery (called "fast pot") and deferred recovery as an addition to the RAV (called "slow pot"); |
| · | provides DNOs with a pass-through for costs the DNOs have no control over (i.e., Ofgem fees, National Grid transmission charges, property taxes and corporate income taxes); |
| · | extends the recovery period of depreciation of RAV additions after April 1, 2015 from a 20 year life as used under DPCR5 to 45 years, with a transitional arrangement that will gradually increase the asset life for new additions over the price control period resulting in an average life of approximately 35 years for RAV additions during RIIO-ED1. The RAV as of March 31, 2015 will continue to be depreciated over 20 years. The asset lives used to determine depreciation expense for U.S. 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; |
| · | provides the DNOs the ability to be fast-tracked through the regulatory approval process, providing a fast-track incentive of 2.5% of Totex during the 8-year price control period for successful DNOs; and |
| · | maintains an incentive scheme for DNOs to be rewarded or penalized for performance in the areas of reliability and customer satisfaction, but places a maximum cap on the amount of incentive revenues that can be earned by a DNO. |
The key components of WPD's four RIIO-ED1 business plans accepted by Ofgem are:
| · | all four DNO business plans were accepted for fast-track status (fast-track incentive is worth approximately $43 million annually for WPD assuming a $1.60/£ foreign currency exchange rate); |
| · | WPD received a higher level of cost savings retention, which was established at 70% for WPD compared to approximately 55% for slow-tracked DNOs; |
| · | a cost of debt recovery comprised of a 10-year trailing average debt allowance, to be adjusted annually, compared to a transition to a 20-year trailing average for the slow tracked DNOs applied to 65% of RAV; |
| · | a return on regulatory equity (RORE) allowance with an equity ratio of 35% of RAV and a cost of equity rate of 6.4% compared to 6.0% for slow-tracked DNOs; |
| · | a Totex split of 80% slow pot and 20% fast pot; |
| · | recovery of approximately 80% of pension deficit funding for certain of WPD's defined benefit pension plans; and |
| · | incentive targets that are significantly more stringent than those set under DPCR5, thus reducing the expected incentive revenues WPD can earn in RIIO-ED1 compared to DPCR5. |
WPD's combined business plans include funding for total expenditures of approximately $20.4 billion over the eight-year period (assuming a $1.60/£ foreign currency exchange rate), broken down as follows:
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| · | Totex - $13.5 billion ($10.8 billion additions to RAV; $2.7 billion fast pot); |
| · | Pension deficit funding - $2.0 billion; |
| · | Cost of debt recovery - $1.6 billion; |
| · | Property taxes, Ofgem fees and National Grid transmissions charges - $2.6 billion; and |
| · | Corporate income taxes recovery - $700 million. |
The U.K. regulatory structure is an incentive-based structure in contrast to the typical U.S. regulatory structure which operates on a cost-recovery model. The base demand revenue that a DNO can earn in each year of the current price control period is the sum of:
| · | a return on capital from RAV; |
| · | a return of capital from RAV (i.e. depreciation); |
| · | the fast pot recovery; |
| · | pension deficit funding; |
| · | 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; |
| · | certain pass-through costs over which the DNO has no control; |
| · | certain legacy price control adjustments from preceding price control periods, including the information quality incentive (also known as the rolling RAV incentive); |
| · | fast track incentive - as WPD's four DNOs were fast-tracked through the price control review process for RIIO-ED1, their base demand revenue also includes the fast-track incentive discussed above; |
| · | profiling adjustments - these adjustments do not affect the total base demand revenue in real terms over the eight-year price control period, but change the year in which the revenue is earned; |
| · | adjustments from the Annual Iteration Process (AIP), discussed further below; and |
| · | adjustments for inflation true-ups, discussed further below. |
In addition to base demand revenue, WPD's allowed revenue primarily includes:
| · | an increase or reduction in revenues based on incentives or penalties for actual performance against pre-established targets; |
| · | adjustments for over- or under-recovery of allowed revenue; and |
| · | a reduction in revenue related to the DPCR4 line loss close out. |
During DPCR5, the prior price control review period, WPD's total base demand revenue for the five-year period was profiled in a manner that resulted in a weighted-average increase of about 5.5% per year for all four DNOs. In the first year of RIIO-ED1, base demand revenue decreased by about 11.8% primarily due to a change in the profiling approach and a lower weighted-average cost of capital. For each regulatory year thereafter for the remainder of RIIO-ED1, base demand revenue will increase by approximately 1% per annum before inflation.
As the regulatory model 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 of adjustments to base demand revenue and/or allowed revenue is evaluated based on revenue recognition and contingency accounting guidance.
Base Demand Revenue True-up Mechanisms
Unlike prior price control reviews, base demand revenue under RIIO-ED1 will be adjusted during the price control period. The most significant of those adjustments are:
| · | Inflation True-Up - The base demand revenue for the RIIO-ED1 period was set in 2012/13 prices. Therefore an inflation factor as determined by forecasted RPI, provided by HM Treasury, is applied to base demand revenue. Forecasted RPI is trued up to actuals and affects future base demand revenue two regulatory years later. This revenue change is called the "TRU" adjustment. The projected TRU for the 2015/16 regulatory year is a $45 million reduction to revenue and will reduce base demand revenue in calendar years 2017 and 2018 by $30 million and $15 million, respectively. |
| · | Annual Iteration Process - The RIIO-ED1 price control period also includes an Annual Iteration Process (AIP). This will allow future base demand revenues agreed with the regulator as part of the price control review to be updated during the price control period for financial adjustments including tax, pensions and 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). Under the TIM, WPD's DNOs are able to retain 70% of any amounts not spent against the RIIO-ED1 plan and bear 70% of any over-spends. The AIP calculates an |
7
incremental change to base demand revenue, known as the "MOD" adjustment. The MOD provided by Ofgem in November 2016 will include 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 projected MOD of $11 million will reduce base demand revenue for calendar years 2017 and 2018 by $5 million and $6 million, respectively.
As both MOD and TRU are changes to future base demand revenues as determined by Ofgem, under applicable GAAP, liabilities for these adjustments have not been recorded. PPL's projected earnings per share growth rate through 2017 includes both the estimated TRU for regulatory year 2015/16 and MOD.
Allowed Revenue Components
In addition to base demand revenue, certain other items are added or subtracted to arrive at allowed revenue. The most significant of these are discussed below.
Incentives - Ofgem has established incentive mechanisms to provide significant opportunities to enhance overall returns by improving network efficiency, reliability and customer service. Some of the more significant incentive mechanisms which may affect allowed revenue include:
| · | Interruptions Incentive Scheme (IIS) - This incentive has two major components: (1) Customer interruptions (CIs) and (2) Customer minutes lost (CMLs), and both are designed to incentivize the DNOs to invest and operate their networks to manage and reduce both the frequency and duration of power outages. The IIS target under RIIO-ED1 is divided into interruptions caused by planned and unplanned work. The target for planned work will be calculated as the annual average level of planned interruptions and minutes lost over a previous three year period. The target for unplanned interruptions for the first year of RIIO-ED1 is specified in the DNOs license and targets for both the CIs and CMLs become more demanding each year. |
| · | In addition to the IIS, the broad measure of customer service is enhanced in RIIO-ED1. This broad measure encompasses: |
| · | customer satisfaction in supply interruptions, connections and general inquiries; |
| · | complaints; |
| · | stakeholder engagement; and |
| · | delivery of social obligations. |
The following table shows the amount of incentive revenue, primarily from IIS, which WPD has earned during DPCR5:
| Incentive Earned | Regulatory Year Ended Incentive | ||||
| Regulatory Year Ended | (in millions) | Included in Revenue | |||
| March 2011 | $ | 30 | March 2013 | ||
| March 2012 | 83 | March 2014 | |||
| March 2013 | 104 | March 2015 | |||
| March 2014 | 125 | March 2016 | |||
| March 2015 | 136 | March 2017 | |||
Based on applicable GAAP, incentive revenues are not recorded as assets and are included in revenues when they are billed to customers.
DPCR4 Line Loss Adjustment
For regulatory years 2015/16 through 2018/19 allowed revenue will also be reduced to reflect Ofgem's final decision on the DPCR4 line loss incentives and penalties mechanism. WPD has a liability recorded related to this future revenue reduction and, therefore, this will not impact future earnings. See Note 6 to the Financial Statements for additional information.
Correction Factor
During the price control period, WPD's revenue is decoupled from volume and 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 also 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 arising from 2014/15 onwards and refunded/recovered under RIIO-ED1 will be refunded/recovered on a two year lag (previously one year). Therefore the 2014/15 over/under-recovery adjustment will occur in 2016/17. In 2016/17 under this mechanism, WPD will recover the £5 per residential network customer reduction
8
given through reduced tariffs in 2014/15 (approximately $56 million) as that amount is currently considered an under-recovery.
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 for 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 2016/17 and 2017/18. 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.
Under applicable GAAP, WPD does not record a receivable for under-recoveries, but does record a liability for over-recoveries. K-factor is measured as of the end of the regulatory year, March 31. While WPD estimates over-recoveries and records a liability when it is probable that there will be an over-recovered position at the end of the regulatory-year, weather-related volume changes and other factors such as sales mix can affect the over or under-recovery between the end of PPL's calendar year and the end of the regulatory year.
See "Item 1A. Risk Factors - Risks Related to U.K. Regulated Segment" for additional information on the risks associated with the U.K. Regulated Segment.
| Customers |
WPD provides regulated electricity distribution services to licensed third party energy suppliers (its customers) who use WPD's networks to transfer electricity to their customers, the end-users. WPD bills the energy supplier for this service and the supplier is responsible for billing the 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.
| · | 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 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, Virginia and Tennessee. LG&E also engages in the distribution and sale of natural gas in Kentucky. LG&E provides electric service to approximately 403,000 customers in Louisville and adjacent areas in Kentucky, covering approximately 700 square miles in nine counties and provides natural gas service to approximately 322,000 customers in its electric service area and eight additional counties in Kentucky. KU provides electric service to approximately 518,000 customers in 77 counties in central, southeastern and western Kentucky, approximately 28,000 customers in five counties in southwestern Virginia, and fewer than ten customers in Tennessee, covering approximately 4,800 non-contiguous square miles. KU also sells wholesale electricity to 11 municipalities in Kentucky under load following contracts. In Virginia, KU operates under the name Old Dominion Power Company.
Details of operating revenues by customer class for the years ended December 31 are shown below.
| 2015 | 2014 | 2013 | ||||||||||||||||
| % of | % of | % of | ||||||||||||||||
| Revenue | Revenue | Revenue | Revenue | Revenue | Revenue | |||||||||||||
| LKE | ||||||||||||||||||
| Commercial | $ | 816 | 26 | $ | 815 | 26 | $ | 770 | 26 | |||||||||
| Industrial | 628 | 20 | 627 | 20 | 587 | 20 | ||||||||||||
| Residential | 1,245 | 40 | 1,281 | 40 | 1,205 | 40 | ||||||||||||
| Retail - other | 267 | 9 | 279 | 9 | 260 | 9 | ||||||||||||
| Wholesale - municipal | 114 | 4 | 109 | 3 | 110 | 4 | ||||||||||||
| Wholesale - other (a) | 45 | 1 | 57 | 2 | 44 | 1 | ||||||||||||
| Total | $ | 3,115 | 100 | $ | 3,168 | 100 | $ | 2,976 | 100 | |||||||||
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| 2015 | 2014 | 2013 | ||||||||||||||||
| % of | % of | % of | ||||||||||||||||
| Revenue | Revenue | Revenue | Revenue | Revenue | Revenue | |||||||||||||
| LG&E | ||||||||||||||||||
| Commercial | $ | 436 | 30 | $ | 433 | 28 | $ | 405 | 29 | |||||||||
| Industrial | 199 | 14 | 194 | 13 | 186 | 13 | ||||||||||||
| Residential | 633 | 44 | 650 | 43 | 614 | 44 | ||||||||||||
| Retail - other | 117 | 8 | 130 | 8 | 119 | 8 | ||||||||||||
| Wholesale - other (a) (b) | 59 | 4 | 126 | 8 | 86 | 6 | ||||||||||||
| Total | $ | 1,444 | 100 | $ | 1,533 | 100 | $ | 1,410 | 100 | |||||||||
| KU | ||||||||||||||||||
| Commercial | $ | 380 | 22 | $ | 382 | 22 | $ | 365 | 22 | |||||||||
| Industrial | 429 | 25 | 433 | 25 | 401 | 25 | ||||||||||||
| Residential | 612 | 35 | 631 | 36 | 591 | 36 | ||||||||||||
| Retail - other | 150 | 9 | 149 | 9 | 141 | 9 | ||||||||||||
| Wholesale - municipal | 114 | 7 | 109 | 6 | 110 | 7 | ||||||||||||
| Wholesale - other (a) (b) | 43 | 2 | 33 | 2 | 27 | 1 | ||||||||||||
| Total | $ | 1,728 | 100 | $ | 1,737 | 100 | $ | 1,635 | 100 | |||||||||
| (a) | Includes wholesale power and transmission revenues. |
| (b) | 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 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 provide indirect competition for natural gas revenues of LKE. 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 profitability. However, some large industrial and commercial customers 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, 2015, LKE owned, controlled or had a minority ownership interest in generating capacity (summer rating) of 7,997 MW, of which 2,919 MW related to LG&E and 5,078 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 2015, LKE's Kentucky power plants generated the following amounts of electricity.
| GWh | |||||
| Fuel Source | LKE | LG&E | KU | ||
| Coal (a) | 29,609 | 12,049 | 17,560 | ||
| Oil / Gas | 4,792 | 1,258 | 3,534 | ||
| Hydro | 372 | 274 | 98 | ||
| Total (b) | 34,773 | 13,581 | 21,192 | ||
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| (a) | Includes 762 GWh of power generated by and purchased from OVEC for LKE, 527 GWh for LG&E and 235 GWh for KU. |
| (b) | This generation represents a 2.4% decrease for LKE, a 13.7% decrease for LG&E and a 6.6% increase for KU from 2014 output. |
A majority of LG&E's and KU's generated electricity was used to supply its retail and 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. When KU has excess generation capacity after serving its own retail and municipal customers and its generation cost is lower than that of LG&E, LG&E purchases electricity from KU.
See "Item 2. Properties - Kentucky Regulated Segment" for additional information regarding LG&E's and KU's construction of a solar generating facility at the E.W. Brown generating site. As a result of environmental requirements, KU retired two coal-fired units, with a combined summer capacity rating of 161 MW, at the Green River plant in September 2015. LG&E retired a 240 MW coal-fired unit in March 2015 and two additional coal-fired units, with a combined summer capacity rating of 323 MW, in June 2015 at the Cane Run plant. KU retired a 71 MW coal-fired unit at the Tyrone plant in 2013.
| Fuel Supply |
Coal is expected to be the predominant fuel used by LG&E and KU for generation for the foreseeable future. Due to Cane Run Unit 7 being placed into operation during 2015, natural gas will play a more significant role going forward. The natural gas for this generating unit is purchased using contractual arrangements separate from LG&E's natural gas distribution operations. Natural gas and oil will continue to be 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.
LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries through 2022 and normally 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 by barge, truck and rail.
To enhance the reliability of natural gas supply, LG&E and KU have secured, firm long-term pipeline capacity on the interstate pipeline serving Cane Run Unit 7 and six simple cycle combustion turbine units located at the Trimble County site through 2024. LG&E has also secured long-term firm pipeline capacity on an interstate pipeline for an additional simple cycle gas turbine under a power purchase agreement for the summer months through October 2018. For the seven simple cycle combustion turbines at Brown, no firm long-term pipeline capacity has been purchased due to the facility being interconnected to multiple pipelines and some of the units having dual fuel capability.
Natural gas purchases for these units currently take place as needed from pipelines but LG&E and KU may seek to augment these purchases with longer term agreements.
(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 Bcf, are used in providing natural gas service to LG&E's firm sales customers. By using natural gas storage facilities, LG&E avoids the costs typically associated with more expensive pipeline transportation capacity to serve peak winter heating loads. 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 typically at their highest. Several suppliers under contracts of varying duration provide competitively priced natural gas. At December 31, 2015, LG&E had 12 Bcf of natural gas stored underground with a carrying value of $42 million.
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LG&E has a portfolio of supply arrangements of varying terms with a number of suppliers 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 2018 and 2021. 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 has two contracts with a total capacity of 10,000 MMBtu/day, during the winter season and 28,000 MMBtu/day, during the summer season; both contracts have been terminated effective October 31, 2016. With this same pipeline, LG&E also has a new contract for pipeline capacity commencing June 2016 through October 31, 2026, in the amount of 60,000 MMBtu/day. Additionally, LG&E has a contract with the same pipeline for the month of January 2016 with a total capacity of 30,000 MMBtu/day. 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 October 31, 2018.
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 Rockies, 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 operator.
During 2013 through 2015, LG&E and KU have submitted various compliance filings to the FERC reflecting their participation with other utilities in the Southeastern Regional Transmission Planning group relating to certain FERC Order 1000 requirements. 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. FERC approvals have been received for all but one remaining of such compliance filings.
| 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, the VSCC and the TRA. LG&E and KU operate under a FERC-approved open access transmission tariff (OATT).
LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including adjustments for certain net investments and costs recovered separately through other means. As such, LG&E and KU generally earn a return on regulatory assets in Kentucky.
KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.
KU's Tennessee base rates are established through approval of the TRA and generally will follow the cost of providing service in Kentucky.
KU's rates to 11 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 deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets. In April 2014, nine municipalities submitted notices of termination, under the original notice period provisions, to cease taking power under the wholesale requirements contracts. Such terminations are to be effective in 2019, except in the case of one municipality with a 2017 effective date.
See Note 6 to the Financial Statements for additional information on cost recovery mechanisms.
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| · | 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 supply to retail customers in this area as a PLR under the Customer Choice Act.
Details of revenues by customer class for the years ended December 31 are shown below.
| 2015 | 2014 | 2013 | |||||||||||||||||
| Revenue | % of Revenue | Revenue | % of Revenue | Revenue | % of Revenue | ||||||||||||||
| Distribution | |||||||||||||||||||
| Residential | $ | 1,338 | 63 | $ | 1,285 | 63 | $ | 1,215 | 65 | ||||||||||
| Industrial | 58 | 3 | 52 | 3 | 52 | 3 | |||||||||||||
| Commercial | 377 | 18 | 367 | 18 | 363 | 19 | |||||||||||||
| Other (a) | (44) | (2) | 5 | (11) | |||||||||||||||
| Transmission | 395 | 18 | 335 | 16 | 251 | 13 | |||||||||||||
| Total | $ | 2,124 | 100 | $ | 2,044 | 100 | $ | 1,870 | 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 investment are subject to competitive processes outlined in the PJM tariff.
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As a transmission owner, PPL Electric's transmission revenues are recovered through PJM in accordance with a FERC approved tariff that allows recovery of incurred transmission costs, a return on transmission-related plant and an automatic annual update based on a formula rate mechanism. As a PLR, PPL Electric also purchases transmission services from PJM. See "PLR" below.
See Note 6 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 earning 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. In January 2013, PPL Electric filed a petition requesting permission to establish a DSIC. In May 2013, the PUC approved PPL Electric's proposed DSIC with an initial rate effective July 1, 2013, subject to refund after hearings. The PUC also assigned four technical recovery calculation issues to the Office of Administrative Law Judge for hearing and preparation of a recommended decision. In November 2015, the PUC issued an opinion and order approving PPL Electric's Petition with minor modifications.
See "Regulatory Matters - Pennsylvania Activities" in Note 6 to the Financial Statements for additional information regarding Act 129, Act 11 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. As of December 31, 2015, the following percentages of PPL Electric's customer load were provided by competitive suppliers: 50% of residential, 85% of small commercial and industrial and 99% of large commercial and industrial customers. The PUC continues to be interested in expanding the competitive market for electricity. See "Regulatory Matters - Pennsylvania Activities - Act 129" in Note 6 to the Financial Statements for additional information.
PPL Electric's cost 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 includes 4 solicitations for electricity supply held in April and October, annually. Pursuant to this plan, PPL Electric contracts for all of the electricity supply for residential, small commercial and small industrial customers, large commercial and large 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, small commercial and small industrial customers, and 12-month real-time pricing contracts for large commercial and large 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. Since the cost of generation supply is a pass-through cost for PPL Electric, its financial results are not impacted if its customers purchase
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electricity supply from these alternative suppliers. See "Energy Purchase Commitments" in Note 13 to the Financial Statements for additional information regarding PPL Electric's solicitations.
See "Regulatory Matters - Pennsylvania Activities - Rate Case Proceedings" in Note 6 to the Financial Statements for information regarding PPL Electric's 2015 rate case proceedings.
| · | Other Corporate Functions (PPL) |
PPL Services provides PPL subsidiaries with administrative, management and support services.
PPL EU Services, formed in 2015, is included within the Pennsylvania Regulated Segment and provides the majority of financial, supply chain, human resources and facilities management services to PPL Electric. Significant portions of the various corporate functions previously within PPL Services were transferred to PPL EU Services in 2015. Certain other functions are to be transferred to PPL EU Services as the transition services agreements with Talen Energy expire. PPL Services will continue to provide certain limited corporate functions. For both service companies, 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.
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 further utilize PPL Capital Funding in future financings, in addition to continued direct financing by the operating companies.
Unlike PPL Services and PPL EU 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 in 2013 and beyond, with certain exceptions, have not been directly assigned or allocated to any segment.
(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 more severe weather conditions such as heat waves or extreme winter weather make such fluctuations more pronounced. The pattern of this fluctuation may change depending on the type and location of the facilities owned. See "Financial Condition - Environmental Matters" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" 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 2016 through 2020. See Note 13 to the Financial Statements for additional information concerning the potential impact on capital expenditures from environmental matters.
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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 recently issued or is in the process of proposing and finalizing numerous environmental regulations relating to air, water and waste that will directly affect the electricity 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" on projected environmental capital expenditures for the years 2016-2020. Also, see "Environmental Matters" in Note 13 to the Financial Statements for additional information. To comply with environmental requirements, PPL's forecast for environmental capital expenditures reflects a best estimate projection of expenditures that may be required within the next five years. Such projections are $1.9 billion for PPL and LKE ($1 billion for KU and $0.9 billion for LG&E). Actual costs (including capital, emission allowance purchases and operational modifications) may be significantly lower or higher depending on the final compliance requirements and market conditions. PPL's and LKE's subsidiaries may also incur capital expenditures and operating expenses, which are not now determinable, but could be significant. Environmental compliance costs incurred by LG&E and KU are subject to recovery through a rate recovery mechanism. See Note 6 to the Financial Statements for additional information.
EMPLOYEE RELATIONS
At December 31, 2015, PPL and its subsidiaries had the following full-time employees and employees represented by labor unions.
| Total Full-Time | Number of Union | Percentage of Total | |||||
| Employees | Employees | Workforce | |||||
| PPL (a) | 12,799 | 6,376 | 50% | ||||
| PPL Electric | 1,935 | 1,227 | 63% | ||||
| LKE | 3,484 | 812 | 23% | ||||
| LG&E | 1,001 | 688 | 69% | ||||
| KU | 926 | 124 | 13% | ||||
| (a) | Includes 4,085 employees of WPD who are members of labor unions (or 62% 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 4,015 union employees, may be amended by agreement between WPD and the unions and can be terminated with 12 months' notice by either side. |
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) and at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549, or by calling 1-800-SEC-0330.
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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 to the former PPL Energy Supply 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 Relating to the Spinoff of PPL Energy Supply and Formation of Talen Energy Corporation
If the spinoff of PPL Energy Supply does not qualify as a tax-free distribution under Sections 355 and 368 of the Internal Revenue Code of 1986, as amended (the "Code"), including as a result of subsequent acquisitions of stock of PPL or Talen Energy, then PPL and/or its shareowners may be required to pay substantial U.S. federal income taxes.
Among other requirements, the completion of the June 1, 2015 spinoff of PPL Energy Supply and subsequent combination with RJS Power was conditioned upon PPL's receipt of a legal opinion of tax counsel to the effect that the spinoff will qualify as a reorganization pursuant to Section 368(a)(1)(D) and a tax-free distribution pursuant to Section 355 of the Code. Although receipt of such legal opinion was a condition to completion of the spinoff and subsequent combination, that legal opinion is not binding on the IRS. Accordingly, the IRS could reach conclusions that are different from those in the tax opinion. If, notwithstanding the receipt of such opinion, the IRS were to determine the distribution to be taxable, PPL would, and its shareowners could, depending on their individual circumstances, recognize a tax liability that could be substantial. In addition, notwithstanding the receipt of such opinion, if the IRS were to determine the merger to be taxable, PPL shareowners may, depending on their individual circumstances, recognize a tax liability that could be material.
In addition, the spinoff will be taxable to PPL pursuant to Section 355(e) of the Code if there is a 50% or greater change in ownership (by vote or value) of either PPL or Talen Energy, directly or indirectly, as part of a plan or series of related transactions that include the spinoff. Because PPL's shareowners collectively owned more than 50% of Talen Energy's common stock following the spinoff and subsequent combination, the combination alone will not cause the spinoff to be taxable to PPL under Section 355(e) of the Code. However, Section 355(e) of the Code might apply if acquisitions of stock of PPL before or after the spinoff, or of Talen Energy after the combination, were considered to be part of a plan or series of related transactions that include the spinoff. PPL is not aware of any such plan or series of transactions that include the spinoff.
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 reduce the results of operations from 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, 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 distribution companies; |
| · | 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; |
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| · | compliance with U.S. foreign corrupt practices laws; and |
| · | prolonged periods of low inflation or deflation. |
We are subject to increased foreign currency exchange rate risks because a majority 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 increased 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 is subject to inflationary risks.
Our U.K. distribution business is subject to the risks associated with fluctuations in the RPI in the U.K., which is a measure of inflation.
In RIIO-ED1, WPD's base demand revenue was established by Ofgem in 2012/13 prices. Base demand revenue is then increased by RPI for each year to arrive at the amount of revenue WPD can collect in tariffs. The RPI is forecasted and subject to true-up in subsequent years. The fluctuations between forecasted and actual RPI can then result in variances in base demand revenue from the business plan accepted by Ofgem. While 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 demand revenue and offsets would likely affect different calendar years. Further, as RAV is also subject to increase in RPI, a reduction in RPI could adversely affect the debt/RAV ratio together with the level of subsequent RAV amortization which is an element of allowed revenue.
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.
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.
(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'
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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. In addition, if PPL elects to receive distributions of earnings from its foreign operations, PPL may incur U.S. income taxes, net of any available foreign tax credits, on such amounts.
(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.
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 generation plants, as well as our transmission and distribution operations, are all reliant on cyber-based technologies and, therefore, subject to the risk that such systems could be the target of disruptive actions, principally by terrorists or vandals, 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.
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, TRA 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; |
| · | siting, construction and operation of facilities; |
| · | mandatory reliability and safety standards under the Energy Policy Act of 2005 and other standards of conduct; |
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| · | 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; |
| · | 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 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, due to a declining trend in the number of available skilled workers and an increase in competition for such workers.
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 also applicable to the operations of our key suppliers, or customers, such as coal 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
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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 Clean Power Plan regulations governing greenhouse gas emissions at existing or new power plants, 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 generation portfolio composition and 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.
Risks Specific to Pennsylvania Regulated Segment
(PPL and PPL Electric)
We plan to selectively pursue growth of our transmission capacity, which involves a number of uncertainties and may not achieve the desired financial results.
We plan to pursue expansion of our transmission capacity over the next several years. We plan to do this through the potential construction or acquisition of transmission projects and capital investments to upgrade transmission infrastructure. These types of projects involve numerous risks. With respect to the construction or acquisition of transmission projects, we may be required to expend significant sums for preliminary engineering, permitting, resource exploration, legal and other expenses before it can be established whether a project is feasible, economically attractive or capable of being financed. Expansion in our regulated businesses is dependent on future load or service requirements and subject to applicable regulatory processes. The success of both a new or acquired project would likely be contingent, among other things, upon the negotiation of satisfactory construction contracts, obtaining acceptable financing and maintaining acceptable credit ratings, as well as receipt of required and appropriate governmental approvals. If we were unable to complete construction or expansion of a project, we may not be able to recover our investment in the project.
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 (OATT), is subject to competition pursuant to FERC Order 1000 from entities that are not incumbent PJM transmission owners with respect to the construction and ownership of transmission facilities within PJM. Increased competition can result in lower rate base growth.
We could be subject to higher costs and/or penalties related to Pennsylvania Conservation and Energy Efficiency Programs.
PPL Electric is subject to Act 129 which contains requirements for energy efficiency and conservation programs and for the use of smart metering technology, imposes PLR electricity supply procurement rules, provides remedies for market misconduct, and made changes to the existing Alternative Energy Portfolio Standard. The law also requires electric utilities to meet specified goals for reduction in customer electricity usage and peak demand. Utilities not meeting these Act 129 requirements are subject to significant penalties that cannot be recovered in rates. Numerous factors outside of our control could prevent compliance with these requirements and result in penalties to us.
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We are or may be subject to costs of remediation of environmental contamination at facilities owned or operated by PPL Electric or its 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 Related to All Segments
(All Registrants)
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 in turn 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.
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.
Disruption in financial markets could adversely affect our financial condition and results of operations.
Our businesses are heavily dependent on credit and access to capital, among other things, for financing capital expenditures. Regulations under the Dodd-Frank Act in the U.S. and Basel III in Europe may impose costly additional requirements on the businesses of others with whom we contract, such as banks or other counterparties, or simply result in increased costs to conduct our business or access sources of capital and liquidity upon which the conduct of our businesses is dependent.
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
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overall operating results may fluctuate substantially on a seasonal basis if weather conditions such as heat waves, extreme cold, unseasonably mild weather or severe storms occur. The patterns of these fluctuations may change depending on the type and location of our facilities.
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, 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 the legal proceedings and investigations currently being conducted with respect to our current and past business activities. An adverse determination 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 subject to ongoing state and federal investigations arising out of our business operations, the most significant of which are summarized in "Federal Matters" in Note 6 and "Legal Matters," "Regulatory Issues" and "Environmental Matters - Domestic" 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. We provide a similar level of benefits to our management employees. 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 be required to record impairment charges in the future for certain of our investments, which could adversely affect our earnings.
Under GAAP, we are required to test our recorded goodwill and indefinite-lived intangible assets for impairment on an annual basis, or more frequently if events or circumstances indicate that these assets may be impaired. Although no
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impairments were recorded based on our annual review in the fourth quarter of 2015, we are unable to predict whether future impairment charges may be necessary.
We also review our long-lived tangible and finite-lived intangible assets, including equity investments, for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. Although no impairment charges have been recorded related to the Company's continuing operations during the reporting periods, we are unable to predict whether impairment charges, or other losses on sales of other assets or businesses, may occur in future years.
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.
We are subject to risks associated with federal and state tax laws and regulations.
Changes in tax law as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, property, gross receipts and 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 whether such tax legislation or regulation will be introduced or enacted or the effect of any such changes on our businesses. If enacted, any changes could increase tax expense and could have a significant negative impact on our results of operations and cash flows.
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
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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 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 raised production costs or closed customer markets.
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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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, 2015, WPD's distribution system in the U.K. includes 1,748 substations with a total capacity of 71 million kVA, 56,562 circuit miles of overhead lines and 81,824 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, electric 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 electric generating capacity at December 31, 2015 was:
| LKE | LG&E | KU | |||||||||||
| Total MW | Ownership or | % Ownership | Ownership or | % Ownership | Ownership or | ||||||||
| Capacity | Other Interest | or Other | Other Interest | or Other | Other Interest | ||||||||
| Primary Fuel/Plant | Summer | in MW | Interest | in MW | 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 | 682 | 682 | 100.00 | 682 | |||||||||
| Trimble County - Unit 1 (a) | 511 | 383 | 75.00 | 383 | |||||||||
| 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 | |||||||
| 7,429 | 5,171 | 2,072 | 3,099 | ||||||||||
| 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 | 642 | 642 | 22.00 | 141 | 78.00 | 501 | |||||||
| Cane Run Unit 11 | 14 | 14 | 100.00 | 14 | |||||||||
| 2,736 | 2,736 | 789 | 1,947 | ||||||||||
| Hydro | |||||||||||||
| Ohio Falls - Units 1-8 | 58 | 58 | 100.00 | 58 | |||||||||
| Dix Dam - Units 1-3 | 32 | 32 | 100.00 | 32 | |||||||||
| 90 | 90 | 58 | 32 | ||||||||||
| Total | 10,255 | 7,997 | 2,919 | 5,078 | |||||||||
| (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 unit's total output and LG&E and KU fund their proportionate share of fuel and other operating costs. 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 10 MW of capacity for LG&E and an additional 88 MW of capacity for KU. |
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, 2015, LG&E's transmission system included in the aggregate, 46 substations (32 of which are shared with the distribution system) with a total capacity of 8 million kVA and 677 pole miles of lines. LG&E's distribution system included 97 substations (32 of which are shared with the transmission system) with a total capacity of 5 million kVA, 3,899 circuit miles of overhead lines and 2,482 underground cable miles. KU's transmission system included 138 substations (58 of which are shared with the distribution system) with a total capacity of 14 million kVA and 4,078 pole miles of lines. KU's distribution system included 479 substations (58 of which are shared with the transmission system) with a total capacity of 7 million kVA, 14,049 circuit miles of overhead lines and 2,408 underground cable miles.
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LG&E's natural gas transmission system includes 4,337 miles of gas distribution mains and 398 miles of gas transmission mains, consisting of 265 miles of gas transmission pipeline, 120 miles of gas transmission storage lines, 14 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 7 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. LG&E and KU received approval from the KPSC to build a 10 MW (4 MW for LG&E and 6 MW for KU) solar generating unit at the existing E.W. Brown site, which is expected to begin commercial operation in June 2016.
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, 2015, PPL Electric's transmission system includes 46 substations with a total capacity of 25 million kVA and 5,297 circuit miles in service. PPL Electric's distribution system includes 353 substations with a total capacity of 13 million kVA, 37,256 circuit miles of overhead lines and 8,410 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 7 to the Financial Statements for additional information.
See Note 8 to the Financial Statements for information on the Regional Transmission Line Expansion Plan.
See Notes 5, 6 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, Common Stock Price and Dividend Data," "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" and "Shareowner and Investor Information" of this report. At January 31, 2016, there were 60,137 common stock shareowners of record.
There were no purchases by PPL of its common stock during the fourth quarter of 2015.
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 $181 million in 2015 and $158 million in 2014.
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 will be paid as determined by LKE's Board of Directors. LKE made cash distributions to PPL of $219 million in 2015 and $436 million in 2014.
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 $119 million in 2015 and $112 million in 2014.
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 $153 million in 2015 and $148 million in 2014.
28
| ITEM 6. SELECTED FINANCIAL AND OPERATING DATA | ||||||||||||||||||
| PPL Corporation (a) (b) | 2015 | 2014 | 2013 | 2012 | 2011 (c) | |||||||||||||
| Income Items (in millions) | ||||||||||||||||||
| Operating revenues | $ | 7,669 | $ | 7,852 | $ | 7,263 | $ | 6,856 | $ | 6,329 | ||||||||
| Operating income | 2,831 | 2,867 | 2,561 | 2,228 | 1,659 | |||||||||||||
| Income from continuing operations after income taxes | ||||||||||||||||||
| attributable to PPL shareowners | 1,603 | 1,437 | 1,368 | 1,114 | 683 | |||||||||||||
| Income (loss) from discontinued operations (net of | ||||||||||||||||||
| income taxes) (h) | (921) | 300 | (238) | 412 | 812 | |||||||||||||
| Net income attributable to PPL shareowners (h) | 682 | 1,737 | 1,130 | 1,526 | 1,495 | |||||||||||||
| Balance Sheet Items (in millions) | ||||||||||||||||||
| Total assets (d)(f) | 39,301 | 48,606 | 45,889 | 43,509 | 42,536 | |||||||||||||
| Short-term debt (f) | 916 | 836 | 701 | 296 | 178 | |||||||||||||
| Long-term debt (d)(f) | 19,048 | 18,054 | 18,269 | 16,120 | 14,879 | |||||||||||||
| Noncontrolling interests | 18 | 268 | ||||||||||||||||
| Common equity (f) | 9,919 | 13,628 | 12,466 | 10,480 | 10,828 | |||||||||||||
| Total capitalization (f) | 29,883 | 32,518 | 31,436 | 26,914 | 26,153 | |||||||||||||
| Financial Ratios | ||||||||||||||||||
| Return on common equity - % (f)(h) | 5.8 | 13.0 | 9.8 | 13.8 | 14.9 | |||||||||||||
| Ratio of earnings to fixed charges (e) | 2.8 | 2.8 | 2.4 | 2.1 | 1.7 | |||||||||||||
| Common Stock Data | ||||||||||||||||||
| Number of shares outstanding - Basic (in thousands) | ||||||||||||||||||
| Year-end | 673,857 | 665,849 | 630,321 | 581,944 | 578,405 | |||||||||||||
| Weighted-average | 669,814 | 653,504 | 608,983 | 580,276 | 550,395 | |||||||||||||
| Income from continuing operations after income taxes | ||||||||||||||||||
| available to PPL common shareowners - Basic EPS | $ | 2.38 | $ | 2.19 | $ | 2.24 | $ | 1.91 | $ | 1.24 | ||||||||
| Income from continuing operations after income taxes | ||||||||||||||||||
| available to PPL common shareowners - Diluted EPS | $ | 2.37 | $ | 2.16 | $ | 2.12 | $ | 1.90 | $ | 1.23 | ||||||||
| Net income available to PPL common shareowners - | ||||||||||||||||||
| Basic EPS | $ | 1.01 | $ | 2.64 | $ | 1.85 | $ | 2.61 | $ | 2.71 | ||||||||
| Net income available to PPL common shareowners - | ||||||||||||||||||
| Diluted EPS | $ | 1.01 | $ | 2.61 | $ | 1.76 | $ | 2.60 | $ | 2.70 | ||||||||
| Dividends declared per share of common stock | $ | 1.50 | $ | 1.49 | $ | 1.47 | $ | 1.44 | $ | 1.40 | ||||||||
| Book value per share (f) | $ | 14.72 | $ | 20.47 | $ | 19.78 | $ | 18.01 | $ | 18.72 | ||||||||
| Market price per share | $ | 34.13 | $ | 36.33 | $ | 30.09 | $ | 28.63 | $ | 29.42 | ||||||||
| Dividend payout ratio - % (g)(h) | 149 | 57 | 84 | 55 | 52 | |||||||||||||
| Dividend yield - % (i) | 4.4 | 4.1 | 4.9 | 5.0 | 4.8 | |||||||||||||
| Price earnings ratio (g)(h)(i) | 33.8 | 13.9 | 17.1 | 11.0 | 10.9 | |||||||||||||
| Sales Data - GWh | ||||||||||||||||||
| Domestic - Electric energy supplied - wholesale | 2,241 | 2,365 | 2,383 | 2,304 | 3,550 | |||||||||||||
| Domestic - Electric energy delivered - retail | 67,798 | 68,569 | 67,848 | 66,931 | 67,806 | |||||||||||||
| U.K. - Electric energy delivered | 75,907 | 75,813 | 78,219 | 77,467 | 58,245 | |||||||||||||
| (a) | The earnings each year were affected by several items that management considers special. See "Results of Operations - Segment Earnings" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of special items in 2015, 2014 and 2013. The earnings were also affected by the spinoff of PPL Energy Supply and the sale of the Montana hydroelectric generating facilities. See Note 8 to the Financial Statements for a discussion of discontinued operations in 2015, 2014 and 2013. |
| (b) | See "Item 1A. Risk Factors" and Notes 1, 6 and 13 to the Financial Statements for a discussion of uncertainties that could affect PPL's future financial condition. |
| (c) | 2011 includes eight months of WPD Midlands activity following the April 1, 2011 acquisition, as PPL consolidates on a one-month lag. |
| (d) | All years reflect the retrospective adoption of new accounting guidance related to the presentation of debt issuance costs and deferred taxes. See Note 1 to the Financial Statements for additional information. |
| (e) | Computed using earnings and fixed charges of PPL and its subsidiaries. Fixed charges consist of interest of on short and long-term debt, amortization of debt discount, expense and premium-net, other interest charges, the estimated interest component of operating rentals and preferred securities distributions of subsidiaries. See Exhibit 12(a) for additional information. |
| (f) | 2015 reflects the impact of the spinoff of PPL Energy Supply and a $3.2 billion related dividend. |
| (g) | Based on diluted EPS. |
| (h) | 2015 includes an $879 million loss on the spinoff of PPL Energy Supply, reflecting the difference between PPL's recorded value for the Supply segment and the estimated fair value determined in accordance with the applicable accounting rules under GAAP. 2015 also includes five months of Supply segment earnings, compared to 12 months in 2014. |
| (i) | Based on year-end market prices. |
29
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
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.
30
Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
(All Registrants)
This "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" is separately filed by PPL Corporation, PPL Electric, LKE, LG&E and KU. Information contained herein relating to any individual Registrant is filed by such Registrant solely on its own behalf, and no Registrant makes any representation as to information relating to any other Registrant. The specific Registrant to which disclosures are applicable is identified in parenthetical headings in italics above the applicable disclosure or within the applicable disclosure for each Registrant's related activities and disclosures. Within combined disclosures, amounts are disclosed for any Registrant when significant.
The following should be read in conjunction with the Registrants' Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, except per share data, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
| · | "Overview" provides a description of each Registrant's business strategy, a description of key factors expected to impact future earnings and a discussion of important financial and operational developments. |
| · | "Results of Operations" for PPL provides a detailed analysis of earnings by segment, and for PPL Electric, LKE, LG&E and KU, includes a summary of earnings. For all Registrants, "Non-GAAP Financial Measures", "Earnings from Ongoing Operations" and "Margins" provide explanations of non-GAAP measures used and reconciliations to the most directly comparable GAAP measure. "Statement of Income Analysis" addresses significant changes in principal line items on the Statements of Income, comparing 2015 with 2014 and 2014 with 2013. |
| · | "Financial Condition - Liquidity and Capital Resources" provides an analysis of the Registrants' liquidity positions and credit profiles. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions. |
| · | "Financial Condition - Risk Management" provides an explanation of the Registrants' risk management programs relating to market and credit risk. |
| · | "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of the Registrants and that require their management to make significant estimates, assumptions and other judgments of inherently uncertain matters. |
For a description of the Registrants and their businesses, see "Item 1. Business."
In June 2014, PPL and PPL Energy Supply executed definitive agreements with affiliates of Riverstone to spin off PPL Energy Supply and immediately combine it with Riverstone's competitive power generation businesses to form a new, stand-alone, publicly traded company named Talen Energy. On June 1, 2015, the spinoff was completed. See "Financial and Operational Developments - Other Financial and Operational Developments - Spinoff of PPL Energy Supply" below for additional information.
(All Registrants)
Following the June 1, 2015 spinoff of PPL Energy Supply, PPL completed its strategic transformation to a fully regulated business model consisting of seven diverse, high-performing utilities. These utilities are located in the U.K., Pennsylvania and Kentucky and each jurisdiction has different regulatory structures and customer classes. The Company believes this diverse portfolio provides strong earnings and dividend growth potential that will create significant value for its shareowners and positions PPL well for continued growth and success.
31
PPL's businesses of WPD, PPL Electric, LG&E and KU plan to achieve this growth by providing efficient, reliable and safe operations and strong customer service, maintaining constructive regulatory relationships and achieving timely recovery of costs. These businesses are expected to achieve strong, long-term growth in rate base and RAV, as applicable, driven by planned significant capital expenditures to maintain existing assets and improve system reliability and, for LKE, LG&E and KU, to comply with federal and state environmental regulations related to coal-fired electricity generation facilities. Additionally, significant transmission rate base growth is expected through 2020 at PPL Electric.
For the U.S. businesses, our strategy is to recover capital project costs efficiently through various rate-making mechanisms, including periodic base rate case proceedings using forward test years, annual FERC formula rate mechanisms and other regulatory agency-approved recovery mechanisms designed to limit regulatory lag. In Kentucky, the KPSC has adopted a series of regulatory mechanisms (ECR, DSM, GLT, fuel adjustment clause, gas supply clause and recovery on construction work-in-progress) that reduce regulatory lag and provide timely recovery of and return on, as appropriate, prudently incurred costs. In addition, the KPSC requires a utility to obtain a CPCN prior to constructing a facility, unless the construction is an ordinary extension of existing facilities in the usual course of business or does not involve sufficient capital outlay to materially affect the utility's financial condition. Although such KPSC proceedings do not directly address cost recovery issues, the KPSC, in awarding a CPCN, concludes that the public convenience and necessity require the construction of the facility on the basis that the facility is the lowest reasonable cost alternative for addressing the need. In Pennsylvania, the FERC transmission formula rate, DSIC mechanism, Smart Meter Rider and other recovery mechanisms are in place to reduce regulatory lag and provide for timely recovery of and a return on prudently incurred costs.
Although rate base growth in the domestic utilities is expected to result in strong earnings growth for the foreseeable future, PPL does not expect significant earnings growth from the U.K. Regulated segment under the RIIO-ED1 price control period, which began on April 1, 2015. Although the U.K. Regulated segment also projects strong RAV growth, earnings from this segment are expected to be relatively flat from 2015 to 2017 during the transition to RIIO-ED1. Higher revenues resulting from the fast-track bonus are partially offset by higher levels of revenue profiling in the prior price control period (DPCR5) and a lower return on regulatory equity. In addition, starting in 2017, the amount of incentive revenues WPD is able to earn is expected to decline as a result of more stringent reliability and customer service targets established by Ofgem under RIIO-ED1. See "Item 1. Business - General - Segment Information - U.K. Regulated Segment" for additional information on revenues under RIIO-ED1.
To manage financing costs and access to credit markets, and to fund capital expenditures, a key objective of the Registrants is to maintain their investment grade credit ratings and adequate liquidity positions. In addition, the Registrants have financial and operational risk management programs that, among other things, are designed to monitor and manage exposure to earnings and cash flow volatility, as applicable, related to changes in interest rates, foreign currency exchange rates and counterparty credit quality. To manage these risks, PPL generally uses contracts such as forwards, options, and swaps.
As discussed above, a key component of this strategy is to maintain constructive relationships with our regulators in all jurisdictions in which we operate (U.K., U.S. federal and state). This is supported by our strong culture of integrity and delivering on commitments to our customers, regulators and shareowners, and a commitment to continue to improve our customer service, reliability and efficiency of operations.
(PPL)
Earnings generated by PPL's U.K. subsidiaries are subject to foreign currency translation risk. The U.K. subsidiaries also have currency exposure to the U.S. dollar to the extent of their U.S. dollar denominated debt. To manage these risks, PPL generally uses contracts such as forwards, options and cross currency swaps that contain characteristics of both interest rate and foreign currency exchange contracts.
Following the June 1, 2015 spinoff of PPL Energy Supply, PPL has no continuing ownership interest in or control of Talen Energy and Talen Energy Supply (formerly, PPL Energy Supply).
See "Item 1. Business," "Item 1A. Risk Factors" and "Financial and Operational Developments - Other Financial and Operational Developments - Cost of Spinoff" and "Loss on Spinoff" below for additional information.
Financial and Operational Developments
PPL's earnings by reportable segment were as follows:
32
| $ Change | ||||||||||||||||
| 2015 | 2014 | 2013 | 2015 vs. 2014 | 2014 vs. 2013 | ||||||||||||
| U.K. Regulated | $ | 1,121 | $ | 982 | $ | 922 | $ | 139 | $ | 60 | ||||||
| Kentucky Regulated | 326 | 312 | 307 | 14 | 5 | |||||||||||
| Pennsylvania Regulated | 252 | 263 | 209 | (11) | 54 | |||||||||||
| Corporate and Other (a) | (96) | (120) | (68) | 24 | (52) | |||||||||||
| Discontinued Operations (b) | (921) | 300 | (240) | (1,221) | 540 | |||||||||||
| Net Income | $ | 682 | $ | 1,737 | $ | 1,130 | $ | (1,055) | $ | 607 | ||||||
| (a) | Primarily represents financing and certain other costs incurred at the corporate level that have not been allocated or assigned to the segments, which are presented to reconcile segment information to PPL's consolidated results. 2015 and 2014 include costs related to the spinoff of PPL Energy Supply. See Note 8 to the Financial Statements for additional information. | |
| (b) | As a result of the spinoff of PPL Energy Supply, substantially representing PPL's Supply segment, the earnings of the Supply segment are included in Discontinued Operations. 2015 includes an $879 million charge reflecting the difference between PPL's recorded value for the Supply segment and its estimated fair value as of the spinoff date, determined in accordance with the applicable accounting rules under GAAP. See Note 8 to the Financial Statements for additional information. 2013 excludes $2 million which has been classified as discontinued operations in the Kentucky Regulated segment. |
PPL's Earnings from Ongoing Operations by reportable segment were as follows:
| $ Change | ||||||||||||||||
| 2015 | 2014 | 2013 | 2015 vs. 2014 | 2014 vs. 2013 | ||||||||||||
| U.K. Regulated | $ | 968 | $ | 907 | $ | 855 | $ | 61 | $ | 52 | ||||||
| Kentucky Regulated | 343 | 312 | 304 | 31 | 8 | |||||||||||
| Pennsylvania Regulated | 252 | 265 | 209 | (13) | 56 | |||||||||||
| Corporate and Other (a)(b) | (74) | (135) | (118) | 61 | (17) | |||||||||||
| Earnings from Ongoing Operations | $ | 1,489 | $ | 1,349 | $ | 1,250 | $ | 140 | $ | 99 | ||||||
| (a) | 2014 and 2013 were adjusted to include costs that were previously allocated to the Supply segment that would remain with PPL after the completion of the transaction, if left unmitigated. See "Non-GAAP Financial Measures - Reconciliation of Earnings from Ongoing Operations" below for an itemization of special items impacting Corporate and Other. |
| (b) | Costs were lower in 2015 compared with 2014, primarily due to the benefits of corporate restructuring. Costs were higher in 2014 compared with 2013, primarily due to higher long-term debt interest expense. |
See "Non-GAAP Financial Measures" below for PPL's definition of Earnings from Ongoing Operations as well as a reconciliation of this non-GAAP financial measure to Net Income.
See "Results of Operations" below for further discussion of PPL's results of operations, details of special items by reportable segments and analysis of the consolidated results of operations.
(PPL)
Excluding special items, higher earnings are expected in 2016 compared with 2015. This increase is primarily attributable to increases in the Kentucky Regulated and Pennsylvania Regulated segments. The following projections and factors underlying these projections (on an after-tax basis) are provided for PPL's segments and the Corporate and Other category and the related Registrants.
(PPL's U.K. Regulated Segment)
Excluding special items, relatively flat earnings are projected in 2016 compared with 2015, due to higher financing costs, depreciation expense, currency, taxes and other expenses, partially offset by lower operation and maintenance expense, including pension expense, and higher gross margins. The 2016 foreign currency exposure for this segment is 95% hedged at an average rate of $1.56 per pound.
(PPL's Kentucky Regulated Segment and LKE, LG&E and KU)
Excluding special items, higher earnings are projected in 2016 compared with 2015, primarily driven by electric and gas base rate increases effective July 1, 2015, and higher returns on additional environmental capital investments, partially offset by higher depreciation expense and higher financing costs.
33
(PPL's Pennsylvania Regulated Segment and PPL Electric)
Excluding special items, higher earnings are projected in 2016 compared with 2015, primarily driven by a distribution base rate increase effective January 1, 2016, and higher transmission margins, partially offset by higher depreciation expense, higher financing costs and a benefit received in 2015 from the release of a gross receipts tax reserve.
(PPL's Corporate and Other Category)
Excluding special items, costs are projected to be relatively flat in 2016 compared with 2015.
(All Registrants)
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7, and Notes 1, 6 and 13 to the Financial Statements (as applicable) for a discussion of the risks, uncertainties and factors that may impact future earnings.
Other Financial and Operational Developments
Regulatory Requirements
(PPL, LKE, LG&E and KU)
The businesses of LKE, LG&E and KU are subject to extensive federal, state and local environmental laws, rules and regulations, including those pertaining to CCRs, GHG, ELGs, MATS and the Clean Power Plan. See "Financial Condition - Environmental Matters" below for additional information on the CCRs requirements and Note 13 to the Financial Statements for a discussion of the other significant environmental matters. These and other stringent environmental requirements have led PPL, LKE, LG&E and KU to retire approximately 800 megawatts of coal-fired generating plants in Kentucky. In September 2015, KU retired two coal-fired units, with a combined summer capacity rating of 161 MW, at the Green River plant. LG&E retired a 240 MW coal-fired unit in March 2015 and two additional coal-fired units, with a combined summer capacity rating of 323 MW, in June 2015 at the Cane Run plant. KU retired a 71 MW coal-fired unit at the Tyrone plant in 2013. The retirement of these units is not expected to have a material impact on the financial condition or results of operations of PPL, LKE, LG&E and KU.
Also as a result of the environmental requirements discussed above, LKE projects $1.9 billion ($1.0 billion at KU and $0.9 billion at LG&E) in environmental capital investment over the next five years. See PPL's "Financial Condition - Forecasted Uses of Cash - Capital Expenditures", Note 6 and Note 13 for additional information.
(All Registrants)
The Registrants cannot predict the impact that future regulatory requirements may have on their financial condition or results of operations.
(PPL)
Spinoff of PPL Energy Supply
In June 2014, PPL and PPL Energy Supply executed definitive agreements with affiliates of Riverstone to spin off PPL Energy Supply and immediately combine it with Riverstone's competitive power generation businesses to form a new, stand-alone, publicly traded company named Talen Energy. In June 2015, the spinoff was completed. See Note 8 to the Financial Statements for additional information relating to the transaction.
Loss on Spinoff
In conjunction with the accounting for the spinoff, PPL evaluated whether the fair value of the Supply segment's net assets was less than the carrying value as of the June 1, 2015 spinoff date.
PPL considered several valuation methodologies to derive a fair value estimate of its Supply segment at the spinoff date. These methodologies included considering the closing "when-issued" Talen Energy market value on June 1, 2015 (the spinoff
34
date) adjusted for the proportional share of the equity value attributable to the Supply segment, as well as the valuation methods consistently used in PPL's goodwill impairment assessments - an income approach using a discounted cash flow analysis of the Supply segment and an alternative market approach considering market multiples of comparable companies.
Although the market value of Talen Energy approach utilized the most observable inputs of the three approaches, PPL considered certain limitations of the "when-issued" trading market for the spinoff transaction including the short trading duration, lack of liquidity in the market and anticipated initial Talen stock ownership base selling pressure, among other factors, and concluded that these factors limit the appropriateness of this input being solely determinative of the fair value of the Supply segment. As such, PPL also considered the other valuation approaches in estimating the overall fair value, but ultimately assigned the highest weighting to the Talen Energy market value approach.
The following table summarizes PPL's fair value analysis:
| Weighted | |||||||
| Fair Value | |||||||
| Approach | Weighting | (in billions) | |||||
| Talen Energy Market Value | 50% | $ | 1.4 | ||||
| Income/Discounted Cash Flow | 30% | 1.1 | |||||
| Alternative Market (Comparable Company) | 20% | 0.7 | |||||
| Estimated Fair Value | $ | 3.2 | |||||
A key assumption included in the fair value estimate is the application of a control premium of 25% in the two market approaches. PPL concluded it was appropriate to apply a control premium in these approaches as the goodwill impairment testing guidance was followed in determining the estimated fair value of the Supply segment, which had historically been a reporting unit for PPL. This guidance provides that the market price of an individual security (and thus the market capitalization of a reporting unit with publically traded equity securities) may not be representative of the fair value of the reporting unit. This guidance also indicates that substantial value may arise to a controlling shareholder from the ability to take advantage of synergies and other benefits that arise from control over another entity, and that the market price of a Company's individual share of stock does not reflect this additional value to a controlling shareholder. Therefore, the quoted market price need not be the sole measurement basis for determining the fair value, and including a control premium is appropriate in measuring the fair value of a reporting unit.
In determining the control premium, PPL reviewed premiums received during the last five years in market sales transactions obtained from observable independent power producer and hybrid utility transactions greater than $1 billion. Premiums for these transactions ranged from 5% to 42% with a median of approximately 25%. Given these metrics, PPL concluded a control premium of 25% to be reasonable for both of the market valuation approaches used.
Assumptions used in the discounted cash flow analysis included forward energy prices, forecasted generation, and forecasted operation and maintenance expenditures that were consistent with assumptions used in the Energy Supply portion of the recent Talen Energy business planning process and a market participant discount rate.
Using these methodologies and weightings, PPL determined the estimated fair value of the Supply segment (classified as Level 3) was below its carrying value of $4.1 billion and recorded a loss on the spinoff of $879 million in the second quarter of 2015, which is reflected in discontinued operations and is nondeductible for tax purposes. This amount served to reduce the basis of the net assets accounted for as a dividend at the June 1, 2015 spinoff date.
Costs of Spinoff
Following the announcement of the transaction to form Talen Energy, efforts were initiated to identify the appropriate staffing for Talen Energy and for PPL and its subsidiaries following completion of the spinoff. Organizational plans were substantially completed in 2014. The new organizational plans identified the need to resize and restructure the organizations and as a result, in 2014, estimated charges of $36 million for employee separation benefits were recorded related to 306 positions. Of this amount, $16 million related to 112 Energy Supply positions and is reflected in discontinued operations. The remaining $20 million is primarily reflected in "Other operation and maintenance" on the PPL Consolidated Statements of Income. In 2015, the organizational structures were finalized for both PPL and Talen Energy which resulted in an additional charge of $10 million for employee separation benefits. Of this amount, $2 million related to Energy Supply positions and is reflected in discontinued operations. The remaining $8 million is reflected in "Other operation and maintenance" on the PPL Consolidated Statements of Income. The separation benefits include cash severance compensation, lump sum COBRA reimbursement payments and outplacement services. At December 31, 2015 and 2014, the recorded
35
liabilities related to the separation benefits were $13 million and $20 million, which are included in "Other current liabilities" on the Balance Sheets.
Additional employee-related costs incurred primarily included accelerated stock-based compensation and prorated performance-based cash incentive and stock-based compensation awards, primarily for PPL Energy Supply employees and for PPL Services employees who became PPL Energy Supply employees in connection with the transaction. PPL Energy Supply recognized $24 million of these costs at the spinoff closing date in 2015, which are reflected in discontinued operations.
PPL recorded $45 million and $27 million of third-party costs related to this transaction in 2015 and 2014. Of these costs, $32 million and $19 million were primarily for bank advisory, legal and accounting fees to facilitate the transaction, and are reflected in discontinued operations. An additional $13 million and $8 million of consulting and other costs were incurred in 2015 and 2014, related to the formation of the Talen Energy organization and to reconfigure the remaining PPL service functions. These costs are recorded primarily in "Other operation and maintenance" on the Statements of Income. No significant additional third-party costs are expected to be incurred.
At the close of the transaction in 2015, $72 million ($42 million after-tax) of cash flow hedges, primarily unamortized losses on PPL interest rate swaps recorded in AOCI and designated as cash flow hedges of PPL Energy Supply's future interest payments, were reclassified into interest expense and reflected in discontinued operations.
As a result of the June 2014 spinoff announcement, PPL recorded $50 million of deferred income tax expense in 2014, to adjust valuation allowances on deferred tax assets primarily for state net operating loss carryforwards that were previously supported by the future earnings of PPL Energy Supply.
Discontinued Operations
The operations of PPL's Supply segment are included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income.
The assets and liabilities of PPL's Supply segment for all periods prior to the spinoff are included in "Current assets of discontinued operations", "Noncurrent assets of discontinued operations", "Current liabilities of discontinued operations" and "Noncurrent liabilities of discontinued operations" on PPL's Balance Sheet.
Net assets, after recognition of the loss on spinoff, of $3.2 billion were distributed to PPL shareowners in the June 1, 2015 spinoff of PPL Energy Supply.
See Note 8 to the Financial Statements for additional information related to the spinoff of PPL Energy Supply, including the components of Discontinued Operations.
(PPL)
RIIO-ED1
On April 1, 2015, the RIIO-ED1 eight-year price control period commenced for WPD's four DNOs. In February 2014, Ofgem published formal confirmation that WPD's Business Plans submitted by its four DNOs under RIIO-ED1 were accepted as submitted, or "fast-tracked." Fast tracking afforded several benefits to the WPD DNOs including the ability to collect additional revenue equivalent to 2.5% of Totex during the eight-year price control period (approximately $43 million annually), greater revenue certainty and a higher level of cost savings retention. See "Item 1. Business - Segment Information - U.K. Regulated Segment" for additional information on RIIO-ED1.
U.K. Depreciation
Effective January 1, 2015, after completing a review of the useful lives of its distribution network assets, WPD extended the weighted average useful lives of these assets to 69 years from 55 years for GAAP reporting of depreciation expense. For 2015, this change in useful lives resulted in lower depreciation expense of $84 million ($66 million after-tax or $0.10 per share).
36
U.K. Distribution Revenue Reduction
In December 2013, WPD and other U.K. DNOs announced agreements with the U.K. Department of Energy and Climate Change and Ofgem to a reduction of £5 per residential customer of electricity distribution revenues that otherwise would have been collected in the regulatory year beginning April 1, 2014. Full recovery of the revenue reduction, together with the associated carrying cost will occur in the regulatory year beginning April 1, 2016. Under GAAP, WPD does not record a receivable for under recovery of regulated income (which this reduction represents), as a result earnings for the U.K. Regulated segment were adversely affected by $15 million in 2015 and $31 million in 2014. PPL projects earnings in 2016 will be positively affected by $32 million and earnings for 2017 will be positively affected by $17 million.
U.K. Tax Rate Change
In November 2015, the U.K. Summer 2015 Budget was enacted, which reduces the U.K.'s statutory income tax rate from 20% to 19% effective April 1, 2017 and from 19% to 18% effective April 1, 2020. As a result of these changes, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit of approximately $90 million (4% effective tax rate impact) in 2015.
Discount Rate Change for U.K. Pension Plans
In selecting the discount rate for its U.K. pension plans, WPD historically used a single weighted-average discount rate in the calculation of net periodic defined benefit cost. WPD will begin using individual spot rates to measure service cost and interest cost beginning with the calculation of 2016 net periodic defined benefit cost. Based on current estimates, PPL expects this change to reduce net periodic defined benefit costs by $44 million ($36 million after-tax or $0.05 per share) in 2016. Assuming interest rates continue to rise, the benefit is highest in the initial year and then falls over time as the additional actuarial losses on liabilities are amortized. See "Application of Critical Accounting Policies-Defined Benefits" for additional information.
(PPL and PPL Electric)
Rate Case Proceedings
On March 31, 2015, PPL Electric filed a request with the PUC to increase its annual distribution revenue requirement by approximately $167.5 million. The application is based on a fully projected future test year of January 1, 2016 through December 31, 2016. On September 3, 2015, PPL Electric filed with the PUC Administrative Law Judge a petition for approval of a settlement agreement resolving all issues in the case. On November 19, 2015, the PUC issued its final order approving the settlement agreement. Under that agreement, PPL Electric was permitted to increase its annual distribution rates by $124 million, effective January 1, 2016.
On March 31, 2015, PPL Electric filed a petition requesting a waiver of the DSIC cap of 5% of billed revenues and approval to increase the maximum allowable DSIC from 5% to 7.5% for service rendered after January 1, 2016. PPL Electric filed the petition concurrently with its 2015 rate case and the Administrative Law Judge granted PPL Electric's request to consolidate these two proceedings. Under the terms of the settlement agreement discussed above, PPL Electric agreed to withdraw the petition without prejudice to filing it at a later date.
Regional Transmission Expansion Plan
In July 2014, PPL Electric announced Project Compass, a proposal to construct a new multi-state transmission line. On October 27, 2015, PPL Electric filed an interconnection application with the New York Independent System Operator for the first segment of the project which contains a proposed 95-mile, $500 million to $600 million line between Blakely, Pennsylvania, and Ramapo, New York. The proposed line is intended to provide significant economic benefits for electricity customers in New York and also to provide grid reliability and grid security benefits for electricity customers in both states. The construction is proposed to begin in 2019 and be in operation by 2023. There will be numerous approvals required, including, among others, the public utility commissions of Pennsylvania and New York, the New York Independent System Operator, PJM, and FERC. As originally proposed in 2014, Project Compass would have run from western Pennsylvania into New York and New Jersey and also south into Maryland, covering approximately 725 miles at an estimated cost of $4 billion to $6 billion. The project has been revised to include about 475 miles of transmission line in Pennsylvania and New York at an estimated cost of $3 billion to $4 billion. Beyond this segment, no schedule is proposed for the rest of the project. There can be no assurance that this segment of Project Compass will be approved as proposed. Additionally, PPL Electric is
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continuing to study the project and may modify it in the future. The capital expenditures related to this project are excluded from the Capital Expenditures table included in "Liquidity and Capital Resources-Forecasted Uses of Cash" below.
FERC Wholesale Formula Rates (LKE and KU)
In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provided wholesale requirements power sales to 12 municipal customers. Among other changes, the application requests an amended formula whereby KU would charge cost-based rates with a subsequent true-up to actual costs, replacing the current formula which does not include a true-up. KU's application proposed an authorized return on equity of 10.7%. Certain elements, including the new formula rate, became effective April 23, 2014, subject to refund. In April 2014, nine municipalities submitted notices of termination, under the original notice period provisions, to cease taking power under the wholesale requirements contracts. Such terminations are to be effective in 2019, except in the case of one municipality with a 2017 effective date. In addition, a tenth municipality has become a transmission-only customer as of June 2015. In July 2014, KU agreed on settlement terms with the two municipal customers that did not provide termination notices and filed the settlement proposal with the FERC for its approval. In August 2014, the FERC issued an order on the interim settlement agreement allowing the proposed rates to become effective pending a final order. During the fourth quarter of 2015, the FERC approved the settlement agreement resolving the rate case with respect to these two municipalities, including approval of the formula rate with a true-up provision and authorizing a return on equity of 10% or the return on equity awarded to other parties in this case, whichever is lower. In August 2015, KU filed a partial settlement agreement with the nine terminating municipalities, resolving all but one open matter with one municipality. The settlement was approved by FERC in the fourth quarter of 2015, including authorizing the agreed-upon refunds, approving the formula rate with a true-up provision, and authorizing a 10.25% return on equity. Refunds to both the remaining municipals and the departing municipals were issued during the fourth quarter of 2015 totaling $3.4 million. A single remaining unresolved issue with one terminating municipality is in FERC litigation proceedings. Hearings on the dispute were conducted in January 2016 and preliminary rulings on the matter may occur in mid- or late-2016. KU cannot predict the ultimate outcome of this remaining FERC proceeding, but the amounts under continuing dispute are not estimated to be significant.
Rate Case Proceedings (LKE, LG&E and KU)
On June 30, 2015, the KPSC approved a rate case settlement agreement providing for increases in the annual revenue requirements associated with KU base electricity rates of $125 million and LG&E base gas rates of $7 million. The annual revenue requirement associated with base electricity rates at LG&E was not changed. Although the settlement did not establish a specific return on equity with respect to the base rates, an authorized 10% return on equity will be utilized in the ECR and GLT mechanisms. The settlement agreement provides for deferred recovery of costs associated with KU's retirement of Green River Units 3 and 4. The new regulatory asset will be amortized over three years. The settlement also provides regulatory asset treatment for the difference between pension expense calculated in accordance with LG&E and KU's pension accounting policy and pension expense using a 15 year amortization period for actuarial gains and losses. The new rates and all elements of the settlement became effective July 1, 2015.
On June 30, 2015, KU filed an application with the VSCC to increase annual Virginia base electricity revenue by approximately $7 million, representing an increase of 10.1%. On December 3, 2015, KU and other parties filed a proposed settlement with the VSCC. On February 2, 2016, the VSCC issued an order approving the settlement. The settlement provides for annual electric base revenues of $6 million and establishes an authorized return on equity range of 9.5% to 10.5% for annual rate review purposes. The new rates became effective February 15, 2016.
(PPL)
The discussion for PPL provides a review of results by reportable segment. The "Non-GAAP Financial Measures" discussion provides explanations of non-GAAP financial measures and a reconciliation of non-GAAP financial measures to the most comparable GAAP measure. The "Statement of Income Analysis" discussion addresses significant changes in principal line items on PPL's Statements of Income, comparing year-to-year changes. "Segment Earnings, Non-GAAP Financial Measures and Statement of Income Analysis" is presented separately for PPL.
Tables analyzing changes in amounts between periods within "Segment Earnings" and "Statement of Income Analysis" are presented on a constant U.K. foreign currency exchange rate basis, where applicable, in order to isolate the impact of the change in the exchange rate on the item being explained. Results computed on a constant U.K. foreign currency exchange
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rate basis are calculated by translating current year results at the prior year weighted-average U.K. foreign currency exchange rate.
(Subsidiary Registrants)
The discussion for each of PPL Electric, LKE, LG&E and KU provides a summary of earnings. The "Margins" discussion includes a reconciliation of non-GAAP financial measures to "Operating Income" and "Statement of Income Analysis" addresses significant changes in principal line items on the Statements of Income comparing year-to-year changes. "Earnings, Margins and Statement of Income Analysis" are presented separately for PPL Electric, LKE, LG&E and KU.
PPL Segment Earnings, Non-GAAP Financial Measures and Statement of Income Analysis
Segment Earnings
U.K. Regulated Segment
The U.K. Regulated segment 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 to U.S. dollars, and certain costs, such as U.S. income taxes, administrative costs, and allocated financing costs. The U.K. Regulated segment represents 70% of PPL's Income from Continuing Operations After Income Taxes for 2015 and 42% of PPL's assets at December 31, 2015.
Net Income and Earnings from Ongoing Operations include the following results.
| Change | ||||||||||||||||
| 2015 | 2014 | 2013 | 2015 vs. 2014 | 2014 vs. 2013 | ||||||||||||
| Operating revenues | $ | 2,410 | $ | 2,621 | $ | 2,403 | $ | (211) | $ | 218 | ||||||
| Other operation and maintenance | 477 | 482 | 499 | (5) | (17) | |||||||||||
| Depreciation | 242 | 337 | 300 | (95) | 37 | |||||||||||
| Taxes, other than income | 148 | 157 | 147 | (9) | 10 | |||||||||||
| Total operating expenses | 867 | 976 | 946 | (109) | 30 | |||||||||||
| Other Income (Expense) - net | 123 | 127 | (39) | (4) | 166 | |||||||||||
| Interest Expense | 417 | 461 | 425 | (44) | 36 | |||||||||||
| Income Taxes | 128 | 329 | 71 | (201) | 258 | |||||||||||
| Net Income | 1,121 | 982 | 922 | 139 | 60 | |||||||||||
| Less: Special Items | 153 | 75 | 67 | 78 | 8 | |||||||||||
| Earnings from Ongoing Operations | $ | 968 | $ | 907 | $ | 855 | $ | 61 | $ | 52 | ||||||
The following after-tax gains (losses), which management considers special items, impacted the U.K. Regulated segment's results and are excluded from Earnings from Ongoing Operations.
| Income Statement | ||||||||||||
| Line Item | 2015 | 2014 | 2013 | |||||||||
| Other Income | ||||||||||||
| Foreign currency-related economic hedges, net of tax of ($30), ($68), $15 (a) | (Expense) - net | $ | 55 | $ | 127 | $ | (29) | |||||
| WPD Midlands acquisition-related adjustments: | ||||||||||||
| Other operation | ||||||||||||
| Separation benefits, net of tax of $0, $0, $1 | and maintenance | (4) | ||||||||||
| Other acquisition-related adjustments, net of tax of ($1), $0, ($2) | 2 | 8 | ||||||||||
| Other: | ||||||||||||
| Change in U.K. tax rate (b) | Income Taxes | 78 | 84 | |||||||||
| Windfall Profits Tax litigation (c) | Income Taxes | 43 | ||||||||||
| Settlement of certain income tax positions (d) | Income Taxes | 18 | ||||||||||
| Change in WPD line loss accrual, net of tax of $0, $13, $10 (e) | Operating Revenues | (52) | (35) | |||||||||
| Total | $ | 153 | $ | 75 | $ | 67 | ||||||
| (a) | Represents unrealized gains (losses) on contracts that economically hedge anticipated GBP-denominated earnings. |
| (b) | The U.K. Finance Acts of 2015 and 2013 reduced the U.K.'s statutory income tax rates. As a result, PPL reduced its net deferred tax liability and recognized a deferred tax benefit in 2015 and 2013. See Note 5 to the Financial Statements for additional information. |
| (c) | In May 2013, the U.S. Supreme Court reversed the December 2011 ruling by the U.S. Court of Appeals for the Third Circuit concerning the creditability of the U.K. Windfall Profits Tax for U.S. Federal income tax purposes. As a result, PPL recorded an income tax benefit in 2013. See Note 5 to the Financial Statements for additional information. |
| (d) | Relates to the 2015 settlement of the IRS audit for the tax years 1998-2011. See Note 5 to the Financial Statements for additional information. |
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| (e) | In 2013, WPD Midlands increased its line loss liability for DCPR4 based on additional information provided by Ofgem regarding the calculation. In March 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism. As a result, WPD increased its existing liability for over-recovery of line losses. See Note 6 to the Financial Statements for additional information. |
The changes in the components of the U.K. Regulated segment's results between these periods were due to the factors set forth below, which reflect amounts classified as U.K. Gross Margins, the items that management considers special and the effects of movements in foreign currency exchange, including the effects of foreign currency hedge contracts, on separate lines and not in their respective Statement of Income line items.
| 2015 vs. 2014 | 2014 vs. 2013 | ||||||
| U.K. | |||||||
| Gross margins | $ | (110) | $ | 94 | |||
| Other operation and maintenance | (14) | 44 | |||||
| Depreciation | 76 | (19) | |||||
| Interest expense | 3 | (15) | |||||
| Other | (5) | 4 | |||||
| Income taxes | 48 | (24) | |||||
| U.S. | |||||||
| Interest expense and other | 12 | 4 | |||||
| Income taxes | 55 | (41) | |||||
| Foreign currency exchange, after-tax | (4) | 5 | |||||
| Earnings from Ongoing Operations | 61 | 52 | |||||
| Special items, after-tax | 78 | 8 | |||||
| Net Income | $ | 139 | $ | 60 | |||
U.K.
| · | See "Non-GAAP Financial Measures - Margins - Changes in Margins" for an explanation of U.K. Gross Margins. |
| · | Lower other operation and maintenance in 2014 compared with 2013 primarily due to $38 million from lower pension expense. |
| · | Lower depreciation expense in 2015 compared with 2014 primarily due to an $84 million impact of an extension of the network asset lives. See Note 1 to the Financial Statements for additional information. |
| · | Higher depreciation expense in 2014 compared with 2013 primarily due to PP&E additions, net. |
| · | Higher interest expense in 2014 compared with 2013 primarily due to an October 2013 debt issuance. |
| · | Lower income taxes in 2015 compared with 2014 primarily due to $25 million from lower U.K. tax rates and $11 million from lower pre-tax income. |
| · | Higher income taxes in 2014 compared with 2013 primarily due to higher pre-tax income. |
U.S.
| · | Lower income taxes in 2015 compared with 2014 primarily due to decreases in taxable dividends. |
| · | Higher income taxes in 2014 compared with 2013 primarily due to a $19 million increase primarily in taxable dividends and a $19 million benefit in 2013 related to an IRS ruling regarding 2010 U.K. earnings and profits calculations. |
Kentucky Regulated Segment
The Kentucky Regulated segment consists primarily of LKE's regulated electricity generation, transmission and distribution operations of LG&E and KU, as well as LG&E's regulated distribution and sale of natural gas. In addition, certain financing costs are allocated to the Kentucky Regulated segment. The Kentucky Regulated segment represents 20% of PPL's Income from Continuing Operations After Income Taxes for 2015 and 35% of PPL's assets at December 31, 2015.
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Net Income and Earnings from Ongoing Operations include the following results.
| Change | ||||||||||||||||
| 2015 | 2014 | 2013 | 2015 vs. 2014 | 2014 vs. 2013 | ||||||||||||
| Operating revenues | $ | 3,115 | $ | 3,168 | $ | 2,976 | $ | (53) | $ | 192 | ||||||
| Fuel | 863 | 965 | 896 | (102) | 69 | |||||||||||
| Energy purchases | 184 | 253 | 217 | (69) | 36 | |||||||||||
| Other operation and maintenance | 837 | 815 | 778 | 22 | 37 | |||||||||||
| Depreciation | 382 | 354 | 334 | 28 | 20 | |||||||||||
| Taxes, other than income | 57 | 52 | 48 | 5 | 4 | |||||||||||
| Total operating expenses | 2,323 | 2,439 | 2,273 | (116) | 166 | |||||||||||
| Other Income (Expense) - net | (13) | (9) | (7) | (4) | (2) | |||||||||||
| Interest Expense | 232 | 219 | 212 | 13 | 7 | |||||||||||
| Income Taxes | 221 | 189 | 179 | 32 | 10 | |||||||||||
| Income (Loss) from Discontinued Operations (net of income taxes) | 2 | (2) | ||||||||||||||
| Net Income | 326 | 312 | 307 | 14 | 5 | |||||||||||
| Less: Special Items | (17) | 3 | (17) | (3) | ||||||||||||
| Earnings from Ongoing Operations | $ | 343 | $ | 312 | $ | 304 | $ | 31 | $ | 8 | ||||||
The following after-tax gains (losses), which management considers special items, impacted the Kentucky Regulated segment's results and are excluded from Earnings from Ongoing Operations.
| Income Statement | ||||||||||||
| Line Item | 2015 | 2014 | 2013 | |||||||||
| Certain valuation allowances (a) | Income Taxes | $ | (12) | |||||||||
| Acquisition-related adjustment, net of tax of $0, $0, $0 (b) | Other Income (Expense) - net | (5) | ||||||||||
| Discontinued operations (c) | Discontinued Operations | $ | 2 | |||||||||
| Adjustment to investment, net of tax of $0, $0, $0 (d) | Other Income (Expense) - net | 1 | ||||||||||
| Total | $ | (17) | $ | 3 | ||||||||
| (a) | Recorded at LKE and represents a valuation allowance against tax credits expiring in 2016 through 2020 that are more likely than not to expire before being utilized. |
| (b) | Recorded at PPL and allocated to the Kentucky Regulated segment. The amount represents a settlement between E.ON AG (a German corporation and the indirect parent of E.ON US Investments Corp., the former parent of LKE) and PPL for a tax matter. |
| (c) | Recorded at LKE. |
| (d) | Recorded by KU. |
The changes in the components of the Kentucky Regulated segment's results between these periods were due to the factors set forth below, which reflect amounts classified as Kentucky Gross Margins and the items that management considers special on separate lines and not in their respective Statement of Income line item.
| 2015 vs. 2014 | 2014 vs. 2013 | |||||
| Kentucky Gross Margins | $ | 88 | $ | 78 | ||
| Other operation and maintenance | (21) | (35) | ||||
| Depreciation | (1) | (14) | ||||
| Taxes, other than income | (3) | (3) | ||||
| Other Income (Expense) - net | 1 | (1) | ||||
| Interest Expense | (13) | (7) | ||||
| Income Taxes | (20) | (10) | ||||
| Earnings from Ongoing Operations | 31 | 8 | ||||
| Special Items, after-tax | (17) | (3) | ||||
| Net Income | $ | 14 | $ | 5 | ||
| · | See "Non-GAAP Financial Measures - Margins - Changes in Margins" for an explanation of Kentucky Gross Margins. |
| · | Higher other operation and maintenance in 2015 compared with 2014 primarily due to $14 million of higher pension expense and $11 million of higher costs related to the Cane Run units' retirements consisting of an inventory write-down and separation benefits, partially offset by $7 million of lower storm costs and lower bad debt expense of $6 million. |
| · | Higher other operation and maintenance in 2014 compared with 2013 primarily due to $14 million of higher expenses due to the timing and scope of scheduled generation maintenance outages, $9 million of higher bad debt expense and higher storm expenses of $8 million. |
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| · | Higher depreciation in 2014 compared with 2013 due to additions to PP&E, net. |
| · | Higher interest expense in 2015 compared with 2014 primarily due to the issuance of $550 million of incremental First Mortgage Bonds by LG&E and KU in September 2015 and higher interest rates on $500 million of First Mortgage Bonds refinanced by LG&E and KU. |
| · | Higher interest expense in 2014 compared with 2013 primarily due to $22 million of higher expense resulting from the issuance of $500 million of First Mortgage Bonds in November 2013 and higher short-term debt balances partially offset by a $10 million loss on extinguishment of debt in 2013 related to the remarketing of the PPL Capital Funding Junior Subordinated Notes component of the 2010 Equity Units and simultaneous exchange into Senior Notes in the second quarter of 2013, and a $5 million decrease due to lower rates on the related Senior Notes as compared with the Junior Subordinated Notes. |
| · | Higher income taxes in 2015 compared with 2014 primarily due to higher pre-tax income. |
Pennsylvania Regulated Segment
The Pennsylvania Regulated segment includes the regulated electricity transmission and distribution operations of PPL Electric. The Pennsylvania Regulated segment represents 16% of PPL's Income from Continuing Operations After Income Taxes for 2015 and 22% of PPL's assets at December 31, 2015.
Net Income and Earnings from Ongoing Operations include the following results.
| Change | ||||||||||||||||
| 2015 | 2014 | 2013 | 2015 vs. 2014 | 2014 vs. 2013 | ||||||||||||
| Operating revenues | $ | 2,124 | $ | 2,044 | $ | 1,870 | $ | 80 | $ | 174 | ||||||
| Energy purchases | ||||||||||||||||
| External | 657 | 587 | 588 | 70 | (1) | |||||||||||
| Intersegment | 14 | 84 | 51 | (70) | 33 | |||||||||||
| Other operation and maintenance | 607 | 543 | 531 | 64 | 12 | |||||||||||
| Depreciation | 214 | 185 | 178 | 29 | 7 | |||||||||||
| Taxes, other than income | 94 | 107 | 103 | (13) | 4 | |||||||||||
| Total operating expenses | 1,586 | 1,506 | 1,451 | 80 | 55 | |||||||||||
| Other Income (Expense) - net | 8 | 7 | 6 | 1 | 1 | |||||||||||
| Interest Expense | 130 | 122 | 108 | 8 | 14 | |||||||||||
| Income Taxes | 164 | 160 | 108 | 4 | 52 | |||||||||||
| Net Income | 252 | 263 | 209 | (11) | 54 | |||||||||||
| Less: Special Items | (2) | 2 | (2) | |||||||||||||
| Earnings from Ongoing Operations | $ | 252 | $ | 265 | $ | 209 | $ | (13) | $ | 56 | ||||||
The following after-tax loss, which management considers a special item, impacted the Pennsylvania Regulated segment's results and is excluded from Earnings from Ongoing Operations.
| Income Statement | ||||||||||
| Line Item | 2015 | 2014 | 2013 | |||||||
| Other operation | ||||||||||
| Separation benefits, net of tax of $0, $1, $0 (a) | and maintenance | $ | (2) | |||||||
| (a) | In June 2014, PPL Electric's largest IBEW local ratified a new three-year labor agreement. In connection with the new agreement, bargaining unit one-time voluntary retirement benefits were recorded. |
The changes in the components of the Pennsylvania Regulated segment's results between these periods were due to the factors set forth below, which reflect amounts classified as Pennsylvania Gross Delivery Margins and the item that management considers special on separate lines and not in their respective Statement of Income line item.
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| 2015 vs. 2014 | 2014 vs. 2013 | |||||
| Pennsylvania Gross Delivery Margins | $ | 65 | $ | 118 | ||
| Other operation and maintenance | (58) | 13 | ||||
| Depreciation | (29) | (7) | ||||
| Taxes, other than income | 18 | |||||
| Other Income (Expense) - net | 1 | 1 | ||||
| Interest Expense | (8) | (14) | ||||
| Income Taxes | (2) | (55) | ||||
| Earnings from Ongoing Operations | (13) | 56 | ||||
| Special Item, after-tax | 2 | (2) | ||||
| Net Income | $ | (11) | $ | 54 | ||
| · | See "Non-GAAP Financial Measures - Margins - Changes in Margins" for an explanation of Pennsylvania Gross Delivery Margins. |
| · | Higher other operation and maintenance for 2015 compared with 2014 primarily due to $30 million of higher corporate service costs allocated to PPL Electric, $11 million of higher vegetation management expenses and related costs for additional work done by outside vendors and $5 million of higher bad debt expenses. |
| · | Lower other operation and maintenance for 2014 compared with 2013 primarily due to $16 million of lower payroll related expenses due to lower headcount, less maintenance projects and more focus on capital work in 2014. |
| · | Higher depreciation for both periods primarily due to transmission and distribution additions to PP&E, net, related to the ongoing efforts to improve reliability and replace aging infrastructure. |
| · | Higher interest expense in 2014 compared with 2013 primarily due to the issuance of First Mortgage Bonds in July 2013 and June 2014. |
| · | Lower taxes, other than income for 2015 compared with 2014 primarily due to the settlement of a 2011 gross receipts tax audit resulting in the reversal of $17 million of previously recognized reserves. |
| · | Higher income taxes in 2014 compared with 2013, primarily due to higher pre-tax income which increased income taxes by $46 million and tax benefits related to federal and state income tax reserves of $8 million in 2013. |
Non-GAAP Financial Measures
Management's Discussion and Analysis includes financial information prepared in accordance with GAAP, as well as non-GAAP financial measures including "Earnings from Ongoing Operations" and "Gross Margins" as further described below.
Earnings from Ongoing Operations
Management utilizes "Earnings from Ongoing Operations" as a non-GAAP financial measure and it should not be considered as an alternative to net income, which is an indicator of operating performance determined in accordance with GAAP. PPL believes that Earnings from Ongoing Operations is useful and meaningful to investors because it provides management's view of PPL's fundamental earnings performance as another criterion in making investment decisions. PPL's management also uses Earnings from Ongoing Operations in measuring certain corporate performance goals. Other companies may use different measures to present financial performance. Earnings from Ongoing Operations is adjusted for the impact of special items as described below, which for all years includes the Supply segment's earnings now reflected in discontinued operations. Also included in special items in 2015 is the loss on spinoff, reflecting the fair value of the Supply segment being less than PPL's recorded value as of the June 1, 2015 spinoff. Earnings from Ongoing Operations for 2014 and 2013 also reflects, within the Corporate and Other category, the impact of spinoff dissynergies that, if not mitigated, would remain with PPL after completion of the spinoff.
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Earnings from Ongoing Operations is adjusted for the impact of special items. Special items include:
• Unrealized gains or losses on foreign currency-related economic hedges.
• Supply segment discontinued operations.
• Gains and losses on sales of assets not in the ordinary course of business.
• Impairment charges.
• Workforce reduction and other restructuring effects.
• Acquisition and divestiture-related adjustments.
• Other charges or credits that are, in management's view, not reflective of the company's ongoing operations.
Reconciliation of Earnings from Ongoing Operations
The following tables contain after-tax gains (losses), in total, which management considers special items, that are excluded from Earnings from Ongoing Operations and a reconciliation to PPL's "Net Income (Loss)" for the years ended December 31.
| 2015 | |||||||||||||||||||
| U.K. | KY | PA | Corporate | Discontinued | |||||||||||||||
| Regulated | Regulated | Regulated | and Other | Operations | Total | ||||||||||||||
| Net Income (Loss) | $ | 1,121 | $ | 326 | $ | 252 | $ | (96) | $ | (921) | $ | 682 | |||||||
| Less: Special Items (expense) benefit: | |||||||||||||||||||
| Foreign currency-related economic hedges | 55 | 55 | |||||||||||||||||
| Spinoff of the Supply segment: | |||||||||||||||||||
| Discontinued operations | (921) | (921) | |||||||||||||||||
| Transition and transaction costs | (12) | (12) | |||||||||||||||||
| Employee transitional services | (5) | (5) | |||||||||||||||||
| Separation benefits | (5) | (5) | |||||||||||||||||
| Other: | |||||||||||||||||||
| Change in U.K. tax rate | 78 | 78 | |||||||||||||||||
| Settlement of certain income tax positions | 18 | 18 | |||||||||||||||||
| WPD Midlands acquisition-related adjustment | 2 | 2 | |||||||||||||||||
| Certain valuation allowances | (12) | (12) | |||||||||||||||||
| LKE acquisition-related adjustment | (5) | (5) | |||||||||||||||||
| Total Special Items | 153 | (17) | (22) | (921) | (807) | ||||||||||||||
| Earnings from Ongoing Operations | $ | 968 | $ | 343 | $ | 252 | $ | (74) | $ | $ | 1,489 | ||||||||
| 2014 | |||||||||||||||||||
| U.K. | KY | PA | Corporate | Discontinued | |||||||||||||||
| Regulated | Regulated | Regulated | and Other | Operations | Total | ||||||||||||||
| Net Income (Loss) | $ | 982 | $ | 312 | $ | 263 | $ | (120) | $ | 300 | $ | 1,737 | |||||||
| Less: Special Items (expense) benefit: | |||||||||||||||||||
| Foreign currency-related economic hedges | 127 | 127 | |||||||||||||||||
| Spinoff of the Supply segment: | |||||||||||||||||||
| Supply segment earnings | 307 | 307 | |||||||||||||||||
| Discontinued operations adjustments | (5) | 5 | |||||||||||||||||
| Change in tax valuation allowances | (46) | (46) | |||||||||||||||||
| Transition and transaction costs | (5) | (12) | (17) | ||||||||||||||||
| Separation benefits | (12) | (12) | |||||||||||||||||
| Other: | |||||||||||||||||||
| Change in WPD line loss accrual | (52) | (52) | |||||||||||||||||
| Separation benefits | (2) | (2) | |||||||||||||||||
| Total Special Items | 75 | (2) | (68) | 300 | 305 | ||||||||||||||
| Dissynergies - spinoff of Supply segment | |||||||||||||||||||
| expense (benefit): | |||||||||||||||||||
| Indirect operation and maintenance | 47 | 47 | |||||||||||||||||
| Interest expense | 29 | 29 | |||||||||||||||||
| Depreciation | 7 | 7 | |||||||||||||||||
| Total dissynergies - spinoff of Supply segment | 83 | 83 | |||||||||||||||||
| Earnings from Ongoing Operations (adjusted) | $ | 907 | $ | 312 | $ | 265 | $ | (135) | $ | $ | 1,349 | ||||||||
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| 2013 | |||||||||||||||||||
| U.K. | KY | PA | Corporate | Discontinued | |||||||||||||||
| Regulated | Regulated | Regulated | and Other | Operations | Total | ||||||||||||||
| Net Income (Loss) | $ | 922 | $ | 307 | $ | 209 | $ | (68) | $ | (240) | $ | 1,130 | |||||||
| Less: Special Items (expense) benefit: | |||||||||||||||||||
| Foreign currency-related economic hedges | (29) | (29) | |||||||||||||||||
| Spinoff of the Supply segment: | |||||||||||||||||||
| Supply segment earnings | (272) | (272) | |||||||||||||||||
| Discontinued operations adjustments | (32) | 32 | |||||||||||||||||
| WPD Midlands acquisition-related adjustments: | |||||||||||||||||||
| Separation benefits | (4) | (4) | |||||||||||||||||
| Other acquisition-related adjustments | 8 | 8 | |||||||||||||||||
| Other: | |||||||||||||||||||
| LKE discontinued operations | 2 | 2 | |||||||||||||||||
| Adjustment to investment | 1 | 1 | |||||||||||||||||
| Windfall tax litigation | 43 | 43 | |||||||||||||||||
| Change in WPD line loss accrual | (35) | (35) | |||||||||||||||||
| Change in U.K. tax rate | 84 | 84 | |||||||||||||||||
| Total Special Items | 67 | 3 | (32) | (240) | (202) | ||||||||||||||
| Dissynergies - spinoff of Supply segment | |||||||||||||||||||
| expense (benefit): | |||||||||||||||||||
| Indirect operation and maintenance | 45 | 45 | |||||||||||||||||
| Interest expense | 30 | 30 | |||||||||||||||||
| Depreciation | 7 | 7 | |||||||||||||||||
| Total dissynergies - spinoff of Supply segment | 82 | 82 | |||||||||||||||||
| Earnings from Ongoing Operations (adjusted) | $ | 855 | $ | 304 | $ | 209 | $ | (118) | $ | $ | 1,250 | ||||||||
Margins
Management also utilizes the following non-GAAP financial measures as indicators of performance for its businesses.
| · | "U.K. Gross Margins" is a single financial performance measure of the electricity distribution operations of the U.K. Regulated segment. In calculating this measure, direct costs such as National Grid connection charges and Ofgem license fees (recorded in "Other operations and maintenance expense" on the Statement of Income) are deducted from operating revenues as they are costs passed through to customers. As a result, this measure represents the net revenues from the delivery of electricity across WPD's distribution network in the U.K. and directly related activities. |
| · | "Kentucky Gross Margins" is a single financial performance measure of the electricity generation, transmission and distribution operations of the Kentucky Regulated segment, LKE, LG&E and KU, as well as the Kentucky Regulated segment's, LKE's and LG&E's distribution and sale of natural gas. In calculating this measure, fuel, energy purchases and certain variable costs of production (recorded as "Other operation and maintenance" on the Statements of Income) are deducted from revenues. In addition, certain other expenses, recorded as "Other operation and maintenance", "Depreciation" and "Taxes, other than income" on the Statements of Income, associated with approved cost recovery mechanisms are offset against the recovery of those expenses, which are included in revenues. These mechanisms allow for direct recovery of these expenses and, in some cases, returns on capital investments and performance incentives. As a result, this measure represents the net revenues from electricity and gas operations. |
| · | "Pennsylvania Gross Delivery Margins" is a single financial performance measure of the electricity transmission and distribution delivery operations of the Pennsylvania Regulated segment and PPL Electric. In calculating this measure, utility revenues and expenses associated with approved recovery mechanisms, including energy provided as a PLR, are offset with minimal impact on earnings. Costs associated with these mechanisms are recorded in "Energy purchases," "Other operation and maintenance," (which are primarily Act 129 and Universal Service program costs), and "Taxes, other than income," which is primarily gross receipts tax. This performance measure includes PLR energy purchases by PPL Electric from PPL EnergyPlus, which are reflected in "Energy purchases from affiliate" in the reconciliation tables. As a result of the June 2015 spinoff of PPL Energy Supply and the formation of Talen Energy, PPL EnergyPlus (renamed Talen Energy Marketing) is no longer an affiliate of PPL Electric. PPL Electric's purchases from Talen Energy Marketing subsequent to May 31, 2015 are reflected in "Energy Purchases" in the reconciliation tables. This measure represents the net revenues from the Pennsylvania Regulated segment's and PPL Electric's electricity delivery operations. |
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These measures are not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and report their results of operations. Management believes these measures provide additional useful criteria to make investment decisions. These performance measures are used, in conjunction with other information, by senior management and PPL's Board of Directors to manage the operations and analyze actual results compared with budget.
Reconciliation of Margins
The following tables contain the components from the Statement of Income that are included in the non-GAAP financial measures and a reconciliation to PPL's "Operating Income" for the years ended December 31.
| 2015 | 2014 | ||||||||||||||||||||||||||||||||
| U.K. | Kentucky | PA Gross | U.K. | Kentucky | PA Gross | ||||||||||||||||||||||||||||
| Gross | Gross | Delivery | Operating | Gross | Gross | Delivery | Operating | ||||||||||||||||||||||||||
| Margins | Margins | Margins | Other (a) | Income (b) | Margins | Margins | Margins | Other (a) | Income (b) | ||||||||||||||||||||||||
| Operating Revenues | $ | 2,364 | (c) | $ | 3,115 | $ | 2,124 | $ | 66 | $ | 7,669 | $ | 2,638 | (c) | $ | 3,168 | $ | 2,044 | $ | 2 | $ | 7,852 | |||||||||||
| Operating Expenses | |||||||||||||||||||||||||||||||||
| Fuel | 863 | 863 | 965 | 965 | |||||||||||||||||||||||||||||
| Energy purchases | 184 | 657 | 14 | 855 | 253 | 587 | 84 | 924 | |||||||||||||||||||||||||
| Energy purchases from affiliate | 14 | (14) | 84 | (84) | |||||||||||||||||||||||||||||
| Other operation and | |||||||||||||||||||||||||||||||||
| maintenance | 121 | 100 | 114 | 1,603 | 1,938 | 111 | 99 | 103 | 1,543 | 1,856 | |||||||||||||||||||||||
| Depreciation | 38 | 845 | 883 | 11 | 912 | 923 | |||||||||||||||||||||||||||
| Taxes, other than income | 4 | 102 | 193 | 299 | 2 | 98 | 217 | 317 | |||||||||||||||||||||||||
| Total Operating Expenses | 121 | 1,189 | 887 | 2,641 | 4,838 | 111 | 1,330 | 872 | 2,672 | 4,985 | |||||||||||||||||||||||
| Total | $ | 2,243 | $ | 1,926 | $ | 1,237 | $ | (2,575) | $ | 2,831 | $ | 2,527 | $ | 1,838 | $ | 1,172 | $ | (2,670) | $ | 2,867 | |||||||||||||
| 2013 | |||||||||||||||||||||||||||
| U.K. | Kentucky | PA Gross | |||||||||||||||||||||||||
| Gross | Gross | Delivery | Operating | ||||||||||||||||||||||||
| Margins | Margins | Margins | Other (a) | Income (b) | |||||||||||||||||||||||
| Operating Revenues | $ | 2,404 | (c) | $ | 2,976 | $ | 1,870 | $ | 13 | $ | 7,263 | ||||||||||||||||
| Operating Expenses | |||||||||||||||||||||||||||
| Fuel | 896 | (1) | 895 | ||||||||||||||||||||||||
| Energy purchases | 217 | 588 | 51 | 856 | |||||||||||||||||||||||
| Energy purchases from affiliate | 51 | (51) | |||||||||||||||||||||||||
| Other operation and | |||||||||||||||||||||||||||
| maintenance | 107 | 97 | 82 | 1,524 | 1,810 | ||||||||||||||||||||||
| Depreciation | 5 | 838 | 843 | ||||||||||||||||||||||||
| Taxes, other than income | 1 | 95 | 202 | 298 | |||||||||||||||||||||||
| Total Operating Expenses | 107 | 1,216 | 816 | 2,563 | 4,702 | ||||||||||||||||||||||
| Total | $ | 2,297 | $ | 1,760 | $ | 1,054 | $ | (2,550) | $ | 2,561 | |||||||||||||||||
| (a) | Represents amounts excluded from Margins. |
| (b) | As reported on the Statements of Income. |
| (c) | 2015, 2014 and 2013 exclude $46 million, $48 million and $44 million of ancillary activity revenues. 2014 and 2013 also exclude $65 million and $45 million of revenue reductions related to adjustments to WPD's line loss accrual related to DPCR4 which are considered special items. |
Changes in Margins
The following table shows Margins by PPL's reportable segments and by component, as applicable, for the year ended December 31 as well as the changes between periods. The factors that gave rise to the changes are described following the table.
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| $ Change | |||||||||||||||||
| 2015 | 2014 | 2013 | 2015 vs. 2014 | 2014 vs. 2013 | |||||||||||||
| U.K. | |||||||||||||||||
| U.K. Gross Margins | $ | 2,243 | $ | 2,527 | $ | 2,297 | $ | (284) | $ | 230 | |||||||
| Impact of changes in foreign currency exchange rates | (174) | 136 | |||||||||||||||
| U.K. Gross Margins excluding impact of foreign currency exchange rates | $ | (110) | $ | 94 | |||||||||||||
| Kentucky Regulated | ||||||||||||||||
| Kentucky Gross Margins | ||||||||||||||||
| LG&E | $ | 867 | $ | 833 | $ | 791 | $ | 34 | $ | 42 | ||||||
| KU | 1,059 | 1,005 | 969 | 54 | 36 | |||||||||||
| LKE | $ | 1,926 | $ | 1,838 | $ | 1,760 | $ | 88 | $ | 78 | ||||||
| Pennsylvania Regulated | ||||||||||||||||
| Pennsylvania Gross Delivery Margins | ||||||||||||||||
| Distribution | $ | 842 | $ | 837 | $ | 803 | $ | 5 | $ | 34 | ||||||
| Transmission | 395 | 335 | 251 | 60 | 84 | |||||||||||
| Total | $ | 1,237 | $ | 1,172 | $ | 1,054 | $ | 65 | $ | 118 | ||||||
U.K. Gross Margins
U.K. Gross Margins excluding the impact of changes in foreign currency exchange rates, decreased in 2015 compared with 2014 primarily due to $171 million from the April 1, 2015 price decrease resulting from the commencement of RIIO-ED1, partially offset by $46 million from the April 1, 2014 price increase.
U.K. Gross Margins excluding the impact of changes in foreign currency exchange rates, increased in 2014 compared with 2013 primarily due to $194 million from the April 1, 2014 and 2013 price increases, partially offset by $88 million from lower volumes due primarily to weather.
Kentucky Gross Margins
Kentucky Gross Margins increased in 2015 compared with 2014, primarily due to higher base rates of $64 million ($61 million at KU and $3 million at LG&E) and returns on additional environmental capital investments of $53 million ($36 million at LG&E and $17 million at KU). The increases in base rates were the result of new rates approved by the KPSC effective July 1, 2015. These increases were partially offset by a decrease in volumes of $28 million ($23 million at KU and $5 million at LG&E) primarily due to milder weather during the fourth quarter of 2015.
Kentucky Gross Margins increased in 2014 compared with 2013, primarily due to returns on additional environmental capital investments of $55 million ($27 million at LG&E and $28 million at KU) and higher volumes of $13 million ($5 million at LG&E and $8 million at KU). The change in volumes was driven by unusually cold weather in the first quarter of 2014.
Pennsylvania Gross Delivery Margins
Distribution
Distribution margins increased in 2015 compared with 2014 primarily due to returns on additional distribution improvement capital investments of $17 million partially offset by a $12 million benefit recorded in the first quarter of 2014 as a result of a change in estimate of a regulatory liability.
Distribution margins increased in 2014 compared with 2013 primarily due to returns on additional distribution improvement capital investments of $18 million and a $12 million benefit from a change in estimate of a regulatory liability.
Transmission
Transmission margins increased for both periods, primarily due to returns on additional capital investments focused on replacing the aging infrastructure and improving reliability.
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Statement of Income Analysis --
Certain Operating Revenues and Expenses Included in "Margins"
The following Statement of Income line items are included above within "Margins" and are not discussed separately.
| 2015 vs. 2014 | 2014 vs. 2013 | |||||
| Operating Revenues | $ | (183) | $ | 589 | ||
| Fuel | (102) | 70 | ||||
| Energy purchases | (69) | 68 | ||||
| Other Operation and Maintenance | |||||||
| The increase (decrease) in other operation and maintenance was due to: | |||||||
| 2015 vs. 2014 | 2014 vs. 2013 | ||||||
| Domestic: | |||||||
| LKE timing and scope of scheduled generation maintenance outages | $ | (1) | $ | 14 | |||
| LKE Cane Run retired units (a) | 11 | ||||||
| LKE pension expense (b) | 14 | (15) | |||||
| PPL Electric Act 129 costs incurred | 9 | 6 | |||||
| PPL Electric vegetation management | 7 | (4) | |||||
| PPL Electric environmental costs | 5 | 1 | |||||
| PPL Electric payroll-related costs (c) | 2 | (16) | |||||
| Bad debts | 7 | 13 | |||||
| Storm costs (d) | (18) | 26 | |||||
| Separation benefits related to the spinoff of PPL Energy Supply (Note 8) | (12) | 20 | |||||
| Third-party costs related to the spinoff of PPL Energy Supply (Note 8) | 5 | 8 | |||||
| Stock compensation expense | 3 | 5 | |||||
| Corporate costs previously included in discontinued operations (e) | 27 | ||||||
| Other | 26 | 7 | |||||
| U.K.: | |||||||
| Third-party engineering | 7 | (9) | |||||
| Pension expense (f) | (14) | (38) | |||||
| Engineering management | 19 | 3 | |||||
| Foreign currency exchange rates (g) | (33) | 23 | |||||
| Acquisition-related adjustments | (3) | 12 | |||||
| National Grid exit charges | 11 | 7 | |||||
| Other | 10 | (17) | |||||
| $ | 82 | $ | 46 | ||||
| (a) | Represents an inventory write-down and separation benefits. |
| (b) | The increase in 2015 compared with 2014 is attributed to the change in mortality tables and lower discount rates. |
| (c) | The decrease in 2014 compared with 2013 was due to lower headcount, less maintenance work and more focus on capital projects in 2014. |
| (d) | The increase in 2014 compared with 2013 was due to more storm events. |
| (e) | The increase in 2015 compared with 2014 was due to the corporate costs allocated to PPL Energy Supply (and included in discontinued operations) prior to the spin. As a result of the spinoff on June 1, 2015, these corporate costs now remain in continuing operations. |
| (f) | The decrease in 2014 compared with 2013 was primarily due to lower amortization of prior period losses and an increase in expected asset returns. |
| (g) | The offsetting impacts from foreign currency hedging instruments are recorded in "Other Income (Expense)-net." |
Depreciation
The increase (decrease) in depreciation was due to:
| 2015 vs. 2014 | 2014 vs. 2013 | |||||
| Additions to PP&E, net | $ | 77 | $ | 67 | ||
| Foreign currency exchange rates | (19) | 18 | ||||
| Network asset useful life extension (a) | (84) | |||||
| Other | (14) | (5) | ||||
| Total | $ | (40) | $ | 80 | ||
| (a) | Effective January 1, 2015, after completion of a review of the useful lives of its distribution network assets, WPD extended the weighted average useful lives of these assets to 69 years from 55 years resulting in lower depreciation of $84 million ($66 million after-tax or $0.10 per share). |
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Taxes, Other Than Income
The increase (decrease) in taxes, other than income was due to:
| 2015 vs. 2014 | 2014 vs. 2013 | ||||||
| State gross receipts tax (a) | $ | (14) | $ | 4 | |||
| Domestic property tax expense | 5 | 4 | |||||
| Foreign currency exchange rates | (9) | 10 | |||||
| Other | 1 | ||||||
| Total | $ | (18) | $ | 19 | |||
| (a) | The decrease in 2015 compared with 2014 was primarily due to the settlement of the 2011 gross receipts tax audit resulting in the reversal of $17 million of previously recognized reserves. |
Other Income (Expense) - net
Other income (expense) - net increased $3 million in 2015 compared with 2014 and increased $160 million in 2014 compared with 2013, primarily due to changes in realized and unrealized gains on foreign currency contracts to economically hedge GBP denominated earnings from WPD.
Interest Expense
The increase (decrease) in interest expense was due to:
| 2015 vs. 2014 | 2014 vs. 2013 | ||||||
| Long-term debt interest expense (a) | $ | 61 | $ | 65 | |||
| Hedging activities and ineffectiveness | (4) | (11) | |||||
| Loss on extinguishment of debt (b) | (9) | (1) | |||||
| Foreign currency exchange rates | (26) | 19 | |||||
| Other | 6 | (7) | |||||
| Total | $ | 28 | $ | 65 | |||
| (a) | The increase in 2015 compared with 2014 is primarily due to 2015 including interest expense related to certain PPL Energy Funding debt that was previously associated with PPL's Supply segment and included in "Income (Loss) from Discontinued Operations (net of income taxes) in 2014. |
| The increase in 2014 compared with 2013 was primarily due to debt issuances at WPD (West Midlands) in October 2013, LG&E and KU in November 2013 and PPL Electric in June 2014 and July 2013. |
| (b) | In March 2014, a $9 million loss was recorded related to PPL Capital Funding's remarketing and debt exchange of the junior subordinated notes originally issued in April 2011 as a component of the 2011 Equity Units. In May 2013, a $10 million loss was recorded related to PPL Capital Funding's remarketing and exchange of the junior subordinated notes that were originally issued in June 2010 as a component of PPL's 2010 Equity Units. |
Income Taxes
The increase (decrease) in income taxes was due to:
| 2015 vs. 2014 | 2014 vs. 2013 | ||||||
| Change in pre-tax income at current period tax rates | $ | (18) | $ | 151 | |||
| Valuation allowance adjustments (a) | (31) | 31 | |||||
| State deferred tax rate change (b) | (16) | ||||||
| Federal and state tax reserve adjustments (c) | (21) | 48 | |||||
| Federal and state tax return adjustments | (4) | 7 | |||||
| U.S. income tax on foreign earnings net of foreign tax credit (d) | (55) | 42 | |||||
| U.K. Finance Act adjustments (e) | (90) | 96 | |||||
| Impact of lower U.K. income tax rates (e) | 4 | (36) | |||||
| Interest benefit on U.K. financing activities | (15) | 2 | |||||
| Other | 3 | 7 | |||||
| Total | $ | (227) | $ | 332 | |||
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