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•	the outcome of rate cases or other cost recovery or revenue filings;

•	changes in U.S. or U.K. tax laws or regulations;

•	effects of cyber-based intrusions or natural disasters, threatened or actual terrorism, war or other hostilities;

•	significant decreases in demand for electricity in the U.S.;

•	expansion of alternative and distributed sources of electricity generation and storage;

•	changes in foreign currency exchange rates for British pound sterling and the related impact on unrealized gains and losses on PPL's foreign currency economic hedges;

•	the effectiveness of our risk management programs, including foreign currency and interest rate hedging;

•	non-achievement by WPD of performance targets set by Ofgem;

•	the effect of changes in RPI on WPD's revenues and index linked debt;

•	the effect of the June 23, 2016 referendum in the U.K. to withdraw from the European Union and any actions taken in response thereto;

•	defaults by counterparties or suppliers for energy, capacity, coal, natural gas or key commodities, goods or services;

•	capital market conditions, including the availability of capital or credit, changes in interest rates and certain economic indices, and decisions regarding capital structure;

•	a material decline in the market value of PPL's equity;

•	significant decreases in the fair value of debt and equity securities and its impact on the value of assets in defined benefit plans, and the potential cash funding requirements if fair value declines;

•	interest rates and their effect on pension and retiree medical liabilities, ARO liabilities and interest payable on certain debt securities;

•	volatility in or the impact of other changes in financial markets and economic conditions;

•	the potential impact of any unrecorded commitments and liabilities of the Registrants and their subsidiaries;

•	new accounting requirements or new interpretations or applications of existing requirements;

•	changes in securities and credit ratings;

•	any requirement to record impairment charges pursuant to GAAP with respect to any of our significant investments;

•	laws or regulations to reduce emissions of "greenhouse" gases or the physical effects of climate change;

•	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;

•	fuel supply for LG&E and KU;

•	weather and other conditions affecting generation, transmission and distribution operations, operating costs and customer energy use;

•	changes in political, regulatory or economic conditions in states, regions or countries where the Registrants or their subsidiaries conduct business;

•	receipt of necessary governmental permits and approvals;

•	new state, federal or foreign legislation or regulatory developments;

•	the impact of any state, federal or foreign investigations applicable to the Registrants and their subsidiaries and the energy industry;

•	our ability to attract and retain qualified employees;

•	the effect of any business or industry restructuring;

•	development of new projects, markets and technologies;

•	performance of new ventures;

•	business dispositions or acquisitions and our ability to realize expected benefits from such business transactions;

•	collective labor bargaining negotiations; and

•	the outcome of litigation against the Registrants and their subsidiaries.

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(a)	Represents RAV for U.K. Regulated, capitalization for Kentucky Regulated and rate base for Pennsylvania Regulated. For U.K. Regulated, RAV is lower for 2016 compared with 2015 due to the effect of foreign currency exchange rates.

•	U.K. Regulated Segment (PPL)

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•	encourage DNOs to deliver safe, reliable and sustainable network service at long-term value to customers;

•	enable DNOs to finance 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

•	continue to stimulate innovation.

•	regulates revenues for the DNOs in real terms using 2012/13 prices;

•	inflates revenue components using the RPI beginning March 31, 2013, which has the effect of inflating RAV, with respect to base demand revenue;

•	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 general pass-through for costs over which the DNOs have no control (i.e., Ofgem fees, National Grid transmission charges and property taxes);

•	provides a tax allowance based on Ofgem's notional tax charge, which may not equal the actual corporate tax paid;

•

extends the recovery period for 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 average asset life for RAV additions during RIIO-ED1 to approximately 35 years. 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 successful DNOs an incentive to be fast-tracked through the regulatory approval process, equivalent to 2.5% of Totex during the 8-year price control period; 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.

•	all four DNO business plans were accepted for fast-track status (fast-track incentive is worth approximately $35 million annually for WPD assuming a $1.30/£ 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 20-year trailing average for 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, reducing the expected incentive revenues WPD can earn in RIIO-ED1 compared to DPCR5.

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•	Totex - $11.0 billion ($8.8 billion additions to RAV; $2.2 billion fast pot);

•	Pension deficit funding - $1.6 billion;

•	Cost of debt recovery - $1.3 billion;

•	Property taxes, Ofgem fees and National Grid transmissions charges - $2.1 billion; and

•	Corporate income taxes recovery - $600 million.

•	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 - because 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.

•	an increase or reduction in revenues based on incentives or penalties for actual performance against pre-established targets from prior periods;

•	adjustments for over- or under-recovery of allowed revenue from prior periods; and

•	a reduction in revenue related to the DPCR4 line loss close out.

•	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 TRU for the 2015/16 regulatory year was a $40 million reduction to revenue and will reduce base demand revenue in calendar years 2017 and 2018 by $27 million and $13 million, respectively.

◦	The projected TRU for the 2016/17 regulatory year is a $6 million reduction to revenue and will reduce base demand revenue in calendar years 2018 and 2019 by $4 million and $2 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

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◦	The MOD provided by Ofgem in November 2016 included the TIM for the 2015/16 regulatory year as well as the cost of debt calculation based on the 10-year trailing average to October 2016. This MOD of $15 million will reduce base demand revenue in calendar years 2017 and 2018 by $10 million and $5 million, respectively.

◦	The projected MOD for the 2016/17 regulatory year is a $52 million reduction to revenue and will reduce base demand revenue in calendar years 2018 and 2019 by $35 million and $17 million, respectively.

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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 in 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 interruptions is calculated as the annual average level of planned interruptions and minutes lost over a previous three-year period. The targets for unplanned interruptions for RIIO-ED1 are 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.

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•	Kentucky Regulated Segment (PPL)

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(a)	Includes wholesale power and transmission revenues.

(a)	Includes wholesale power and transmission revenues.

(b)	Includes intercompany power sales and transmission revenues, which are eliminated upon consolidation at LKE.

(a)	Includes wholesale power and transmission revenues.

(b)	Includes intercompany power sales and transmission revenues, which are eliminated upon consolidation at LKE.

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(a)	Includes 864 GWh of power generated by and purchased from OVEC for LKE, 598 GWh for LG&E and 266 GWh for KU.

(b)	This generation represents a 0.1% increase for LKE, a 0.6% decrease for LG&E and a 0.4% increase for KU from 2015 output.

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•	Pennsylvania Regulated Segment (PPL)

(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.

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•	Corporate and Other (PPL)

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•	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.;

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•	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;

•	compliance with U.S. foreign corrupt practices laws; and

•	prolonged periods of low inflation or deflation.

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•	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;

•	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.

•	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;

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(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.

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(d)	This unit is a 10 MW facility and achieves such production. The 8 MW solar facility summer capacity rating is reflective of an average expected output across the peak hours during the summer period based on average weather conditions at the solar facility.

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(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 2016, 2015 and 2014. 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 and 2014.

(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)	Computed using earnings and fixed charges of PPL and its subsidiaries. Fixed charges consist of interest 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.

(d)	2015 reflects the impact of the spinoff of PPL Energy Supply and a $3.2 billion related dividend.

(e)	Based on diluted EPS.

(f)	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.

(g)	Based on year-end market prices.

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•	"Overview" provides a description of each Registrant's business strategy and a discussion of important financial and operational developments.

•

"Results of Operations" for all Registrants includes a "Statement of Income Analysis," which discusses significant changes in principal line items on the Statements of Income, comparing 2016 with 2015 and 2015 with 2014. For PPL, "Results of Operations" also includes "Segment Earnings" and "Margins" which provide a detailed analysis of earnings by reportable segment. These discussions include non-GAAP financial measures, including "Earnings from Ongoing Operations" and "Margins" and provides explanations of the non-GAAP financial measures and a reconciliation of the non-GAAP financial measures to the most comparable GAAP measure. The "2017 Outlook" discussion identifies key factors expected to impact 2017 earnings. For PPL Electric, LKE, LG&E and KU, a summary of earnings is also provided.

•	"Financial Condition - Liquidity and Capital Resources" provides an analysis of the Registrants' liquidity positions and credit profiles. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.

•	"Financial Condition - Risk Management" provides an explanation of the Registrants' risk management programs relating to market and credit risk.

•	"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of the Registrants and that require their management to make significant estimates, assumptions and other judgments of inherently uncertain matters.

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(a)	Distribution rate case effective January 1, 2016, resulted in increases of $160 million for the year ended December 31, 2016.

(b)	Decreases due to lower recoveries of fuel and energy purchases primarily as a result of lower commodity costs at LKE and lower energy purchase prices at PPL Electric.

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(c)	In 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism, which resulted in a $65 million reduction to Operating Revenues in 2014. See Note 6 to the Financial Statements for additional information.

(a)	Includes a $29 million reduction of costs in 2016 due to the retirement of Cane Run and Green River coal units partially offset by $5 million of additional costs for Cane Run Unit 7 plant operations.

(b)	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.

(c)	The decrease in 2016 compared with 2015 was primarily due to an increase in expected returns on higher asset balances and lower interest costs due to a change in the discount rate methodology.

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(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.

(a)	2015 includes the settlement of the 2011 gross receipts tax audit that resulted in the reversal of $17 million of previously recognized reserves.

(a)	The increase in 2016 compared with 2015 was primarily due to debt issuances at WPD in November 2015, LG&E and KU in September 2015 and PPL Capital Funding in May 2016 as well as higher interest rates on bonds refinanced in September 2015 at LG&E and KU.

(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.

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(a)	During 2016, PPL recorded deferred tax expense for valuation allowances primarily related to the increase in Pennsylvania net operating loss carryforwards expected to be unutilized.

(b)	During 2015, PPL recorded a $9 million tax benefit related to a planned amendment of a prior period tax return and a $12 million tax benefit related to the settlement of the IRS audit for the tax years 1998-2011.

(c)	During 2016, PPL recorded lower income taxes primarily attributable to foreign tax credit carryforwards, arising from a decision to amend prior year tax returns to claim foreign tax credits rather than deduct foreign taxes. This decision was prompted by changes to the Company's most recent business plan.

(d)	The U.K.’s Finance Act 2016, enacted in September 2016, reduces the U.K. statutory income tax rate from 18% to 17% effective April 1, 2020. As a result, PPL reduced its net deferred tax liabilities and recognized a $42 million deferred tax benefit in 2016.

(e)	During 2016, PPL recorded lower income tax expense related to the application of new stock-based compensation accounting guidance. See Note 1 of the Financial Statements for additional information.

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(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 certain 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 former Supply segment, the earnings of the Supply segment prior to the spinoff 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.

•	Unrealized gains or losses on foreign currency-related economic hedges (as discussed below).

•	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, non-recurring or otherwise not reflective of the company's ongoing operations.

(a)	2014 was 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.

(b)	Costs were lower in 2015 compared with 2014 primarily due to the benefits of corporate restructuring.

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(a)	Represents unrealized gains (losses) on contracts that economically hedge anticipated GBP-denominated earnings. 2016 includes the reversal of $310 million ($202 million after-tax) of unrealized gains related to the settlement of 2017 and 2018 contracts.

(b)	In 2016, PPL settled 2017 and 2018 foreign currency contracts, resulting in $310 million of cash received ($202 million after-tax). The settlement did not have a material impact on net income as the contracts were previously marked to fair value and recognized in "Other Income (Expense) - net" on the Statement of Income. See Note 17 to the Financial Statements for additional information.

(c)	The U.K. Finance Acts of 2016 and 2015 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 2016 and 2015. See Note 5 to the Financial Statements for additional information.

(d)	Relates to the April 2015 settlement of the IRS audit for the tax years 1998-2011. See Note 5 to the Financial Statements for additional information.

(e)	In 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism. As a result, during 2014 WPD increased its existing liability for over-recovery of line losses. See Note 6 to the Financial Statements for additional information.

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•	See "Margins - Changes in Margins" for an explanation of U.K. Gross Margins.

•	Lower other operation and maintenance expense in 2016 compared with 2015 primarily due to $86 million from lower pension expense due to an increase in estimated returns on higher asset balances and lower interest costs due to a change in the discount rate methodology.

•	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.

•	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.

•	Lower income taxes in 2016 compared with 2015 primarily due to a benefit related to foreign tax credit carryforwards.

•	Lower income taxes in 2015 compared with 2014 primarily due to decreases in taxable dividends.

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(a)	Recorded at LKE and represents a valuation allowance against tax credits expiring 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.

•	See "Margins - Changes in Margins" for an explanation of Kentucky Gross Margins.

•

Lower other operation and maintenance expense in 2016 compared with 2015 primarily due to a $29 million reduction of costs as a result of coal units retired in 2015 at the Cane Run and Green River plants, partially offset by $5 million of additional costs for Cane Run Unit 7 plant operations and $12 million of lower pension expense mainly due to higher discount rates and deferred amortization of actuarial losses.

•	Higher other operation and maintenance expense 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.

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Higher interest expense for both periods primarily due to the September 2015 issuance of $550 million of incremental First Mortgage Bonds by LG&E and KU, higher interest rates on the September 2015 issuance of $500 million of First Mortgage Bonds by LG&E and KU used to retire the same amount of First Mortgage Bonds in November 2015 and $400 million of notes refinanced by LKE with an affiliate in November 2015.

•	Higher income taxes for both periods primarily due to higher pre-tax income.

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(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.

•	See "Margins - Changes in Margins" for an explanation of Pennsylvania Gross Margins.

•	Other operation and maintenance expense for 2016 was comparable with 2015 primarily due to $26 million of lower payroll related expenses, partially offset by $8 million of higher corporate service costs allocated to PPL Electric, $8 million of higher costs for additional work done by outside vendors and other costs, which were not individually significant in comparison to the prior year.

•	Higher other operation and maintenance expense 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.

•	Higher depreciation expense for both periods primarily due to transmission and distribution additions placed into service related to the ongoing efforts to improve reliability and replace aging infrastructure, net of retirements.

•	Higher taxes, other than income for 2016 compared with 2015 and 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 in 2015.

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•	Higher income taxes in 2016 compared with 2015 primarily due to higher pre-tax income.

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•

"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 connection charges from National Grid, which owns and manages the electricity transmission network in England and Wales, and Ofgem license fees (recorded in "Other operation and maintenance" on the Statements 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 in "Other operation and maintenance" on the Statements of Income) are deducted from operating revenues. In addition, certain other expenses, recorded in "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 operating 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 Margins" is a single financial performance measure of the electricity transmission and distribution 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) on the Statements of Income. 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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(a)	Represents amounts excluded from Margins.

(b)	As reported on the Statements of Income.

(c)	2016, 2015 and 2014 exclude $42 million, $46 million and $48 million of ancillary activity revenues. 2014 also excludes $65 million of revenue reductions related to adjustments to WPD's line loss accrual related to DPCR4, which is considered a special item.

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(a)	Distribution rate case effective January 1, 2016, resulted in increases of $160 million for the year ended December 31, 2016.

(b)	In 2016 compared with 2015 the decrease was primarily due to lower energy purchase prices as described below.

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(a)	The increase in 2015 compared with 2014 was due to higher corporate support costs charged to Electric Utilities primarily as a result of the spinoff of PPL Energy Supply.

(a)	During 2016, PPL Electric recorded lower income tax expense related to the application of the new stock-based compensation accounting guidance. See Note 1 to the Financial Statements for additional information.

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(a)	Represents amounts excluded from Margins.

(b)	As reported on the Statements of Income.

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(a)	Decreases due to lower recoveries of fuel and energy purchases due to lower commodity costs as described below.

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(a)	Includes a $29 million reduction of costs in 2016 due to the retirement of Cane Run and Green River coal units partially offset by $5 million of additional costs for Cane Run Unit 7 plant operations.

(a)	Management considers this a special item. See PPL's "Results of Operations - Segment Earnings - Kentucky Regulated Segment" for details of this item.

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(a)	See PPL's "Results of Operations - Segment Earnings - Kentucky Regulated Segment" for details of the special item.

(a)	Represents amounts excluded from Margins.

(b)	As reported on the Statements of Income.

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(a)	Decreases due to lower recoveries of fuel and energy purchases due to lower commodity costs as described below.

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(a)	Includes a $23 million reduction of costs in 2016 due to the retirement of Cane Run coal units.

(a)	There are no items management considers special for the periods presented.

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(a)	Represents amounts excluded from Margins.

(b)	As reported on the Statements of Income.

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(a)	Decreases due to lower recoveries of fuel and energy purchases due to lower commodity costs as described below.

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(a)	There are no items management considers special for the periods presented.

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(a)	Represents amounts excluded from Margins.

(b)	As reported on the Statements of Income.

(a)

At December 31, 2016, $5 million of cash and cash equivalents were denominated in GBP. If these amounts would be remitted as dividends, PPL would not anticipate a material incremental U.S. tax cost. Historically, dividends paid by foreign subsidiaries have been limited to distributions of the current year's earnings. See Note 5 to the Financial Statements for additional information on undistributed earnings of WPD.

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•

Net income improved by $299 million between the periods. This included an additional $195 million of net non-cash charges, including a $132 million increase in deferred income taxes and $96 million of lower unrealized gains on hedging activity (primarily due to the settlement of hedges in the third quarter of 2016) partially offset by a $96 million increase in defined benefit plan income (primarily due to an increase in estimated returns on higher asset balances and lower interest costs due to a change in the discount rate for the U.K. pension plans).

•

The $47 million increase in cash from changes in working capital was primarily due to an increase in taxes payable (due to timing of payments) and an increase in accounts payable (primarily due to timing of payments) partially offset by an increase in unbilled revenues (primarily due to favorable weather compared to December 2015), an increase in net regulatory assets/liabilities (due to timing of rate recovery mechanisms) and an increase in accounts receivable (primarily due to increased volumes and favorable weather in 2016).

•	Defined benefit plan funding was $72 million lower in 2016.

•

Net income improved by $166 million between the periods, but included a decrease in net non-cash charges of $280 million. These net non-cash charges included a $238 million decrease in deferred income taxes and $65 million of changes to the WPD line loss accrual. These decreases in non-cash charges were partially offset by $110 million of lower unrealized gains on hedging activities. The net $114 million decrease from net income and non-cash adjustments between the periods was primarily due to lower margins from the U.K. Regulated segment, partially offset by higher margins from the Kentucky and Pennsylvania Regulated segments.

•

The $341 million decrease in cash from changes in working capital was primarily due to a decrease in taxes payable (primarily due to a decrease in current income tax expense in 2015) and a decrease in accounts payable (primarily due to timing of fuel purchases and payments and unfavorable weather in 2015) partially offset by a decrease in accounts receivable (primarily due to unfavorable weather in 2015).

•	The $99 million decrease in cash provided by other operating activities was primarily due to payments of $101 million for the settlement in 2015 of forward starting interest rate swaps.

•	Net income improved by $88 million between the periods. This included an additional $40 million of net non-cash benefits primarily due to a $39 million increase in depreciation expense (primarily due to the replacement of aging infrastructure and to ensure system reliability).

•

The $101 million increase in cash from changes in working capital was primarily due to an increase in accounts payable (primarily due to timing of payments), an increase in taxes payable (primarily due to timing of payments) and a decrease in prepayments (primarily due to higher tax payments in 2015) partially offset by an increase in net regulatory assets and liabilities (due to timing of rate recovery mechanisms), an increase in unbilled revenues (primarily due to higher volumes and favorable weather compared to December 2015) and an increase in accounts receivable.

•	Pension funding was $33 million lower in 2016.

•	Net income decreased by $11 million between the periods and included an additional $181 million of net non-cash charges primarily due to increases in deferred tax expense and depreciation.

•	The $148 million decrease in cash from changes in working capital was partially due to a decrease in taxes payable (primarily due an increase in current income tax benefits in 2015) and a decrease in accounts payable (primarily due to milder weather and lower energy prices in December 2015), partially offset by a decrease in accounts receivable (primarily due to improved collection performance).

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•	Pension funding was $10 million higher in 2015.

•	Net income improved by $65 million and included an increase of $66 million of net non-cash charges primarily due to a $55 million increase in deferred income taxes and a $22 million increase in depreciation expense.

•

The decrease in cash from changes in working capital was driven primarily by lower tax payments received from PPL for the use of prior year excess tax depreciation deductions. Other decreases in cash were related to accounts receivable and unbilled revenues due to more favorable weather in December 2016 compared to December 2015, and a decrease in taxes payable due to the timing of payments, partially offset by an increase in accounts payable due to the timing of fuel purchases and payments.

•	Defined benefit plan funding was $15 million higher in 2016.

•	The increase in cash from LKE's other operating activities was driven primarily by lower payments for the settlement of interest rate swaps, partially offset by an increase in ARO expenditures.

•	LKE's non-cash components of net income included a $213 million decrease in deferred income taxes, partially offset by a $28 million increase in depreciation due to additional assets in service in 2015. Deferred income taxes were lower in 2015 as a large portion of the effect of accelerated tax depreciation did not result in cash as a result of the Federal net operating losses.

•

The increase in cash from changes in working capital was driven primarily by a decrease in income tax receivable as a result of receiving payment from PPL in 2015 for the use of excess tax depreciation deductions in 2014, decreases in accounts receivable and unbilled revenues due to milder weather in December 2015, a decrease in coal inventory as a result of plant retirements, and a decrease in natural gas stored underground due to lower gas prices in 2015, partially offset by a decrease in accounts payable due to the timing of fuel purchases and payments.

•	The decrease in cash from LKE's other operating activities was driven primarily by $88 million in payments for the settlement of interest rate swaps.

•	Net income improved by $18 million and included an increase of $20 million of net non-cash charges primarily due to a $21 million increase in deferred income taxes.

•

The decrease in cash from changes in working capital was driven primarily by lower tax payments received from LKE for the use of prior year excess tax depreciation deductions. Other decreases in cash were related to accounts receivable and unbilled revenues due to more favorable weather in December 2016 compared to December 2015, and an increase in accounts receivable from affiliates due to higher intercompany settlements associated with energy sales and inventory, partially offset by an increase in accounts payable due to the timing of fuel purchases and payments.

•	Defined benefit plan funding was $20 million higher in 2016.

•	The increase in cash from LG&E's other operating activities was driven primarily by lower payments for the settlement of interest rate swaps, partially offset by an increase in ARO expenditures.

•	LG&E's non-cash components of net income included an $8 million increase in deferred income taxes and a $5 million increase in depreciation due to additional assets in service in 2015.

•	The increase in cash from changes in working capital was driven primarily by a decrease in income tax receivable as a result of receiving payment from LKE in 2015 for the use of excess tax depreciation deductions in 2014, a decrease in accounts receivable from affiliates due to lower fuel costs for jointly owned units compared to an increase in the prior

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•	The decrease in cash from LG&E's other operating activities was driven primarily by $44 million in payments for the settlement of interest rate swaps.

•	Net income improved by $31 million and included a decrease of $20 million of net non-cash charges primarily due to a $34 million decrease in deferred income taxes, partially offset by a $14 million increase in depreciation expense.

•

The decrease in cash from changes in working capital was driven primarily by lower tax payments received from LKE for the use of prior year excess tax depreciation deductions. Other decreases in cash were related to accounts receivable and unbilled revenues due to more favorable weather in December 2016 compared to December 2015, partially offset by an increase in accounts payable to affiliates due to higher intercompany settlements associated with energy purchases and inventory, and an increase in taxes payable due to the timing of payments.

•	The increase in cash from KU's other operating activities was driven primarily by lower payments for the settlement of interest rate swaps, partially offset by an increase in ARO expenditures.

•	KU's non-cash components of net income included a $64 million decrease in deferred income taxes, partially offset by a $23 million increase in depreciation due to additional assets in service in 2015. Deferred income taxes were lower in 2015 as a large portion of the effect of accelerated tax depreciation did not result in cash as a result of the Federal net operating losses.

•

The increase in cash from changes in working capital was driven primarily by a decrease in income tax receivable as a result of receiving payment from LKE in 2015 for the use of excess tax depreciation deductions in 2014, a decrease in coal inventory as a result of the retirement of Green River coal units, and decreases in accounts receivable and unbilled revenues due to milder weather in December 2015, partially offset by a decrease in accounts payable to affiliates compared to an increase in the prior year due to lower fuel costs for jointly owned units and a decrease in accounts payable due to the timing of fuel purchases and payments.

•	The decrease in cash from KU's other operating activities was driven primarily by $44 million in payments for the settlement of interest rate swaps.

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(a)	Includes net increase (decrease) in notes payable with affiliates.

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(a)	Issuances are net of pricing discounts, where applicable, and exclude the impact of debt issuance costs.

(a)	The syndicated credit facilities, as well as KU's letter of credit facility, each contain a financial covenant requiring debt to total capitalization not to exceed 70% for PPL Capital Funding, PPL Electric, LKE, LG&E and KU, as calculated in accordance with the facility, and other customary covenants.

(b)	The commitments under the domestic credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than the following percentages of the total committed capacity: PPL - 10%, PPL Electric 7%, LKE - 21%, LG&E - 7% and KU - 37%.

(c)	Each company pays customary fees under its respective syndicated credit facility, as does KU under its letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.

(d)	The facilities contain financial covenants to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, calculated in accordance with the credit facility.

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(e)

The amounts borrowed at December 31, 2016, include a USD-denominated borrowing of $200 million and GBP-denominated borrowings of £119 million, which equated to $148 million. The unused capacity reflects the USD-denominated amount borrowed in GBP of £161 million as of the date borrowed. At December 31, 2016, the USD equivalent of unused capacity under the U.K. committed credit facilities was $969 million.

(a)	LG&E and KU participate in an intercompany agreement whereby LKE, LG&E and/or KU make available funds up to $500 million at an interest rate based on a market index of commercial paper issues. However, the FERC has authorized a maximum aggregate short-term debt limit for each utility at $500 million from all covered sources.

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(a)	Construction expenditures include capitalized interest and AFUDC, which are expected to total approximately $86 million for PPL and $67 million for PPL Electric.

(b)	The 2017 total excludes amounts included in accounts payable as of December 31, 2016.

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(a)	Reflects principal maturities based on stated maturity or earlier put dates. See Note 7 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of LG&E and KU. The Registrants do not have any significant capital lease obligations.

(b)	Assumes interest payments through stated maturity or earlier put dates. For PPL, LKE, LG&E and KU the payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated and for PPL, payments denominated in British pounds sterling have been translated to U.S. dollars at a current foreign currency exchange rate.

(c)	See Note 9 to the Financial Statements for additional information.

(d)	The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes as

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(e)

The amounts for PPL include WPD's contractual deficit pension funding requirements arising from actuarial valuations performed in March 2013 and March 2016. The U.K. electricity regulator currently allows a recovery of a substantial portion of the contributions relating to the plan deficit. The amounts also include contributions made or committed to be made in 2017 for PPL's and LKE's U.S. pension plans (for PPL Electric, LG&E and KU includes their share of these amounts). Based on the current funded status of these plans, except for WPD's plans, no cash contributions are required. See Note 11 to the Financial Statements for a discussion of expected contributions.

(f)	Represents contracts to purchase coal, natural gas and natural gas transportation. See Note 13 to the Financial Statements for additional information.

(g)	Represents future minimum payments under OVEC power purchase agreements through June 2040. See Note 13 to the Financial Statements for additional information.

(h)	Represents construction commitments, including commitments for LG&E's and KU's Trimble County landfill construction, LG&E's Paddy's Run plant demolition, Ohio Falls refurbishment and completion of the Mill Creek environmental air project, which are also reflected in the Capital Expenditures table presented above.

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(a)	Includes accrued interest, if applicable.

(b)	Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability. Sensitivities represent a 10% adverse movement in interest rates, except for cross-currency swaps which also includes a 10% adverse movement in foreign currency exchange rates.

(c)	Changes in the fair value of such cash flow hedges are recorded in equity or as regulatory assets or regulatory liabilities, if recovered through regulated rates, and reclassified into earnings in the same period during which the item being hedged affects earnings.

(d)	Cross-currency swaps are utilized to hedge the principal and interest payments of WPD's U.S. dollar-denominated senior notes. Changes in the fair value of these instruments are recorded in equity and reclassified into earnings in the same period during which the item being hedged affects earnings.

(e)	Realized changes in the fair value of such economic hedges are recoverable through regulated rates and any subsequent changes in the fair value of these derivatives are included in regulatory assets or regulatory liabilities.

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(a)	Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability.

(b)	To protect the value of a portion of its net investment in WPD, PPL executes forward contracts to sell GBP.

(c)	To economically hedge the translation of expected earnings denominated in GBP.

•

PPL Electric is exposed to commodity price risk from its obligation as PLR; however, its PUC-approved cost recovery mechanism substantially eliminates its exposure to this risk. PPL Electric also mitigates its exposure to commodity price risk by entering into full-requirement supply agreements to serve its PLR customers. These supply agreements transfer the commodity price risk associated with the PLR obligation to the energy suppliers.

•	LG&E's and KU's rates include certain mechanisms for fuel and fuel-related expenses. In addition, LG&E's rates include a mechanism for natural gas supply expenses. These mechanisms generally provide for timely recovery of market price fluctuations associated with these expenses.

•	WPD is exposed to volumetric risk which, is significantly mitigated as a result of the method of regulation in the U.K. Under the RIIO-ED1 price control period, recovery of such exposure occurs on a two year lag. See Note 1 for additional information on revenue recognition under RIIO-ED1.

•	PPL Electric, LG&E and KU are exposed to volumetric risk on retail sales, mainly due to weather and other economic conditions for which there is limited mitigation between rate cases.

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•	Legal Matters,

•	Climate Change,

•	Coal Combustion Residuals,

•	Effluent Limitations Guidelines, and

•	National Ambient Air Quality Standards.

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(a)	Does not sponsor or participate in other postretirement benefits plans.

•

Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.

•	Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets that will be earned over the life of the plan. These projected returns reduce the net benefit costs the Registrants record currently.

•	Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.

•	Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.

•	U.S. - at December 31, 2014, the plan sponsors adopted the new mortality tables issued by the Society of Actuaries in October 2014 (RP-2014 base tables) for all U.S. defined benefit pension and other postretirement benefit plans. In

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•

U.K. - at March 31 2016, the UK plan sponsors adopted the new mortality assumptions based on the “SAPS S2 All” tables issued by the Self-Administered Pensions Schemes’ (SAPS) study for all U.K. defined benefit pension plans. In addition, the UK plan sponsors updated the basis for estimating projected mortality improvements and selected the CMI 2015 Core Projections model published by the Continuous Mortality Investigation study with a long-term future improvement rate of 1% for all U.K. defined benefit pension plans. These new mortality assumptions reflect the impact of the most recently available actual scheme mortality data (which has been higher than previously expected) on both current life expectancies and the expectation of continuing improvements in life expectancies. The use of the new base tables and improvement scale resulted in a decrease to U.K. defined benefit pension obligations, a decrease to future expense and an increase to funded status.

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(a)

WPD began using individual spot rates from the yield curve used to discount the benefit obligation to measure service cost and interest cost for the calculation of net periodic defined benefit cost in 2016. PPL's U.S. plans use a single discount rate derived from an individual bond matching model to measure the benefit obligation, service cost and interest cost. See Note 1 to the Financial Statements for additional details.

(a)

As a result of the 2014 Kentucky rate case settlement that became effective July 1, 2015, the difference between pension cost calculated in accordance with LG&E's and KU's pension accounting policy and pension cost calculated using a 15 year amortization period for actuarial gains and losses is recorded as a regulatory asset. As of December 31, 2016, the balances were $20 million for PPL and LKE, $11 million for LG&E and $9 million for KU. See Note 6 to the Financial Statements for additional information.

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(a)	Only impacts other postretirement benefits.

(a)	Only impacts other postretirement benefits.

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•	current year financial performance versus the prior year,

•	changes in planned capital expenditures,

•	the consistency of forecasted free cash flows,

•	earnings quality and sustainability,

•	changes in market participant discount rates,

•	changes in long-term growth rates,

•	changes in PPL's market capitalization, and

•	the overall economic and regulatory environments in which these regulated entities operate.

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(a)	1,560,000 shares authorized; 679,731 shares issued and outstanding at December 31, 2016; 780,000 shares authorized; 673,857 shares issued and outstanding at December 31, 2015.

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(a)	Shares in thousands. Each share entitles the holder to one vote on any question presented at any shareowners' meeting.

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(a)	Net income equals comprehensive income.

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(a)	170,000 shares authorized; 66,368 shares issued and outstanding at December 31, 2016 and 2015.

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(a)	Shares in thousands. All common shares of PPL Electric stock are owned by PPL.

(b)	Includes non-cash contributions of $56 million. See Note 11 for additional information.

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(a)	Net income equals comprehensive income.

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(a)	75,000 shares authorized; 21,294 shares issued and outstanding at December 31, 2016 and December 31, 2015.

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(a)	Net income approximates comprehensive income.

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(a)	80,000 shares authorized; 37,818 shares issued and outstanding at December 31, 2016 and December 31, 2015.

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•	Transactions to lock in an interest rate prior to a debt issuance can be designated as cash flow hedges, to the extent the forecasted debt issuances remain probable of occurring.

•	Cross-currency transactions to hedge interest and principal repayments can be designated as cash flow hedges.

•	Transactions entered into to hedge fluctuations in the fair value of existing debt can be designated as fair value hedges.

•	Transactions entered into to hedge the value of a net investment of foreign operations can be designated as net investment hedges.

•

Derivative transactions that do not qualify for cash flow or net investment hedge treatment are marked to fair value through earnings. These transactions generally include foreign currency forwards and options to hedge GBP earnings translation risk associated with PPL's U.K. subsidiaries that report their financial statements in GBP. As such, these transactions reduce earnings volatility due solely to changes in foreign currency exchange rates.

•	Derivative transactions may be marked to fair value through regulatory assets/liabilities at PPL Electric, LG&E and KU if approved by the appropriate regulatory body. These transactions generally include the effect of interest rate swaps that are included in customer rates.

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(a)	Represents revenues from cost-based rate-regulated generation, transmission and/or distribution in Pennsylvania, Kentucky, Virginia and Tennessee, including regulated wholesale revenue.

(b)	Primarily represents regulated electricity distribution revenues from the operation of WPD's distribution networks.

•	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.

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•

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 incremental change to base demand revenue, known as the "MOD" adjustment.

•	Incentives - Ofgem has established incentives to provide opportunities for DNO's to enhance overall returns by improving network efficiency, reliability and customer service. 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 for additional information.

•

Correction Factor - During the price control period, WPD sets its tariffs to recover allowed revenue. However, in any fiscal period, WPD's revenue could be negatively affected if its tariffs and the volume delivered do not fully recover the revenue allowed 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 for the periods beginning with the 2014/15 regulatory year and refunded/recovered under RIIO-ED1 will be refunded/recovered on a two year lag (previously one year). Therefore the 2014/15 over/under-recovery adjustment will occur in the 2016/17 regulatory year.

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(a)	Primarily related to uncollectible accounts written off.

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(a)	Funds received by WPD, which are to be spent on approved initiatives to support a low carbon environment.

•	Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that are accessible at the measurement date. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

•	Level 2 - inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for substantially the full term of the asset or liability.

•	Level 3 - unobservable inputs that management believes are predicated on the assumptions market participants would use to measure the asset or liability at fair value.

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•	current year financial performance versus the prior year,

•	changes in planned capital expenditures,

•	the consistency of forecasted free cash flows,

•	earnings quality and sustainability,

•	changes in market participant discount rates,

•	changes in long-term growth rates,

•	changes in PPL's market capitalization, and

•	the overall economic and regulatory environments in which these regulated entities operate.

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(a)	Natural gas stored underground is primarily held to serve retail customers.

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•

Using the required prospective method of transition, for the year ended December 31, 2016, PPL recorded tax benefits of $10 million ($0.01 per share), and PPL Electric recorded tax benefits of $6 million, related to excess tax benefits for awards that were exercised and vested. These amounts were recorded to "Income Taxes" on the Statements of Income and "Deferred income taxes" on the Balance Sheets. The impact on LKE was not significant.

•	PPL elected to use the prospective method of transition for classifying excess tax benefits as an Operating activity on the Statement of Cash Flows. The amounts classified as Financing activities in the prior periods were not significant.

•	Upon adoption, using the required modified retrospective method of transition, PPL recorded a cumulative effect adjustment of $7 million to increase "Earnings reinvested" and decrease "Deferred income taxes" on the Balance Sheet related to prior period unrecognized excess tax benefits.

•	PPL has historically presented employee taxes paid for net settled awards as a Financing activity on the Statement of Cash Flows. Therefore, there is no transition impact for this requirement.

•	PPL has elected to recognize forfeitures when they occur. Due to past experience of insignificant forfeitures, there is no transition impact of this policy election.

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(a)	See Note 1 for additional information on Operating Revenues.

(b)	Represents non-cash expense items that include amortization of regulatory assets, debt discounts and premiums, debt issuance costs, emission allowances and RECs.

(c)	Includes unrealized gains and losses from economic activity. See Note 17 for additional information.

(d)	2015 and 2014 include certain costs related to the spinoff of PPL Energy Supply, including deferred income tax expense, transition costs and separation benefits for PPL Services employees. See Note 8 for additional information.

(e)	Represents both current and deferred income taxes, including investment tax credits.

(f)	Represents a non-cash expense item that is also included in "Income Taxes."

(g)	2015 includes an $879 million loss on the spinoff of PPL Energy Supply and five months of Supply segment earnings. 2014 includes a gain of $237 million ($137 million after-tax) on the sale of the Montana hydroelectric generating facilities. See Note 8 for additional information on these transactions.

(h)	Includes $10.8 billion and $12.2 billion of net PP&E as of December 31, 2016 and December 31, 2015. WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP.

(i)	Primarily consists of unallocated items, including cash, PP&E and the elimination of inter-segment transactions.

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(a)	In 2014, the If-Converted Method was applied to the Equity Units prior to settlement. See Note 7 for additional information on the Equity Units, including the issuance of PPL common stock to settle the Purchase contracts.

(b)	The Treasury Stock Method was applied to non-participating share-based payment awards.

(a)	Includes stock options exercised, vesting of performance units, vesting of restricted stock and restricted stock units and conversion of stock units granted to directors.

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(a)	Includes $77 million of deferred tax assets related to state loss carryforwards and related valuation allowances previously reflected on the PPL Energy Supply Segment. The deferred tax assets and related valuation allowance remained with PPL after the spinoff.

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(a)

The reductions of the U.K. statutory income tax rates in 2016 and 2015 resulted in $19 million and $44 million in reductions in the deferred tax assets and corresponding valuation allowances. See "Reconciliation of Income Tax Expense" below for more information on the impact of the U.K. Finance Acts 2016 and 2015. In addition, the deferred tax assets and corresponding valuation allowances were reduced in 2016 by approximately $65 million due to the effect of foreign currency exchange rates.

(b)	Valuation allowance related to the deferred tax assets previously reflected on the PPL Energy Supply Segment. The deferred tax assets and related valuation allowance remained with PPL after the spinoff.

(a)	Increase in Federal loss carryforwards for 2015 primarily relates to the extension of bonus depreciation and the impact of bonus depreciation related to provision to return adjustments.

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(a)	During 2016, PPL recorded deferred tax expense for valuation allowances primarily related to increased Pennsylvania net operating loss carryforwards expected to be unutilized.

(b)	The U.K. Finance Act 2016, enacted in September 2016, reduces the U.K. statutory income tax rate effective April 1, 2020 from 18% to 17%. As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2016.

(c)	During 2016, PPL recorded lower income taxes primarily attributable to foreign tax credit carryforwards, arising from a decision to amend prior year tax returns to claim foreign tax credits rather than deduct foreign taxes. This decision was prompted by changes to the Company's most recent business plan.

(d)	During 2015, PPL recorded a $12 million tax benefit related to the settlement of the IRS audit for the tax years 1998-2011.

(e)	During 2016, PPL recorded lower income tax expense related to the application of new stock-based compensation accounting guidance. See Note 1 for additional information.

(a)	The decrease in 2015 was primarily due to the settlement of a 2011 gross receipts tax audit resulting in the reversal of $17 million of previously recognized reserves.

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(a)	An immaterial amount of valuation allowances has been recorded against the deferred tax asset for state contributions.

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(a)	During 2016, PPL recorded lower income tax expense related to the application of new stock-based compensation accounting guidance. See Note 1 for additional information.

(a)	The decrease in 2015 was primarily due to the settlement of a 2011 gross receipts tax audit resulting in the reversal of $17 million of previously recognized reserves.

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(a)	Federal tax credit expiring in 2016.

(b)	Federal tax credits expiring in 2016 through 2020 that are more likely than not to expire before being utilized.

(c)	Primarily related to the expiration of state capital loss carryforwards.

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(a)	Excludes current and deferred federal and state tax expense (benefit) recorded to Discontinued Operations of less than $1 million in 2016, 2015 and 2014. Also, excludes deferred federal and state tax expense (benefit) recorded to OCI of $(16) million in 2016, less than $(1) million in 2015 and $(36) million in 2014.

(a)	Represents a valuation allowance against tax credits expiring through 2020 that are more likely than not to expire before being utilized.

(b)	During 2016, LKE recorded lower income tax expense related to the application of new stock-based compensation accounting guidance. See Note 1 for additional information.

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(a)	Excludes deferred federal and state tax expense (benefit) recorded to OCI of less than $(1) million in 2016, 2015 and 2014.

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(a)	For PPL, these amounts are included in "Other current assets" on the Balance Sheets.

(b)	These liabilities were recorded as offsets to certain intangible assets that were recorded at fair value upon the acquisition of LKE by PPL.

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(a)	The facilities contain financial covenants to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, calculated in accordance with the credit facility.

(b)

The WPD plc amounts borrowed at December 31, 2016 and 2015 included USD-denominated borrowings of $200 million for both periods, which bore interest at 1.43% and 1.83%. The unused capacity reflects the amount borrowed in GBP of £161 million as of the date borrowed. The WPD (South West) amount borrowed at December 31, 2016 was a GBP-denominated borrowing, which equated to $137 million and bore interest at 0.66%. The WPD (East Midlands) amount borrowed at December 31, 2016 was a GBP-denominated borrowing, which equated to $11 million and bore interest at 0.66%. The WPD Uncommitted Credit Facilities amounts borrowed at December 31, 2016 were GBP-denominated borrowings which equated to $75 million and bore interest at 1.26%. At December 31, 2016, the unused capacity under the U.K. credit facilities was approximately $1 billion.

(c)	Each company pays customary fees under its respective facility and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.

(d)

The facilities contain a financial covenant requiring debt to total capitalization not to exceed 70% for PPL Capital Funding, PPL Electric, LKE, LG&E and KU, as calculated in accordance with the facilities and other customary covenants. Additionally, as it relates to the syndicated and bilateral credit facilities and subject to certain conditions, PPL Capital Funding may request that the capacity of its facilities expiring in November 2018 and March 2017

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(e)	KU's letter of credit facility agreement allows for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment.

(f)	At December 31, 2015, LKE's interest rate on outstanding borrowings was 1.68%.

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(a)	Includes PPL Electric's senior secured and first mortgage bonds that are secured by the lien of PPL Electric's 2001 Mortgage Indenture, which covers substantially all electric distribution plant and certain transmission plant owned by PPL Electric. The carrying value of PPL Electric's property, plant and equipment was approximately $7.6 billion and $6.7 billion at December 31, 2016 and 2015.

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(b)

Includes PPL Electric's series of senior secured bonds that secure its obligations to make payments with respect to each series of Pollution Control Bonds that were issued by the LCIDA and the PEDFA on behalf of PPL Electric. These senior secured bonds were issued in the same principal amount, contain payment and redemption provisions that correspond to and bear the same interest rate as such Pollution Control Bonds. These senior secured bonds were issued under PPL Electric's 2001 Mortgage Indenture and are secured as noted in (a) above. This amount includes $224 million of which PPL Electric is allowed to convert the interest rate mode on the bonds from time to time to a commercial paper rate, daily rate, weekly rate, or term rate of at least one year and $90 million that may be redeemed, in whole or in part, at par beginning in October 2020, and are subject to mandatory redemption upon determination that the interest rate on the bonds would be included in the holders' gross income for federal tax purposes.

(c)

Includes LG&E's and KU's series of first mortgage bonds that were issued to the respective trustees of tax-exempt revenue bonds to secure its respective obligations to make payments with respect to each series of bonds. The first mortgage bonds were issued in the same principal amounts, contain payment and redemption provisions that correspond to and bear the same interest rate as such tax-exempt revenue bonds. These first mortgage bonds were issued under the LG&E 2010 Mortgage Indenture and the KU 2010 Mortgage Indenture and are secured as noted in (a) above. The related tax-exempt revenue bonds were issued by various governmental entities, principally counties in Kentucky, on behalf of LG&E and KU. The related revenue bond documents allow LG&E and KU to convert the interest rate mode on the bonds from time to time to a commercial paper rate, daily rate, weekly rate, term rate of at least one year or, in some cases, an auction rate or a LIBOR index rate.

(d)	Includes £225 million ($281 million at December 31, 2016) of notes that may be redeemed, in total but not in part, on December 21, 2026, at the greater of the principal value or a value determined by reference to the gross redemption yield on a nominated U.K. Government bond.

(e)

The principal amount of the notes issued by WPD (South West) and WPD (East Midlands) is adjusted based on changes in a specified index, as detailed in the terms of the related indentures. The adjustment to the principal amounts from 2015 to 2016 was an increase of approximately £10 million ($13 million) resulting from inflation. In addition, this amount includes £225 million ($281 million at December 31, 2016) of notes issued by WPD (South West) that may be redeemed, in total by series, on December 1, 2026, at the greater of the adjusted principal value and a make-whole value determined by reference to the gross real yield on a nominated U.K. government bond.

(f)

Includes £4.4 billion ($5.5 billion at December 31, 2016) of notes that may be put by the holders to the issuer for redemption if the long-term credit ratings assigned to the notes are withdrawn by any of the rating agencies (Moody's or S&P) or reduced to a non-investment grade rating of Ba1 or BB+ or lower in connection with a restructuring event, which includes the loss of, or a material adverse change to, the distribution licenses under which the issuer operates.

(g)	The table reflects principal maturities only, based on stated maturities or earlier put dates, and the weighted-average rates as of December 31, 2016.

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(a)	Includes interest associated with the Supply segment with no additional allocation as the Supply segment was sufficiently capitalized.

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(a)	Excludes 862,337 restricted stock units for which restrictions lapsed for former PPL Energy Supply employees as a result of the spinoff, but for which distribution will not occur until the end of the original restriction period of the awards.

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(a)	Excludes 230,196 performance units for which the service vesting requirement was waived for former PPL Energy Supply employees as a result of the spinoff, but for which the ultimate number of shares to be distributed will depend on the actual attainment of the performance goals at the end of the specified performance periods.

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(a)	As a result of the spinoff of PPL Energy Supply, amounts in AOCI were allocated to certain former active and inactive employees of PPL Energy Supply and included in the distribution. See Note 8 for additional details.

(b)	WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP. As a result, WPD does not record regulatory assets/liabilities.

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(a)	As a result of the 2014 Kentucky rate case settlement that became effective July 1, 2015, the difference between actuarial (gain)/loss calculated in accordance with LKE's pension accounting policy and actuarial (gain)/loss calculated using a 15 year amortization period was $6 million in 2016 and $9 million in 2015.

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(a)	As a result of the 2014 Kentucky rate case settlement that became effective July 1, 2015, the difference between actuarial (gain)/loss calculated in accordance with LG&E's pension accounting policy and actuarial (gain)/loss calculated using a 15 year amortization period was $5 million in 2016 and $3 million in 2015.

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(a)	PPL Electric and KU do not directly sponsor any defined benefit plans. PPL Electric and KU were allocated these costs of defined benefit plans sponsored by PPL Services (for PPL Electric) and by LKE (for KU), based on their participation in those plans, which management believes are reasonable.

(b)

As a result of the 2014 Kentucky rate case settlement that became effective July 1, 2015, the difference between net periodic defined benefit costs calculated in accordance with LKE's, LG&E's and KU's pension accounting policy and the net periodic defined benefit costs calculated using a 15 year amortization period for gains and losses is recorded as a regulatory asset. Of the costs charged to operating expense or regulatory assets, excluding amounts charged to construction and other non-expense accounts, $3 million for LG&E and $2 million for KU were recorded as regulatory assets in 2016 and $4 million for LG&E and $1 million for KU were recorded as regulatory assets in 2015.

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(a)	The expected long-term rates of return for pension and other postretirement benefits are based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption.

(b)	As of January 1, 2016, WPD began using individual spot rates from the yield curve used to discount the benefit obligation to measure service cost and interest cost. PPL's U.S. plans use a single discount rate derived from an individual bond matching model to measure the benefit obligation, service cost and interest cost. See Note 1 for additional details.

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(a)	As a result of the spinoff of PPL Energy Supply, obligations and assets attributable to certain former active and inactive employees of PPL Energy Supply were transferred to Talen Energy plans.

(b)	WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and as a result, does not record regulatory assets/liabilities.

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(a)

The pension plans were amended in December 2015 to allow active participants and terminated vested participants who had not previously elected a form of payment of their benefit to elect to receive their accrued pension benefit as a one-time lump-sum payment effective January 1, 2016. The projected benefit obligation at December 31, 2015 increased by $19 million as a result of the amendment. Gross benefits paid by the plans include $53 million of lump-sum cash payments made to participants during 2016 in connection with these offerings.

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(a)

The pension plan was amended in December 2015 to allow active participants and terminated vested participants who had not previously elected a form of payment of their benefit to elect to receive their accrued pension benefit as a one-time lump-sum payment effective January 1, 2016. The projected benefit obligation at December 31, 2015 increased by $10 million as a result of the amendment. Gross benefits paid by the plan include $14 million of lump-sum cash payments made to the participants during 2016 in connection with this offering.

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(a)	Allocations exclude consideration of a group annuity contract held by the LG&E and KU Retirement Plan.

(b)	Includes commingled debt funds, which PPL treats as debt securities for asset allocation purposes.

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(a)

In accordance with accounting guidance certain investments that are measured at fair value using the net asset value per share (NAV), or its equivalent, practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position.

(b)	Receivables and payables represent amounts for investments sold/purchased but not yet settled along with interest and dividends earned but not yet received.

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(a)	Includes commingled debt funds and debt securities.

(b)	Includes money market funds.

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(a)

In accordance with accounting guidance certain investments that are measured at fair value using the net asset value per share (NAV), or its equivalent, practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position.

(b)	Receivables and payables represent amounts for investments sold/purchased but not yet settled along with interest and dividends earned but not yet received.

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(a)	Includes commingled debt funds.

(a)

In accordance with accounting guidance certain investments that are measured at fair value using the net asset value per share (NAV), or its equivalent, practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position.

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(a)

Indemnifications related to certain liabilities, including a specific unresolved tax issue and those relating to properties and assets owned by the seller that were transferred to WPD Midlands in connection with the acquisition. A cross indemnity has been received from the seller on the tax issue. The maximum exposure and expiration of these indemnifications cannot be estimated because the maximum potential liability is not capped and the expiration date is not specified in the transaction documents.

(b)

Indemnification to the liquidators and certain others for existing liabilities or expenses or liabilities arising during the liquidation process. The indemnifications are limited to distributions made from the subsidiary to its parent either prior or subsequent to liquidation or are not explicitly stated in the agreements. The indemnifications generally expire two to seven years subsequent to the date of dissolution of the entities. The exposure noted only includes those cases where the agreements provide for specific limits.

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(c)

Relates to certain obligations of discontinued or modified electric associations that were guaranteed at the time of privatization by the participating members. Costs are allocated to the members and can be reallocated if an existing member becomes insolvent. At December 31, 2016, WPD has recorded an estimated discounted liability for which the expected payment/performance is probable. Neither the expiration date nor the maximum amount of potential payments for certain obligations is explicitly stated in the related agreements, and as a result, the exposure has been estimated.

(d)	A third party logistics firm provides inventory procurement and fulfillment services. The logistics firm has title to the inventory, however, upon termination of the contracts, PPL Electric has guaranteed to purchase any remaining inventory that has not been used or sold.

(e)

LKE provides certain indemnifications covering the due and punctual payment, performance and discharge by each party of its respective obligations. The most comprehensive of these guarantees is the LKE guarantee covering operational, regulatory and environmental commitments and indemnifications made by WKE under a 2009 Transaction Termination Agreement. This guarantee has a term of 12 years ending July 2021, and a maximum exposure of $200 million, exclusive of certain items such as government fines and penalties that may exceed the maximum. Another WKE-related LKE guarantee covers other indemnifications related to the purchase price of excess power, has a term expiring in 2023, and a maximum exposure of $100 million. In May 2012, LKE's indemnitee received an unfavorable arbitration panel's decision interpreting this matter. In October 2014, LKE's indemnitee filed a motion for discretionary review with the Kentucky Supreme Court seeking to overturn the arbitration decision, and such motion was denied by the court in September 2015. In September 2015, the counterparty issued a demand letter to LKE's indemnitee. In February 2016, the counterparty filed a complaint in Henderson, Kentucky Circuit Court, seeking an award of damages in the matter. The proceeding is currently in the discovery phase. LKE does not believe appropriate contractual, legal or commercial grounds exist for the claim made. LKE believes its indemnification obligations in the WKE matter remain subject to various uncertainties, including additional legal and contractual developments, as well as future prices, availability and demand for the subject excess power. Although the parties have also conducted certain settlement discussions, the ultimate outcomes of the WKE termination-related indemnifications cannot be predicted at this time. Additionally, LKE has indemnified various third parties related to historical obligations for other divested subsidiaries and affiliates. The indemnifications vary by entity and the maximum exposures range from being capped at the sale price to no specified maximum. LKE could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party. LKE cannot predict the ultimate outcomes of the various indemnification scenarios, but does not expect such outcomes to result in significant losses above the amounts recorded.

(f)

Pursuant to the OVEC power purchase contract, LG&E and KU are obligated to pay for their share of OVEC's excess debt service, post-retirement and decommissioning costs, as well as any shortfall from amounts included within a demand charge designed and expected to cover these costs over the term of the contract. LKE's proportionate share of OVEC's outstanding debt was $123 million at December 31, 2016, consisting of LG&E's share of $85 million and KU's share of $38 million. The maximum exposure and the expiration date of these potential obligations are not presently determinable. See "Energy Purchase Commitments" above for additional information on the OVEC power purchase contract. In connection with recent credit market related developments at OVEC or certain of its sponsors, such parties, including LG&E and KU, are analyzing certain potential additional credit support actions to preserve OVEC's access to credit markets or mitigate risks or adverse impacts relating thereto, including increased interest costs and accelerated maturities of OVEC's existing short and long-term debt. The ultimate outcome of these matters, including any potential impact on LG&E's and KU's obligations relating to OVEC debt under the power purchase contract cannot be predicted.

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(a)	Current portion is included in "Other current assets" and long-term portion is included in "Other noncurrent assets" on the Balance Sheets.

(b)	Current portion is included in "Price risk management assets" and "Other current liabilities" and noncurrent portion is included in "Price risk management assets" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets.

(c)	Included in "Other current assets" on the Balance Sheets.

(d)	Included in "Other noncurrent assets" on the Balance Sheets. Represents cash collateral posted to offset the exposure with counterparties related to certain interest rate swaps under master netting arrangements that are not offset.

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•

PPL and its subsidiaries are exposed to interest rate risk associated with forecasted fixed-rate and existing floating-rate debt issuances. PPL and WPD hold over-the-counter cross currency swaps to limit exposure to market fluctuations on interest and principal payments from changes in foreign currency exchange rates and interest rates. LKE and LG&E utilize over-the-counter interest rate swaps to limit exposure to market fluctuations on floating-rate debt. PPL, LKE, LG&E and

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•	PPL and its subsidiaries are exposed to interest rate risk associated with debt securities and derivatives held by defined benefit plans. This risk is significantly mitigated to the extent that the plans are sponsored at, or sponsored on behalf of, the regulated domestic utilities and for certain plans at WPD due to the recovery mechanisms in place.

•	PPL is exposed to foreign currency exchange risk primarily associated with its investments in and earnings of U.K. affiliates.

•

PPL Electric is exposed to commodity price risk from its obligation as PLR; however, its PUC-approved cost recovery mechanism substantially eliminates its exposure to this risk. PPL Electric also mitigates its exposure to commodity price risk by entering into full-requirement supply agreements to serve its PLR customers. These supply agreements transfer the commodity price risk associated with the PLR obligation to the energy suppliers.

•	LG&E's and KU's rates include certain mechanisms for fuel and fuel-related expenses. In addition, LG&E's rates include a mechanism for natural gas supply expenses. These mechanisms generally provide for timely recovery of market price fluctuations associated with these expenses.

•	WPD is exposed to volumetric risk which, is significantly mitigated as a result of the method of regulation in the U.K. Under the RIIO-ED1 price control period, recovery of such exposure occurs on a two year lag. See Note 1 for additional information on revenue recognition under RIIO-ED1.

•	PPL Electric, LG&E and KU are exposed to volumetric risk on retail sales, mainly due to weather and other economic conditions for which there is limited mitigation between rate cases.

•	PPL and its subsidiaries are exposed to equity securities price risk associated with defined benefit plans. This risk is significantly mitigated at the regulated domestic utilities and for certain plans at WPD due to the recovery mechanisms in place.

•	PPL is exposed to equity securities price risk from future stock sales and/or purchases.

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(a)	Current portion is included in "Price risk management assets" and "Other current liabilities" and noncurrent portion is included in "Price risk management assets" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets.

(b)	Excludes accrued interest, if applicable.

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(a)	Represents the location on the Balance Sheets.

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(a)	Includes the effect of net receivables and payables already recorded on the Balance Sheet.

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(a)	There were no accumulated impairment losses related to goodwill.

(a)

Gross carrying amount includes the fair value at the acquisition date of the OVEC power purchase contract and coal contracts with terms favorable to market recognized as a result of the 2010 acquisition of LKE by PPL. Offsetting regulatory liabilities were recorded related to these contracts, which are being amortized over the same period as the intangible assets, eliminating any income statement impact. This is referred to as "regulatory offset" in the tables below. See Note 6 for additional information.

(b)	Emission allowances/RECs are expensed when consumed or sold; therefore, there is no accumulated amortization.

(c)	The increase during 2016 was primarily from increases at WPD.

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(a)	Gross carrying amount represents the fair value at the acquisition date of coal contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these contracts, which was amortized over the same period as the intangible assets, eliminating any income statement impact. See Note 6 for additional information.

(b)	Emission allowances are expensed when consumed or sold; therefore, there is no accumulated amortization.

(c)	Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 6 for additional information.

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(a)	Gross carrying amount represents the fair value at the acquisition date of coal contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these contracts, which was amortized over the same period as the intangible assets, eliminating any income statement impact. See Note 6 for additional information.

(b)	Emission allowances are expensed when consumed or sold; therefore, there is no accumulated amortization.

(c)	Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 6 for additional information.

(a)	Gross carrying amount represents the fair value at the acquisition date of coal contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these contracts, which was amortized over the same period as the intangible assets, eliminating any income statement impact. See Note 6 for additional information.

(b)	Emission allowances are expensed when consumed or sold; therefore, there is no accumulated amortization.

(c)	Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 6 for additional information.

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(a)	1,560,000 shares authorized; 679,731 shares issued and outstanding at December 31, 2016; 780,000 shares authorized; 673,857 shares issued and outstanding at December 31, 2015.

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(a)	Quarterly results can vary depending on, among other things, weather. Accordingly, comparisons among quarters of a year may not be indicative of overall trends and changes in operations.

(b)	The second quarter of 2015 includes a loss of $879 million from the spinoff of PPL Energy Supply. See Note 8 to the Financial Statements for additional information.

(c)	The sum of the quarterly amounts may not equal annual earnings per share due to changes in the number of common shares outstanding during the year or rounding.

(d)	PPL has paid quarterly cash dividends on its common stock in every year since 1946. Future dividends, declared at the discretion of the Board of Directors, will be dependent upon future earnings, cash flows, financial requirements and other factors.

(e)	In the second quarter of 2015, PPL completed the spinoff of PPL Energy Supply substantially representing PPL's Supply segment. Accordingly, the previously reported operating results for PPL's Supply segment have been reclassified as discontinued operations. See Note 8 to the Financial Statements for additional information.

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(a)	PPL Electric's business is seasonal in nature, with peak sales periods generally occurring in the winter and summer months. Accordingly, comparisons among quarters of a year may not be indicative of overall trends and changes in operations.

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(a)	Evaluation of disclosure controls and procedures.

(b)	Changes in internal control over financial reporting.

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(a)	Designated an executive officer of PPL by virtue of their respective positions at a PPL subsidiary.

(b)	Effective January 3, 2017, Paul W. Thompson was elected President and Chief Operating Officer of LKE and was deemed to be an Executive Officer of PPL as of that date. Mr. Staffieri's title changed on that date to Chairman of the Board and Chief Executive Officer of LKE.

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(1)

Includes (a) the ICP, under which stock options, restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based awards were awarded to executive officers of PPL and no awards remain for issuance under this plan; (b) the ICPKE, under which stock options, restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based awards may be awarded to non-executive key employees of PPL and its subsidiaries; (c) the PPL 2012 SIP approved by shareowners in 2012 under which stock options, restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based awards may be awarded to executive officers of PPL and its subsidiaries; and (d) the DDCP, under which stock units may be awarded to directors of PPL. See Note 10 to the Financial Statements for additional information.

(2)	All of PPL's current compensation plans under which equity securities of PPL are authorized for issuance have been approved by PPL's shareowners.

(3)

Relates to common stock issuable upon the exercise of stock options awarded under the ICP, SIP and ICPKE as of December 31, 2016. In addition, as of December 31, 2016, the following other securities had been awarded and are outstanding under the ICP, SIP, ICPKE and DDCP:  15,000 shares of restricted stock under the ICP; 644,169 restricted stock units and 740,817 performance units under the SIP; 1,540,193 restricted stock units and 559,915 performance units under the ICPKE; and 385,167 stock units under the DDCP.

(4)

Based upon the following aggregate award limitations under the ICP, SIP, ICPKE and DDCP: (a) under the ICP, 15,769,431 awards (i.e., 5% of the total PPL common stock outstanding as of April 23, 1999) granted after April 23, 1999; (b) under the SIP, 10,000,000 awards; (c) under the ICPKE, 16,573,608 awards (i.e., 5% of the total PPL common stock outstanding as of January 1, 2003) granted after April 25, 2003, reduced by outstanding awards for which common stock was not yet issued as of such date of 2,373,812 resulting in a limit of 14,199,796; and (d) under the DDCP, the number of stock units available for issuance was reduced to 2,000,000 stock units in March 2012. In addition, each of the ICP and ICPKE includes an annual award limitation of 2% of total PPL common stock outstanding as of January 1 of each year.

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(a)	Includes estimated fees for audit of annual financial statements and review of financial statements included in PPL Electric's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

(b)	Includes fees for agreed upon procedures related to Annual EPA filings.

(a)	Includes estimated fees for audit of annual financial statements and review of financial statements included in LKE's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

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(a)	Includes estimated fees for audit of annual financial statements and review of financial statements included in LG&E's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

(a)	Includes estimated fees for audit of annual financial statements and review of financial statements included in KU's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

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1.	Financial Statements - Refer to the "Table of Contents" for an index of the financial statements included in this report.

2.	Supplementary Data and Supplemental Financial Statement Schedule - included in response to Item 8.

3.	Exhibits

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