On September 26, 2018 the PUCO issued the DRO establishing new base distribution rates for DP&L, which became effective October 1, 2018. The DRO approved, without modification, a stipulation and recommendation previously filed by DP&L, along with various intervening parties and the PUCO staff. The DRO established a revenue requirement for DP&L's electric service base distribution rates of $248.0 million, reflecting an increase to distribution revenues of approximately $29.8 million per year. The DRO, in conjunction with the 2017 ESP, provided for the following items (among other matters):

On November 21, 2019, the PUCO issued a supplemental order modifying the 2017 ESP Stipulation by, among other matters, removing the DMR, which reduced DPL’s annual revenues by $105.0 million beginning November 29, 2019. As a result, DP&L filed a Notice of Withdrawal of its 2017 ESP Application and requested to revert to rates based on its ESP 1. On December 18, 2019, the PUCO approved DP&L’s Notice of Withdrawal and reversion to its ESP 1 rate plan. Among other items, the PUCO Order approving the ESP 1 rate plan includes:

DP&L is also subject to a retrospective SEET threshold whereby it must demonstrate its return on equity is below 12%, excluding DMR revenues. The ultimate outcome of this and the ESP v. MRO and prospective SEET could have a material adverse effect on our results of operations, financial condition and cash flows.

Separate from the ESP process, DP&L filed a petition seeking recovery of ongoing OVEC costs through a Legacy Generation Rider and was granted approval effective January 1, 2020. Additionally, in the first quarter of 2020, DP&L filed a separate petition seeking authority to record a regulatory asset to accrue revenues that would have otherwise been collected under the 2017 ESP through the Decoupling Rider. The outcome of this petition is pending.

Certain parties which intervened in the ESP proceedings have filed petitions for rehearing of the recent PUCO ESP orders; some of which seek to eliminate DP&L’s RSC from the ESP 1 rates that are currently in place and others seek to re-implement the 2017 ESP, but without the DMR. We are unable to predict the outcomes of these petitions, but if these result in terms that are more adverse than DP&L's current ESP rate plan, it could have a material adverse effect on our results of operations, financial condition and cash flows.

On January 10, 2018 the PUCO initiated a proceeding to consider the impacts of the TCJA to determine the appropriate course of action to pass benefits resulting from the legislation on to ratepayers. The PUCO also directed Ohio utilities to record deferred liabilities for the estimated reduction in federal income tax resulting from the TCJA beginning January 1, 2018. Under the terms of the stipulation in the distribution rate case mentioned above, DP&L filed an application at the PUCO to refund eligible excess accumulated deferred income taxes (ADIT) and any related regulatory liability over a 10-year period with a minimum reversal of $4.0 million per year over the first five years. Excess ADIT related to depreciation life and method differences will be returned to customers in accordance with federal tax law and related regulations. DP&L’s rates were set using the new tax rate as a result of the distribution rate case. Consistent with the DRO requirement, DP&L filed an application on March 1, 2019 and subsequently entered into a stipulation to resolve all remaining TCJA items related to its distribution rates. That stipulation was approved by the PUCO on September 26, 2019. In accordance with terms of that stipulation, DP&L will return a total of $65.1 million ($83.2 million when including taxes associated with the refunds). In connection with this stipulation, we reduced our long-term regulatory liability related to deferred income taxes by $23.4 million. See Note 8 – Income Taxes for additional information.

On May 8, 2018, DP&L filed to adjust its FERC jurisdictional transmission rates to reflect the effects of the decrease in federal income tax rates on the current portion of income tax expense as part of the TCJA, resulting in a decrease of approximately $2.4 million annually. The revised rates are in effect and all DP&L over and undercollections dating back to the March 21st effective date were settled in December 2018.

On November 15, 2018 FERC issued a Notice of Proposed Rulemaking to address amortization of excess accumulated deferred income taxes resulting from the TCJA and their impact on transmission rates. Such notice requires all public utility transmission providers with stated transmission rates under an Open Access Transmission Tariff (OATT) to determine the amount of excess deferred income taxes caused by the TCJA. DP&L is unable to predict the outcome of this notice or the impact it may have on our Consolidated Financial Statements.

On May 31, 2018, the FERC issued an Order on Contested Settlement regarding the cost allocation method for existing and new transmission facilities contained in the PJM Interconnection’s OATT. The FERC order approved the settlement which reduces DP&L’s transmission costs through PJM beginning in August 2018, including credits to reimburse DP&L for amounts overcharged in prior years. DP&L estimates the prior overcharge by PJM to be $41.1 million, of which approximately $30.4 million has been repaid to DP&L through December 31, 2019 and $1.8 million is classified as current in "Accounts receivable, net" and $8.9 million is classified as non-current in "Other non-current assets" on the accompanying Consolidated Balance Sheet. All of the transmission charges and credits impacted by this FERC order are items that are included for full recovery in DP&L’s non-bypassable TCRR. Accordingly, DP&L has also established offsetting regulatory liabilities. While this development will have a temporary cash flow benefit to DP&L, there is no impact to operating income or net income as all credits will be passed to DP&L’s customers through the TCRR, which began in November 2018.

In accordance with FASC 980, we have recognized total regulatory assets of $193.5 million and $193.7 million at December 31, 2019 and 2018, respectively, and total regulatory liabilities of $271.5 million and $313.2 million at December 31, 2019 and 2018, respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities.



	Type of Recovery	Amortization Through	December 31,
$ in millions	Type of Recovery	Amortization Through	2019		2018
Regulatory assets, current:
Undercollections to be collected through rate riders	A/B	2020	$	19.1	$	40.5
Rate case expenses being recovered in base rates	B	2020	0.6		0.6
Total regulatory assets, current			19.7		41.1

Regulatory assets, non-current:
Pension benefits	B	Ongoing	83.9		87.5
Unrecovered OVEC charges	C	Undetermined	29.1		28.7
Fuel costs	B		—		3.3
Regulatory compliance costs	B	Undetermined	6.3		6.1
Smart grid and AMI costs	B	Undetermined	8.5		8.5
Unamortized loss on reacquired debt	B	Various	10.0		6.0
Deferred storm costs	A	Undetermined	5.1		4.7
Deferred vegetation management and other	A/B	Undetermined	12.7		7.8
Decoupling deferral	C	Undetermined	13.8		—
Uncollectible deferral	C	Undetermined	4.4		—
Total regulatory assets, non-current			173.8		152.6

Total regulatory assets			$	193.5	$	193.7

Regulatory liabilities, current:
Overcollection of costs to be refunded through rate riders	A/B	2020	$	27.9	$	34.9
Total regulatory liabilities, current			27.9		34.9

Regulatory liabilities, non-current:
Estimated costs of removal - regulated property		Not Applicable	143.6		139.1
Deferred income taxes payable through rates		Various	73.6		116.3
TCJA regulatory liability	B	Ongoing	12.9		—
PJM transmission enhancement settlement	A	2025	8.9		16.9
Postretirement benefits	B	Ongoing	4.6		6.0
Total regulatory liabilities, non-current			243.6		278.3

Total regulatory liabilities			$	271.5	$	313.2

Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate order; recovery for the remaining costs is probable, but not certain. DP&L is earning a net return on $5.5 million of this net deferral. These items include undercollection of: (i) Energy Efficiency Rider, (ii) Alternative Energy Rider, (iii) unrecovered OVEC costs and (iv) Economic Development Rider. It also includes the current portion of deferred fuel costs and deferred storm costs, which are described in greater detail below. As current liabilities, this includes overcollection of competitive bidding energy and auction costs and certain transmission related costs including the current portion of the PJM transmission enhancement settlement (see above).

Pension benefits represent the qualifying FASC 715 “Compensation - Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI. As per PUCO and FERC precedents, these costs are probable of future rate recovery.

Unrecovered OVEC charges includes the portion of charges from OVEC that were not recoverable through DP&L’s Fuel Rider from October 2014 through October 2017. Additionally, it includes net OVEC costs from December 19, 2019 through December 31, 2019. DP&L expects to recover these costs through a future rate proceeding. Beginning on November 1, 2017, through December 18, 2019, current OVEC costs were being recovered through DP&L’s reconciliation rider which was authorized as part of the 2017 ESP. Beginning January 1, 2020, DP&L began recovering its current net OVEC costs through its Legacy Generation Rider, established pursuant to ORC 4928.148.

Fuel costs represent unrecovered fuel costs related to DP&L’s Fuel Rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L was granted recovery of these costs without a return through the SSO as approved in the 2017 ESP; this authorization continued in the approval of ESP 1. These costs are being recovered over the three-year period that began November 1, 2017.

Regulatory compliance costs represent the long-term portion of the regulatory compliance costs which include the following costs: (i) Consumer Education Campaign, (ii) Retail Settlement System, (iii) Generation Separation, (iv) Bill Format Redesign, (v) Green Pricing Tariff and (vi) Supplier Consolidated Billing. All of these costs except for Generation Separation earn a return. These costs were being recovered over a three-year period that began November 1, 2017 through a rider approved in the 2017 ESP. That rider was eliminated with the approval of the ESP 1 rate plan, so the balance as of December 18, 2019 remains a regulatory asset for future recovery.

Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of AMI. In a PUCO order on January 5, 2011, the PUCO indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. DP&L requested recovery of these costs as part of the December 2018 Distribution Modernization Plan filing with the PUCO described in Item 1 Business - COMPETITION AND REGULATION.

Deferred storm costs represent the long-term portion of deferred costs for major storms which occurred during 2017, 2018 and 2019. The 2017 ESP granted DP&L approval to establish a rider by which to seek recovery of these types of costs with a return. This authorization continued in the approval of ESP 1. DP&L plans to file petitions seeking recovery of each calendar year of storm costs in the following calendar year. Recovery of these costs is probable, but not certain.

Vegetation management costs represents costs incurred from outside contractors for tree trimming and other vegetation management services. Calculation terms were agreed to in the stipulation approved in the DRO. The terms were an annual baseline of $10.7 million in 2018 and $15.7 million thereafter. Amounts over the baseline will be deferred subject to an annual deferral maximum of $4.6 million. Annual spending less than the vegetation management baseline amount will result in a reduction to the regulatory asset or creation of a regulatory liability. A future filing will be made to determine how this cost will be collected from or returned to customers.

Decoupling deferral represents the change in the revenue requirement based on a per customer methodology in the stipulation approved in the DRO and includes deferrals through December 18, 2019. These costs were previously recovered through a Decoupling Rider; however, DP&L withdrew its application in the 2017 ESP and in doing so, the PUCO ordered on December 18, 2019 in the ESP 1 order, that DP&L no longer has a Decoupling Rider. As described above, DP&L recently filed a petition seeking authority to record a regulatory asset to accrue revenues that would have otherwise been collected through the Decoupling Rider.

Uncollectible deferral represents deferred uncollectible expense associated with the nonpayment of electric service, less the revenues associated with the bypassable uncollectible portion of the standard offer rate. The DRO established that these costs would be recovered in a rider outside of base rates, thus no uncollectible expense is included in base rates. A future filing will be made to determine how these expenses will be collected from customers.

Deferred income taxes payable through rates represent deferred income tax liabilities recognized from the normalization of flow-through items as the result of taxes previously charged to customers. A deferred income tax asset or liability is created from a difference in income recognition between tax laws and accounting methods. As a

TCJA regulatory liability represents the long-term portion of both protected and unprotected excess ADIT for both transmission and distribution portions, grossed up to reflect the revenue requirement. As a part of the DRO, DP&L agreed that savings from the TCJA attributable to distribution facilities, including the excess ADIT and the regulatory liability, constitute amounts that will be returned to customers. As a result of the TCJA and subsequent DRO, DP&L entered into a stipulation to resolve all remaining TCJA items related to its distribution rates, including a proposal to return no less than $4.0 million per year for the first five years unless fully returned in the first five years via a tax savings cost rider for the distribution portion of the balance. On September 26, 2019, an order approved the stipulation in its entirety.

Transmission rates are regulated by FERC and DP&L has reduced its stated transmission rate to reflect the effects of the lower current tax rate. With respect to the transmission portion of amortization of excess ADIT, on November 15, 2018, FERC issued a Notice of Proposed Rulemaking entitled, “Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes.” Among other things, this notice proposes “to require all public utilities with transmission stated rates to determine the amount of excess and deferred income tax caused by the Tax Cuts and Jobs Act’s reduction to the federal corporate income tax rate and return or recover this amount to or from customers.” DP&L is a public utility with transmission stated rates and will make a filing in conformance to the requirements once the proposed rule is finalized.

Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.