Overview and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Overview and Summary of Significant Accounting Policies

Note 1– Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. See Note 17 for more information relating to these reportable segments. The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.

On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. See Note 2. Following the merger of DPL and Dolphin Subsidiary II, Inc., DPL became an indirectly wholly-owned subsidiary of AES.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail service are still regulated. DP&L has exclusive right to provide such service to its more than 515,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at seven coal-fired power stations. Beginning in 2014, DP&L no longer provides 100% of the generation for its SSO customers. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.

DP&L filed a generation separation application at the end of December 2013, as required in its ESP order, with the PUCO and on February 25, 2013, filed a supplemental application. In the supplemental application, DP&L reaffirmed its commitment to separate the generation assets on or before May 31, 2017. DP&L continues to look at multiple options to effectuate the separation including transfer into a new unregulated affiliate of DPL or through a sale.

DPLER sells competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER’s operations include those of its wholly-owned subsidiary, MC Squared, which was acquired on February 28, 2011. DPLER has approximately 308,000 customers currently located throughout Ohio and Illinois. Approximately 130,000 of DPLER’s customers are also electric distribution customers of DP&L. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the area.

DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, our captive insurance company that provides insurance services to us and our other subsidiaries. All of DPL’s subsidiaries are wholly-owned.

DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries employed 1,266 people as of December 31, 2013, of which 1,218 employees were employed by DP&L. Approximately 59% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2014.

Financial Statement Presentation

We prepare Consolidated Financial Statements for DPL. DPL’s Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP. DP&L’s undivided ownership interests in certain coal-fired generating stations are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations. See Note 5 for more information.

Certain immaterial amounts from prior periods, including derivative assets and liabilities and restricted cash, have been reclassified to conform to the current period presentation.

All material intercompany accounts and transactions are eliminated in consolidation.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; goodwill; and intangibles.

On November 28, 2011, AES completed the Merger with DPL. As a result of the Merger, DPL is an indirect wholly-owned subsidiary of AES. DPL’s basis of accounting incorporates the application of FASC 805, “Business Combinations” (FASC 805) as of the Merger date. FASC 805 required the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the Merger date. DPL’s Consolidated Financial Statements and accompanying footnotes have been segregated to present pre-merger activity as the “Predecessor” Company and post-merger activity as the “Successor” Company. Purchase accounting impacts, including goodwill recognition, have been “pushed down” to DPL, resulting in the assets and liabilities of DPL being recorded at their respective fair values as of November 28, 2011. See Note 2 for additional information. AES finalized its purchase price allocation during the third quarter of 2012.

As a result of the push down accounting, DPL’s Consolidated Statements of Operations subsequent to the Merger include amortization expense relating to purchase accounting adjustments and depreciation of fixed assets based upon their fair value. Therefore, the DPL financial data prior to the Merger will not generally be comparable to its financial data subsequent to the Merger. See Note 2 for additional information.

DPL remeasured the carrying amount of all of its assets and liabilities to fair value, which resulted in the recognition of approximately $2,576.3 million of goodwill, after adjustments. FASC 350, “Intangibles – Goodwill and Other”, requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions; operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. In the fourth quarter of 2013, we recorded an impairment of $306.3 against the goodwill at DPL’s DP&L reporting unit. In the third quarter of 2012, we recorded an estimated impairment charge of $1,850.0 million against the goodwill at DPL’s DP&L reporting unit. This was adjusted to $1,817.2 million in the fourth quarter of 2012. See Note 18 for information regarding the impairments of goodwill in 2013 and 2012.

As part of the purchase accounting, values were assigned to various intangible assets, including customer relationships, customer contracts and the value of our electric security plan. See Note 6 for more information.

Revenue Recognition

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of results of operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.

All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. These power sales and purchases are reported on a net hourly basis as revenues or purchased power on our Statements of Results of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.

Allowance for Uncollectible Accounts

We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues.

Sale of Receivables

In the first quarter of 2012, DPLER began selling receivables from DPLER customers in Duke Energy’s territory to Duke Energy. These sales are at face value for cash at the billed amounts for DPLER customers’ use of energy. There is no recourse or any other continuing involvement associated with the sold receivables. Total receivables sold to Duke Energy during the years ended December 31, 2013 and 2012 was $20.7 million and $15.7 million, respectively. In addition, MC Squared sells receivables from their customers in ComEd territory to ComEd. Total receivables sold to ComEd during the years ended December 31, 2013 and 2012 was $75.4 million and $27.7 million, respectively.

Property, Plant and Equipment

We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $1.5 million, $4.0 million, $0.5 million and $3.9 million in the years ended December 31, 2013, and 2012, the period from November 28, 2011 through December 31, 2011, and the period January 1, 2011 through November 27, 2011, respectively.

For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest.

For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization.

Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.

Repairs and Maintenance

Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.

Depreciation – Changes in Estimates

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates.

During the fourth quarter of 2013, the Company tested the recoverability of long-lived assets at certain generating stations. See Note 19 for more information. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator. The effect of this impairment will be to reduce future depreciation related to these stations by approximately $1.6 million per year.

For DPL’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 5.8% in 2013, 4.8% in 2012 and 5.8% in 2011.

The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2013 and 2012:



	December 31,
$ in millions	2013		Composite Rate		2012		Composite Rate

Regulated:
Transmission	$	213.1		4.1%	$	208.9		4.4%
Distribution		970.1		5.6%		935.0		5.4%
General		56.8		12.1%		50.6		10.8%
Non-depreciable		60.8		N/A		60.0		N/A

Total regulated		1,300.8				1,254.5

Unregulated:
Production / Generation		1,340.8		6.2%		1,299.7		4.4%
Other		15.7		8.9%		16.6		11.6%
Non-depreciable		19.7		N/A		19.6		N/A

Total unregulated		1,376.2				1,335.9

Total property, plant and equipment in service	$	2,677.0		5.8%	$	2,590.4		4.8%

AROs

We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations associated with the retirement of our long-lived assets consists primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within Other deferred credits on the consolidated balance sheets.

Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.

Changes in the Liability for Generation AROs



$ in millions
Balance at December 31, 2011	$	23.6

Calendar 2012
Accretion expense		0.8
Settlements		(0.4)
Estimated cash flow revisions		(0.1)
Balance at December 31, 2012		23.9

Calendar 2013
Accretion expense		0.8
Settlements		(0.3)
Balance at December 31, 2013	$	24.4

Asset Removal Costs

We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $114.9 million and $112.1 million in estimated costs of removal at December 31, 2013 and 2012, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 4 for additional information.

Changes in the Liability for Transmission and Distribution Asset Removal Costs



$ in millions
Balance at December 31, 2011	$	112.4

Calendar 2012
Additions		10.1
Settlements		(10.4)
Balance at December 31, 2012		112.1

Calendar 2013
Additions		22.0
Settlements		(19.2)
Balance at December 31, 2013	$	114.9

Regulatory Accounting

As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator, such as with our CCEM energy efficiency program. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DPL expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 4 for more information about Regulatory Assets and Liabilities.

Inventories

Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.

Intangibles

Intangibles include emission allowances, renewable energy credits, customer relationships, customer contracts and the value of our ESP. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. In addition, we recorded emission allowances at their fair value as of the Merger date. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized.

Customer relationships recognized as part of the purchase accounting are amortized over nine to fifteen years and customer contracts are amortized over the average length of the contracts. The ESP was amortized over one year on a straight-line basis. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are amortized as they are used or retired. See Note 6 for additional information.

Income Taxes

GAAP requires an asset and liability approach for financial accounting and reporting of income taxes with tax effects of differences, based on currently enacted income tax rates, between the financial reporting and tax basis of accounting reported as Deferred tax assets or liabilities in the balance sheets. Deferred tax assets are recognized for deductible temporary differences. Valuation allowances are provided against deferred tax assets unless it is more likely than not that the asset will be realized.

Investment tax credits, which have been used to reduce federal income taxes payable, are deferred for financial reporting purposes and are amortized over the useful lives of the property to which they relate. For rate-regulated operations, additional deferred income taxes and offsetting regulatory assets or liabilities are recorded to recognize that income taxes will be recoverable or refundable through future revenues.

DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. Prior to the Merger, DPL and its subsidiaries filed a consolidated U.S. federal income tax return. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 8 for additional information.

Financial Instruments

We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other than temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost basis for public equity security and fixed maturity investments is average cost and amortized cost, respectively.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Results of Operations. These and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues. The amounts for the years ended December 31, 2013, and 2012, the period November 28, 2011 through December 31, 2011, and the period January 1, 2011 through November 27, 2011, were $50.5 million, $50.5 million, $4.3 million and $49.4 million, respectively.

Share-Based Compensation

We measure the cost of employee services received and paid with equity instruments based on the fair value of such equity instrument on the grant date. This cost is recognized in results of operations over the period that employees are required to provide service. Liability awards are initially recorded based on the fair value of equity instruments and are to be re-measured for the change in stock price at each subsequent reporting date until the liability is ultimately settled. The fair value for employee share options and other similar instruments at the grant date are estimated using option-pricing models and any excess tax benefits are recognized as an addition to paid-in capital. The reduction in income taxes payable from the excess tax benefits is presented in the Statements of Cash Flows within Cash flows from financing activities. See Note 12 for additional information. As a result of the Merger, discussed in Note 2, vesting of all share-based awards was accelerated as of the Merger date, and none are in existence at December 31, 2013 or 2012.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions include restrictions imposed by agreements related to deposits held as collateral.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective and MTM accounting when the hedge or a portion of the hedge is not effective. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 11 for additional information.

Insurance and Claims Costs

In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage to us, our subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, property damage, and directors’ and officers’ liability. DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, DP&L has estimated liabilities for medical, life, and disability reserves for claims costs below certain coverage thresholds of third-party providers. We record these additional insurance and claims costs of approximately $18.8 million and $17.7 million at 2013 and 2012, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined based using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.

Related Party Transactions

Effective December 22, 2013, AES US Services, LLC (the “Service Company”) began providing services including accounting, legal, human resources, information technology and other services of a similar nature on behalf of the AES U.S. Strategic Business Unit (“U.S. SBU”). The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable distribution. This includes ensuring that the regulatory utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

DPL Capital Trust II

DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.4 million and $0.5 million at December 31, 2013 and 2012, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $19.6 million at December 31, 2013 and 2012 , respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 7 for additional information.

In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.

Recently Adopted Accounting Standards

Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11) effective for interim and annual reporting periods beginning on or after January 1, 2013. We adopted ASU 2011-11 on January 1, 2013. This standard was clarified by ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”, which also was effective on January 1, 2013. This standard updates FASC Topic 210 “Balance Sheet.” ASU 2011-11 updates the disclosures for financial instruments and derivatives to provide more transparent information around the offsetting of assets and liabilities. Entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and/or subject to an agreement similar to a master netting agreement. In ASU 2013-01, the FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement. We adopted this rule, which resulted in enhanced disclosures, but it did not have an effect on our overall results of operations, financial position or cash flows.

Testing Indefinite-Lived Intangible Assets for Impairments

In July 2012, the FASB issued ASU 2012-02 “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02) effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012. We adopted ASU 2012-02 on January 1, 2013. This standard updates FASC Topic 350 “Intangibles-Goodwill and Other.” ASU 2012-02 permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with FASC Subtopic 350-30. We adopted this rule but it did not have an effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. ASU 2013-02 does not change the current requirements for reporting net income or OCI in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the Notes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. We adopted this rule, which resulted in enhanced disclosures, but it did not have an effect on our overall results of operations, financial position or cash flows.

DP&L [Member]

Overview and Summary of Significant Accounting Policies

Note 1 – Overview and Summary of Significant Accounting Policies

Description of Business

On November 28, 2011, DP&L’s parent company DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. See Note 2 for more information. Following the Merger of DPL and Dolphin Subsidiary II, Inc., DPL became an indirectly wholly-owned subsidiary of AES.

DP&L employed 1,218 people as of December 31, 2013. Approximately 62% of all employees are under a collective bargaining agreement which expires on October 31, 2014.

Financial Statement Presentation

DP&L does not have any subsidiaries. DP&L has undivided ownership interests in seven electric generating facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in DP&L’s Financial Statements.

Certain immaterial amounts from prior periods, including derivative assets and liabilities and restricted cash, have been reclassified to conform to the current period presentation.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; Regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.

Revenue Recognition

All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. These power sales and purchases are reported on a net hourly basis as revenues or purchased power on our statements of results of operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.

Allowance for Uncollectible Accounts

We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues.

Property, Plant and Equipment

We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. Property, plant and equipment are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $1.5 million, $4.0 million, and $4.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization.

Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.

At December 31, 2013, DP&L did not have any material plant acquisition adjustments or other plant-related adjustments.

Repairs and Maintenance

Costs associated with maintenance activities, primarily station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.

Depreciation – Changes in Estimates

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DP&L’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates.

During the fourth quarter of 2013, the Company tested the recoverability of long-lived assets at certain generating stations. See Note 15 for more information. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator. The effect of this impairment will be to reduce future depreciation related to these stations by approximately $3.8 million per year.

In the third quarter of 2012, a series of events led DP&L management to conclude that there was an impairment in the value of certain generating stations. See Note 15 for more information. The effect of this impairment will be to reduce future depreciation related to these stations by approximately $7.1 million per year. The effect in the years ended December 31, 2013 and 2012 was a reduction of approximately $5.4 million and $1.8 million, respectively.

For DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 4.4% in 2013, 4.2% in 2012 and 2.6% in 2011.

The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2013 and December 31, 2012:



	December 31,
$ in millions	2013		Composite Rate		2012		Composite Rate

Regulated:
Transmission	$	388.3		2.3%	$	380.9		2.4%
Distribution		1,528.2		3.5%		1,480.7		3.4%
General		111.1		6.2%		100.0		5.4%
Non-depreciable		60.8		N/A		60.1		N/A

Total regulated		2,088.4				2,021.7

Unregulated:
Production / Generation		3,002.1		5.2%		3,210.8		4.9%
Non-depreciable		14.8		N/A		16.5		N/A

Total unregulated		3,016.9				3,227.3

Total property, plant and equipment in service	$	5,105.3		4.4%	$	5,249.0		4.2%

AROs

We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations associated with the retirement of our long-lived assets consisted primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within other deferred credits on the balance sheets.

Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.

Changes in the Liability for Generation AROs



$ in millions

Balance at December 31, 2011	$	18.8

Calendar 2012
Accretion expense		0.9
Settlements		(0.4)
Estimated cash flow revisions		(0.1)
Balance at December 31, 2012		19.2

Calendar 2013
Accretion expense		1.0
Settlements		(0.3)
Balance at December 31, 2013	$	19.9

Asset Removal Costs

We continue to record cost of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $114.9 million and $112.1 million in estimated costs of removal at December 31, 2013 and 2012, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 4 for additional information.

Changes in the Liability for Transmission and Distribution Asset Removal Costs



$ in millions
Balance at December 31, 2011	$	112.4

Calendar 2012
Additions		10.1
Settlements		(10.4)
Balance at December 31, 2012		112.1

Calendar 2013
Additions		22.0
Settlements		(19.2)
Balance at December 31, 2013	$	114.9

Regulatory Accounting

Inventories

Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.

Intangibles

Intangibles consist of emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Beginning in January 2010, part of the gains on emission allowances were used to reduce the overall fuel rider charged to our SSO retail customers. Emission allowances are amortized as they are used in our operations. Renewable energy credits are amortized as they are used or retired.

Prior to the Merger date, emission allowances and renewable energy credits were carried as inventory. Emission allowances and renewable energy credits are now carried as intangibles in accordance with AES’ policy.

Income Taxes

GAAP requires an asset and liability approach for financial accounting and reporting of income taxes with tax effects of differences, based on currently enacted income tax rates, between the financial reporting and tax basis of accounting reported as deferred tax assets or liabilities in the balance sheets. Deferred tax assets are recognized for deductible temporary differences. Valuation allowances are provided against deferred tax assets unless it is more likely than not that the asset will be realized.

Financial Instruments

We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: available-for-sale and held-to-maturity. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost basis for public equity security and fixed maturity investments is average cost and amortized cost, respectively.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Results of Operations in accordance with AES policy. The amounts for the years ended December 31, 2013, 2012 and 2011 were $50.5 million, $50.5 million and $53.7 million, respectively.

Share-Based Compensation

We measure the cost of employee services received and paid with equity instruments based on the fair value of such equity instrument on the grant date. This cost is recognized in results of operations over the period that employees are required to provide service. Liability awards are initially recorded based on the fair value of equity instruments and are to be re-measured for the change in stock price at each subsequent reporting date until the liability is ultimately settled. The fair value for employee share options and other similar instruments at the grant date are estimated using option-pricing models and any excess tax benefits are recognized as an addition to paid-in capital. The reduction in income taxes payable from the excess tax benefits is presented in the statements of cash flows within Cash flows from financing activities. See Note 11 for additional information. As a result of the Merger, discussed in Note 2, vesting of all share-based awards was accelerated as of the Merger date, and none are in existence at December 31, 2013 or 2012.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions include restrictions imposed by agreements related to deposits held as collateral.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless they are designated as a cash flow hedge of a forecasted transaction or qualify for the normal purchases and sales exception.

Insurance and Claims Costs

In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage to DP&L and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, property damage, and directors’ and officers’ liability. Furthermore, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, DP&L has estimated liabilities for medical, life, and disability reserves for claims costs below certain coverage thresholds of third-party providers. We record these additional insurance and claims costs of approximately $18.8 million and $17.7 million at December 31, 2013 and 2012, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for MVIC at DPL and the estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined based on certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.

Related Party Transactions

In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial Statements.

The following table provides a summary of these transactions:



	Years ended December 31,
$ in millions	2013		2012		2011

DP&L revenues:
Sales to DPLER (a)	$	345.8	$	350.8	$	327.0
Sales to MC Squared (a)	$	108.1	$	40.0	$	-

DP&L Operation & Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(2.9)	$	(2.6)	$	(3.1)
Expense recoveries for services provided to DPLER (c)	$	5.2	$	4.0	$	4.6

DP&L Customer security deposits:
Deposits received from DPLER (d)	$	19.2	$	20.2	$	-

(a)DP&L sells power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to DPLER during the year ended December 31, 2012, compared to the year ended December 31, 2011 is primarily due to customers electing to switch their generation service from DP&L to DPLER. DP&L started selling physical power to MC Squared during June 2012 and became their sole source of power in September 2012.

(b)MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC.

(c)In the normal course of business DP&L incurs and records expenses on behalf of DPLER. Such expenses include but are not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charges these expenses to DPLER at DP&L’s cost and credits the expense in which they were initially recorded.

(d)DP&L requires credit assurance from the CRES providers serving customers in its service territory because DP&L is the default energy provider should the CRES provider fail to fulfill its obligations to provide electricity. Due to DPL’s credit downgrade, DP&L required cash collateral from DPLER.

Recently Adopted Accounting Standards

Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11) effective for interim and annual reporting periods beginning on or after January 1, 2013. We adopted this ASU on January 1, 2013. This standard was clarified by ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”, which also was effective on January 1, 2013. This standard updates FASC Topic 210 “Balance Sheet.” ASU 2011-11 updates the disclosures for financial instruments and derivatives to provide more transparent information around the offsetting of assets and liabilities. Entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and/or subject to an agreement similar to a master netting agreement. In ASU 2013-01, the FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement. We adopted this rule, which resulted in enhanced disclosures, but it did not have an effect on our overall results of operations, financial position or cash flows.

Testing Indefinite-Lived Intangible Assets for Impairments

In July 2012, the FASB issued ASU 2012-02 “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02) effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012. We adopted this ASU on January 1, 2013. This standard updates FASC Topic 350 “Intangibles-Goodwill and Other.” ASU 2012-02 permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with FASC Subtopic 350-30. We adopted this rule but it did not have an effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or OCI in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the Notes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. We adopted this rule, which resulted in enhanced disclosures, but it did not have an effect on our overall results of operations, financial position or cash flows.

- Definition

The entire disclosure for all significant accounting policies of the reporting entity.

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