THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED BALANCE ~~SHEETS~~SHEET

	At			At			At			At
	September 30,			December 31,			June 30,			December 31,
$ in millions	2006			2005			2007			2006

ASSETS

Current assets:
Cash and cash equivalents	$	57.7		$	46.2		$	4.4		$	46.1
Restricted funds held in trust	75.5			—			—			10.1
Accounts receivable, less provision for uncollectible accounts of $1.7 and $1.0, respectively	204.0			182.7
Net intercompany receivable from parent	2.4			—
Accounts receivable, less provision for uncollectible accounts of $1.6 and $1.4, respectively							245.0			205.6
Inventories, at average cost	85.2			77.7			95.4			83.0
Taxes applicable to subsequent years	11.5			45.9			23.6			48.0
Other current assets	36.1			19.3			14.2			38.2
Total current assets	472.4			371.8			382.6			431.0

Property, plant and equipment:
Property:
Property, plant and equipment	4,363.1			4,118.0			4,616.1			4,450.6
Less: Accumulated depreciation and amortization	(2,050.2		)	(1,973.3		)	(2,112.9		)	(2,079.0		)
Net property	2,312.9			2,144.7			2,503.2			2,371.6

Other noncurrent assets:
Regulatory assets	78.8			83.8			140.4			148.6
Other deferred assets	136.5			138.3
Other assets							107.9			139.1
Total other noncurrent assets	215.3			222.1			248.3			287.7

Total Assets	$	3,000.6		$	2,738.6		$	3,134.1		$	3,090.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED BALANCE ~~SHEETS~~SHEET

September 30,

December 31,

June 30,

December 31,

$ in millions

2006

2005

2007

2006

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:

Current portion - long-term debt

0.8

0.9

Accounts payable

137.8

116.2

205.7

166.2

Accrued taxes

126.1

167.7

103.1

159.6

Accrued interest

15.2

9.8

13.0

12.6

Short-term debt

105.0

—

Other current liabilities

32.1

28.4

29.3

35.4

Total current liabilities

311.2

322.1

456.9

374.7

Noncurrent liabilities:

Long-term debt

785.3

685.9

784.9

785.2

Deferred taxes

314.7

323.2

372.6

360.2

Unamortized investment tax credit

44.3

46.4

42.2

43.6

Other deferred credits

268.9

258.7

222.0

272.5

Total noncurrent liabilities

1,413.2

1,314.2

1,421.7

1,461.5

Cumulative preferred stock not subject to mandatory redemption

22.9

22.9

22.9

22.9

Commitments and contingencies (Note 7)

Commitments and contingencies (Note 9)

—

Common shareholders’ equity:

Common stock, at par value of $0.01 per share

0.4

0.4

Common stock, at par value of $0.01 per share:

0.4

0.4

Other paid-in capital

781.6

783.4

783.2

783.7

Accumulated other comprehensive income

13.5

15.1

Retained earnings

464.7

290.5

435.5

432.0

Accumulated other comprehensive income

6.6

5.1

Total common shareholders’ equity

1,253.3

1,079.4

1,232.6

1,231.2

Total Liabilities and Shareholders’ Equity

3,000.6

2,738.6

3,134.1

3,090.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Notes to Condensed Consolidated Financial Statements

1.Basis of Presentation

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s principal subsidiary is The Dayton Power and Light Company (DP~~&L, the Company, we, our, or ours unless the context indicates otherwise) is a wholly-owned subsidiary of DPL Inc. (DPL)~~&L). ~~We are~~DP&L is a public utility incorporated in 1911 under the laws of ~~Ohio and we conduct our principal business in one business segment – Electric Utility. We sell~~Ohio. DP&L sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for ~~our 24-county~~DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. WeDP&L also ~~purchase~~purchases retail peak load requirements from DPL Energy LLC ~~(DPLE), a~~(DPLE, one of our wholly-owned ~~subsidiary of DPL Inc.~~subsidiaries). Principal industries served include automotive, food processing, paper, plastic manufacturing, and defense. ~~Our~~DP&L’s sales reflect the general economic conditions and seasonal weather patterns of the area. ~~We sell~~DP&L sells any excess energy and capacity into the wholesale market.

DPL’s other significant subsidiaries (all of which are wholly-owned) include DPLE, which engages in the operation of peaking generating facilities; DPL Energy Resources, Inc. (DPLER), which sells retail electric energy under contract to major industrial and commercial customers in West Central Ohio; MVE, Inc., which was primarily responsible for the management of our financial asset portfolio; and Miami Valley Insurance Company (MVIC), our captive insurance company that provides insurance sources to us and our subsidiaries. DP&L has one significant subsidiary, DPL Finance Company, Inc., which is wholly-owned and provides financing to DPL, DP&L and other affiliated companies.

DPL and DP&L conduct their principal business in one business segment - Electric.

Financial Statement Presentation

We prepare ~~our~~ consolidated financial statements in accordance with ~~accounting principles generally accepted~~Generally Accepted Accounting Principles (GAAP) in the United States of ~~America (GAAP).~~America. The condensed consolidated financial statements include the accounts of DPL and DP&L and ~~our~~their majority-owned subsidiaries. Investments that are not majority owned are accounted for using the equity method when our investment allows us the ability to exert significant influence, as defined by GAAP. Undivided interests in jointly-owned generation facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions are eliminated in consolidation. Interim results for the ~~three~~quarter and ~~nine~~six months ended ~~September~~June 30, ~~2006~~2007 may not be indicative of our results that will be realized for the full year ending December 31, ~~2006.~~2007.

Pursuant to the Securities and Exchange Commission (SEC) rules, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from interim reports. Therefore, these financial statements should be read along with the annual financial statements included in our Annual Report on Form 10-K for the year ended December 31, ~~2005 and our quarterly reports on Form 10-Q ended March 31, 2006 and June 30,~~ 2006. In the opinion of our management, the condensed consolidated financial statements contain all adjustments (which are all of a normal recurring nature) necessary to fairly state our financial condition as of ~~September~~June 30, ~~2006,~~2007, our results of operations for the ~~three~~quarter and ~~nine~~six months ended ~~September~~June 30, ~~2006,~~2007, and our cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2006~~2007 in accordance with GAAP.

Estimates, Judgments and Reclassifications

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 at the date of the financial statements and the revenue and expenses of the period reported. Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these ~~policies and~~ estimates may result in materially different amounts being reported under different conditions or circumstances. 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 costs; valuation allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; ~~regulatory proceedings and orders;~~ and assets and liabilities related to employee benefits. Actual results may differ from those estimates. Certain amounts from prior periods have been reclassified to conform to the current reporting presentation.

Depreciation Expense

Depreciation expense is calculated using the straight-line method, which depreciates the cost of property over its estimated useful life. For DPL’s and DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates. With the addition of scrubbers at certain of its generation facilities, DP&L has undertaken an evaluation of its depreciation rates which it expects to be completed during the third quarter of 2007. Management expects depreciation rates to decrease due to the extension of depreciation lives for certain of its assets. The Public Utility Commission of Ohio would need to approve a change in depreciation rates for our regulated assets.

Recently Adopted Accounting Standards

~~Recently Issued~~ Accounting ~~Standards~~for Uncertainty in Income Taxes

~~Stock-Based Compensation~~

~~In December 2004, the~~On January 1, 2007, we adopted Financial Accounting Standards Board (FASB) ~~issued Statement of Financial Accounting Standard~~Interpretation No. ~~123 (revised 2004), “Share-Based Payment” (SFAS 123R). SFAS 123R replaces SFAS 123,~~48, “Accounting for ~~Stock-Based Compensation,” and supersedes Accounting Principles Board (APB) Opinion No. 25 (Opinion 25), “Accounting for Stock Issued~~Uncertainty in Income Taxes” (FIN 48). There was no significant impact to Employees.” SFAS 123R requires a public entity to measure the cost of employee services received and paid with equity instruments to be based on the fair-value of such equity on the grant date. This cost is recognized inour overall results of operations, ~~over the period in which employees are required to provide service. Liabilities initially incurred are based on the fair-value~~cash flows or financial position. The total amount of equity instruments and are to be re-measured 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 excessunrecognized tax benefits ~~are recognized~~ as of the date of adoption was $36.8 million and we have recorded $3.5 million (net of tax) of accrued interest. During the second quarter ending June 30, 2007, we recorded an ~~addition to paid-in capital. Cash retained from~~additional $0.9 million in accrued interest resulting in a total reserve for uncertain tax positions of $41.2 million as of June 30, 2007. None of the ~~excess~~amount of unrecognized tax benefits is ~~presented~~due to uncertainty in the ~~statement~~timing of ~~cash flows as financing cash inflows. The provisions of this Statement became effective as of January 1, 2006. Our September 30,~~deductibility.

We recognize interest and penalties related to unrecognized tax benefits in income taxes.

Taxes for calendar years 2004 – 2006 ~~year-to-date pre-tax results of operations were increased~~remain open to examination by ~~approximately $0.6 million as a result of~~ the ~~adoption of SFAS 123R,~~jurisdictions in which we ~~apply~~are subject to ~~stock-based transactions related to DPL Inc. common stock. See Note 5 of Notes to Consolidated Financial Statements.~~taxation.

~~How~~Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities ~~Should be Presented in the Income Statement~~

In ~~June 2006, the FASB ratified the consensuses of~~January 2007, we adopted Emerging Issues Task Force ~~(EITF) Issue~~ No. ~~06-3,~~6-03 “How Taxes Collected from Customers and Remitted to Governmental Authorities Should beBe Presented in the Income ~~Statement (That Is, Gross versus Net Presentation)”~~Statement” (EITF ~~06-3)~~No. 6-03). EITF 06-3 indicates that the income statement presentation on either a gross basis or a net basis of the taxes within the scope of the issue is an accounting policy decision. The consensus in this issue should be applied to interim and annual reporting periods beginning after December 15, 2006. We are in the process of evaluating EITF 06-3 and have not determined the impact to our overall results of operations, financial position or cash flows.

~~Accounting for Uncertainty in Income Taxes~~

~~In July 2006, the FASB issued Interpretation~~ No. ~~48, “Accounting for Uncertainty in Income Taxes” (FIN 48), effective for fiscal years beginning after December 15, 2006. FIN 48~~6-03 requires a ~~two-step approach~~registrant to ~~determine~~disclose how ~~to recognize tax benefits~~taxes collected from customers are presented in the financial statements, ~~where recognition~~i.e. gross or net. 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 gross basis and ~~measurement~~recorded as revenues in the accompanying Condensed Consolidated Statements of ~~a tax benefit must be evaluated separately. A tax benefit will be recognized only if it meets a “more-likely-than-not” recognition threshold. For tax positions that meet this threshold,~~Operations for the tax benefit recognized is based on the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with the taxing authority. We are currently evaluating the impact of adopting FIN 48,quarter and ~~have not yet determined the significance of this new rule to our overall results of operations, financial position or cash flows.~~six months ended June 30, 2007 and June 30, 2006 as follows:

					Six Months Ended
	Three Months Ended				June 30,
($ in millions)	2007		2006		2007		2006
	$	12.1	$	11.7	$	26.4	$	25.2

Recently Issued Accounting Standards

Accounting for Fair Value Measurements

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements,” (SFAS 157) effective for fiscal years beginning after November 15, 2007. ~~The Standard~~SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. ~~The Standard~~SFAS 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, ~~the Standard~~SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those standards. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under ~~the Standard,~~SFAS 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. ~~The Standard~~SFAS 157 does not expand the use of fair value in any new circumstances. In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115” (SFAS 159) effective for fiscal years beginning after November 15, 2007. SFAS 159 permits entities to choose to measure many financial instruments and certain warranty and insurance contracts at fair value on a contract-by-contract basis. We are currently evaluating the impact of adopting SFAS 157 and SFAS 159, and have not yet determined the significance of ~~this~~these new ~~rule~~rules to our overall results of operations, financial position or cash flows.

~~Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)~~2. Earnings per Share

~~In September~~Basic earnings per share (EPS) is based on the weighted-average number of DPL common shares outstanding during the year. Diluted earnings per share is based on the weighted-average number of DPL common and common equivalent shares outstanding during the year, except in periods where the inclusion of such common equivalent shares is anti-dilutive. Excluded from outstanding shares for this weighted-average computation are the unallocated shares held by DP&L’s Master Trust Plan for deferred compensation and unallocated shares held by DP&L’s Employee Stock Ownership Plan (ESOP).

As a result of the May 21, 2007 settlement of the litigation with three former executives (see Note 10 of Notes to Condensed Consolidated Financial Statements), the three former executives relinquished all of their rights to certain deferred compensation, restricted stock units (RSUs), MVE incentives, stock options and reimbursement of legal fees. There were approximately 1.3 million RSUs and 3.6 million stock options relinquished and cancelled that were included in the dilutive share calculation through May 20, 2007. These RSUs and stock options will no longer be included in the dilutive share calculation.

For the quarter ended June 30, 2007, there were no dilutive securities excluded from the computation of diluted earnings per share while for the quarter ended June 30, 2006, there were 0.4 million stock options excluded from the ~~FASB issued Financial Accounting Standards No. 158: “Employers’ Accounting~~calculation because they were anti-dilutive. For the six months ended June 30, 2007, there were 25 thousand restricted and performance shares excluded from the computation of diluted earnings per share. For the six months ended June 30, 2006, there were 0.4 million stock options excluded from the computation of diluted earnings per share because they were anti-dilutive.

The following illustrates the reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for ~~Defined Benefit Pension~~income after discontinued operations:

Three Months Ended June 30,

2007

2006

$ in millions except per

Net

Per

Net

Per

share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

58.7

107.9

0.54

22.6

114.1

0.20

Effect of Dilutive Securities:

Restricted Stock Units

0.7

1.3

Warrants

9.9

6.9

Stock options, performance and restricted shares

1.0

1.1

Diluted EPS

58.7

119.5

0.49

22.6

123.4

0.18

Six Months Ended June 30,

2007

2006

$ in millions except per

Net

Per

Net

Per

share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

114.8

107.7

1.07

81.5

117.1

0.70

Effect of Dilutive Securities:

Restricted Stock Units

1.0

1.3

Warrants

9.5

6.7

Stock options, performance and restricted shares

1.2

1.2

Diluted EPS

114.8

119.4

0.96

81.5

126.3

0.65

3. Discontinued Operations

	Three Months Ended					Six Months Ended
	June 30,					June 30,
$ in millions	2007			2006		2007			2006

Investment expenses	$	(0.1	)	$	—	$	(0.4	)	$	(0.5	)
Income from discontinued operations	(0.1		)	—		(0.4		)	(0.5		)

Gain realized from sale	—			—		8.2			13.2
Net gain on sale	—			—		8.2			13.2

Gain on settlement of executive litigation	8.2			—		8.2			—

Earnings before income taxes	8.1			—		16.0			12.7
Income tax expense	(3.0		)	—		(6.0		)	(5.1		)
Earnings from discontinued operations, net	$	5.1		$	—	$	10.0		$	7.6

On February 13, 2005, DPL’s subsidiaries, MVE and ~~Other Postretirement Plans,~~MVIC, entered into an ~~amendment~~agreement to sell their respective interests in forty-six private equity funds to AlpInvest/Lexington 2005, LLC, a joint venture of ~~FASB Statements No. 87, 88, 106~~AlpInvest Partners and ~~132(R)”(SFAS158). This Statement requires an employer that is a business entity~~Lexington Partners, Inc. Sales proceeds and ~~sponsors one or more single-employer defined benefit plans to: a.) recognize the funded status of a benefit plan; b.) recognize as a component of other comprehensive income, net of tax, the~~any related gains or losses ~~and prior service costs or credits that arise~~were recognized during 2005 as the ~~period but are~~sale of each of these funds closed.

During 2005, MVE entered into alternative closing arrangements with AlpInvest/Lexington 2005, LLC for the remaining funds where legal title to said funds could not ~~recognized as components of net periodic benefit cost; c.) measure defined benefit plan assets and obligations as~~be transferred until a later time. Pursuant to these arrangements, MVE transferred the economic aspects of the ~~date~~remaining private equity funds, consisting of two funds and a portion of one fund, to AlpInvest/Lexington 2005, LLC without a change in ownership of the ~~employer’s fiscal year-end statement~~interests. The alternative arrangements resulted in a 2005 deferred gain of ~~financial position; d.) disclose~~$27.1 million in 2005 and $18.9 million in 2006. The remaining portion of the gain, $8.2 million, was recognized in the ~~notes~~first quarter of 2007 as all legal and economic considerations relating to ~~financial statements additional information about certain effects on net periodic benefit cost for~~ the ~~next fiscal year that arise from delayed recognition~~alternative closing arrangements were satisfied.

As a result of the ~~gains or losses, prior service costs or credits,~~May 21, 2007 settlement of the litigation with three former executives (see Note 10 of the Notes to Condensed Consolidated Financial Statements), the three former executives relinquished all of their rights to certain deferred compensation, RSUs, MVE incentives, stock options and ~~transition asset or obligation. This Statement is effective for fiscal years ending after December 15, 2006 except for the measuring~~reimbursement of ~~plan assets at the employer’s fiscal year end which is effective for fiscal years ending after December 15, 2008.~~ ~~We are currently evaluating the impact~~legal fees. The reversal of ~~this Statement and have not yet determined the significance of this new rule to our overall results of operations, cash flows or financial position.~~

~~Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements~~

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (Topic 1N): “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB108). ~~The SEC believes that a registrant should quantify a current year misstatement using both the iron curtain approach and the rollover approach.~~ ~~If the over/understatement of current year expense is material~~accruals related to the ~~current year, after all~~performance of the ~~relevant quantitative and qualitative factors are considered,~~financial asset portfolio were recorded in discontinued operations. Additionally, a portion of the ~~prior year financial statements should be corrected. Correcting prior year financial statements for immaterial errors would not require previously filed reports~~$25 million settlement expense was allocated to ~~be amended. We are currently evaluating~~discontinued operations. These transactions resulted in a net gain of $8.2 million on the ~~impact~~settlement of ~~this Statement and have not yet determined the significance of this new rule to our overall results of operations, cash flows or financial position.~~

~~Accounting for Planned Major Maintenance Activity~~

In September 2006, the FASB posted Financial Statement of Position AUG AIR-1 – “Accounting for Planned Major Maintenance Activity” (FSP AUG AIR-1). Previous guidance for planned major maintenance, such as repairing or replacing a boiler, allowed four different methods for accruing for these major repairs. These included direct expense, built-in overhaul, deferral and accrue-in-advance. The FASB has decided that the accrue-in-advance method is no longer valid because it allows a liability to accrue for future charges that may or may not happen. We use the direct expense method for major planned maintenance which calls for expensing the charges as incurred. Since we do not use the accrue-in-advance method, this FSP will have no effect on our overall results of operation, statement of financial position or cash flows.litigation, being recorded in discontinued operations.

2.4. Supplemental Financial Information

DPL Inc.

	At			At			At			At
Balance Sheet	September 30,			December 31,
							June 30,			December 31,
$ in millions	2006			2005			2007			2006

Accounts receivable, net:
Unbilled revenue							$	68.2		$	68.7
Retail customers	$	72.6		$	60.8		65.4			65.0
Unbilled revenue	46.0			57.5
Partners in commonly-owned plants	56.6			37.7			73.8			51.5
Wholesale customers and subsidiary customers	8.6			2.8
Wholesale and subsidiary customers							15.8			15.8
PJM including financial transmission rights	13.6			11.0			23.1			13.1
Other							14.8			7.1
Refundable franchise tax	3.1			11.8			5.2			5.2
Other	5.2			2.1
Provision for uncollectible accounts	(1.7		)	(1.0		)	(1.6		)	(1.4		)
Total accounts receivable, net	$	204.0		$	182.7		$	264.7		$	225.0

Inventories, at average cost:
Fuel and emission allowances	$	55.4		$	48.6		$	63.4		$	52.4
Plant materials and supplies	29.8			29.1			33.2			32.6
Other							0.2			0.4
Total inventories, at average cost	$	85.2		$	77.7		$	96.8		$	85.4

Other current assets:
Deposits and other advances							$	0.9		$	17.8
Prepayments	$	8.0		$	7.6		6.9			13.3
Deposits and other advances	16.7			5.8
Derivatives							0.6			3.2
Current deferred income taxes	4.7			4.9			0.8			2.0
Derivatives	5.0			—
Other	1.7			1.0			3.3			1.4
Total other current assets	$	36.1		$	19.3		$	12.5		$	37.7

Property, plant and equipment:
Construction work in process	$	346.3		$	165.1		$	460.1		$	376.0
Property, plant and equipment	4,016.8			3,952.9
Property, plant and equipment (a)							4,425.1			4,626.0
Total property, plant and equipment	$	4,363.1		$	4,118.0		$	4,885.2		$	5,002.0

Other deferred assets:
Other assets:
Master Trust assets	$	106.1		$	107.7		$	8.4		$	39.4
Unamortized loss on reacquired debt	20.8			22.0			19.6			20.4
Unamoritized debt expense	8.5			7.4
Unamortized debt expense							10.1			10.6
Commercial activities tax benefit							6.8			6.8
Investments							6.9			7.0
Other	1.1			1.2			0.2			0.5
Total other deferred assets	$	136.5		$	138.3
Total other assets							$	52.0		$	84.7

Accounts payable:
Trade payables	$	57.9		$	26.1		$	78.3		$	75.7
Fuel accruals	40.0			39.5			45.4			37.3
Other	39.9			50.6			83.7			56.4
Total accounts payable	$	137.8		$	116.2		$	207.4		$	169.4

Other current liabilities:
Customer security deposits	$	19.7		$	19.2		$	18.8		$	19.4
Deferred revenue - financial transmission rights	4.3			—
Current portion of long-term debt	1.0			0.9
Pension and retiree benefits payable							0.8			5.8
Financial transmission rights - future proceeds							—			2.7
Payroll taxes payable	0.3			2.3			0.1			0.1
Unearned revenues	0.1			0.4
Other	6.7			5.6			9.6			10.3
Total other current liabilities	$	32.1		$	28.4		$	29.3		$	38.3

Other deferred credits:
Asset retirement obligations - regulated property	$	85.2		$	81.7		$	88.4		$	86.3
Master Trust obligations	73.8			74.5
Retirees’ health and life benefits	32.4			32.9
Pension liability	28.7			23.5
Trust obligations							21.0			76.2
Pension liabilities							36.4			37.7
Retiree health and life benefits							27.8			28.5
SECA net revenue subject to refund	21.5			20.5			20.6			18.7
Asset retirement obligations - generation	13.2			13.2
Litigation and claims pending	3.3			3.0
Asset retirement obligations - generation property							12.0			11.7
Deferred gain on sale of portfolio							—			8.2
Claims reserves							4.6			3.4
Environmental reserves	0.1			0.1			0.1			0.1
Other	10.7			9.3			11.1			9.9
Total other deferred credits	$	268.9		$	258.7		$	222.0		$	280.7

(a) The sale of $283.5 million of assets held for sale at December 31, 2006 was completed on April 25, 2007.

4. Supplemental Financial Information (Continued)

DP&L

		At				At
		June 30,				December 31,
$ in millions		2007				2006
Accounts receivable, net:
Retail customers	$		65.4		$		65.0
Partners in commonly-owned plants	73.8				51.5
Unbilled revenue	60.2				61.0
PJM including financial transmission rights	23.1				13.9
Wholesale and subsidiary customers	10.2				8.3
Refundable franchise tax	3.1				3.1
Other	10.8				4.2
Provision for uncollectible accounts	(1.6			)	(1.4			)
Total accounts receivable, net	$		245.0		$		205.6

Inventories, at average cost:
Fuel and emission allowances	$		63.4		$		52.4
Plant materials and supplies	31.8				30.2
Other	0.2				0.4
Total inventories, at average cost	$		95.4		$		83.0

Other current assets:
Deposits and other advances	$		0.7		$		17.0
Prepayments	8.6				15.8
Derivatives	0.6				3.2
Current deferred income taxes	0.9				0.7
Other	3.4				1.5
Total other current assets	$		14.2		$		38.2

Property, plant and equipment:
Construction work in process	$		459.2		$		375.2
Property, plant and equipment	4,156.9				4,075.4
Total property, plant and equipment	$		4,616.1		$		4,450.6

Other assets:
Master Trust assets	$		78.9		$		109.0
Unamortized loss on reacquired debt	19.6				20.4
Unamortized debt expense	8.4				8.6
Investments	0.6				0.6
Other	0.4				0.5
Total other assets	$		107.9		$		139.1

Accounts payable:
Trade payables	$		78.1		$		74.7
Fuel accruals	43.3				36.7
Other	84.3				54.8
Total accounts payable	$		205.7		$		166.2

Other current liabilities:
Customer security deposits	$		18.8		$		19.4
Financial transmission rights - future proceeds	—				2.7
Payroll taxes payable	0.1				0.2
Pension and retiree benefits payable	0.8				5.8
Other	9.6				7.3
Total other current liabilities	$		29.3		$		35.4

Other deferred credits:
Asset retirement obligations - regulated property	$		88.4		$		86.3
Trust obligations	21.0				76.2
Retiree health and life benefits	27.8				28.5
Pension liabilities	36.4				37.7
SECA net revenue subject to refund	20.6				18.7
Asset retirement obligations - generation property	12.0				11.7
Claims reserves	4.6				3.4
Environmental reserves	0.1				0.1
Other	11.1				9.9
Total other deferred credits	$		222.0		$		272.5

2.4. Supplemental Financial Information ~~(continued)~~(Continued)

DPL Inc.

	Nine months ended
	September 30,						Six Months Ended June 30,
$ in millions	2006			2005			2007			2006

Cash flows - other:
Payroll taxes payable	$	(2.0	)	$	0.1		$	—		$	(1.4	)
Employee/director stock plan							2.2			1.8
Lump sum retirement payment							(4.9		)	—
Deposits and other advances	(10.5		)	(6.7		)	17.3			0.7
Deferred storm costs	—			(5.6		)
FERC transitional payment deferral	1.0			15.4
Other	—			(2.6		)	5.7			(1.4		)
Total cash flows - other	$	(11.5	)	$	0.6		$	20.3		$	(0.3	)

	Three months ended						Nine months ended						Three Months Ended June 30,						Six Months Ended June 30,
	September 30,						September 30,
$ in millions	2006			2005			2006			2005
													2007			2006			2007			2006
Comprehensive income:
Net income	$	64.0		$	63.1		$	174.9		$	152.3		$	58.7		$	22.6		$	114.8		$	81.5
Net change in unrealized gains on financial instruments	1.2			1.1			1.8			6.6
Net change in unrealized gains (losses) on financial instruments													(1.9		)	0.4			(1.5		)	0.8
Net change in deferred gains (losses) on cash flow hedges	0.1			(2.0		)	2.9			(4.8		)	(0.8		)	2.2			(4.4		)	2.8
Minimum pension liability													0.6			—			1.1			—
Deferred income taxes related to unrealized gains and (losses)	(0.8		)	0.2			(3.2		)	(1.0		)	0.8			(1.3		)	1.9			(3.1		)
Total comprehensive income	$	64.5		$	62.4		$	176.4		$	153.1
Comprehensive income													$	57.4		$	23.9		$	111.9		$	82.0

~~3. Preferred Stock~~DP&L

	Six Months Ended June 30,
$ in millions	2007			2006

Cash flows - other:
Payroll taxes payable	$	—		$	(1.4	)
Deposits and other advances	16.7			(1.8		)
Lump sum retirement payment	(4.9		)	—
Other	6.5			2.0
Total cash flows - other	$	18.3		$	(1.2	)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Comprehensive income:
Net income	$	59.1		$	44.0		$	128.9		$	110.9
Net change in unrealized gains (losses) on financial instruments	(8.8		)	(0.2		)	(0.4		)	0.6
Net change in deferred gains (losses) on cash flow hedges	(0.8		)	2.2			(4.4		)	2.8
Minimum pension liability	0.5			—			1.1			—
Deferred income taxes related to unrealized gains and (losses)	3.5			(1.0		)	2.1			(2.4		)
Comprehensive income	$	53.5		$	45.0		$	127.3		$	111.9

5. Asset Sales

$Sale of Peaking Units

On April 25, ~~par~~2007, DPLE completed the sale of its Darby and Greenville electric peaking generation facilities providing DPL with approximately $151 million in cash. Darby Station was sold to Columbus Southern Power Company, a utility subsidiary of American Electric Power Company (AEP), for approximately $102 million in cash. Greenville Station was sold to Buckeye Power, Inc. for approximately $49 million in cash.

During the fourth quarter of 2006, DPL recorded a $71.0 million impairment charge that included the fair market value ~~4,000,000 shares authorized,~~write-down of the peaking unit assets, accrued legal fees and other costs associated with the sale. There were no ~~shares outstanding;~~material costs or adjustments to the $71.0 million impairment charge that would result in a reportable gain or loss on the sale realized in 2007.

Sale of Corporate Aircraft

On June 7, 2007, Miami Valley CTC, Inc. (indirect wholly-owned subsidiary of DPL), sold its corporate aircraft and ~~$100 par~~associated inventory and parts for $7.4 million. The net book value ~~4,000,000 shares authorized, 228,508 shares without mandatory redemption provisions outstanding.~~of the assets written down and subsequently sold were approximately $1.0 million and severance and other costs of approximately $0.4 million were accrued. Miami Valley CTC, Inc. recorded a net gain on the sale of approximately $6.0 million for the quarter and the six-month period ended June 30, 2007, which is included in DPL’s operation and maintenance expense.

Preferred
Stock

Rate

Current
Redemption
Price

Current Shares
Outstanding at
September 30,
2006

Par Value At
September 30,
2006

Par Value At
December 31,
2005

($ in millions)

($ in millions)

Series A

3.75%

$
102.50

93,280

$
9.3

$
9.3

Series B

3.75%

$
103.00

69,398

7.0

7.0

Series C

3.90%

$
101.00

65,830

6.6

6.6

Total

228,508

$
22.9

$
22.9

~~The preferred stock may be redeemed at our option at~~In relation to this sale, Miami Valley CTC, Inc., placed in escrow approximately $2.2 million. These funds are listed as the ~~per-share prices indicated, plus cumulative accrued dividends.~~

~~As long as any preferred stock is outstanding, our Amended Articles of Incorporation contain provisions restricting~~caption “Restricted funds held in trust” in the ~~payment of cash dividends~~Condensed Consolidated Balance Sheet for DPL. These funds were released from escrow on any of our common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income available for dividends on our common stock subsequent to December 31, 1946, plus $1.2 million. As of September 30, 2006, all earnings were available for common stock dividends. We expect all 2006 earnings to be available for common stock dividends, payable to DPL.July 12, 2007.

4.6. Pension and Postretirement Benefits

We sponsor a defined benefit plan for substantially all full-time employees. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees, the defined benefit plan is based primarily on compensation and years of service. We fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain active and retired key executives. Benefits under this SERP have been frozen and no additional benefits can be earned. Wealso have unfunded liabilities related to retirement benefits for certain active, terminated and retired key executives (not related to the litigation settlement with three former executives) that include The DPL Inc. Supplemental Executive Defined Contribution Retirement Plan (SEDCRP). These liabilities totaled approximately $0.8 million at June 30, 2007.

Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits. We have funded the union-eligible health benefit using a Voluntary Employee Beneficiary Association Trust.

The net periodic benefit ~~cost~~costs of the pension and postretirement benefit plans for the ~~three months~~quarter ended ~~September~~June 30, 2007 and 2006 ~~and 2005 was:~~were:

Net periodic benefit cost

	Pension						Postretirement						Pension						Postretirement
$ in millions	2006			2005			2006			2005			2007			2006			2007			2006
Service cost	$	1.0		$	0.9		$	—		$	—		$	1.1		$	1.1		$	—		$	—
Interest cost	4.3			3.9			0.5			0.5			4.1			4.1			0.3			0.4
Expected return on assets(a)	(5.5		)	(5.4		)	(0.2		)	(0.1		)	(5.4		)	(5.4		)	(0.1		)	(0.1		)

Amortization of unrecognized:
Actuarial (gain) loss	0.9			1.0			(0.2		)	(0.1		)	0.9			1.0			(0.3		)	(0.2		)
Prior service cost	0.7			0.6			—			—			0.6			0.6			—			—
Transition obligation	—			—			0.1			—			—			—			0.1			—
Net periodic benefit cost before adjustments	1.4			1.0			0.2			0.3
Settlement cost (a)	2.6			—			—			—
Curtailment cost (b)	—			0.1			—			—
Net periodic benefit cost after adjustments	$	4.0		$	1.1		$	0.2		$	0.3
Net periodic benefit cost													$	1.3		$	1.4		$	—		$	0.1

(a)The ~~settlement cost relates~~market-related value of assets is equal to ~~a former officer (not related to our ongoing litigation~~the fair value of assets at implementation with ~~three former executives) who has elected to receive a lump sum distribution in 2007 from the Supplemental Executive Retirement Plan.~~

~~(b)~~ ~~The curtailment cost relates to a freeze in benefits for the remaining active employee participating~~subsequent asset gains and losses recognized in the ~~Supplemental Executive Retirement Plan.~~market-value systematically over a three-year period.

The net periodic benefit ~~cost~~costs of the pension and postretirement benefit plans for the ~~nine~~six months ended ~~September~~June 30, 2007 and 2006 ~~and 2005 was:~~were:

Net periodic benefit cost

	Pension						Postretirement						Pension						Postretirement
$ in millions	2006			2005			2006			2005			2007			2006			2007			2006
Service cost	$	3.2		$	2.9		$	—		$	—		$	2.2		$	2.2		$	—		$	—
Interest cost	12.5			11.8			1.3			1.4			8.2			8.2			0.7			0.8
Expected return on assets(a)	(16.3		)	(16.1		)	(0.4		)	(0.4		)	(10.9		)	(10.8		)	(0.2		)	(0.2		)

Amortization of unrecognized:
Actuarial (gain) loss	2.9			2.9			(0.6		)	(0.6		)	1.8			2.0			(0.5		)	(0.4		)
Prior service cost	1.9			1.7			—			—			1.2			1.2			—			—
Transition obligation	—			—			0.2			0.1			—			—			0.1			0.1
Net periodic benefit cost before adjustments	4.2			3.2			0.5			0.5
Settlement cost (a)	2.6			—			—			—
Net periodic benefit cost before adjustment													2.5			2.8			0.1			0.3
Special termination benefit cost (b)	0.3			—			—			—			—			0.3			—			—
Curtailment cost (c)	—			0.1			—			—
Net periodic benefit cost after adjustments	$	7.1		$	3.3		$	0.5		$	0.5
Net periodic benefit cost after adjustment													$	2.5		$	3.1		$	0.1		$	0.3

(a)The ~~settlement cost relates~~market-related value of assets is equal to the fair value of assets at implementation with subsequentasset gains and losses recognized in the market-value systematically over a ~~former officer (not related to our ongoing litigation with three former executives) who has elected to receive a lump sum distribution in 2007 from the Supplemental Executive Retirement Plan.~~three-year period.

(b)In 2006, a special termination benefit cost was recognized as a result of 16 employees who participated in a voluntary early retirement program and ~~were all~~ retired asat various dates during 2006; this program was completed as of April 1, 2006.

~~(c)~~ ~~The curtailment cost relates to a freeze in benefits for the remaining active employee participating in the Supplemental Executive Retirement Plan.~~

The following estimated benefit payments, which reflect future ~~and past~~ service, are expected to be paid as follows:

Estimated Future Benefit Payments

$ in millions	Pension		Postretirement
2007	$	9.7	$	1.3
2008	$	19.8	$	2.6
2009	$	20.2	$	2.6
2010	$	20.7	$	2.5
2011	$	20.9	$	2.4
2012 – 2016	$	111.9	$	10.0

$ in millions

Pension

Postretirement

2006

$
4.9

$
0.8

2007

$
24.6

$
3.1

2008

$
19.8

$
3.0

2009

$
20.2

$
3.0

2010

$
20.7

$
2.9

2011

$
20.9

$
2.7

2012 – 2016

$
111.9

$
10.7

5.7. Share-Based Compensation ~~Stock-Based Compensation~~

~~We adopted SFAS 123R on January 1, 2006 using the modified prospective approach for stock options and restricted stock units (RSUs).~~ As a result of ~~our adoption~~the May 21, 2007 settlement of ~~SFAS 123R, we recognized $0.6~~the litigation with three former executives (see Note 10 of the Notes to the Condensed Consolidated Financial Statements), the three former executives relinquished all of their rights to certain deferred compensation, restricted stock units (RSUs), MVE incentives, stock options and reimbursement of legal fees. A portion of this settlement included the forfeitures and cancellations of RSUs and stock options of 1.3 million ~~less~~and 3.6 million, respectively.

The following table summarizes share-based compensation expense:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
$ in millions	2007			2006			2007			2006
Stock options	$	—		$	0.6		$	—		$	1.3
Restricted stock units	—			(0.2		)	0.1			1.2
Performance shares	0.4			0.8			0.8			0.8
Restricted shares	0.1			—			0.1			—
Non-employee directors’ restricted stock units	0.1			—			0.1			—
Share-based compensation included in operations and maintenance expense	0.6			1.2			1.1			3.3
Income tax expense	(0.2		)	(0.4		)	(0.4		)	(1.2		)
Total share-based compensation, net of tax	$	0.4		$	0.8		$	0.7		$	2.1

Share-based awards issued in DPL’s common stock will be distributed from treasury stock. DPL believes it has sufficient treasury stock to satisfy all outstanding share-based awards.

Determining Fair Value

Valuation and Amortization Method. We estimate the fair value of stock options and RSUs using a Black-Scholes-Merton model; performance shares are valued using a Monte Carlo simulation; restricted shares are valued at the market price on the day of grant and the Directors’ RSUs are valued at the market price on the day prior to the grant date. We amortize the fair value of all awards on a straight-line basis over the requisite service periods, which are generally the vesting periods.

Expected Volatility. The Company’s expected volatility assumptions are based on the historical volatility of DPL’s stock. The volatility range captures the high and low volatility values for each award granted based on its specific terms.

Expected Life. The expected life assumption represents the estimated period of time from grant until exercise and reflects historical employee exercise patterns.

Risk-Free Interest Rate. The risk-free interest rate for the expected term of the award is based on the corresponding yield curve in effect at the time of the valuation for U.S. Treasury bonds having the same term as the expected life of the award, i.e., a five year bond rate is used for valuing an award with a five year expected life.

Expected Dividend Yield. The expected dividend yield is based on DPL’s current dividend rate, adjusted as necessary to capture anticipated dividend changes and the 12 month average DPL Inc. stock price.

Expected Forfeitures. The forfeiture rate used to calculate compensation expense ~~for~~is based on the ~~nine months ended September 30, 2006,~~Company’s historical experience, adjusted as ~~compared~~necessary to ~~what we would have recognized under SFAS 123.~~reflect special circumstances.

Stock Options

In 2000, ~~our~~DPL’s Board of Directors adopted, and ~~DPL~~DPL’s shareholders approved, The DPL Inc. Stock Option Plan. The plan provides that “no single Participant shall receive Options with respect to more than 2,500,000 shares.” Options granted in 2000, 2001 and 2002 were fully vested as of December 31, 2005 and expire ten years from the grant date. In 2003, 100,000 options were granted which vested equitably over five years and expire ten years from the grant date. In 2004, 200,000 options were granted that vest over nineteen months and expire approximately 6.5 years from the grant date; 100,000 of these options vested in May of 2005 and the remaining 100,000 vested in May 2006. Another 20,000 options were granted in 2004 that vested in five months and expire ten years from the grant date. In December 2004, 30,000 options were granted that vest equitably over three years and expire ten years from the grant date. In 2005, 350,000 options were granted that vested in June 2006 and expire three years from the grant date. At September 30, 2006, there were 1,528,500 options available for grant. On April 26, 2006, ~~DPL~~DPL’s shareholders approved ~~the~~ The DPL Inc. 2006 Equity and Performance Incentive Plan (EPIP). With the approval of the EPIP, no ~~further~~new awards will be ~~made~~granted under ~~the~~ The DPL Inc. Stock Option ~~Plan.~~Plan, but shares relating to awards that are forfeited or terminated under The DPL Inc. Stock Option Plan may be granted under the EPIP. There are currently 10,000 unvested stock options outstanding under The DPL Inc. Stock Option Plan that will vest as of December 21, 2007.

The schedule of ~~non-vested~~ option activity for the ~~nine~~six months ended ~~September~~June 30, ~~2006~~2007 was as follows:

$ in millions

Number of Options

Weighted-Average Grant
Date Fair Value

Non-vested at January 1, 2006

510,000

$
2.2

Granted in 1st nine months 2006

—

—

Vested in 1st nine months 2006

450,000

$
2.0

Forfeited in 1st nine months 2006

40,000

$
0.1

Non-vested at September 30, 2006

20,000

$
0.1

		Weighted-Avg.
	Number of	Grant Date
$ in millions (except share amounts)	Options	Fair Value
Non-vested at January 1, 2007	10,000	$	0.05
Granted in first half 2007	—	—
Vested in first half 2007	—	—
Forfeited in first half 2007	—	—
Non-vested at June 30, 2007	10,000	$	0.05

Summarized stock option activity was as follows:

							Six Months Ended
							June 30,
	Nine months ended September 30, 2006			Twelve months ended December 31, 2005			2007			2006
Options:
Outstanding at beginning of year (a)	5,486,500			6,165,500
Outstanding at beginning of year							5,091,500			5,486,500
Granted	0			350,000			—			—
Exercised	(10,000		)	(1,025,000		)	(520,000		)	(10,000		)
Forfeited	(40,000		)	(4,000		)
Outstanding at end of period	5,436,500			5,486,500
Exercisable at end of period	5,416,000			4,100,000
Forfeited (a)							(3,620,000		)	—
Outstanding at period-end							951,500			5,476,500
Exercisable at period-end							941,500			5,416,000

Weighted average exercise prices per share:
Weighted average option prices per share:
Outstanding at beginning of year	$	21.86		$	21.39		$	21.95		$	21.86
Granted	—			$	26.82		$	—		$	—
Exercised	$	21.00		$	21.18		$	26.83		$	21.00
Forfeited	$	15.88		$	29.63		$	20.38		$	—
Outstanding at end of period	$	22.02		$	21.86
Exercisable at end of period	$	20.98		$	20.98
Outstanding at period-end							$	24.08		$	21.90
Exercisable at period-end							$	24.07		$	20.98

(a) ~~In dispute with certain~~ As a result of the settlement of the former ~~executives, among other things, are approximately 1 million forfeited options not included above and~~executive litigation on May 21, 2007, 3.6 million outstanding options ~~that are included~~shown above ~~(see Note 7 of Notes to Consolidated Financial Statements).~~

~~No stock options~~ were granted in the first three quarters of 2006. The weighted-average fair value of options granted was $3.80 per share in 2005. The fair values of the options were estimated as of the dates of grant using a Black-Scholes option pricing model.

~~In the first quarter of 2006, 10,000 stock options were exercised. No stock options were exercised~~forfeited in the second ~~or third~~ quarter of ~~2006. The market value of~~2007 and another approximately one million disputed options ~~that~~not shown above were vested at September 30, 2006 was approximately $31 million. Shares issued upon share option exercise are issued from treasury stock. We have sufficient treasury stock to satisfy outstanding options.also forfeited.

The following table reflects information about stock options outstanding at ~~September~~June 30, ~~2006:~~2007:

Options Outstanding

Options Exercisable

Range of Exercise
Prices

Outstanding

Weighted-
Average
Contractual
Life

Weighted-
Average
Exercise
Price

Exercisable

Weighted-
Average
Exercise
Price

$14.95-$21.00

4,650,000

3.7 years

$
20.43

4,650,000

$
20.47

$21.01-$29.63

786,500

3.0 years

$
28.01

766,000

$
28.08

		Options Outstanding			Options Exercisable
Range of Exercise Prices	Outstanding	Weighted- Average Contractual Life	Weighted- Average Exercise Price		Exercisable	Weighted- Average Exercise Price

$14.95 - $21.00	625,000	3.3 years	$	20.60	625,000	$	20.60
$21.01 - $29.63	326,500	4.0 years	$	28.83	316,500	$	28.93

The following table reflects information about stock option activity during the period:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
$ in millions	2007			2006		2007		2006
Weighted average grant date fair value of options granted during the period	$	—		$	—	$	—	$	—
Intrinsic value of options exercised during the period	$	1.6		$	—	$	2.3	$	0.1
Proceeds from stock options exercised during the period	$	10.6		$	—	$	14.5	$	0.2
Tax benefit from proceeds of stock options exercised	$	(0.9	)	$	—	$	0.5	$	—
Fair value of shares that vested during the period	$	—		$	1.0	$	—	$	1.0
Unrecognized compensation expense	$	—		$	0.2	$	—	$	0.2
Weighted average period to recognize compensation expense (in years)	0.5			1.0		0.5		1.0

AsThe following table shows the assumptions used in the Black-Scholes-Merton model to calculate the fair value of ~~September 30, 2006, there was $0.1 million of total unrecognized compensation cost related to~~the non-vested stock options at the time of grant:

Number of Non-vested Shares		10,000
Date of Grant		December 29, 2004
Expected Volatility		26.1%
Weighted-average expected volatility		26.1%
Expected life (in years)		9.9
Expected dividends		4.7%
Weighted-average expected dividends		4.7%
Risk-free interest rate		4.3%

No options were granted ~~under the Plan. We expect to recognize $0.1 million of this cost in~~during 2006 and 2007.

~~In addition,~~ Restricted Stock Units (RSUs)

RSUs were granted to certain key employees prior to 2001. As a result of the settlement of the former executive litigation, all disputed RSUs were forfeited by the three former executives. There were ~~1.3 million~~49,998 RSUs outstanding as of ~~September~~June 30, ~~2006,~~2007, of which ~~1.3 million were~~all have not vested. Substantially all of the vested RSUs are in dispute as part of our ongoing litigation with Peter H. Forster, formerly DPL’s Chairman; Caroline E. Muhlenkamp, formerly DPL’s Group Vice President and interim Chief Financial Officer; and Stephen F. Koziar, formerly DPL’s Chief Executive Officer and President. The ~~remaining 0.1 million~~ non-vested RSUs will be paid in cash upon vesting and will vest as follows: 20,097 in the second half of 2007; 14,688 in 2008; 10,205 in 2009; and 5,008 in 2010.

~~Vested RSUs are marked to market each quarter and any adjustment to compensation expense is recognized at that time.~~ Non-vested RSUs are valued quarterly at fair value using the ~~Black-Scholes~~Black-Scholes-Merton model to determine the amount of compensation expense to be recognized. Non-vested RSUs do not earn dividends.

		Weighted-Avg.
	Number of	Grant Date
$ in millions (except share amounts)	RSUs	Fair Value
Non-vested at January 1, 2007	49,998	$	1.2
Granted in first half 2007	—	—
Vested in first half 2007	—	—
Forfeited in first half 2007	—	—
Non-vested at June 30, 2007	49,998	$	1.2

Summarized RSU activity was as follows:

	Six Months Ended
	June 30,
	2007		2006
RSUs:
Outstanding at beginning of year	1,345,995		1,340,912
Granted	—		—
Exercised	—		—
Forfeited	(1,295,997	)	—
Outstanding at period-end	49,998		1,340,912
Exercisable at period-end	—		—

Compensation expense is recognized each quarter based on the change in the market price of DPL common shares.

As of June 30, 2007 and 2006, liabilities recorded for outstanding RSUs were $1.4 million and $35.7 million, respectively, which are included in “Other deferred credits” on the Condensed Consolidated Balance Sheets. The decrease in the liability is due to the executive litigation settlement and the forfeiture of 1.3 million RSUs (see Note 10 to Condensed Consolidated Financial Statements).

The following table shows the assumptions ~~were~~ used in the ~~Black-Scholes~~Black-Scholes-Merton model to calculate the fair value of the non-vested ~~stock options and RSUs:~~RSUs during the respective periods:

Volatility
10.3
–
29.1
%
Expected life (years)
0.8
–
8.0

Dividend yield rate
3.7
–
4.8
%
Risk-free interest rate
3.7
–
4.9
%

	Three Months Ending		Six Months Ending
	June 30,		June 30,
	2007	2006	2007	2006

Expected Volatility	15.7-43.5%	7.3-25.4%	10.6-43.5%	7.3-28.6%
Weighted-average expected volatility	19.5%	19.0%	16.6%	23.5%
Expected life (in years)	0.1-3.1	0.1-4.1	0.1-3.3	0.1-4.3
Expected dividends	3.5%	3.8%	3.5%	3.8%
Weighted-average expected dividends	3.5%	3.8%	3.5%	3.8%
Risk-free interest rate	4.4-5.0%	4.7-5.2%	4.4-5.0%	4.7-5.2%

Performance Shares

~~At the 2006 Annual Shareholder’s Meeting, DPL shareholders approved the DPL Inc. 2006 Equity and Performance Incentive Plan (EPIP).~~ Under the EPIP, the Board adopted a Long-Term Incentive Plan (LTIP) under which weDPL will award a targeted number of performance shares of ~~DPL Inc.~~ common stock to executives. Awards under the LTIP will be awarded based on a Total Shareholder Return Relative to Peers performance. No performance shares will be earned in a performance period if the three-year Total Shareholder Return Relative to Peers is below the threshold of the 40th percentile. Further, the LTIP awards will be capped at 200% of the target number of performance shares, if the Total Shareholder Return Relative to Peers is at or above the threshold of the 90th percentile. The Total Shareholder Return Relative to Peers is considered a ~~performance~~market condition under FAS 123R. ~~The~~There is a three year requisite ~~performance~~service period for each tranche of the Performance ~~Shares is:~~Shares.

~~Tranche 1~~		~~January 1, 2004 to December 31, 2006~~
~~Tranche 2~~		~~January 1, 2005 to December 31, 2007~~
~~Tranche 3~~		~~January 1, 2006 to December 31, 2008~~

The schedule of non-vested performance share activity for the ~~nine~~six months ended ~~September~~June 30, ~~2006~~2007 follows:

$ in millions

Number of
Performance Shares

Weighted-Average Grant
Date Fair Value

Non-vested at January 1, 2006

—

—

Granted in 1st nine months 2006

223,289

$ 5.9

Vested in 1st nine months 2006

—

—

Forfeited in 1st nine months 2006

(89,655
)

(2.4)

Non-vested at September 30, 2006

133,634

$ 3.5

	Number of		Weighted-Avg.
	Performance		Grant Date
$ in millions (except share amounts)	Shares		Fair Value
Non-vested at January 1, 2007	110,723		$	2.7
Granted in first half 2007	74,714		2.5
Vested in first half 2007	—		—
Forfeited in first half 2007	(14,172	)	(0.5		)
Non-vested at June 30, 2007	171,265		$	4.7

	Six Months Ended
	June 30,
	2007		2006
Performance Shares:
Outstanding at beginning of year	154,768		—
Granted	74,714		223,289
Exercised	(22,462	)	—
Expired	(21,583	)	—
Forfeited	(14,172	)	—
Outstanding at period-end	171,265		223,289
Exercisable at period-end	—		—

~~Summarized~~24

The following table reflects information about performance ~~shares~~share activity ~~was as follows:~~

	~~Nine months~~		~~Twelve months~~
	~~ended~~		~~ended~~
	~~September 30, 2006~~		~~December 31, 2005~~
~~Performance Shares:~~
~~Outstanding at beginning of year~~	—		—
~~Granted~~	~~223,289~~		—
~~Exercised~~	—		—
~~Forfeited~~	~~(89,655~~	)	—
~~Outstanding at end of period~~	~~133,634~~		—
~~Exercisable at end of period~~	—		—

~~There are no exercise prices associated with performance shares.~~

~~As of September 30, 2006, there was $1.6 million of total unrecognized compensation cost related to non-vested performance shares granted under~~during the ~~LTIP. We expect to recognize $0.5 million of this cost over the remainder of 2006 and $1.1 million in 2007 and 2008. A forfeiture rate of 20% was estimated in calculating the compensation expense.~~period:

~~Shares issued upon achievement of the required performance condition will be issued from treasury stock. We have sufficient treasury stock to satisfy outstanding performance shares.~~

	Three Months Ended June 30,				Six Months Ended June 30,
$ in millions	2007		2006		2007		2006
Weighted average grant date fair value of performance shares granted during the period	$	0.1	$	—	$	2.5	$	5.9
Intrinsic value of performance shares exercised during the period	$	—	$	—	$	1.3	$	—
Proceeds from performance shares exercised during the period	$	—	$	—	$	—	$	—
Tax benefit from proceeds of performance shares exercised	$	—	$	—	$	—	$	—
Fair value of performance shares that vested during the period	$	—	$	—	$	—	$	—
Unrecognized compensation expense	$	2.7	$	2.0	$	2.7	$	3.9
Weighted average period to recognize compensation expense (in years)	1.5		1.1		1.5		1.1

The following table shows the assumptions ~~were~~ used in athe Monte Carlo ~~simulation calculated by an actuarial consultant~~Simulation to ~~estimate~~calculate the fair value of the performance ~~shares:~~shares granted during the period:

~~Volatility~~	~~20.3~~	%
~~Expected life (years)~~	~~3.0~~
~~Dividend yield rate~~	~~3.7~~	%
~~Risk-free interest rate~~	~~4.7~~	%

	Three Months Ending June 30,		Six Months Ending June 30,
	2007	2006	2007	2006

Expected Volatility	16.1%	20.3%	16.1-17.3%	20.3%
Weighted-average expected volatility	16.1%	20.3%	16.5%	20.3%
Expected life (in years)	3.0	3.0	3.0	3.0
Expected dividends	3.3%	3.7%	3.3-3.5%	3.7%
Weighted-average expected dividends	3.3%	3.7%	3.3%	3.7%
Risk-free interest rate	4.7-4.9%	4.7%	4.5-4.9%	4.7%

~~For~~Restricted Shares

Under the ~~quarter ended September 30, 2006, total compensation expense was $0.8 million with an associated tax benefit of $0.3 million. Compensation expense for~~EPIP, the nine months ended September 30, 2006 was $4.1 million for all share-based compensation (stock options, RSUs, and performance shares) and the tax benefit associated with these expenses was $1.5 million.

For the nine months ended September 30, 2006, operating income was $0.6 million higher under SFAS 123R than under SFAS 123, while the impact to net income was $0.4 million due to a decrease in the tax benefit of $0.2 million. There was no impact on basic or diluted earnings per share.

~~On October 2, 2006, Paul M. Barbas (President and Chief Executive Officer) was~~Board granted ~~19,000~~ shares of DPL ~~Inc.~~ Restricted ~~Stock (Restricted Shares), granted under the 2006 Equity and Performance Incentive Plan. These shares were not included in the above calculations as the shares were issued subsequent~~Shares to ~~September 30, 2006.~~various executives. The Restricted Shares are to be registered in ~~Mr. Barbas’~~the executive’s name, receive dividends as declared and paid on all DPL common stock and will vest after a specified service period.

During the second quarter of 2007, 11,400 restricted shares were awarded.

$ in millions (except share amounts)	Number of Restricted Shares	Weighted-Avg. Grant Date Fair Value
Non-vested at January 1, 2007	19,000	$	0.5
Granted in first half 2007	16,400	0.5
Vested in first half 2007	—	—
Forfeited in first half 2007	—	—
Non-vested at June 30, 2007	35,400	$	1.0

	Six Months Ended June 30,
	2007	2006
Restricted Shares:
Outstanding at beginning of year	19,000	—
Granted	16,400	—
Exercised	—	—
Forfeited	—	—
Outstanding at period-end	35,400	—
Exercisable at period-end	—	—

The following table reflects information about restricted share activity during the period:

Three Months Ended
June 30,

Six Months Ended
June 30,

$ in millions

2007

2006

2007

2006

Weighted average grant date fair value of restricted shares granted during the period

0.4

—

0.5

—

Intrinsic value of restricted shares exercised during the period

—

Proceeds from restricted shares exercised during the period

—

Tax benefit from proceeds of restricted shares exercised

—

Fair value of restricted shares that vested during the period

—

Unrecognized compensation expense

0.9

—

0.9

—

Weighted average period to recognize compensation
expense (in years)

2.7

—

2.7

—

Non-Employee Director Restricted Stock Units

Under the EPIP, as part of their annual compensation for service to DPL and DP&L, each non-employee Director received a $54,000 retainer in ~~two tranches. A total~~restricted stock units (RSUs) on the date of ~~9,000 Restricted Shares shall~~the annual meeting. The RSUs will become ~~nonforfeitable~~non-forfeitable on ~~December 31, 2009~~April 15 of the following year but, if ~~Mr. Barbas remains~~the Director resigns, dies or retires prior to the April 15 vesting date, the vested shares will be distributed on a pro rata basis. The RSUs accrue quarterly dividends in the ~~continuous employ~~form of additional RSUs. Upon vesting, the RSUs will become exercisable and will be distributed in DPL common shares, unless the Director chooses to defer receipt of the ~~Company~~shares until ~~such~~a later date. The ~~remaining 10,000 Restricted Shares will become nonforfeitable~~RSUs are valued at the closing stock price on ~~December 31, 2011 if Mr. Barbas remains a Company employee.~~the day prior to the grant and the compensation expense is recognized evenly over the vesting period.

$ in millions (except for share amounts)	Number of Director RSUs		Weighted-Avg. Grant Date Fair Value
Non-vested at January 1, 2007	—		$	—
Granted in first half 2007	13,552		0.4
Dividends accrued in the first half 2007	99		—
Vested in first half 2007	(3,204	)	(0.1		)
Forfeited in first half 2007	(1,553	)	—
Non-vested at June 30, 2007	8,894		$	0.3

	Six Months Ended June 30,
	2007		2006
Restricted Stock Units:
Outstanding at beginning of year	—		—
Granted	13,552		—
Dividends accrued	99		—
Exercised	(142	)	—
Forfeited	(1,553	)	—
Outstanding at period-end	11,956		—
Exercisable at period-end	—		—

The following table reflects information about non-employee Director RSU activity during the period:

Three Months Ended
June 30,

Six Months Ended
June 30,

$ in millions

2007

2006

2007

2006

Weighted average grant date fair value of Director RSUs granted during the period

0.4

—

0.4

—

Intrinsic value of Director RSUs exercised during the period

—

Proceeds from Director RSUs exercised during the period

—

Tax benefit from proceeds of Director RSUs exercised

—

Fair value of Director RSUs that vested during the period

0.1

—

0.1

—

Unrecognized compensation expense

0.3

—

0.3

—

Weighted average period to recognize compensation expense (in years)

0.8

—

0.8

—

8. Long-Term Debt and Notes Payable

~~6. Long-term Debt~~DPL Inc.

At

At

September 30,

December 31,

$ in millions

2006

2005

First Mortgage Bonds maturing 2013 - 5.125%

$
470.0

$
470.0

Pollution Control Series maturing through 2036 - 4.79% and 4.78% (a)

314.4

214.4

$
784.4

$
684.4

Obligation for capital leases

2.2

3.0

Unamortized debt discount

(1.3
)
(1.5
)
Total

$
785.3

$
685.9

$ in millions		At June 30, 2007			At December 31, 2006
DP&L -	First mortgage bonds maturing 2013 - 5.125%	$	470.0		$	470.0
DP&L -	Pollution control series maturing 2036 - 4.80%	100.0			100.0
DP&L -	Pollution control series maturing 2034 - 4.80%	137.8			137.8
DP&L -	Pollution control series maturing 2034 - 4.80%	41.3			41.3
DP&L -	Pollution control series maturing 2028 - 4.70%	35.3			35.3
		784.4			784.4

DPL Inc. -	Note to Capital Trust II 8.125% due 2031	195.0			195.0
DPL Inc. -	Senior Notes 6.875% Series due 2011	297.4			297.4
DPL Inc. -	Senior Notes 6.25% Series due 2008	—			100.0
DPL Inc. -	Senior Notes 8.00% Series due 2009	175.0			175.0
DP&L -	Obligations for capital leases	1.7			2.0
Unamortized debt discount (a)		(1.8		)	(2.0		)
Total		$	1,451.7		$	1,551.8

(a) ~~Weighted average interest rates~~DP&L’s unamortized debt discount was $(1.2) million and $(1.2) million for June 30, 2007 and December 31, 2006, ~~and 2005,~~ respectively.

DP&L

$ in millions	At June 30, 2007			At December 31, 2006
DP&L First mortgage bonds maturing 2013 - 5.125%	$	470.0		$	470.0
DP&L Pollution control series maturing 2036 - 4.80%	100.0			100.0
DP&L - Pollution control series maturing 2034 - 4.80%	137.8			137.8
DP&L - Pollution control series maturing 2034 - 4.80%	41.3			41.3
DP&L - Pollution control series maturing 2028 - 4.70%	35.3			35.3
	784.4			784.4

Obligations for capital leases	1.7			2.0
Unamortized debt discount	(1.2		)	(1.2		)
Total	$	784.9		$	785.2

~~The amounts~~

At June 30, 2007, DPL’s scheduled maturities of ~~maturities and mandatory redemptions for first mortgage bonds and~~long-term debt, including capital ~~leases~~lease obligations, over the next five years are ~~$0.2~~$0.4 million for the remainder of ~~2006, $0.9~~2007, $100.7 million in 2008, $175.8 million in 2009, $0.6 million in 2010 and $297.4 million in 2011.

At June 30, 2007, DP&L’s scheduled maturities of long-term debt, including capital lease obligations, over the next five years are $0.4 million for the remainder of 2007, $0.7 million in 2008, ~~$0.7~~$0.8 million in 2009, ~~and $0.7~~$0.6 million in ~~2010.~~2010 and none in 2011. Substantially all property of ~~our property~~DP&L is subject to the mortgage lien securing the first mortgage bonds.

During the first quarter of 2006, the Ohio Department of Development (ODOD) awarded DP&L the ability to issue over the next three years up to $200 million of qualified tax-exempt financing from the ODOD’s 2005

volume cap carryforward. The financing is to be used to partially fund the ongoing flue gas desulfurization (FGD) capital projects. On September 13, 2006, the Ohio Air Quality Development Authority (OAQDA) issued $100 million of 4.80% fixed interest rate OAQDA Revenue Bonds 2006 Series A due September 1, 2036. In turn, DP&L borrowed these funds from the OAQDA. These funds were placed in escrow with a trustee and, as of April 3, 2007, DP&L has drawn out the entirety of the funds. DP&L is considering issuing in conjunction with the OAQDA another series of tax-exempt bonds to finance the remaining qualifying solid waste disposal facility costs at Miami Fort, Killen and ~~the pollution control series.~~Stuart Generating Stations.

~~We have~~On November 21, 2006, DP&L entered into a ~~$100~~new $220 million unsecured revolving credit agreement replacing its $100 million facility. This new agreement has a five-year term that ~~is renewable annually~~expires November 21, 2011 and ~~expires on May 30, 2010. This~~provides DP&L with the ability to increase the size of the facility ~~may be increased up to $150 million.~~by an additional $50 million at any time. The facility contains one financial covenant: ~~our~~DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This covenant is currently met. WeAs of June 30, 2007, DP&L had no borrowings outstanding ~~borrowings~~ under this ~~credit facility at September 30, 2006.~~facility. Fees associated with this credit facility are approximately $0.2 million per year. Changes in credit ratings, however, may affect fees and the applicable interest ~~rate for our~~rate. This revolving credit ~~agreement.~~

~~On February 17, 2006, we renewed our $10~~agreement also contains a $50 million ~~Master Letter~~letter of ~~Credit Agreement for one year with a financial lending institution. This agreement supports performance assurance needs in the ordinary course of business. We have~~credit sublimit. DP&L has certain contractual agreements for the sale and purchase of power, fuel and related energy services that contain credit rating related clauses allowing the counter parties to seek additional surety under certain conditions. As of ~~September~~June 30, ~~2006, we~~2007, DP&L had ~~two~~no outstanding letters of credit ~~for a total of $2.2 million.~~against the facility.

During the ~~first~~second quarter of ~~2006, the Ohio Department of Development (ODOD) awarded us the ability~~2007, DPL entered into a short-term loan to ~~issue over the next three years up to $200 million of qualified tax-exempt financing from the ODOD's 2005 volume cap carryforward. The financing is to be used to partially fund the ongoing~~ ~~flue gas desulfurization (FGD) projects. The PUCO approved our application~~DP&L for ~~this additional financing on July 26, 2006.~~

On September 13, 2006, the Ohio Air Quality Development Authority (OAQDA) issued $100 million of 4.80% fixed interest rate OAQDA Revenue Bonds 2006 Series A due September 1, 2036. In turn, DP&L then borrowed these funds from the OAQDA. Payment of principal and interest on the Bonds when due is insured by an insurance policy issued by Financial Guaranty Insurance Company. We are using the proceeds from these borrowings to assist in financing our portion of the costs of acquiring, constructing and installing certain solid waste disposal facilities comprising air quality facilities at Miami Fort, Killen and Stuart Generating Stations. These facilities are currently under construction and the proceeds from the borrowings have been placed in escrow with the trustee (the Bank of New York) and are being drawn upon only as facilities are built and qualified costs incurred. In the event any of the proceeds are not drawn, we would eventually be required to return the unused proceeds to bondholders. We expect to draw down all of the proceeds from the borrowing over the next year.

We expect to use the remaining $100 million of volume cap carry forward prior to the end of 2008. We are planning to issue in conjunction with the OAQDA another $100 million of tax-exempt bonds to finance the remaining solid waste disposal facilities at Miami Fort, Killen, Stuart and Conesville Generating Stations.

$105 million. There are no other inter-company debt collateralizations or debt guarantees between usDPL, DP&L and ~~our parent.~~their subsidiaries. None of ~~our~~the debt obligations of DPL or DP&L are guaranteed or secured by affiliates and no cross-collateralization exists between any subsidiaries.

7.9. Commitments and Contingencies

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At June 30, 2007, these include:

Contractual Obligations

	Payment Year
$ in millions	Total		2007		2008-2009		2010-2011		2012- Thereafter
DPL

Long-term debt	$	1,550.0	$	—	$	275.0	$	297.4	$	977.6
Interest payments	1,050.3		47.8		170.7		144.0		687.8
Pension and postretirement payments	224.6		11.0		45.2		46.5		121.9
Capital leases	2.5		0.4		1.5		0.6		—
Operating leases	0.7		0.3		0.3		0.1		—
Coal contracts (a)	716.4		195.9		362.8		157.7		—
Limestone contracts(a)	58.1		1.0		9.5		10.9		36.7
Reserve for uncertain tax provisions	41.2		41.2		—		—		—
Other contractual obligations	465.6		397.0		55.4		11.0		2.2
Total contractual obligations	$	4,109.4	$	694.6	$	920.4	$	668.2	$	1,826.2

DP&L

Long-term debt	$	783.2	$	—	$	—	$	—	$	783.2
Interest payments	552.4		19.6		78.3		78.3		376.2
Pension and postretirement payments	224.6		11.0		45.2		46.5		121.9
Capital leases	2.5		0.4		1.5		0.6		—
Operating leases	0.7		0.3		0.3		0.1		—
Coal contracts (a)	716.4		195.9		362.8		157.7		—
Limestone contracts(a)	58.1		1.0		9.5		10.9		36.7
Reserve for uncertain tax provisions	41.2		41.2		—		—		—
Other contractual obligations	465.6		397.0		55.4		11.0		2.2
Total contractual obligations	$	2,844.7	$	666.4	$	553.0	$	305.1	$	1,320.2

(a) DP&L-operated units

Long-term debt:

DPL’s long-term debt as of June 30, 2007 consists of DP&L’s first mortgage bonds and tax-exempt pollution control bonds, DPL unsecured notes and includes current maturities and unamortized debt discounts.

DP&L’s long-term debt as of June 30, 2007 consists of first mortgage bonds, tax-exempt pollution control bonds and includes an unamortized debt discount.

See Note 8 of Notes to Condensed Consolidated Financial Statements.

Interest payments:

Interest payments associated with the long-term debt described above.

Pension and postretirement payments:

As of June 30, 2007, DP&L had estimated future benefit payments as outlined in Note 6 of Notes to Condensed Consolidated Financial Statements. These estimated future benefit payments are projected through 2016.

Capital leases:

As of June 30, 2007, DP&L had two capital leases that expire in November 2007 and September 2010.

Operating leases:

As of June 30, 2007, DPL and DP&L had several operating leases with various terms and expiration dates. Not included in this total is approximately $88,000 per year related to right-of-way agreements that are assumed to have no definite expiration dates.

Coal contracts:

DP&L has entered into various long-term coal contracts to supply portions of its coal requirements for its generating plants. Contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.

Limestone contracts:

DP&L has entered into a limestone contract to supply limestone for its generating facilities.

Reserve for uncertain tax positions:

On January 1, 2007, we adopted Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). There was no significant impact to our overall results of operations, cash flows or financial position. The total amount of unrecognized tax benefits as of the date of adoption was $36.8 million and we have recorded $3.5 million (net of tax) of accrued interest. During the second quarter ending June 30, 2007, we recorded an additional $0.9 million in accrued interest resulting in a total reserve for uncertain tax positions of $41.2 million as of June 30, 2007. None of the amount of unrecognized tax benefits is due to uncertainty in the timing of deductibility.

Other contractual obligations:

As of June 30, 2007, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

We enter into various commercial commitments, which may affect the liquidity of our operations. At June 30, 2007, these include:

Credit facilities:

In November 2006, DP&L replaced its previous $100 million revolving credit agreement with a $220 million five-year facility that expires on November 21, 2011. DP&L has the ability to increase the size of the facility by an additional $50 million at any time. At June 30, 2007, there were no outstanding borrowings under this facility.

Guarantees:

DP&L owns a 4.9% equity ownership interest in an electric generation company. As of June 30, 2007, DP&L could be responsible for the repayment of 4.9%, or $21.8 million, of a $445 million debt obligation that matures in 2026.

In two separate transactions in November and December 2006, DPL agreed to be a guarantor of the obligations of its wholly-owned subsidiary, DPL Energy, LLC (DPLE) regarding the sale of the Darby Electric Peaking Station to American Electric Power and the sale of the Greenville Electric Peaking Station to Buckeye Electric Power, Inc. In both cases, DPL has agreed to guarantee the obligations of DPLE over a multiple year period as follows:

$ in millions	2007		2008		2009		2010
Darby	$	30.6	$	23.0	$	15.3	$	7.7

Greenville	$	14.8	$	11.1	$	7.4	$	3.7

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. ~~(See Note 1 of Notes to Consolidated Financial Statements.)~~ However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, ~~regulatory proceedings and orders,~~ claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of June 30, 2007, cannot be reasonably determined.

Employees

Approximately 53% of our employees are under a collective bargaining agreement.

Environmental Matters

~~Our~~DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and law. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We have been identified, either by a government agency or by a private party seeking contribution to site clean-up costs, as a potentially responsible party (PRP) at two sites pursuant to state and federal laws. ~~Our units are subject to the acid rain provisions of the Clean Air Act and the NO~~x ~~and Ozone Transport rule. All of the SO~~2 ~~and NO~~x emissions data submitted to the EPA pursuant to these provisions for 2005 and the first quarter 2006 were recorded and reported in compliance with EPA regulations. Subsequently we detected a malfunction with its emission monitoring system at one of its generation stations and ultimately determined its SO2 ~~and NO~~x emissions data was under reported. We have petitioned the EPA to accept an alternative methodology for calculating actual emissions for 2005 and the first quarter 2006. The Company has sufficient allowances in its general account to cover the understatement and is working with the EPA to resolve the matter. Management does not believe the ultimate resolution of this matter will have a material impact on operating results or financial position. We record liabilities for probable estimated loss in accordance with Statement of Financial Accounting Standards No. 5 (SFAS 5), “Accounting for Contingencies.” To the extent a probable loss can only be estimated by reference to a range of equally probable outcomes, and no amount within the range appears to be a better estimate than any other amount, we accrue for the low end of the range. Because of uncertainties related to these matters, accruals are based on the best information available at the time. We evaluate the potential liability related to probable losses quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material effect on our results of operations and financial position.

~~Legal Matters~~

In September 2004, the ~~normal course~~Sierra Club filed a lawsuit against DP&L and the other owners of ~~business, we~~the Stuart Generating Station in the United States District Court for the Southern District of Ohio for alleged violations of the Clean Air Act (CAA) and the Station’s operating permit. DP&L, on behalf of all co-owners, is leading the defense of this matter. A sizable amount of discovery has taken place, the first set of expert reports have been ~~named~~filed with additional reports scheduled to be filed in September 2007. Dispositive motions are to be filed in January 2008. No trial date has been set yet.

In February 2007, Ohio’s Regional Air Pollution Control Agency (RAPCA), issued a ~~defendant~~Notice of Violation (NOV) to DP&L with respect to an allegedly failed performance test of one boiler in ~~various legal actions, including arbitrations, class actions~~November 2006 for particulate matter at DP&L’s Hutchings Generating Station. On June 29, 2007, the federal Environmental Protection Agency Region V, issued an NOV to DP&L with respect to the same performance test and ~~other litigation. Certain of~~with respect to earlier tests for particulates conducted in 1996 and 1998 for a different boiler at the ~~legal actions include claims for substantial compensatory and/or punitive damages or claims for indeterminate amounts of damages. We are also involved in other reviews,~~

~~investigations~~same station. Representatives from DP&L met with officials from EPA Region V and ~~proceedings by governmental~~RAPCA on July 24, 2007 to discuss the referenced performance tests, subsequent performance tests, and ~~self-regulatory organizations regarding our business. Certain of~~past and planned operations at the ~~foregoing could result in adverse judgments, settlements, fines, penalties or other relief.~~

~~Because litigation~~station. DP&L is ~~inherently unpredictable, particularly in cases where claimants seek substantial or indeterminate damages or where investigations and proceedings are in the early stages, we cannot~~unable to predict with certainty the loss or range of loss related to such matters, how such matters will be resolved, when they will be ultimately resolved, or what the eventual settlement, fine, penalty or other relief might be. Consequently, we cannot estimate losses or ranges of losses for matters where there is only a reasonable possibility that a loss may have been incurred. Although the ultimate outcome of these matters cannot be ascertained at this time itwhat further actions, if any, will be taken by the US EPA or RAPCA with respect to these NOVs.

10. Executive Litigation

On May 21, 2007, we settled the litigation with the three former executives. As part of this settlement, the three former executives relinquished and dismissed all their claims including those related to certain deferred compensation, RSUs, MVE incentives, stock options and legal fees. The RSUs and stock options relinquished and forfeited were 1.3 million and 3.6 million, respectively. Prior to the settlement date, DPL had accrued obligations of approximately $64.2 million of which DP&L had accrued obligations of approximately $60.3 million. Included in these amounts is approximately $3.1 million associated with the ~~opinion~~forfeiture of ~~management, that the resolution~~stock options. In exchange for our payment of $25 million, all of these claims were settled.

As a result of this settlement, DPL realized a net pre-tax gain in continuing and discontinued operations of approximately $31.0 million and $8.2 million, respectively. The net gain is comprised of the ~~foregoing matters will not have~~reversal of the $64.2 million of accrued obligations less the $25 million settlement. The obligations related to the discontinued operations were associated with the management of DPL’s financial asset portfolio, which was conducted in our MVE subsidiary. The MVE operations were discontinued in 2005 with the sale of the financial asset portfolio. The $25 million settlement expense was allocated between continuing and discontinued operations based on

the proportionate share of continuing and discontinued obligations. The following table outlines the components of DPL’s net pre-tax gain for continuing and discontinued operations:

Continuing operations:
Reversal of accrued obligations	$	50.8
Allocated settlement expense	(19.8		)
Net gain from continuing operations	$	31.0

Discontinued operations:
Reversal of accrued obligations	$	13.4
Allocated settlement expense	(5.2		)
Net gain from discontinued operations	$	8.2

As a ~~material adverse effect on~~result of this settlement, DP&L realized a net pre-tax gain in continuing operations of approximately $35.3 million. Accrued obligations associated with the former executives’ litigation were recorded by DP&L since the obligations were associated with our non-qualified benefit plans. DP&L had no ownership of DPL’s discontinued financial ~~condition, taken as a whole; such resolution may, however, have a material effect on~~asset portfolio business, therefore these liabilities were reversed and DP&L’s net pre-tax gain was recorded within continuing operations. The following table outlines the ~~operating results in any future period, depending on the level~~components of ~~income for such period.~~DP&L’s net gain:

Continuing operations:
Reversal of accrued obligations	$	60.3
Allocated settlement expense	(25.0		)
Net gain from continuing operations	$	35.3

~~We have provided reserves for such matters in accordance with SFAS 5, “Accounting for Contingencies.”~~ The ~~ultimate resolution may differ~~$25 million settlement was funded from the ~~amounts reserved.~~sale of financial assets held in DP&L’s Master Trust Plan for deferred compensation. As part of this transaction, DPL and DP&L recorded a $3.2 million realized gain which is reflected in investment income.

Certain legal proceedings in which we are involved are discussed in Note 11 to the Consolidated Financial Statements and, Part I, Item 3, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2005; and Note 7 to the Consolidated Financial Statements and Part II, Item 1, included in our Form 10-Q for the quarterly periods ended March 31, 2006 and June11. Insurance Recovery Claim

On April 30, ~~2006. The following discussion is limited to recent developments concerning our legal proceedings and should be read in conjunction~~2007, DP&L executed a settlement agreement with ~~those earlier reports.~~

~~On January 13, 2006, we filed a claim against~~ one of our insurers, Associated Electric & Gas Insurance Services ~~Limited~~ (AEGIS), under a fiduciary liability policy to recoup a portion of legal fees associated with our litigation against the three former executives for $14.5 million. This was recorded as a reduction to operation and maintenance expense during the quarter ended June 30, 2007.

On May 16, 2007, DPL and DP&L notified one of our insurers, Energy Insurance Mutual Limited, under an umbrella fiduciary liability policy, of our intent to pursue a claim for legal fees that DPL and DP&L incurred in defending claims made by the three former executives. An arbitration of this matter was held on August 4, 2006. The arbitration panel ruled on or about September 12, 2006 that the AEGIS policy does not require an advance of defense expenses to us. Rather, the arbitration panel stated that we are required to file a written undertaking as a condition precedent to repay expenses finally established not to be insured. We have filed a written undertaking with AEGIS and will continue to pursue resolution of the claim through mediation and arbitration in 2007.

On February 13, 2006, we received correspondence from the Ohio Department of Taxation (ODT) notifying us that ODT has completed their examination and review of our Ohio Corporation Franchise Tax Returns for tax years 2002 through 2004 and that the final proposed audit adjustments result in a balance due of $90.8 million before interest and penalties. We have reviewed the proposed audit adjustments and are vigorously contesting the ODT findings and notice of assessment through all administrative and judicial means available. On March 29, 2006, we filed petitions for reassessment with the ODT to protest each assessment as well as request corrected assessments for each tax year. On October 12, 2006, we signed a Memorandum of Understanding with the ODT that stated if the ODT’s positions are ultimately sustained in judicial proceedings, the total additional tax liability that we would be subject to for tax years 2002 through 2004 would be no more than $50.7 million before interest as opposed to the $90.8 million stated in the ODT’s correspondence of February 13, 2006. We believe we have recorded adequate tax reserves related to the proposed adjustments; however, we cannot predict the outcome, which could be material to our results of operations and cash flows.

We are also under audit review by various state agencies for tax years 2002 through 2004. We have also filed an appeal to the Ohio Board of Tax Appeals for tax years 1998 through 2001. Depending upon the outcome of these audits and the appeal, we may be required to increase our tax provision if actual amounts ultimately determined exceed recorded reserves. We believe we have adequate reserves in each tax jurisdiction but cannot predict the outcome of these audits.

In September 2006, we became aware of unasserted claims under the Fair Labor Standards Act concerning the calculation of overtime rates for our unionized workforce. We will vigorously oppose these claims, if asserted against us. However, if we do not prevail, the cost to us would be in the range of $0-$3.5 million.

~~Contractual Obligations and Commercial Commitments~~12. Regulatory Matters

We ~~enter into various contractual~~apply the provisions of SFAS 71 to our regulated operations. This accounting standard defines regulatory assets as the deferral of costs expected to be recovered in future customer rates and ~~other long-term obligations that may affect~~regulatory liabilities as current cost recovery of expected future expenditures.

Regulatory liabilities are reflected on the ~~liquidity of our operations. At September 30, 2006, these~~Condensed Consolidated Balance Sheet under the caption entitled “Other Deferred Credits”. Regulatory assets and liabilities on the Condensed Consolidated Balance Sheet include:

~~Contractual Obligations~~

Payment Year

$ in millions

Total

Less than 1
Year

2 - 3 Years

4 - 5 Years

More than 5
Years

Long-term debt

$
783.1

$
—

$
—

$
—

$
783.1

Interest payments

581.7

39.1

78.3

78.3

386.0

Pension and postretirement payments

249.2

33.4

46.0

47.2

122.6

Capital leases

3.2

1.1

1.4

0.7

—

Operating leases

0.5

0.3

0.2

—

—

Fuel and limestone contracts (a)

586.8

86.7

315.5

97.5

87.1

Other long-term obligations

27.5

14.6

9.8

3.1

—

Total contractual obligations

$
2,232.0

$
175.2

$
451.2

$
226.8

$
1,378.8

			At		At
	Type of	Amortization	June 30,		December 31,
$ in millions	Recovery (a)	Through	2007		2006
Regulatory Assets:
Deferred recoverable income taxes	C/B	Ongoing	$	52.0	$	53.1
Pension and postretirement benefits	C	Ongoing	45.3		47.1
Electric Choice systems costs	F	2010	11.9		13.5
Regional transmission organization costs	C	2014	10.7		11.4
Deferred storm costs	C	2008	3.7		5.4
PJM administrative costs	F	2009	3.8		4.6
Power plant emission fees	C	Ongoing	4.3		4.5
Rate case expenses	F	2010	0.9		3.5
Retail settlement system costs			3.1		3.1
PJM integration costs	F	2015	1.2		1.4
Other costs			3.5		1.0
Total regulatory assets			$	140.4	$	148.6

Regulatory Liabilities:
Asset retirement obligations - regulated property			$	88.4	$	86.3
Postretirement benefits			7.3		7.6
SECA net revenue subject to refund			20.6		18.7
Total regulatory liabilities			$	116.3	$	112.6

(a)		F – Recovery of incurred costs plus rate of return.
		C – Recovery of incurred costs only.
		B – Balance has an offsetting liability resulting in no impact on rate base.

~~(a)~~Regulatory Assets ~~DP&L operated units.~~

We evaluate our regulatory assets each period and believe recovery of these assets is probable. We have received or requested a return on certain regulatory assets for which we are currently recovering or seeking recovery through rates.

~~Long-term debt:~~Deferred recoverable income taxes

~~Long-term debt~~ represent deferred income tax assets recognized from the normalization of flow-through items as the result of ~~September 30, 2006, consists~~amounts previously provided to customers. Since currently existing temporary differences between the financial statements and the related tax basis of ~~our first mortgage bonds and tax-exempt pollution control bonds and includes an unamortized debt discount. (See Note 6 of Notes to Consolidated Financial Statements.)~~

~~Interest payments:~~

~~Interest payments associated with the long-term debt described above.~~assets will reverse in subsequent periods, deferred recoverable income taxes are amortized.

Pension and postretirement ~~payments:~~benefits

As represent the unfunded benefit obligation related to the transmission and distribution areas of ~~September 30, 2006, we had estimated~~our electric business. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through rates. This factor, combined with the historical precedents from the PUCO and the FERC, makes future ~~benefit payments as outlined in Note 4~~rate recovery of ~~Notes to Consolidated Financial Statements. These estimated future benefit payments are projected through 2016.~~these costs probable.

~~Capital leases:~~Electric Choice systems costs

As represent costs incurred to modify the customer billing system for unbundled rates and electric choice bills relative to other generation suppliers and information reports provided to the state administrator of ~~September 30,~~the low-income electric program. In February 2005, the PUCO approved a stipulation allowing us to recover certain costs incurred for modifications to its billing system from all customers in its service territory. We filed a subsequent case to implement the PUCO’s order to begin charging customers for billing costs. On March 1, 2006, ~~we had two capital leases~~the PUCO issued an order that ~~expire in November 2007~~approved our tariff as filed. We began collecting this rider immediately, and ~~September 2010.~~expect to recover all costs over five years.

~~Operating leases:~~Regional transmission organization costs

As represent costs incurred to join a Regional Transmission Organization (RTO) that controls the receipts and delivery of ~~September 30, 2006, we had several operating leases with various terms and expiration dates. Not included~~bulk power within the service area. These costs are being amortized over a 10-year period that commenced in ~~this total is approximately $88 thousand per year related to right-of-way agreements that are assumed to have no definite expiration dates.~~October 2004.

~~Fuel~~Deferred storm costs include costs incurred by us to repair damage from December 2004 and ~~limestone contracts:~~January 2005 ice storms. On July 12, 2006, the PUCO approved our tariff as proposed and we began recovering these deferred costs over a two-year period beginning August 1, 2006.

PJM administrative costs

~~We have entered into various long-term coal contracts~~ contain the administrative fees billed to ~~supply portions~~us by PJM Interconnection, L.L.C. (PJM) as a member of ~~our coal requirements for our generating plants and~~PJM. Pursuant to a long-term contract to supply limestone for the operation of our flue gas desulfurization (FGD) units. Coal contract prices are subject to periodic adjustment, and have features that limit price escalation in any given year.

~~A new long-term barge agreement was executed for five years~~PUCO order issued on January 25, 2006, these deferred costs will be recovered over a 3-year period from retail ratepayers beginning ~~September~~February 2006.

Power plant emission fees represent costs paid to the State of Ohio for environmental monitoring that are or will be recovered over various periods under a PUCO rate rider from customers.

Retail settlement system costs represent costs to implement a retail settlement system that reconciles the amount of energy a competitive retail electric service (CRES) supplier delivers to its customers and what its customers actually use. Based on case precedent in other utilities’ cases, the cost of this system is recoverable through our next transmission rate case that will be filed at the FERC. The timing of this case is uncertain at this time.

PJM integration costs include infrastructure costs and other related expenses incurred by PJM and reimbursed by DP&L to integrate us into the RTO. Pursuant to a FERC order, the costs are being recovered over a 10-year period beginning May 2005 from wholesale customers within PJM.

Rate case expenses represent costs incurred in connection with the Rate Stabilization Surcharge that was approved by the PUCO and implemented in January 2006. These costs are being amortized over a five-year period.

Other ~~long-term obligations:~~costs include consumer education advertising regarding electric deregulation and costs pertaining to a recent rate case and are or will be recovered over various periods.

Regulatory Liabilities

Asset retirement obligations - regulated property reflect an estimate of amounts recovered in rates that are expected to be expended to remove existing transmission and distribution property from service upon retirement.

Postretirement benefits reflect a regulatory liability that was recorded for the portion of the unrealized gain on our postretirement trust assets related to the transmission and distribution areas of our electric business. We have historically recorded these transactions on the accrual basis and this is how these costs have historically been recovered through rates. This factor, combined with the historical precedents from the PUCO and the FERC, make it probable that these amounts will be reflected in future rates.

SECA (Seams Elimination Charge Adjustment) net revenue subject to refund represents the deferral of net SECA revenue accrued in 2005 and 2006. SECA revenue and expenses represent FERC-ordered transitional payments to replace the through-and-out transmission rates that were eliminated within the PJM/MISO region. A hearing was held in early 2006 to determine the amount of these transitional payments. As of ~~September~~June 30, ~~2006, we~~2007, no ruling has been issued. We received and paid these transitional payments from May 2005 through March 2006.

13. Ownership of Facilities

DP&L and other Ohio utilities have undivided ownership interests in seven electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, as well as investments in fuel inventory, plant materials and operating supplies, and capital additions, are allocated to the owners in accordance with their respective ownership interests. As of June 30, 2007, DP&L had ~~various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.~~$425.0 million of construction in progress at such facilities.

~~We enter into various commercial commitments, which may affect the liquidity of our operations. At September 30, 2006, these include:~~

~~Credit facilities:~~DP&L’s

We have a $100 million, 364-day unsecured credit facility that is renewable annually and expires on May 30, 2010. At September 30, 2006, there were no borrowings outstanding under this credit agreement. The new facility may be increased up to $150 million.

~~Guarantee:~~

~~We own a 4.9% equity~~undivided ownership interest in ~~an electric generation company. As of September~~such jointly owned facilities at June 30, ~~2006, we could be responsible for the repayment of 4.9%, or $21.8 million, of a $445 million debt obligation that matures in 2026.~~2007 is as follows:

	DP&L Share		DP&L Investment
	Ownership	Production Capacity	Gross Plant in Service	Accumulated Depreciation	Construction Work in Progress
	(%)	(MW)	($ in millions)	($ in millions)	($ in millions)
Production Units:
Beckjord Unit 6	50.0	207	63	53	3
Conesville Unit 4	16.5	129	34	27	21
East Bend Station	31.0	186	197	127	1
Killen Station	67.0	424	419	246	150
Miami Fort Units 7&8	36.0	360	264	101	55
Stuart Station	35.0	839	383	204	189
Zimmer Station	28.1	365	1,050	562	6
Transmission (at varying percentages)			90	49	0

8.DPL’s and ~~Peaking Generating Facilities~~DP&L

~~Through DPL Energy, DPL owns peaking~~ shares of operating costs associated with the jointly-owned generating facilities ~~to which DP&L has rights to~~are included within the ~~capacity, energy~~corresponding line on the Condensed Consolidated Statements of Results of Operations and ~~ancillary service output. DPL has received and~~our share of the investment in facilities is evaluating purchase offers for three of its peaking generation sites. The sites represent a combined capacity of 872 megawatts and a net book value of approximately $300 million. A decision about whether to sell these assets has not been made or approved. The Company believes that if terms could be reached with potential buyers a transaction could be taken to its Board for approval duringincluded in the ~~fourth quarter of 2006. If approved, a transaction is not expected to close until the first half of 2007.~~Condensed Consolidated Balance Sheets.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Certain statements contained in this ~~discussion~~report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Matters discussed in this report that relate to events or developments that are expected to occur in the future, including management’s expectations, strategic objectives, business prospects, anticipated economic performance and financial condition and other similar matters constitute forward-looking statements. Forward-looking statements are based on management’s beliefs, assumptions and expectations of ~~our~~ future economic performance, taking into account the information currently available to management. These statements are not statements of historical ~~fact.~~fact and are typically identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will” and similar expressions. Such forward-looking statements are subject to risks and uncertainties, and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond ~~our~~DPL’s control, including but not limited to: abnormal or severe ~~weather;~~weather and catastrophic weather-related damage; unusual maintenance or repair requirements; changes in fuel costs and purchased power, coal, environmental emissions, gas and other commodity prices; volatility and changes in markets for electricity and other energy-related commodities; increased ~~competition;~~competition and deregulation in the electric utility industry; increased competition in the retail generation market; changes in interest rates; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels, rate structures or tax laws; changes in federal and/or state environmental laws and ~~decisions;~~regulations to which DPL and its subsidiaries are subject; the development of Regional Transmission Organizations, including the PJM to which DPL’s operating subsidiary has given control of its transmission functions; changes in DPL’s purchasing processes, pricing, delays, contractor and supplier performance and availability; significant delays associated with large construction projects; growth in DPL’s service territory and changes in demand and demographic patterns; changes in accounting ~~rules;~~rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; financial market conditions; the outcomes of litigation and regulatory investigations, proceedings or inquiries; general economic ~~conditions.~~conditions; and the risks and other factors discussed in DPL’s filings with the Securities and Exchange Commission.

Forward-looking statements speak only as of the date of the document in which they are made. These forward-looking statements are identified by terms and phrases such as “anticipate”, “believe”, “intend”, “estimate”, “expect”, “continue”, “should”, “could”, “may”, “plan”, “project”, “predict”, “will”, and similar expressions. We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based.

BUSINESS OVERVIEW

This report includes the combined filing of DPL Inc. (DPL) and The Dayton Power and Light Company(DP&L). DP&L is the principal subsidiary of DPL providing approximately 99% of DPL’s total consolidated revenue and approximately 93% of DPL’s total consolidated asset base. Throughout this report the terms we, us, our and ours are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section. Historically, DPL and DP&L have filed separate SEC filings. Beginning with the 2006 Form 10-K and in the future, DPL and DP&L will file combined SEC reports on an interim and annual basis.

~~UPDATES/~~DPL is a regional electric energy and utility company and through its principal subsidiary, DP&L, is primarily engaged in the generation, transmission and distribution of electricity in West Central Ohio. DPL and DP&L strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings, and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, DPL and DP&L’s strategy is to match energy supply with load or customer demand; maximize profits while effectively managing exposure to movements in energy and fuel prices; and utilize the transmission and distribution assets that transfer electricity at the most efficient cost, while maintaining the highest level of customer service and reliability.

We operate and manage generation assets and are exposed to a number of risks through this process. These risks include, but are not limited to, electricity wholesale price risk, fuel supply and price risk and power plant performance. We attempt to manage these risks through various means. For instance, we operate a portfolio of wholly-owned and jointly-owned generation assets that is diversified as to fuel source, cost structure and operating characteristics. We are focused on the operating efficiency of these power plants and maintaining their availability.

Like other electric utilities and energy marketers, DP&L and DPL Energy, LLC (DPLE, one of our wholly-owned subsidiaries) may sell or purchase electric products on the wholesale market. DP&L and DPLE compete with other generators, power marketers, privately and municipally-owned electric utilities and rural electric cooperatives when selling electricity. The ability of DP&L and DPLE to sell this electricity will depend on how DP&L’s and DPLE’s price, terms and conditions compare to those of other suppliers.

Weoperate and managetransmission and distribution assets in a rate-regulated environment. Accordingly, this subjects us to regulatory risk in terms of the costs that we may recover and the investment returns that we may collect in customer rates. We are focused on delivering electricity and maintaining high standards of customer service and reliability in a cost-effective manner.

We operate in a regulated and deregulated environment. The electric utility industry has historically operated in a regulated environment. However, in recent years, there have been a number of federal and state regulatory and legislative decisions aimed at promoting competition and providing customer choice. Market participants have therefore created new business models to exploit opportunities. The marketplace is now comprised of independent power producers, energy marketers and traders, energy merchants, transmission and distribution providers and retail energy suppliers. There have also been new market entrants and activity among the traditional participants, such as mergers, acquisitions, asset sales and spin-offs of lines of business. In addition, transmission systems are being operated by Regional Transmission Organizations (RTOs).

As part of Ohio’s electric deregulation law, all of the state’s investor-owned utilities are required to join a RTO. The role of the RTO is to administer an electric marketplace and ensure reliability of the transmission grid. In October 2004, DP&L successfully integrated its 1,000 miles of high-voltage transmission into the PJM Interconnection, L.L.C. (PJM) RTO. PJM ensures the reliability of the high-voltage electric power system serving 51 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region’s transmission grid; administers the world’s largest competitive wholesale electricity market; and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion.

As a member of PJM, DP&L is subject to charges and costs associated with PJM operations as approved by the Federal Energy Regulatory Commission (FERC). As discussed below, in connection with the recovery of such costs in retail rates, DP&L incurs significant administrative charges. Additionally, PJM’s role in administering the regional transmission grid and planning regional transmission expansion improvements results in periodic proposals by PJM and other stakeholder members of PJM to the FERC to allocate and charge costs

associated with the transmission system to PJM’s members, including DP&L. DP&L and other interested parties have the right to intervene and offer counter-proposals.

UPDATES / OTHER MATTERS

~~Peaking Generating Facilities~~Executive Litigation

~~Through DPL Energy, DPL owns peaking facilities~~On May 21, 2007, we settled the litigation with the three former executives. As part of this settlement, the three former executives relinquished and dismissed all their claims including those related to ~~which DP&L has rights~~certain deferred compensation, RSUs, MVE incentives, stock options and legal fees. The RSUs and stock options relinquished and forfeited were 1.3 million and 3.6 million, respectively. Prior to the ~~capacity, energy~~settlement date, DPL had accrued obligations of approximately $64.2 million of which DP&L had accrued obligations of approximately $60.3 million. Included in these amounts is approximately $3.1 million associated with the forfeiture of stock options. In exchange for our payment of $25 million, all of these claims were settled.

As a result of this settlement, DPL realized a net pre-tax gain in continuing and ~~ancillary service output. DPL has received~~discontinued operations of approximately $31.0 million and $8.2 million, respectively. The net gain is ~~evaluating purchase offers~~comprised of the reversal of the $64.2 million of accrued obligations less the $25 million settlement. The obligations related to the discontinued operations were associated with the management of DPL’s financial asset portfolio, which was conducted in our MVE subsidiary. The MVE operations were discontinued in 2005 with the sale of the financial asset portfolio. The $25 million settlement expense was allocated between continuing and discontinued operations based on the proportionate share of continuing and discontinued obligations. The following table outlines the components of DPL’s net pre-tax gain for ~~three~~continuing and discontinued operations:

Continuing operations:
Reversal of accrued obligations	$	50.8
Allocated settlement expense	(19.8		)
Net gain from continuing operations	$	31.0

Discontinued operations:
Reversal of accrued obligations	$	13.4
Allocated settlement expense	(5.2		)
Net gain from discontinued operations	$	8.2

As a result of this settlement, DP&L realized a net pre-tax gain in continuing operations of approximately $35.3 million. Accrued obligations associated with the former executives’ litigation were recorded by DP&L since the obligations were associated with our non-qualified benefit plans. DP&L had no ownership of DPL’s discontinued financial asset portfolio business, therefore these liabilities were reversed and DP&L’s net pre-tax gain was recorded within continuing operations. The following table outlines the components of DP&L’s net gain:

Continuing operations:
Reversal of accrued obligations	$	60.3
Allocated settlement expense	(25.0		)
Net gain from continuing operations	$	35.3

The $25 million settlement was funded from the sale of financial assets held in DP&L’s Master Trust Plan for deferred compensation. As part of this transaction, DPL and DP&L recorded a $3.2 million realized gain which is reflected in investment income.

Sale of Corporate Aircraft

On June 7, 2007, Miami Valley CTC, Inc. (indirect wholly-owned subsidiary of DPL), sold its ~~peaking generation sites.~~corporate aircraft and associated inventory and parts for $7.4 million. The ~~sites represent a combined capacity of 872 megawatts and a~~ net book value of the assets being written down and subsequently sold were approximately ~~$300~~$1.0 million and severance and other costs of approximately $0.4 million were accrued. Miami Valley CTC, Inc. recorded a net gain on the sale of approximately $6.0 million for the quarter and the six-month period ended June 30, 2007, which is included in DPL’s operation and maintenance expense.

In relation to this sale, Miami Valley CTC, Inc., placed in escrow approximately $2.2 million. ~~A decision about whether~~These funds are listed as the caption “Restricted funds held in trust” in the Condensed Consolidated Balance Sheet for DPL. These funds were released from escrow on July 12, 2007.

Sale of Peaking Units

On April 25, 2007, DPL Energy, LLC, completed the sale of its Darby and Greenville electric peaking generation facilities providing DPL with approximately $151 million in cash. Darby Station was sold to ~~sell these assets has not been made or approved. The~~Columbus Southern Power Company, ~~believes that if terms could be reached~~a utility subsidiary of American Electric Power Company (AEP), for approximately $102 million in cash. Greenville Station was sold to Buckeye Power, Inc. for approximately $49 million in cash. See Note 5 of the Notes to Condensed Consolidated Financial Statements.

Insurance Recovery Claim

On April 30, 2007, DP&L executed a settlement agreement with ~~potential buyers~~one of our insurers, Associated Electric & Gas Insurance Services (AEGIS), under a ~~transaction could be taken~~fiduciary liability policy to ~~its Board~~recoup a portion of legal fees associated with our litigation against three former executives for ~~approval~~$14.5 million. This was recorded as a reduction to operation and maintenance expense during the ~~fourth~~second quarter ended June 30, 2007.

On May 16, 2007, DPL and DP&L noticed one of our insurers, Energy Insurance Mutual Limited, under an umbrella fiduciary liability policy, of our intent to pursue a claim for legal fees that DPL and DP&L incurred in defending claims made by the three former executives.

Depreciation Study

Depreciation expense is calculated using the straight-line method, which depreciates the cost of property over its estimated useful life. For DPL’s and DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates. With the addition of scrubbers at certain of its generation facilities, DP&L has undertaken an evaluation of its depreciation rates which it expects to be completed during the third quarter of ~~2006. If approved,~~2007. Management expects depreciation rates to decrease due to the extension of depreciation lives for certain of its assets. The Public Utility Commission of Ohio would need to approve a ~~transaction is not expected to close until the first half of 2007.~~change in depreciation rates for our regulated assets.

Updates on Competition and Regulation

~~On April 4, 2005, we filed a request at~~Ohio Matters

Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier.DP&L continues to have the exclusive right to provide delivery service in its state certified territory. The Public Utilities Commission of Ohio (PUCO) ~~to implement a new rate stabilization surcharge effective January 1, 2006 to recover cost increases~~maintains jurisdiction over DP&L’s delivery of electricity, the standard offer supply service that customers receive if they do not choose an alternative retail electricity supplier, and other rates and charges associated with environmental capital and related operations and maintenance costs, and fuel expenses. On November 3, 2005, we entered into a settlement agreement that extended our rate stabilization period through December 31, 2010. During this time, we will continue to providethe provision of retail electric ~~service at fixed rates with the ability to recover increased fuel and environmental costs through surcharges and riders. Specifically, the agreement provides for:~~service.

· ~~A rate stabilization surcharge equal to 11%~~As of ~~generation rates beginning January 1, 2006 and continuing through December 2010. Based on 2004 sales, this rider is expected to result in approximately $65 million in net revenues per year.~~

· ~~A new environmental investment rider to begin January 1,~~June 30, 2007, equal to 5.4% of generation rates, with incremental increases equal to 5.4% each year through 2010. Based on 2004 sales, this rider is expected to result in approximately $35 million in annual net revenues beginning January 2007, growing to approximately $140 million in annual new revenues by 2010.

· An increase to the residential generation discount from January 1, 2006 through December 31, 2008 which is expected to result in a revenue decrease of approximately $7 million per year for three years, based on 2004 sales. The residential discount is accounted for in the $65 million net revenue stated above, and will expire on December 31, 2008.

On December 28, 2005, the PUCO adopted the settlement with certain modifications (RSS Stipulation). The PUCO ruled that the environmental rider will be bypassable by all customers who take service from alternate generation suppliers. Future additional revenues are dependent upon actual sales and levels of customer switching. Applications for rehearingfour unaffiliated marketers were denied and the case was appealed to the Ohio Supreme Court by the Ohio Consumers’ Counsel (OCC) on April 21, 2006. On September 1, 2006, DP&L made a tariff filing to implement the environmental investment rider beginning January 1, 2007.

We agreed to implement a Voluntary Enrollment Process that would provide residential customers with an option to choose a competitive supplier to provide their retail generation service should switching not reach 20% in each customer class. During 2005, approximately 51 thousand residential customers that volunteered for the program were bid out toregistered as Competitive Retail Electric Service (CRES) providers ~~who were registered~~ in ~~our~~DP&L’s service territory; however, no bids were received and the 2005 program ended. As part of the RSS Stipulation, we agreed to implement the Voluntary Enrollment Program again in 2006 and 2007. Approximately 25 thousand residential customers have volunteered for the 2006 program. As of October 16, 2006, all four rounds of bids were complete, which resulted in no bids being received. The magnitude of any customer switching and the financial impact of this program in 2007 cannot be determined at this time.

~~As of September 30, 2006, four unaffiliated marketers were registered as CRES providers in our service territory; to date,~~territory. While there has been ~~little activity from these suppliers.~~some customer switching to date, it represented less than 0.15 percent of sales in 2006. DPL Energy Resources, Inc. (DPLER), ~~one of our parent’s significant subsidiaries,~~an affiliated company, is also a registered CRES provider and accounted for ~~substantially~~nearly all of the ~~load served~~total kWh supplied by CRES providers within ~~our~~DP&L’s service territory in 2006. In addition, several communities in ~~our~~DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date, none of these communities have aggregated their generation load.

In early 2004, there was a complaint filed at the PUCO concerning the pricing of our billing services. The parties reached a settlement on the price we charge CRES providers for performing billing services. The PUCO issued an Order approving the settlement with minor modifications. This Order gave us the authority to defer costs of approximately $16 million plus carrying charges, and later request PUCO approval for recovery of those costs from all customers. The PUCO denied applications for rehearing, and the deferral case was appealed to the Ohio Supreme Court. On September 27, 2006, the Supreme Court issued a decision affirming the PUCO’s order in this case. On June 17, 2005, we filed a subsequent case, requesting PUCO approval for recovery of the deferred billing

costs plus carrying charges. On March 1, 2006, the PUCO approved our recovery of this cost with one minor modification. This new rider is expected to result in approximately $7 million in additional annual revenue beginning March 2006 through 2010. On March 30, 2006, the OCC filed an appeal of this new rider to the Ohio Supreme Court. Within that appeal, the OCC filed a motion to stay our recovery of this new rider. The motion for stay was subsequently denied by the Court. On October 19, 2006, the OCC filed to dismiss their appeal, but an appeal related to this matter filed by the Ohio Partners for Affordable Energy is still pending.

On September 1, 2005, we filed an application requesting the PUCO grant us authority to recover distribution costs associated with storm restoration efforts for ice storms that took place in December 2004 and January 2005. In February 2006, we filed updated schedules in support of our application. On July 12, 2006, the PUCO approved our filing, allowing the Company to recover approximately $8.6 million in additional revenues over a two-year period. The OCC filed an application for rehearing in this case that was subsequently denied by the PUCO.

~~On August 28, 2006, the Staff of the PUCO issued a report relating to compliance with the Federal Energy Policy Act of 2005. In that report the Staff makes recommendations to the Commission~~DP&L agreed to implement ~~new rules~~a Voluntary Enrollment Program (VEP) that would provide customers with an option to choose a competitive supplier to provide their retail generation service should switching not reach 20% in each customer class. The 20% threshold has never been reached. Customers who elected to participate in the program have been grouped together and ~~procedures relating~~collectively bid out to ~~net metering,~~CRES providers. The second of four rounds of bidding for the 2007 program was conducted in June resulting in no bids being received. To date, the VEP process has resulted in no customer generator interconnection, stand by power, time-of-use rates, and renewable energy portfolio standards. We, among others, filed comments on September 18, 2006, and reply comments on October 6, 2006. If adopted by the Commission, these recommendations may result in new regulatory requirements for Ohio investor-owned utilities related to renewable energy standards, fuel sources, automated meter infrastructure, and time differentiated rate options for customers. The financial implications of this matterswitching. Future period effects cannot be determined at this time.

Federal Matters

On ~~July 23, 2003,~~April 19, 2007, the ~~Federal Energy Regulatory Commission (FERC)~~FERC issued an Order with regard to the allocation of costs associated with new planned transmission facilities. FERC ordered that the ~~rates~~cost of new, high-voltage facilities be socialized across the PJM region and the costs of new facilities at lower voltages be assigned to the load centers that benefit from the new facilities. The methodology for identifying beneficiaries has been set for hearing. On April 19, 2007, the FERC issued an Order relating to the allocation of costs associated with existing transmission ~~service~~facilities, upholding the existing PJM rate design. These Orders are subject to rehearing and the appeal process. The financial impact of ~~seven companies, including us, may~~the order to socialize new, high-voltage facilities will be ~~unjust, unreasonable, or unduly discriminatory or preferential. A number~~passed on as costs are incurred by utilities

constructing such projects and will be reflected in PJM charges to DP&L. Over time, this order is likely to increase PJM charges to DP&L. Although the impact of ~~orders have since been issued on the subject of how best to modify~~cost allocation could be material, management believes these costs should be recoverable through retail rates.

As a result, the FERC ordered utilities to eliminate certain charges and to implement transitional charges, known as Seams Elimination Charge Adjustment (SECA), effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, we are obligated to pay SECA charges to other utilities, but we receive a net benefit from these transitional payments. Beginning May 2005, we began receiving SECA payments and have received over $24.8 million, netmember of SECA charges, through September 2006. Several parties have sought rehearing of the FERC orders which are still pending. The hearing was held in May 2006 and an initial decision was issued on August 10, 2006 that, if upheld by the FERC, would reduce the amount of SECA charges we and other parties are permitted to recover. We, among others, have taken exception to the initial decision. A final FERC order on this issue is expected later this year. We have entered into a significant number of bi-lateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the FERC’s decision to affirm, modify, or reject the initial decision. We believe we have recorded adequate reserves related to the proposed adjustments; however, we cannot predict the outcome.

On May 31, 2005, the FERC instituted a proceeding under Federal Power Act Section 206 concerning the justness and reasonableness of PJM’s transmission rate design. This proceeding sets the rates for hearing and requests that all of PJM, members, which include us, address the justness and reasonableness of the current rate design. On November 22, 2005, we, along with ten other transmission owners, filed in support of PJM’s existing rate design. A hearing was held in April 2006 and an initial decision was issued on July 13, 2006 recommending a rate design different than PJM’s existing rate design. We expect a final FERC order on this issue later this year. Due to the comment and appeal process, the potential for adjustments to the initial decision and the complexity of the issues, we cannot determine what effect the final outcome of this proceeding may have on our future recovery of transmission revenues.

~~PJM has a proposal before FERC that may affect~~ the value of ~~our~~DP&L’s generation ~~capacity.~~capacity will be affected by changes in and the clearing results of the PJM capacity construct. The ~~proposal~~new construct introduces a new Reliability Pricing Model (RPM) that ~~would change~~changes the way generation capacity is priced and planned for by PJM. ~~On September 29, 2006, a settlement agreement executed by us along with most of~~PJM held its first RPM auction during April 2007 for the ~~parties to~~2007/2008 planning year and held its second RPM auction during July 2007 for the case was filed that generally retains the RPM concept as proposed by PJM, with certain modifications. If approved by the FERC, the economic effects of the settlement will vary depending on future market conditions.

2008/2009 planning year. ~~Updates on Environmental Considerations~~DP&L

~~Air and Water Quality~~

~~On December 17, 2003, the United States Environmental Protection Agency (USEPA) proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap sulfur dioxide (SO~~2) and nitrogen oxide (NOx) emissions from electric utilities. The proposed IAQR focused on states, including Ohio, whose power plant emissions are believed to be significantly contributing to fine particle and ozone pollution in other downwind states in

the eastern United States. On June 10, 2004, the USEPA issued a supplemental proposal to the IAQR, now renamed as the Clean Air Interstate Rule (CAIR). The final rules were signed on March 10, 2005 and were published on May 12, 2005. On August 24, 2005, the USEPA proposed additional revisions to the CAIR and initiated reconsideration on one issue. On March 15, 2006, the USEPA announced it had completed its review of the requests for reconsideration and determined that it would propose no changes to CAIR and denied the requests for stay. We have determined that CAIR requirements will have does not expect a material ~~effect~~impact on our operations, requiring the installation of flue gas desulfurization (FGD) equipment and continual operation of the currently installed Selective Catalytic Reduction (SCR) equipment. As a result, we are proceeding with the installation and have begun the construction of FGD equipment at various generating units.

~~On January 30, 2004, the USEPA published~~ its proposal to restrict mercury and other air toxins from coal-fired and oil-fired utility plants. The final Clean Air Mercury Rule (CAM-R) was signed March 15, 2005 and was published on May 18, 2005. The final rules will have a material effect on our operations. We anticipate that the FGDs being installed to meet the requirements of CAIR may be adequate to meet the Phase I requirements of CAM-R. We expect that additional controls will be needed to meet the Phase II requirements of CAM-R that go into effect January 1, 2018. On March 29, 2005, nine states filed lawsuits against USEPA, opposing the regulatory approach taken by USEPA. On March 31, 2005, various groups requested that USEPA stay implementation of CAM-R. On August 4, 2005, the United States Court of Appeals for the District of Columbia denied the motion for stay. On October 21, 2005, USEPA initiated reconsideration proceedings on a number of issues. On May 31, 2006, USEPA took final action on CAM-R essentially reaffirming its original rulemaking.

~~Under the CAIR and CAM-R cap and trade programs for SO~~2, NOx and mercury, we estimate we will spend more than $465 million from 2006 through 2008 to install the necessary pollution controls. If CAM-R litigation results in plant specific mercury controls, our costs may be higher. Due to the ongoing uncertainties associated with the litigation of the CAM-R, we cannot project the final costs at this time.

~~RISK FACTORS~~

A comprehensive listing of risk factors that we consider to be the most significant to your decision to invest in us is provided in our most recent Form 10-K and is incorporated herein by reference. The Form 10-K may be obtained as discussed on page 2, ‘Available Information.’ Any updates are provided in Part II, Item 1A “Risk Factors” of this quarterly report and the quarterly reports for March 31, 2006 and June 30, 2006. If any of these events occur, our business results of operations, financial position or cash ~~flow could~~flows due to the outcome of these auctions. An additional auction will be ~~materially affected.~~held during 2007 for the 2009/2010 planning year. The financial results and impact of this auction is unknown and will depend on a number of factors including projections made by PJM as well as market participant bidding behavior.

~~RESULTS OF OPERATIONS~~ENVIRONMENTAL CONSIDERATIONS

~~Income~~DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for probable estimated loss in accordance with Statement ~~Highlights~~of Financial Accounting Standards No. 5 (SFAS 5), “Accounting for Contingencies.” To the extent a probable loss can only be estimated by reference to a range of equally probable outcomes, and no amount within the range appears to be a better estimate than any other amount, we accrue for the low end of the range. Because of uncertainties related to these matters, accruals are based on the best information available at the time. DPL,

Three months ended

Nine months ended

September 30,

September 30,

$ in millions

2006

2005

2006

2005

Revenues

$
390.3

$
355.5

$
1,036.1

$
952.0

Less:
Fuel

91.0

87.9

251.1

235.1

Purchased power

70.7

48.3

134.7

116.0

Gross margin

$
228.6

$
219.3

$
650.3

$
600.9

Gross margin as a percentage of revenues

58.6
%
61.7
%
62.8
%
63.1
%

Operating income

$
107.1

$
112.1

$
295.3

$
279.5

through its captive insurance subsidiary, MVIC, has an actuarial calculated reserve for environmental matters. Weevaluate the potential liability related to probable losses quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material effect on our results of operations, financial position or cash flows.

~~Revenues~~FINANCIAL OVERVIEW

~~Revenues~~As more fully discussed in later sections of this Form 10-Q, the following were the significant themes and events for the quarter and six months ended June 30, 2007:

·DPL’s revenues for the quarter and six months ended June 30, 2007 increased ~~10%~~11% and 11%, respectively, over the same periods in 2006 primarily due to $390.3 million in the third quarter of 2006 compared to $355.5 million in the third quarter of 2005 reflecting higher average rates for retail sales and greater wholesale sales volume. These increases were partially offset by lowerweather driven retail sales volume, ~~lower average rates~~the rate stabilization surcharge and other regulated asset recovery riders. DPL’s purchased power costs for ~~wholesale sales~~the quarter and ~~decreased ancillary revenues associated with participation~~six months ended June 30, 2007 increased$46.2 million and $73.1 million, respectively, over the same periods in ~~a RTO.~~

~~Retail revenues increased $13.5 million~~2006. The increase in ~~the third quarter of 2006 compared to 2005, primarily resulting from $21.0 million in higher average rates and $0.5 million of higher miscellaneous revenues, partially offset by decreased sales~~purchased power volume ~~of $8.0 million relating to milder weather experienced in 2006 compared to 2005. The higher average rates were~~was primarily the result of the rate stabilization plan surcharge and regulated asset recovery riders, most of which were implemented early in 2006. Wholesale revenues increased $22.9 million, primarily resulting from a $44.6 million increase inhigher sales volume ~~partially offset by a $21.7 million decrease in average~~and DPL and partner operated generating facilities being less available than the same period of the prior year due to planned and unplanned outages. In addition, we purchase power when market ~~rates. During~~prices are below the ~~third quarter of 2006, RTO ancillary revenues decreased $1.6 million to $20.6 million~~marginal costs associated with our higher cost generating facilities.

·DPL’s cash flows from ~~$22.2 million in the third quarter of 2005. Cooling degree-days were down 17% to 639~~operations for the ~~third quarter~~six months ended June 30, 2007 of ~~2006 compared to 772~~$112.4 million were 16% lower than the cash flows from operations of $133.4 million for the same period of 2006 primarily due to changes in ~~2005. Heating degree-days increased~~working capital.

·DPL realized a net (pre-tax) gain in both continuing and discontinued operations of approximately $31.0 million and $8.2 million, respectively, resulting from the $25.0 million settlement of the litigation with the three former executives. See note 10 of the Notes to ~~105~~Condensed Consolidated Financial Statements.

·DP&L’s revenues for the ~~third~~ quarter ~~of 2006 compared to 23 for the same period in 2005.~~

~~Revenues increased 9% to $1,036.1 million in the first nine months of 2006 compared to $952.0 million in the first nine months of 2005, primarily reflecting higher average rates for retail sales~~ and greater wholesale sales volume. These increases were partially offset by lower retail sales volume relating to the milder weather in 2006 as compared to 2005 and lower wholesale average market rates.

Retail revenues increased $38.2 million in the first nine months of 2006 compared to the first nine months of 2005, primarily resulting from a $56.3 million increase relating to higher average rates and increased miscellaneous revenues of $0.9 million, partially offset by decreased sales volume of $19.0 million resulting from milder weather experienced in 2006 compared to 2005. The higher average rates were primarily the result of the rate stabilization plan surcharge, and regulated asset recovery riders implemented throughout 2006. Wholesale revenues increased $45.4 million, primarily related to a $71.5 million increase in sales volume, partially offset by a $26.1 million decrease in average market rates. During the first nine months of 2006, RTO ancillary revenues increased $0.5 million to $55.7 million from $55.2 million in the first nine months of 2005. Heating degree-days were down 10% to 3,173 for the ninesix months ended ~~September~~June 30, ~~2006 compared to 3,538 for the same period in 2005. In addition, cooling degree-days were down 20% to 845 for the first nine months of 2006 compared to 1,050 for the same period in 2005.~~

~~Gross Margin, Fuel~~2007 increased 11% and ~~Purchased Power~~

Gross margin in the third quarter of 2006 increased $9.3 million to $228.6 million from $219.3 million in the third quarter of 2005. As a percentage of total revenues, however, gross margin decreased 3.1 percentage points to 58.6% from 61.7%. Fuel costs increased by $3.1 million or 4% in the three months ended September 30, 2006, as compared to the same period in 2005, primarily resulting from higher market prices. Purchased power costs increased $22.4 million or 46%11%, ~~primarily resulting from higher volumes of power purchased due to less generation being available relating to scheduled maintenance and forced outages, partially offset by lower market prices.~~

Gross margin in the first nine months of 2006 increased $49.4 million to $650.3 million from $600.9 million in the first nine months of 2005. As a percentage of total revenues, however, gross margin decreased by 0.3 percentage points to 62.8% from 63.1%. Fuel costs increased by $16.0 million or 7% in the nine months ended September 30, 2006, as a result of higher market prices and higher generation output as compared to 2005. Purchased power costs increased by $18.7 million or 16% in the first nine months of 2006 compared to the same period in 2005 primarily resulting from higher volumes of power purchased.

~~Operation and Maintenance Expense~~

Operation and maintenance expense increased $12.7 million or 27% in the third quarter of 2006 compared to the same period in 2005 primarily resulting from a $3.8 million increase in employee compensation and benefit expenses, the majority of which was pension related; increased service operations costs of $2.8 million, most of which was related to greater line clearance activity and electric system overhead and substation costs; a $2.6 million increase in power production costs of which $1.5 million was due to credits received in 2005 that were not received in 2006 and increased operating expenses; $1.4 million in PJM administrative fees; and increased low-income assistance program costs of $1.3 million.

Operation and maintenance expense increased $27.1 million or 19% in the first nine months of 2006 compared to the same period in the prior year primarily resulting from a $7.9 million increase in employee compensation and benefit expenses, most of which was related to pension expense and incentive accruals; increased service operations costs of $4.8 million, the majority of which was related to greater line clearance activity; a $4.6 million increase in power production costs relating to $3.0 million of credits received in 2005 that were not received in 2006 and increased operating expenses; $4.2 million in PJM administrative fees, including $2.5 million deferred in 2005 by PUCO authority until rate relief was granted in

February 2006; increased low-income assistance program costs of $2.9 million; and a $1.8 million increase in reserves for injuries and damages. These increases were partially offset by a $1.1 million decrease in Directors’ and Officers’ liability insurance premiums.

~~Depreciation and Amortization~~

~~Depreciation and amortization increased $1.2 million and $3.9 million in the third quarter and in the first nine months of 2006,~~ respectively, compared to the same periods in ~~2005~~2006 resulting from the weather driven sales volume, rate stabilization surcharge and other regulated asset recovery riders. DP&L’s purchased power costs for the quarter and six months ended June 30, 2007, increased $45.4 million and $72.5 million, respectively, over the same periods in 2006. The increase in purchased power volume was primarily ~~reflecting~~the result of higher sales volume and DP&L and partner operated generating facilities being less available than the same period of the prior year due to planned and unplanned outages. In addition, we purchase power when market prices are below the marginal costs associated with our higher cost generating facilities.

·DP&L’s cash flows from operations for the six months ended June 30, 2007 of $137.9 million were 21% lower than the cash flows from operations of $175.2 million for the same period in 2006 primarily due to changes in working capital.

·DP&L realized a ~~higher plant base.~~net (pre-tax) gain of approximately $35.3 million resulting from the settlement of the litigation with the three former executives. See Note 10 of the Notes to Condensed Consolidated Financial Statements.

·DP&L had borrowings against the $220 million revolving line of credit facility of $65 million from February 26, 2007 through May 28, 2007 and of $30 million from April 12, 2007 through May 13, 2007. At June 30, 2007, there were no outstanding borrowings against the revolving credit facility.

RESULTS OF OPERATIONS – DPL Inc.

~~General Taxes~~DPL’s results of operations include the results of its subsidiaries, including the consolidated results of DP&L and all of DP&L’s consolidated subsidiaries. DP&L provides approximately 99% of the total revenues of DPL. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for DP&L is presented elsewhere in this report.

Financial Highlights – DPL

	Three Months Ended June 30,						Six Months Ended June 30,
$ in millions	2007			2006			2007			2006

Revenues:
Retail	$	284.2		$	258.2		$	588.7		$	541.5
Wholesale	30.4			30.5			87.1			67.9
RTO ancillary	25.8			17.4			41.5			35.1
Other revenues, net of fuel costs	2.7			2.9			5.5			5.6
Total revenues	$	343.1		$	309.0		$	722.8		$	650.1

Less: Fuel	$	63.5		$	78.6		$	153.8		$	162.8
Purchased power (a)	83.2			37.0			135.4			62.3
Gross margins (b)	$	196.4		$	193.4		$	433.6		$	425.0

Gross margins as a percentage of revenues	57.2		%	62.6		%	60.0		%	65.4		%

Operating income	$	69.4		$	55.9		$	172.9		$	159.1

Basic Earnings per share:
Continuing operations	$	0.50		$	0.20		$	0.98		$	0.63
Discontinued operations	0.04			—			0.09			0.07
Net income	$	0.54		$	0.20		$	1.07		$	0.70

(a)		Purchased power includes RTO ancillary charges of $17.0 million and $12.1 million for the quarter ended June 30, 2007 and 2006, respectively. Purchased power includes RTO ancillary charges of $29.4 million and $24.3 million for the six months ended June 30, 2007 and 2006, respectively.
(b)		For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.

DPL Inc. – Revenues

~~General taxes decreased $1.4 million~~Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, DPL’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. Since DPL plans to utilize its internal generating capacity to supply its retail customers’ needs first, increases in retail demand will decrease the volume of internal generation available to be sold in the ~~third~~wholesale market and vice versa.

The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting DPL’s wholesale sales volume each hour of the year include wholesale market prices, DPL’s retail demand, retail demand elsewhere throughout the entire wholesale market area, DPL and non-DPL plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DPL’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities not being utilized to meet its retail demand.

	Three Months Ended June 30,			Six Months Ended June 30,
$ in millions	2007 vs. 2006			2007 vs. 2006

Retail
Rate	$	11.5		$	17.8
Volume	15.4			30.5
Other miscellaneous	(0.9		)	(1.1		)
Total retail change	$	26.0		$	47.2

Wholesale
Rate	$	5.4		$	11.1
Volume	(5.5		)	8.1
Total wholesale change	$	(0.1	)	$	19.2

Other
RTO services	$	8.4		$	6.4
Other	(0.2		)	(0.1		)
Total other revenues change	$	8.2		$	6.3

Total revenues change	$	34.1		$	72.7

For the quarter ended June 30, 2007, revenues increased $34.1 million, or 11% to $343.1 million from $309.0 million for the same period in the prior year. This increase was primarily the result of higher average rates for retail and wholesale, higher retail sales volume and an increase in RTO ancillary revenue. Retail revenues increased $26.0 million, or 10%, resulting from a 6% increase in weather driven sales volume as total degree days increased 18% and a 4% increase in average retail rates related to the Rate Stabilization Plan surcharge and other regulated asset recovery riders. These increases resulted in a $15.4 million sales volume variance and a $11.5 million price variance. Wholesale revenue remained flat for the second quarter of 2007 compared to the same period of the prior year resulting from lower wholesale sales volume, partially offset by higher average market rates. The decrease in wholesale sales volume of 123 GWh resulted in an unfavorable sales volume variance of $5.5 million which was partially offset by a 22% increase in average market rates resulting in $5.4 million price variance. For the second quarter of 2007, the RTO ancillary revenues increased $8.4 million compared to the second quarter of 2006 ~~compared~~primarily resulting from $4.3 million realized from the PJM capacity auction, $1.8 million of PJM transmission congestion credits and $1.0 million from the sale of financial transmission rights (FTRs). RTO ancillary revenues primarily consist of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves. These revenues are substantially offset by RTO ancillary charges included in purchased power costs.

For the six months ended June 30, 2007, revenues increased $72.7 million, or 11% to $722.8 million from $650.1 million for the same period in the prior year. This increase was primarily the result of higher average rates and sales volume for both retail and wholesale. Retail revenues increased $47.2 million resulting from a 6% increase in weather driven sales volume as total degree days increased 16% and a 3% increase in average retail rates related to the ~~third quarter of 2005 primarily due to~~Rate Stabilization Plan surcharge and other regulated asset recovery riders. These increases resulted in a ~~decrease in the Ohio kWh tax related to lower retail customer~~$30.5 million sales ~~resulting from the milder weather experienced in 2006 compared to 2005~~volume variance and a ~~2006 adjustment to payroll taxes.~~

~~General taxes decreased $1.1~~$17.8 million price variance. For the six months ended June 30, 2007, wholesale revenue increased $19.2 million over the same period of the prior year primarily as a result of a 12% increase in sales volume (178 GWh) and a 15% increase in wholesale average rates. These increases resulted in an $11.1 million sales volume variance and an $8.1 million price volume variance for wholesale revenues. For the ~~first nine~~six months ~~of 2006 as~~ended June 30, 2007, the RTO ancillary revenues increased $6.4 million compared to the same period in ~~2005~~2006 primarily resulting from $4.3 million realized from the PJM capacity auction, $1.8 million of PJM transmission congestion credits and $2.4 million from the sale of financial transmission rights (FTRs), partially offset by an adjustment of $2.8 million for Seams Elimination Cost Adjustment (SECA). RTO ancillary revenues primarily consist of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves. These revenues are substantially offset by RTO ancillary charges included in purchased power costs.

DPL Inc. – Margins, Fuel and Purchased Power

For the second quarter of 2007, gross margin of $196.4 million increased $3.0 million, or 2%, from $193.4 million in the second quarter of 2006. As a percentage of total revenues, gross margin decreased to 57.2% in

the second quarter of 2007 compared to 62.6% in the second quarter of 2006. This result reflects the favorable impact of the increase in retail revenues and lower fuel costs, offset by increased purchased power costs. Fuel costs, which include coal, gas, oil and emission allowance costs, decreased by $15.1 million, or 19%, in the second quarter of 2007 compared to the same period in 2006 due to lower average fuel prices and a 16% (629 GWh) decrease in generation output. Purchased power increased $46.2 million in the second quarter of 2007 compared to the same period in 2006 primarily resulting from increased charges of $34.5 million relating to higher purchased power volume (685 GWh) and $6.9 million increase due to higher average market rates. The increase in purchased power volume was primarily the result of increased sales volume and partner operated generating facilities being less available compared to the same period of the prior year due to planned and unplanned outages. In addition, we purchase power when market prices are below the marginal costs associated with our higher cost generating facilities.

For the six months ended June 30, 2007, gross margin of $433.6 million increased $8.6 million, or 2%, from $425.0 million compared to the same period in 2006. As a percentage of total revenues, gross margin decreased to 60.0% in 2007 compared to 65.4% in 2006. This result reflects the favorable impact of both retail and wholesale revenues discussed above and lower fuel costs offset by increased purchased power costs. Fuel costs, which include coal, gas, oil and emission allowance costs, decreased by $9.0 million, or 6%, for the six months ended June 30, 2007 compared to the same period in 2006 primarily due to a 7% decrease in generation output (580 GWh), partially offset by an ~~Ohio kWh tax decrease~~increase in average fuel prices. Purchased power increased $73.1 million for the six months ended June 30, 2007 compared to the same period in 2006 primarily resulting from increased charges of $56.9 million relating to higher purchased power volume (1,148 GWh) and $11.1 million increase due to higher average market rates. The increase in purchased power volume was primarily the result of increased sales volume and partner operated generating facilities being less available compared to the prior year due to planned and unplanned outages. In addition, we purchase power when market prices are below the marginal costs associated with our higher cost generating facilities.

DPL Inc. – Operation and Maintenance

	Three Months Ended			Six Months Ended
	June 30,			June 30,
$ in millions	2007 vs. 2006			2007 vs. 2006
Legal costs	$	0.3		$	4.3
Mark-to-market adjustments of restricted stock units (RSUs)	(0.5		)	2.3
Power production costs	12.0			14.2
Service operations	1.3			1.9
Long-term and other incentive compensation	—			(2.5		)
MVIC reserve adjustment	(2.0		)	(2.0		)
Insurance settlement	(14.5		)	(14.5		)
Gain on sale of corporate aircraft	(6.0		)	(6.0		)
Other, net	0.3			0.1
Total operation and maintenance expense	$	(9.1	)	$	(2.2	)

For the quarter ended June 30, 2007, operation and maintenance expense decreased $9.1 million, or 13%, compared to the same period in 2006 primarily resulting from a $14.5 million insurance settlement reimbursing us for legal fees relating to the litigation with the three former executives, the gain on the sale of the corporate aircraft of $6.0 million and an actuarial adjustment reducing our MVIC reserve by $2.0 million, partially offset by increased power production costs largely related to ~~lower retail customer sales~~boiler maintenance of $6.6 million and other power production maintenance costs of $5.4 million.

For the six months ended June 30, 2007, operation and maintenance expense decreased $2.2 million, or 2%, compared to the same period in 2006 primarily resulting from a $14.5 million insurance settlement reimbursing us for legal fees relating to the ~~milder weather experienced~~litigation with the three former executives, the gain on sale of the corporate aircraft of $6.0 million and an actuarial adjustment of $2.0 million, partially offset by increased power production costs largely related to boiler maintenance of $7.1 million and other power production maintenance costs of $7.1 million and increased legal costs of $4.3 million related to the litigation with the three former executives.

DPL Inc. – Depreciation and Amortization

For the quarter and six months ended June 30, 2007, depreciation and amortization expense decreased $2.7 million and $6.1 million, respectively, compared to the same periods in 2006 ~~compared to 2005~~primarily reflecting the absence of depreciation on the peaking units, the corporate aircraft becoming fully depreciated and ~~a payroll tax adjustment in 2006.~~the impact of asset retirements. These decreases were partially offset by ~~higher taxes from~~increased depreciation relating to the ~~new State of Ohio Commercial Activities Tax that began in July 2005.~~increased plant balances.

DPL Inc. –Amortization of Regulatory Assets

For the quarter and six months ended ~~September~~June 30, ~~2006,~~2007, amortization of regulatory assets ~~was $1.8~~increased $0.8 million ~~higher than~~and $2.6 million, respectively, compared to the same period in ~~2005 primarily reflecting $0.9 million for~~2006. These increases reflect the amortization of costs incurred to ~~modify the customer billing system for~~accommodate unbundled rates and electric choice ~~bills; $0.4 million for~~bills in the customer billing system; the amortization of PJM administrative fees deferred for the period October 2004 through January 2006; and ~~$0.4 million for~~ the amortization of incremental ~~costs incurred in 2004 and~~ 2004/2005 ~~for~~ severe ~~storms.~~storm costs.

DPL Inc. – Investment Income

~~Amortization of regulatory assets~~For the quarter ended June 30, 2007, investment income increased ~~$3.7~~$0.8 million to $5.3 million from $4.5 million for the ~~nine~~same period in 2006. This increase was primarily the result of $3.2 million realized gains from the sale of financial assets held in DP&L’s Master Trust Plan for deferred compensation used for the settlement payment to the three former executives, partially offset by lower interest income relating to lower cash and short-term investment balances in 2007 compared to 2006.

For the six months ended ~~September~~June 30, 2007, investment income decreased $2.6 million to $8.3 million from $10.9 million for the same period in 2006. This decrease was primarily the result of lower interest income relating to lower cash and short-term investment balances in 2007 compared to 2006, partially offset by $3.2 million realized gains from the sale of financial assets held in DP&L’s Master Trust Plan for deferred compensation used for the settlement payment to the three former executives.

DPL Inc. – Net Gain on Settlement of Executive Litigation

On May 21, 2007, we settled the litigation with the three former executives. In exchange for a payment of $25 million, the three former executives relinquished and dismissed all of their claims including those related to deferred compensation, RSUs, MVE incentives, stock options and legal fees. As a result of this settlement, DPL realized a net pre-tax gain in continuing and discontinued operations of approximately $39.2 million. See Note 10 of Notes to Condensed Consolidated Financial Statements.

DPL Inc. – Interest Expense

For the quarter ended June 30, 2007, interest expense decreased $6.5 million or 25% compared to the same period in 2006 primarily from lower interest of $4.6 million associated with the redemption of DPL debt ($225 million 8.25% Senior Note) and $2.9 million of greater capitalized interest than the prior year mostly relating to increased pollution control capital expenditures. These decreases were partially offset by $1.2 million of interest expense associated with DP&L’s new $100 million 4.8% Series pollution control bonds issued September 13, 2006.

For the six months ended June 30, 2007, interest expense decreased $9.7 million or 19% compared to 2006 primarily from $5.7 million of greater capitalized interest than the prior year mostly relating to increased pollution control capital expenditures; and lower interest of $6.2 million from redemption of DPL debt ($225 million 8.25% Senior Note). These decreases were partially offset by $2.4 million of interest expense associated with DP&L’s new $100 million 4.8% Series pollution control bonds issued September 13, 2006 and $1.1 million of interest expense associated with DP&L’s short-term borrowing of $95 million from its unsecured revolving credit agreement of $220 million.

DPL Inc. – Other Income (Deductions)

For the quarter ended June 30, 2007, other deductions of $0.2 million changed from $0.6 million of other income in 2006 primarily resulting from a refund of tax penalties in 2006.

For the six months ended June 30, 2007, other income of $0.6 million increased from $0.3 million of other income in 2006 primarily resulting from the sale of emission allowances and gains realized on the expiration of forward contracts partially offset by a refund of tax penalties in 2006.

DPL Inc. – Income Tax Expense

For the second quarter and six months ended June 30, 2007, income taxes increased $20.0 million and $21.3 million, respectively, compared to the same periods in 2006, primarily reflecting an increase in pre-tax book income.

DPL Inc. – Discontinued Operations

For the quarter ended June 30, 2007, discontinued operations increased $5.1 million compared to the same period in 2006, primarily resulting from the net (pre-tax) gain of $8.2 million realized from the settlement of the litigation with the three former executives less associated income taxes.

For the six months ended June 30, 2007, discontinued operations increased $2.4 million compared to the same period in 2006 primarily resulting from the net (pre-tax) gain of $8.2 million realized from the settlement of the litigation with the three former executives less associated income taxes. This increase was partially offset by a decrease in the deferred gains of $5.0 million relating to the financial asset portfolio realized during 2007 compared to the same period of the prior year less associated income taxes.

See Note 3 and Note 10 of the Notes to Condensed Consolidated Financial Statements.

RESULTS OF OPERATIONS – The Dayton Power and Light Company (DP&L)

Income Statement Highlights – DP&L

	Three Months Ended June 30,						Six Months Ended June 30,
$ in millions	2007			2006			2007			2006

Revenues:
Retail	$	246.3		$	225.7		$	518.1		$	476.7
Wholesale	69.0			63.7			159.0			134.1
RTO ancillary	25.9			17.3			41.6			35.0
Total revenues	$	341.2		$	306.7		$	718.7		$	645.8

Less: Fuel	$	62.3		$	76.2		$	151.8		$	160.1
Purchased power (a)	83.8			38.4			136.5			64.0
Gross margins (b)	$	195.1		$	192.1		$	430.4		$	421.7

Gross margins as a percentage of revenues	57.2		%	62.6		%	59.9		%	65.3		%

Operating income	$	59.7		$	72.7		$	174.4		$	188.2

(a)		Purchased power includes RTO ancillary charges of $17.0 million and $12.1 million for the quarter ended June 30, 2007 and 2006, respectively. Purchased power includes RTO ancillary charges of $29.4 million and $24.3 million for the six months ended June 30, 2007 and 2006, respectively.
(b)		For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance

DP&L – Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, DP&L’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. Since DP&L plans to utilize its internal generating capacity to supply its retail customers’ needs first, increases in retail demand will decrease the volume of internal generation available to be sold in the wholesale market and vice versa.

The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting DP&L’s wholesale sales volume each hour of the year include wholesale market prices, DP&L’s retail demand, retail demand elsewhere throughout the entire wholesale market area, DP&L and non-DP&L plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DP&L’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities not being utilized to meet its retail demand.

	Three Months Ended June 30,			Six Months Ended June 30,
$ in millions	2007 vs. 2006			2007 vs. 2006

Retail
Rate	$	8.1		$	15.7
Volume	13.4			26.8
Other miscellaneous	(0.9		)	(1.1		)
Total retail change	$	20.6		$	41.4

Wholesale
Rate	$	16.8		$	9.0
Volume	(11.5		)	15.9
Total wholesale change	$	5.3		$	24.9

RTO ancillary
RTO services	$	8.6		$	6.6

Total revenues change	$	34.5		$	72.9

For the quarter ended June 30, 2007, revenues increased $34.5 million, or 11%, to $341.2 million from $306.7 million for the same period in the prior year. This increase was primarily the result of higher average rates for retail and wholesale sales, higher retail sales volume and an increase in RTO ancillary revenue. Retail revenues increased $20.6 million, or 9%, resulting from a 6% increase in weather driven sales volume as total degree days increased 18% and a 3% increase in average retail rates related to the Rate Stabilization Plan surcharge and other regulated asset recovery riders. These increases resulted in a $13.4 million sales volume variance and a $8.1 million price variance. Wholesale revenue increased $5.3 million for the second quarter of 2007 compared to the same period of the prior year resulting from higher average market rates, partially offset by lower wholesale sales volume. The increase in average market rates of 32% resulted in a $16.8 million price variance, partially offset by a decrease in wholesale sales volume of 123 GWh resulting in an unfavorable sales volume variance of $11.5 million. For the second quarter of 2007, the RTO ancillary revenues increased $8.6 million compared to the second quarter of 2006 primarily resulting from $4.3 million realized from the PJM capacity auction, $1.8 million of PJM transmission congestion credits and $1.0 million from the sale of financial transmission rights (FTRs). RTO ancillary revenues primarily consist of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves. These revenues are substantially offset by RTO ancillary charges included in purchased power costs.

For the six months ended June 30, 2007, revenues increased $72.9 million, or 11%, to $718.7 million from $645.8 million for the same period in the prior year. This increase was primarily the result of higher average rates and greater sales volumes for both retail and wholesale customers. Retail revenues increased $41.4 million resulting from a 6% increase in weather driven sales volume as total degree days increased 16% and a 3% increase in average retail rates related to the Rate Stabilization Plan surcharge and other regulated asset recovery riders. These increases resulted in a $26.8 million sales volume variance and a $15.7 million price variance. For the six months ended June 30, 2007, wholesale revenue increased $24.9 million over the same period of the prior year primarily ~~reflecting~~as a result of a 12% increase in sales volume (178 GWh) and an 6% increase in wholesale average rates. These increases resulted in a $15.9 million sales volume variance and a $9.0 million price volume variance for wholesale revenues. For the six months ended June 30, 2007, the RTO ancillary revenues increased $6.6 million compared to the same period in 2006 primarily resulting from $4.3 million realized from the PJM capacity auction, $1.8 million of PJM transmission congestion credits and $2.4 million from the sale of financial transmission rights (FTRs), partially offset by an adjustment of $2.8 million for Seams Elimination Cost Adjustment (SECA). RTO ancillary revenues primarily consist of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves. These revenues are substantially offset by RTO ancillary charges included in purchased power costs.

DP&L – Margins, Fuel and Purchased Power

For the second quarter of 2007, gross margin of $195.1 million increased $3.0 million, or 2%, from $192.1 million in the second quarter of 2006. As a percentage of total revenues, gross margin decreased to 57.2% in the second quarter of 2007 compared to 62.6% in the second quarter of 2006. This result reflects the favorable impact of the increase in revenues and lower fuel costs, offset by increased purchased power costs. Fuel costs, which include coal, gas, oil and emission allowance costs, decreased by $13.9 million, or 18%, in the second quarter of 2007 compared to the same period in 2006 due to lower average fuel prices and a 16% (629 GWh) decrease in generation output. Purchased power increased $45.4 million in the second quarter of 2007

compared to the same period in 2006 primarily resulting from increased charges of $39.6 million relating to higher purchased power volume (685 GWh) and $5.8 million increase due to higher average market rates. The increase in purchased power volume was primarily the result of increased sales volume and partner operated generating facilities being less available compared to the same period of the prior year due to planned and unplanned outages. In addition, we purchase power when market prices are below the marginal costs associated with our higher cost generating facilities.

For the six months ended June 30, 2007, gross margin of $430.4 million increased $8.7 million, or 2%, from $421.7 million compared to the same period in 2006. As a percentage of total revenues, gross margin decreased to 59.9% in 2007 compared to 65.3% in 2006. This result reflects the favorable impact of both retail and wholesale revenues discussed above and lower fuel costs offset by increased purchased power costs. Fuel costs, which include coal, gas, oil and emission allowance costs, decreased by $8.3 million, or 5%, for the six months ended June 30, 2007 compared to the same period in 2006 primarily due to a 7% decrease in generation output (580 GWh), partially offset by an increase in average fuel prices. Purchased power increased $72.5 million for the six months ended June 30, 2007 compared to the same period in 2006 primarily resulting from increased charges of $62.2 million relating to higher purchased power volume (1,148 GWh) and $10.3 million increase due to higher average market rates. The increase in purchased power volume was primarily the result of increased sales volume and partner operated generating facilities being less available compared to the prior year due to planned and unplanned outages. In addition, we purchase power when market prices are below the marginal costs associated with our higher cost generating facilities.

DP&L – Operation and Maintenance

	Three Months Ended June 30,			Six Months Ended June 30,
$ in millions	2007 vs. 2006			2007 vs. 2006
Mark-to-market adjustments of restricted stock units (RSUs)	$	(0.5	)	$	2.1
Power production costs	12.0			14.2
Low income payment program	0.8			1.5
Service operations	1.3			1.9
Long-term and other incentive compensation	—			(2.4		)
Legal fees	(2.3		)	(1.4		)
Other, net	1.5			2.1
Total operation and maintenance expense	$	12.8		$	18.0

For the quarter ended June 30, 2007, operation and maintenance expense increased $12.8 million, or 21%, compared to the same period in 2006 primarily resulting from increased power production costs largely related to boiler maintenance of $6.6 million and other power production maintenance expense of $5.4 million.

For the six months ended June 30, 2007, operation and maintenance expense increased $18.0 million, or 16%, compared to the same period in 2006 primarily resulting from increased power production costs largely related to boiler maintenance of $7.1 million and other power production maintenance of $7.1 million. In addition, we had increased mark-to-market adjustments relating to RSUs and increased expense in service operation’s costs relating to overhead line maintenance.

DP&L – Amortization of Regulatory Assets

For the quarter and six months ended June 30, 2007, amortization of regulatory assets increased $0.8 million and $2.6 million, respectively, compared to the same period in 2006. These increases reflect the amortization of costs incurred ~~to modify the customer billing system~~ to accommodate unbundled rates and electric choice ~~bills; $1.0~~bills in the customer billing system; the amortization of PJM administrative fees deferred for the period October 2004 through January 2006; and the amortization of incremental 2004/2005 severe storm costs.

DP&L – Investment Income

For the quarter ended June 30, 2007, investment income increased $3.4 million to $4.7 million from $1.3 million for the ~~amortization~~same period in 2006. This increase was primarily the result of $3.2 million realized gains from the sale of financial assets held in DP&L’s Master Trust Plan for deferred ~~PJM administrative fees; $0.4~~compensation used for the settlement payment to the three former executives.

For the six months ended June 30, 2007, investment income increased $3.0 million to $6.2 million from $3.2 million for the ~~amortization~~same period in 2006. This increase was primarily the result of $3.2 million realized gains from the sale of financial assets held in DP&L’s Master Trust Plan for deferred ~~severe storm costs incurred in 2004 and 2005; and $0.3 million~~compensation used for the amortization of costs incurred to integrate us into the PJM system. We received orders from the PUCO in the first quarter of 2006 approving the recovery of the customer billing costs and PJM administrative fees through rate riders beginning March 2006 and February 2006, respectively. In July 2006, we received a PUCO order approving the recovery of the incremental storm costs through a rate rider beginning in August 2006. The customer billing costs rate rider is expected to be in place for five years, the PJM administrative fee rate rider is expected to collect deferred costs over a three-year period, and the storm costs rate rider is expected to be in place for two years.

~~Investment Income~~

~~Investment income decreased $0.9 million during the third quarter of 2006 compared~~settlement payment to the ~~third quarter of 2005 primarily due to~~three former executives, partially offset by lower interest income ~~earned from~~relating to lower cash ~~on deposit.~~

~~Investment income remained stable for the nine months ended September 30, 2006~~and short-term investment balances in 2007 compared to 2006.

DP&L – Net Gain on Settlement of Executive Litigation

On May 21, 2007, we settled the ~~nine months~~litigation with the three former executives. In exchange for a payment of $25 million, the three former executives relinquished and dismissed all of their claims including those related to deferred compensation, RSUs, MVE incentives, stock options and legal fees. As a result of this settlement, DP&L realized a net pre-tax gain in continuing operations of approximately $35.3 million. See Note 10 of Notes to Condensed Consolidated Financial Statements.

DP&L – Interest Expense

For the quarter ended ~~September~~June 30, ~~2005, increasing only $0.2 million or 4%.~~

Other Income (Deductions)

~~Other income (deductions) remained relatively stable in the third quarter of 2006 compared to the third quarter of 2005, decreasing only $0.6 million that was comprised of various minor items.~~

~~Other income (deductions) for the nine months ended September 30, 2006~~2007, interest expense decreased ~~$4.4~~$0.5 million compared to the same period ~~in 2005. This decrease is primarily attributable to $12.3 million in gains recognized on the sale~~ of ~~pollution control emission allowances during 2005, partially offset by $7.0 million in reduced investment management fees.~~

~~Charge for Early Redemption of Debt~~

For the three months and nine months ended September 30, 2005, we recorded a $4.1 million charge resulting from premiums paid for the early redemption of debt, including the write-off of unamortized debt expense associated with the refinancing of our pollution control debt at reduced interest rates. There was no such activity in 2006.

~~Interest Expense~~

~~Interest expense decreased $4.6 million or 46% for the three months ended September 30,~~ 2006, ~~compared to the same period in 2005,~~ primarily relating to $3.6 million of greater capitalized interest resulting from increased capital expenditures for pollution control equipment at the generating plants and $1.7 million of lower interest expense reflecting the 2005 refinancing of pollution control bonds at reduced interest rates and lower debt service charges associated with DPL Inc.’s early retirement of ESOP debt.

~~Interest expense decreased $13.2 million or 43% in the first nine months of 2006 compared to the first nine months of 2005, primarily relating to $8.0~~$2.9 million of increased capitalized interest resulting from ~~higher~~ pollution control capital expenditures at the generating plants, ~~and $5.3~~partially offset by increased interest of $1.2 million ~~of lower interest expense reflecting~~related to the ~~refinancing of~~$100 million 4.8% Series pollution control bonds issued in September 2006 and $0.7 million of interest related to the $95 million draw on our revolving credit facility.

For the six months ended June 30, 2007, interest expense decreased $1.8 million compared to the same periods of 2006, primarily relating to $5.7 million of increased capitalized interest resulting from pollution control capital expenditures at ~~reduced~~the generating plants, partially offset by increased interest ~~rates~~of $2.4 million related to the $100 million 4.8% Series pollution control bonds issued in ~~2005, lower debt service charges associated with DPL Inc.’s early retirement~~September 2006 and $1.1 million of ~~ESOP debt, and~~interest related to the ~~elimination~~$95 million draw on our revolving credit facility.

DP&L – Other Income (Deductions)

For the quarter ended June 30, 2007, other deductions of $0.2 million changed from $0.8 million of other income in 2006 primarily resulting from a refund of tax penalties in 2006.

For the ~~interest penalty~~six months ended June 30, 2007, other income of $0.6 million increased from $0.3 million of other income in 2006 primarily resulting from the ~~delayed exchange offer~~sale of emission allowances and gains realized on the ~~$470 million 5.125% series First Mortgage Bonds. See Note 6~~expiration of ~~Notes to Consolidated Financial Statements.~~forward contracts partially offset by a refund of tax penalties in 2006.

DP&L – Income Tax Expense

~~Income~~For the second quarter and six months ended June 30, 2007, income taxes increased ~~$1.3~~$10.1 million ~~for the third quarter of 2006~~and $8.6 million compared to the same ~~period~~periods in ~~2005~~2006, primarily reflecting ~~higher~~an increase in pre-tax book ~~income offset by a decrease in the effective tax rate related to the phase-out of the Ohio Franchise Tax.~~

Income taxes increased $6.3 million for the first nine months of 2006 compared to the first nine months of 2005 reflecting higher book income offset in part by a decrease in the effective tax rate related to the phase-out of the Ohio Franchise Tax and a decrease in the tax reserve.

income.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL ~~RESOURCES~~REQUIREMENTS

~~Our~~DPL’s financial condition, liquidity and capital requirements, includes the consolidated results of DP&L and all of DP&L’s consolidated subsidiaries. All material intercompany accounts and transactions have been eliminated in consolidation.

DPL’s Cash Position

DPL’s cash and cash equivalents totaled ~~$57.7~~$103.9 million at ~~September~~June 30, ~~2006,~~2007, compared to ~~$46.2~~$262.2 million at December 31, ~~2005, an increase~~2006, a decrease of ~~$11.5~~$158.3 million. ~~This increase~~In addition, DPL had restricted funds held in trust at June 30, 2007 of $2.2 million in comparison to $10.1 million at December 31, 2006. The decrease in cash and cash equivalents was primarily attributed to ~~$270.7~~the retirement of the $225.0 million DPL 8.25% Senior Notes, $171.2 million in capital expenditures and $55.8 million in dividends paid on common stock. The decrease caused by such payments was partially offset by $158.4 million in proceeds realized from the sale of property ($151.0 million for two peaking units and $7.4 million for an aircraft); $112.4 million in cash generated from operating activities; $15.0 million from the exercise of stock options, including tax effects; and $10.1 million of restricted funds drawn to fund pollution control capital expenditures.

DP&L’s Cash Position

DP&L’s cash and cash equivalents totaled $4.4 million at June 30, 2007, compared to $46.1 million at December 31, 2006, a decrease of $41.7 million. The decrease in cash and cash equivalents was primarily attributed to $169.3 million in capital expenditures and $125.0 million in dividends paid on common stock to our parent DPL. These cash outflows were largely offset by $137.9 million in cash generated from operating activities, $105.0 million in short-term debt owed to our parent DPL, and ~~$23.1~~$10.1 million ofin restricted fund draws to finance pollution control ~~restricted funds, partially offset by $281.7 million in~~ capital expenditures at our generating plants.

Operating Activities

For the six months ended June 30, 2007 and ~~$0.6 million in dividends paid on preferred stock.~~2006, cash flows from operations were as follows:

~~We generated net cash from operating activities of $270.7 million and $273.5 million for the first nine months of 2006 and 2005, respectively. The net cash~~Net Cash provided by ~~operating activities in both years was primarily the result of operating profitability; and by cash provided by certain assets and liabilities.~~ Operating Activities

$ in millions	2007		2006

DPL	$	112.4	$	133.4

DP&L	$	137.9	$	175.2

The tariff-based revenue from our energy business continues to be the principal source of cash from operating activities. Management believes that the diversified retail customer mix of residential, commercial, and industrial classes coupled with the rate relief approved by the PUCO for 2006 and beyond provides us with a reasonably predictable cash flow from ~~utility~~ operations.

DPL’s Cash provided by Operating Activities

DPL generated net cash from operating activities of $112.4 million and $133.4 million for the six months ended June 30, 2007 and 2006, respectively. The net cash provided by operating activities for the six months ended June 30, 2007 was primarily the result of operating profitability, partially offset by an increase in cash used for working capital, specifically receivables, taxes and inventories. The net cash provided by operating activities for the six months ended June 30, 2006 was primarily the result of operating profitability, partially offset by cash used for working capital, specifically taxes.

DP&L’s Cash provided by Operating Activities

DP&L generated net cash from operating activities of $137.9 million and $175.2 million in the six months ended June 30, 2007 and 2006, respectively. The net cash provided by operating activities for the six months ended June 30, 2007 was primarily the result of operating profitability, partially offset by an increase in cash used for working capital, specifically receivables, taxes and inventories. The net cash provided by operating activities for the six months ended June 30, 2006 was primarily the result of operating profitability.

Investing Activities

For the six months ended June 30, 2007 and 2006, cash flows from investing activities were as follows:

Net Cash used for Investing Activities

$ in millions	2007			2006

DPL	$	(15.0	)	$	(72.3	)

DP&L	$	(169.3	)	$	(199.3	)

DPL’s Cash used for Investing Activities

DPL’s net cash used for investing activities was $15.0 million and $72.3 million for the six months ended June 30, 2007 and 2006, respectively. Net cash flows used for investing activities ~~were $281.7 million and $137.1 million in~~for the ~~nine~~six months ended ~~September~~June 30, ~~2006~~2007 were related to capital expenditures that were largely offset by proceeds from the sale of two peaking units and ~~2005, respectively, to provide funding for capital expenditures.~~

an aircraft. Net cash flows ~~provided by financing activities were $22.5 million in the first nine months of 2006 compared to cash~~ used for ~~financing activities of $83.3 million in the first nine months of 2005. Net cash flows provided by financing~~investing activities for the ~~nine~~six months ended ~~September~~June 30, 2006 were ~~primarily the result of $23.1 million of draws from funds held by the trustee~~related to ~~finance our solid waste pollution control~~ capital expenditures, partially offset by ~~$0.6~~the net sale of short-term investments and securities.

DP&L’s Cash used for Investing Activities

DP&L’s net cash flows used for investing activities were $169.3 million and $199.3 million for the six months ended June 30, 2007 and 2006, respectively. Net cash flows used for investing activities for both years were related to capital expenditures.

Financing Activities

For the six months ended June 30, 2007 and 2006, cash flows from financing activities were as follows:

Net Cash used for Financing Activities

$ in millions	2007			2006

DPL	$	(255.7	)	$	(407.0	)

DP&L	$	(10.3	)	$	(0.4	)

DPL’s Cash used for Financing Activities

DPL’s net cash flows used for financing activities for the six months ended June 30, 2007 were $255.7 million compared to the same period of ~~dividends on preferred stock.~~2006 of $407.0 million. Net cash flows used for financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2005~~2007 were the result of cash used to ~~retire long-term debt~~redeem the $225 million 8.25% Senior Notes on March 1, 2007 and to pay dividends to stockholders of $55.8 million, partially offset by cash received from the exercise of stock options, including tax effects, of $15.0 million and the $10.1 million of restricted funds held in trust. Net cash flows used for financing activities for the six months ended June 30, 2006 were the result of cash used to repurchase $348.2 million of common stock and pay dividends onto common shareholders of $59.0 million.

DP&L’s Cash used for Financing Activities

DP&L’s net cash flows used for financing activities were $10.3 million and $0.4 million for the six months ended June 30, 2007 and 2006, respectively. Net cash flows used for financing activities for 2007 were the result of cash used to pay common stock dividends to our parent DPL of $125.0 million and preferred ~~stock. These uses~~dividends to third parties of ~~cash were~~$0.4 million, partially offset by $105.0 million from short-term borrowings from our parent DPL and $10.1 million of withdrawals from the ~~issuance~~trust set up as a result of ~~long-term debt.~~issuing the $100 million 4.8% Series pollution control bonds in September 2006. Net cash flows used for financing activities in 2006 were for the payment of preferred dividends to third parties.

WeDPL and DP&L have obligations to make future payments for capital expenditures, debt agreements, lease agreements and other long-term purchase obligations, and have certain ~~other~~ contingent ~~commitments.~~commitments such as guarantees. We believe our cash flows from operations, the credit facilities (existing or future arrangements), the senior notes and other short- and long-term debt financing, will be sufficient to satisfy our future working capital, capital expenditures and other financing requirements for the foreseeable future. Our ability to generate positive cash flows from operations is dependent on general economic conditions, competitive pressures and other business and risk ~~factors.~~factors described in Item 1a of our fiscal 2006 Form 10-K and Part II, Item 1a of this Form 10-Q. If we are unable to generate sufficient cash flows from operations, or otherwise comply with the terms of our credit facilities, the senior notes and other long-term debt, we may be required to refinance all or a portion of our existing debt or seek additional financing alternatives. A discussion of each of our critical liquidity commitments is outlined below.

Capital Requirements

~~Capital expenditures~~DPL’s construction additions were ~~$281.7~~$193.5 million and ~~$137.1~~$184.2 million for the first ~~nine~~six months of 2007 and 2006, respectively.

DP&L’s construction additions were $192.0 million and ~~2005,~~$183.1 million for the first six months of 2007 and 2006, respectively, and are expected to approximate ~~an aggregate amount of $360~~$308 million in ~~2006.~~ 2007.

Planned construction additions for ~~2006 primarily~~2007 relate to ~~our~~DP&L’s environmental compliance program, power plant equipment and ~~our~~its transmission and distribution system.

Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors. ~~For~~Over the ~~period 2006~~next three years, DPL, through ~~2008, we are~~its subsidiary DP&L, is projecting to spend an estimated ~~$820~~$675 million in capital projects, ~~(previously $810 million),~~ approximately ~~57%~~40% of which is to meet changing environmental standards. In our Form 10-Q as of March 31, 2007, we reported our estimated capital spending to be approximately $645 million. This increase is due primarily to increases capital projects at partner-operated generating plants. Our ability to complete ~~our~~ capital projects and the reliability of future service will be affected by

our financial condition, the availability of internal funds and ~~external funds at~~the reasonable cost ~~and adequate and timely return on these capital investments.~~of external funds. We expect to finance our construction additions in ~~2006~~2007 with a combination of cash on hand, short-term financing, tax-exempt debt and ~~internally-generated funds.~~cash flows from operations.

Debt and Debt Covenants

~~At September 30, 2006, our scheduled maturities~~DP&L is considering issuing in conjunction with the OAQDA another series of capital lease obligations, over the next five years are $0.2 million for the remainder of 2006, $0.9 million in 2007, $0.7 million in 2008, $0.7 million in 2009 and $0.7 million in 2010. Substantially all of our property is subject to the mortgage lien securing the first mortgage bonds. Debt maturities in 2006 are expected to be financed with internal funds. Certain debt agreements contain reporting and financial covenants for which we are in compliance as of September 30, 2006 and expect to be in compliance during the near term.

~~Issuance of additional amounts of first mortgage bonds is limited by the provisions of our mortgage; however, management believes that we continue to have sufficient capacity to issue first mortgage~~tax-exempt bonds to ~~satisfy our requirements in connection with our construction programs. The amounts~~finance the remaining solid waste disposal facility costs at Miami Fort, Killen and ~~timing of future financings will~~

Stuart Generating Stations.

~~depend upon market and other conditions, interest rate increases, levels of electric sales and construction plans.~~

~~We have~~On November 21, 2006, DP&L entered into a ~~$100~~new $220 million unsecured revolving credit agreement replacing its $100 million facility. This new agreement has a five year term that ~~is renewable annually and~~ expires on ~~May 30, 2010. This~~November 21, 2011 and that provides DP&L with the ability to increase the size of the facility ~~may be increased up to $150 million.~~by an additional $50 million at any time. The facility contains one financial covenant: ~~our~~DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This covenant is currently met. WeAs of June 30, 2007, DP&L had no borrowings outstanding ~~borrowings~~ under this ~~credit facility at September 30, 2006.~~facility. Fees associated with this credit facility are approximately $0.2 million per year. Changes in credit ratings, however, may affect fees and the applicable interest ~~rate for our~~rate. This revolving credit ~~agreement.~~

~~During the first quarter~~agreement also contains a $50 million letter of 2006, the Ohio Department of Development (ODOD) awarded us the ability to issue over the next three years up to $200 million of qualified tax-exempt financing from the ODOD’s 2005 volume cap carryforward. The financing is to be used to partially fund the ongoing FGD projects. The PUCO approved our application for this additional financing on July 26, 2006.

~~On September 13, 2006, the Ohio Air Quality Development Authority (OAQDA) issued $100 million of 4.80% fixed interest rate OAQDA Revenue Bonds 2006 Series A due September 1, 2036. In turn,~~ credit sublimit. DP&L then borrowed these funds from the OAQDA. Payment of principal and interest on the Bonds when due is insured by an insurance policy issued by Financial Guaranty Insurance Company. We are using the proceeds from these borrowings to assist in financing our portion of the costs of acquiring, constructing and installing certain solid waste disposal facilities comprising air quality facilities at Miami Fort, Killen and Stuart Generating Stations. These facilities are currently under construction and the proceeds from the borrowings have been placed in escrow with the trustee (the Bank of New York) and are being drawn upon only as facilities are built and qualified costs incurred. In the event any of the proceeds are not drawn, we would eventually be required to return the unused proceeds to bondholders. We expect to draw down all of the proceeds from this borrowing over the next year.

We expect to use the remaining $100 million volume cap carryforward prior to the end of 2008. We are planning to issue in conjunction with the OAQDA another $100 million of tax-exempt bonds to finance the remaining solid waste disposal facilities at Miami Fort, Killen, Stuart and Conesville Generating Stations.

On February 17, 2006, we renewed our $10 million Master Letter of Credit Agreement for one year with a financial lending institution. This agreement supports performance assurance needs in the ordinary course of business. We have has certain contractual agreements for the sale and purchase of power, fuel and related energy services that contain credit rating related clauses allowing the counter parties to seek additional surety under certain conditions. As of ~~September~~June 30, ~~2006, we~~2007, DP&L had ~~two~~no outstanding letters of credit against the facility.

Issuance of additional amounts of first mortgage bonds by DP&L is limited by the provisions of its mortgage; however, management believes that DP&L continues to have sufficient capacity to issue first mortgage bonds to satisfy its requirements in connection with its current refinancing and construction programs. The amounts and timing of future financings will depend upon market and other conditions, rate increases, levels of sales and construction plans.

During the second quarter of 2007, DPL entered into a short-term loan to DP&Lfor ~~a total of $2.2~~$105 million.

This short-term loan does not affect our debt covenants. There are no other inter-company debt collateralizations or debt guarantees between usDPL, DP&L and ~~our parent.~~their subsidiaries. None of ~~our~~the debt obligations of DPL or DP&L are guaranteed or secured by affiliates and no cross-collateralization exists between any subsidiaries.

There was no change to our debt covenants as described in our Form 10-K as of December 31, 2006.

Credit Ratings

Currently, ~~our~~DPL’s senior unsecured and DP&L’s senior secured debt credit ratings are as follows:

	~~Rating~~DPL Inc.	DP&L	Outlook	Effective

Fitch Ratings	ABBB+	A+	Stable	~~April 2006~~March 2007
Moody’s Investors Service
~~Moody’s Investors Service~~Baa3	A3	Positive	June 2006

Standard & Poor’s Corp.	~~BBB~~BBB-	~~Positive~~BBB+	~~August 2006~~Stable	February 2007

Off-Balance Sheet Arrangements

WeDPL and DP&L do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other ~~long-term obligations~~commercial commitments that may affect the liquidity of our operations. At ~~September~~June 30, ~~2006,~~2007, these include:

Contractual Obligations

													Payment Year
			Payment Year												2008-		2010-		2012 &
$ in millions	Total		Less than 1 Year		2 - 3 Years		4 - 5 Years		More than 5 Years		Total		2007		2009		2011		Thereafter
DPL Inc.

Long-term debt	$	783.1	$	—	$	—	$	—	$	783.1	$	1,550.0	$	—	$	275.0	$	297.4	$	977.6
Interest payments	581.7		39.1		78.3		78.3		386.0		1,050.3		47.8		170.7		144.0		687.8
Pension and postretirement payments	249.2		33.4		46.0		47.2		122.6		224.6		11.0		45.2		46.5		121.9
Capital leases	3.2		1.1		1.4		0.7		—		2.5		0.4		1.5		0.6		—
Operating leases	0.5		0.3		0.2		—		—		0.7		0.3		0.3		0.1		—
Fuel and limestone contracts (a)	586.8		86.7		315.5		97.5		87.1
Other long-term obligations	27.5		14.6		9.8		3.1		—
Coal contracts (a)											716.4		195.9		362.8		157.7		—
Limestone contracts (a)											58.1		1.0		9.5		10.9		36.7
Reserve for uncertain tax provisions											41.2		41.2		—		—		—
Other contractual obligations											465.6		397.0		55.4		11.0		2.2
Total contractual obligations	$	2,232.0	$	175.2	$	451.2	$	226.8	$	1,378.8	$	4,109.4	$	694.6	$	920.4	$	668.2	$	1,826.2

DP&L

Long-term debt	$	783.2	$	—	$	—	$	—	$	783.2
Interest payments	552.4		19.6		78.3		78.3		376.2
Pension and postretirement payments	224.6		11.0		45.2		46.5		121.9
Capital leases	2.5		0.4		1.5		0.6		—
Operating leases	0.7		0.3		0.3		0.1		—
Coal contracts (a)	716.4		195.9		362.8		157.7		—
Limestone contracts (a)	58.1		1.0		9.5		10.9		36.7
Reserve for uncertain tax provisions	41.2		41.2		—		—		—
Other contractual obligations	465.6		397.0		55.4		11.0		2.2
Total contractual obligations	$	2,844.7	$	666.4	$	553.0	$	305.1	$	1,320.2

~~(a) DP&L operated units.~~

(a) DP&L operated units

Long-term debt:

~~Long-term~~DPL’s long-term debt as of ~~September~~June 30, ~~2006,~~2007, consists of ~~our~~DP&L’s first mortgage bonds and tax-exempt pollution control bonds, DPL unsecured notes and includes current maturities and unamortized debt discounts.

DP&L’s long-term debt as of June 30, 2007, consists of first mortgage bonds, tax-exempt pollution control bonds and includes an unamortized debt discount. ~~(See~~

See Note 68 of Notes to Condensed Consolidated Financial Statements.)

Interest payments:

Interest payments associated with the long-term debt described above.

Pension and postretirement payments:

As of ~~September~~June 30, ~~2006, we~~2007, DP&L had estimated future benefit payments as outlined in Note 46 of Notes to Condensed Consolidated Financial Statements. These estimated future benefit payments are projected through 2016.

Capital leases:

As of ~~September~~June 30, ~~2006, we~~2007, DP&L had two capital leases that expire in November 2007 and September 2010.

Operating leases:

As of ~~September~~June 30, ~~2006, we~~2007, DPL and DP&L had several operating leases with various terms and expiration dates. Not included in this total is approximately ~~$88 thousand~~$88,000 per year related to right-of-way agreements that are assumed to have no definite expiration dates.

~~Fuel and limestone~~Coal contracts:

~~We have~~DP&L has entered into various long-term coal contracts to supply portions of ~~our~~its coal requirements for ~~our~~its generating ~~plants and a long-term contract to supply limestone for the operation of our flue gas desulfurization (FGD) units. Coal contract~~plants. Contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.

~~A new long-term barge agreement~~Limestone contracts:

DP&L has entered into a limestone contract to supply limestone for its generating facilities.

Reserve for uncertain tax positions:

On January 1, 2007, we adopted Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). There was ~~executed~~no significant impact to our overall results of operations, cash flows or financial position. The total amount of unrecognized tax benefits as of the date of adoption was $36.8 million and we have recorded $3.5 million (net of tax) of accrued interest. During the second quarter ending June 30, 2007, we recorded an additional $0.9 million in accrued interest resulting in a total reserve for ~~five years beginning September 2006.~~uncertain tax positions of $41.2 million as of June 30, 2007. None of the amount of unrecognized tax benefits is due to uncertainty in the timing of deductibility.

Other ~~long-term~~contractual obligations:

As of ~~September~~June 30, ~~2006, we~~2007, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

We enter into various commercial commitments, which may affect the liquidity of our operations. At ~~September~~June 30, ~~2006,~~2007, these include:

Credit facilities:

~~We have a~~In November 2006, DP&L replaced its previous $100 million ~~364-day unsecured~~revolving credit agreement with a $220 million five-year facility that ~~is renewable annually and~~ expires on ~~May~~November 21, 2011. DP&L has the ability to increase the size of the facility by an additional $50 million at any time. At June 30, ~~2010. At September 30, 2006,~~2007, there were no outstanding borrowings ~~outstanding~~ under this ~~credit agreement. The facility may be increased up to $150 million.~~facility.

~~Guarantee:~~Guarantees:

~~We own~~DP&L owns a 4.9% equity ownership interest in an electric generation company. As of ~~September~~June 30, ~~2006, we~~2007, DP&L could be responsible for the repayment of 4.9%, or $21.8 million, of a $445 million debt obligation that matures in 2026.

$ in millions	2007		2008		2009		2010
Darby	$	30.6	$	23.0	$	15.3	$	7.7

Greenville	$	14.8	$	11.1	$	7.4	$	3.7

MARKET RISK

As a result of our operating, investing and financing activities, we are subject to certain market risks including ~~fluctuations in interest rates and~~ changes in commodity prices for electricity, coal, environmental emissions and ~~gas.~~gas as well as fluctuations in interest rates. Commodity pricing exposure includes the impacts of weather, market demand, ~~potential coal supplier contract breaches or defaults,~~ increased competition and other economic conditions. For purposes of potential risk analysis, we use sensitivity ~~analyses~~analysis to quantify potential impacts of market rate changes on the results of operations. The sensitivity ~~analyses represent~~analysis represents hypothetical changes in market values that may or may not occur in the future.

Commodity Pricing Risk

Approximately 12% of DPL’s and 22% of ~~our first nine~~DP&L’s electric revenues for the six months ~~2006 revenues~~ended June 30, 2007 were from sales of excess energy and capacity in the wholesale market. Energy and capacity in excess of the needs of existing retail customers are sold inon the wholesale market when we can identify opportunities with positive margins. As of ~~September~~June 30, ~~2006,~~2007, a hypothetical increase or decrease of 10% in DPL’sannual wholesale revenues could result in approximately ~~a $19~~an $11 million increase or decrease to annual net income, assuming no increases or decreases in fuel and purchased power costs. As of June 30, 2007, a hypothetical increase or decrease of 10% in DP&L’s annual wholesale revenues could result in approximately a $20 million increase or decrease to annual net income, assuming no increases or decreases in fuel and purchased power costs.

DPL’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percent of total operating costs in the six months ended June 30, 2007 and 2006, respectively, were 52% and 46%, respectively. DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percent of total operating costs were 53% and 49% in the six months ended June 30, 2007 and 2006, respectively. We have ~~approximately 100% and 83%~~substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for ~~2006 and~~ 2007 ~~respectively,~~ under contract. The majority of our contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustment and some are priced based on market indices. Substantially all contracts have features that limit price escalations in any given year. Our ~~2006 emission allowance (SO~~2 ~~and NO~~x) consumption ~~is expected to be similar to 2005. Our holdings~~ of SO2 ~~and NO~~x allowances ~~are approximately equal~~should decline in 2007 due to ~~our expected needs from 2006 through 2010. There may be exchanges of allowances between future years to balance our 2006-2010 position.~~planned emission control upgrades. We do not expect to purchase SO2 allowances ~~outright~~ for ~~2006.~~2007. The exact consumption of SO2 ~~and NO~~xallowances will depend on market prices for power, ~~and~~ availability of our ~~generating units. The utilization~~generation units, the timing of SO2 ~~allowances will depend upon~~emission control equipment upgrade completion and the actual sulfur content of the coal burned.DP&L does not plan to purchase NOx allowances for 2007. Fuel costs are impacted by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and generation plant mix. Fuel costs are forecasted to ~~increase approximately 7% in 2006 compared to 2005 and are forecasted to increase approximately 5%~~be flat in 2007 compared to 2006. ~~This forecast assumes coal prices will increase approximately 10% in 2006 as compared to 2005 and increase approximately 5% in 2007 as compared to 2006.~~

Purchased power costs depend, in part, upon the timing and extent of planned and unplanned outages of our generating capacity. We will purchase power on a discretionary basis when wholesale market conditions provide opportunities to obtain power at a cost below our internal production costs. As of ~~September~~June 30, ~~2006,~~2007, a hypothetical increase or decrease of 10% in DPL’sannual fuel and purchased power costs ~~excluding Regional Transmission Organization (RTO) services,~~ could result in approximately a ~~$29~~$32 million decrease or increase to annual net income, assuming no decreases or increases in sales revenues. As of June 30, 2007, a hypothetical increase or decrease of 10% in DP&L’s annual fuel and purchased power costs could result in approximately a $32 million increase or decrease to annual net ~~income.~~

income, assuming no decreases or increases in sales revenues.

Interest Rate Risk

As a result of our normal borrowing and leasing activities, our results are exposed to fluctuations in interest rates, which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. Our long-term debt represents ~~publicly-held~~publicly and privately held secured and unsecured notes and debentures with fixed interest rates. At ~~September~~June 30, ~~2006,~~2007, we had no ~~short-term borrowings.~~outstanding borrowings under our revolving credit facility.

The carrying value of ~~our~~DPL’s debt was ~~$786.3~~$1,552.5 million at ~~September~~June 30, ~~2006,~~2007, consisting of ~~our~~DP&L’s first mortgage bonds, ~~our~~DP&L’s tax-exempt pollution control bonds, our unsecured notes and ~~our~~DP&L’s capital leases. The fair value of this debt was ~~$789.5~~$1,566.8 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The principal cash repayments and related weighted average interest rates by maturity date for long-term, fixed-rate debt at ~~September~~June 30, ~~2006~~2007, are as follows:

		Long-term Debt
Expected Maturity	Expected Maturity	Amount				DPL’s Long-term Debt
Date	Date	($ in millions)		Average Rate		Amount		Average Rate
						($ in millions)
2006		$	0.2	6.0	%

2007		0.9		6.1	%	$	0.4	6.3	%
2008		0.7		6.9	%	100.7		6.3	%
2009		0.7		6.9	%	175.8		8.0	%
2010		0.7		6.9	%	0.6		6.9	%
2011						297.4		6.9	%
2012						—		—
Thereafter		783.1		5.0	%	977.6		5.6	%
Total		$	786.3	5.0	%	$	1,552.5	6.2	%

Fair Value		$	789.5			$	1,566.8

The carrying value of DP&L’s debt was $785.7 million at June 30, 2007, consisting of our first mortgage bonds, our tax-exempt pollution control bonds and our capital leases. The fair value of this debt was $767.3 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The principal cash repayments and related weighted average interest rates by maturity date for long-term, fixed-rate debt at June 30, 2007, are as follows:

Expected Maturity	DP&L’s Long-term Debt
Date	Amount		Average Rate
	($ in millions)

2007	$	0.4	6.3	%
2008	0.7		6.9	%
2009	0.8		6.9	%
2010	0.6		6.9	%
2011	—		—
2012	—		—
Thereafter	783.2		5.0	%
Total	$	785.7	5.0	%

Fair Value	$	767.3

Debt maturities for DPL and DP&Lin ~~2006~~2007 are expected to be financed with a combination of short-term borrowings, tax-exempt pollution control bonds and internal funds.

CRITICAL ACCOUNTING ~~POLICIES AND~~ ESTIMATES

~~We prepare our~~DPL’s and DP&L’s condensed consolidated financial statements are prepared in accordance with ~~accounting principles generally accepted in~~GAAP. In connection with the ~~United States of America (GAAP).~~

~~The~~ preparation of these financial statements, ~~in conformity with GAAP requires us~~our management is required to make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and ~~liabilities,~~ the related disclosure of contingent ~~assets~~liabilities. These assumptions, estimates and ~~liabilities~~judgments are based on our historical experience and assumptions that we believed to be reasonable at the ~~date~~time. However, because future events and their effects cannot be determined with certainty, the determination of estimates requires the ~~financial statements, and the revenue and expenses~~exercise of ~~the period reported.~~ judgment. Our critical accounting estimates are those which require assumptions to be made about matters that are highly uncertain.

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Significant items subject to such ~~estimates and~~ judgments ~~include~~include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of ~~derivative instruments;~~insurance and claims costs; valuation allowances for receivables and deferred income taxes; the valuation of reserves ~~recorded for income tax exposures;~~related to current litigation; ~~regulatory proceedings and orders;~~ and assets and liabilities related to employee benefits. Actual results may differ from those estimates. Refer to our ~~2005~~2006 Annual Report filed on Form 10-K for a complete listing of our critical accounting policies and estimates.

Recently Issued Accounting Pronouncements

A discussion of recently issued accounting pronouncements is described in Note 1 of Notes to Condensed Consolidated Financial Statements and such discussion is incorporated by reference in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.

~~THE DAYTON POWER AND LIGHT COMPANY~~

OPERATING STATISTICS

	DPL Inc.								DP&L (a)
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006		2007		2006		2007		2006
Electric sales (millions in kWh)
Residential	1,133		1,039		2,771		2,507		1,133		1,039		2,771		2,507
Commercial	1,005		938		1,937		1,831		1,005		938		1,937		1,831
Industrial	1,117		1,097		2,094		2,085		1,117		1,097		2,094		2,085
Other retail	376		351		714		689		376		351		714		689
Total retail	3,631		3,425		7,516		7,112		3,631		3,425		7,516		7,112

Wholesale	558		681		1,678		1,500		558		681		1,678		1,500

Total	4,189		4,106		9,194		8,612		4,189		4,106		9,194		8,612

Operating revenues ($ in thousands)
Residential	$	114,340	$	101,464	$	262,317	$	232,095	$	114,340	$	101,464	$	262,317	$	232,095
Commercial	81,064		73,000		155,762		144,299		75,888		67,630		146,875		133,520
Industrial	62,993		59,687		120,489		117,492		34,905		32,537		66,524		63,372
Other retail	24,304		21,627		45,830		42,234		19,659		21,626		38,067		42,295
Other miscellaneous revenues	1,433		2,414		4,283		5,393		1,453		2,427		4,317		5,411
Total retail	$	284,134	$	258,192	$	588,681	$	541,513	$	246,245	$	225,684	$	518,100	$	476,693

Wholesale	30,418		30,522		87,103		67,942		68,975		63,671		159,007		134,031

RTO ancillary revenues	25,894		17,339		41,556		35,043		25,894		17,339		41,556		35,043

Other revenues, net of fuel costs	2,694		2,925		5,493		5,623		—		—		—		—

Total	$	343,140	$	308,978	$	722,833	$	650,121	$	341,114	$	306,694	$	718,663	$	645,767

Electric customers at end of period
Residential	456,098		456,654		456,098		456,654		456,098		456,654		456,098		456,654
Commercial	49,450		49,134		49,450		49,134		49,450		49,134		49,450		49,134
Industrial	1,818		1,839		1,818		1,839		1,818		1,839		1,818		1,839
Other	6,377		6,338		6,377		6,338		6,377		6,338		6,377		6,338

Total	513,743		513,965		513,743		513,965		513,743		513,965		513,743		513,965

Three months ended

Nine months ended

September 30,

September 30,

2006

2005

2006

2005

Sales (millions of kWh)

Residential

1,432

1,546

3,939

4,182

Commercial

1,075

1,086

2,906

2,937

Industrial

1,169

1,174

3,254

3,281

Other retail

380

380

1,069

1,077

Other miscellaneous revenues

—

—

—

—

Total retail

4,056

4,186

11,168

11,477

Wholesale

1,149

719

2,649

1,913

Total sales

5,205

4,905

13,817

13,390

Revenues ($ in thousands)

Residential

$
137,317

$
136,337

$
369,412

$
362,294

Commercial

73,672

64,875

207,192

184,372

Industrial

35,214

33,887

98,586

95,602

Other retail

22,779

20,844

65,074

60,707

Other miscellaneous revenues

3,289

2,771

8,700

7,836

Total retail

272,271

258,714

748,964

710,811

Wholesale

97,438

74,567

231,469

186,029

RTO ancillary revenues

20,653

22,239

55,696

55,191

Total revenues

$
390,362

$
355,520

$
1,036,129

$
952,031

Electric customers at end of period

513,469

511,948

513,469

511,948

(a) DP&L sells power to DPLER (a subsidiary of DPL). These sales are classified as wholesale on DP&L’s financial statements and retail sales for DPL. The kWh volumes contain all volumes distributed on the DP&L system which include the retail sales by DPLER. The sales for resale volumes are omitted to avoid duplicate reporting

Item 3. Quantitative and Qualitative Disclosures about Market Risk

See the “Market Risk” section of Item 2.

Item 4. Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to us and our subsidiaries is communicated to the CEO and CFO. We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are ~~effective~~effective: (i) to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) to ensure that information required to be disclosed by us in the reports that we submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

There was no change in our internal control over financial reporting during the most recently completed quarter ended June 30, 2007 that has materially affected, or is reasonably likely to materially affect, internal control over reporting.

PART II~~Part II. Other Information~~

Item 1. 1 - Legal Proceedings

In the normal course of business, we ~~have has been named a defendant~~are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal ~~actions, including arbitrations, class actions~~proceedings, claims, and other ~~litigation. Certain~~matters discussed below, and to comply with applicable laws and regulations will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of ~~the legal actions include claims for substantial compensatory and/or punitive damages or claims for indeterminate~~those amounts provided as of damages. We are is also involved in other reviews, investigations and proceedings by governmental and self-regulatory organizations regarding our business. Certain of the foregoing could result in adverse judgments, settlements, fines, penalties or other relief.

Because litigation is inherently unpredictable, particularly in cases where claimants seek substantial or indeterminate damages or where investigations and proceedings are in the early stages, we cannot predict with certainty the loss or range of loss related to such matters, how such matters will be resolved, when they will be ultimately resolved, or what the eventual settlement, fine, penalty or other relief might be. Consequently, we cannot estimate losses or ranges of losses for matters where there is only a reasonable possibility that a loss may have been incurred. Although the ultimate outcome of these mattersJune 30, 2007, cannot be ascertained at this time, it is the opinion of management, that the resolution of the foregoing matters will not have a material adverse effect on our financial condition, taken as a whole; such resolution may, however, have a material effect on the operating results in any future period, depending on the level of income for such period.

~~We have provided reserves for such matters in accordance with SFAS 5, “Accounting for Contingencies.” The ultimate resolution may differ from the amounts reserved.~~reasonably determined.

Certain legal proceedings in which we are involved are discussed in Part I, Item 1—Environmental Considerations, Item 1—Competition and Regulation, Item 3 and Note 1115 to the Consolidated Financial Statements ~~and, Part I, Item 3,~~included therein of our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2005; and Note 7 to the Consolidated Financial Statements and Part II, Item 1, included in our Form 10-Q for the quarterly period ended March 31, 2006 and June 30,~~ 2006. The following discussion is limited to recent developments concerning our legal proceedings and should be read in conjunction with this earlier report.

Executive Litigation

On May 21, 2007, we settled the litigation with the three former executives. As part of this settlement, the three former executives relinquished and dismissed all their claims including those ~~earlier reports.~~related to certain deferred compensation, restricted stock units (RSUs), MVE incentives, stock options and legal fees. The RSUs and stock options relinquished and forfeited were 1.3 million and 3.6 million, respectively. Prior to the settlement date, DPL had accrued obligations of approximately $64.2 million of which DP&L had accrued obligations of approximately $60.3 million. Included in these amounts is approximately $3.1 million associated with the forfeiture of stock options. In exchange for our payment of $25 million, all of these claims were settled.

~~On January 13, 2006, we filed~~As a ~~claim against one~~result of this settlement DPL realized a net pre-tax gain in continuing and discontinued operations of approximately $31.0 million and $8.2 million, respectively. The net gain is comprised of the reversal of the $64.2 million of accrued obligations less the $25 million settlement. The obligations related to the discontinued operations were associated with the management of DPL’s financial asset portfolio which was conducted in our ~~insurers, Associated Electric & Gas Insurance Services (AEGIS), under~~MVE subsidiary. The MVE operations were discontinued in 2005 with the sale of the financial asset portfolio. The $25 million settlement expense was allocated between continuing and discontinued operations based on the proportionate share of continuing and discontinued obligations. The following table outlines the components of DPL’s net pre-tax gain for continuing and discontinued operations:

Continuing operations:
Reversal of accrued obligations	$	50.8
Allocated settlement expense	(19.8		)
Net gain from continuing operations	$	31.0

Discontinued operations:
Reversal of accrued obligations	$	13.4
Allocated settlement expense	(5.2		)
Net gain from discontinued operations	$	8.2

As a ~~fiduciary liability policy to recoup legal fees~~result of this settlement, DP&L realized a net pre-tax gain in continuing operations of approximately $35.3 million. Accrued obligations associated with the former executives’ litigation were recorded by DP&L since the obligations were associated with our ~~litigation against three former executives. An arbitration~~non-qualified benefit plans. DP&L had no ownership of DPL’s financial asset portfolio business which was discontinued, therefore these liabilities were reversed and DP&L net pre-tax gain was recorded within continuing operations. The following table outlines the components of DP&L’s net gain:

Continuing operations:
Reversal of accrued obligations	$	60.3
Allocated settlement expense	(25.0		)
Net gain	$	35.3

The $25 million settlement was funded from the sale of financial assets held in DP&L’s Master Trust Plan for deferred compensation. As part of this matter was held on August 4, 2006. The arbitration panel ruled on or about September 12, 2006 that the AEGIS policy does not require an advance of defense expenses to us. Rather, the arbitration panel stated that we are required to filetransaction, DPL and DP&L recorded a written undertaking as a condition precedent to repay expenses finally established not to be insured. We have filed a written undertaking with AEGIS and will continue to pursue resolution of the claim through mediation and arbitration$3.2 million realized gain which is reflected in ~~2007.~~investment income.

In September 2006, we became aware of unasserted claims under the Fair Labor Standards Act concerning the calculation of overtime rates for our unionized workforce. We will vigorously oppose this claim, if asserted against us. However, if we do not prevail, the cost to us would be in the range of $0-$3.5 million.

~~On September 21,~~ 2004, the Sierra Club filed a lawsuit against us DP&L and the other owners of the Stuart Generating Station in the United States District Court for the Southern District of Ohio for alleged violations of the ~~Clean Air Act (CAA). On October 13, 2006,~~CAA and ~~pursuant~~the Station’s operating permit. DP&L, on behalf of all co-owners, is leading the defense of this matter. A sizable amount of discovery has taken place, the first set of expert reports have been filed with additional report scheduled to ~~an approved procedural schedule, the Sierra Club~~be filed ~~an amended complaint setting forth additional actions taken by us that the Sierra Club alleges were also~~ in ~~violation of the CAA. We~~September 2007. Dispositive motions are ~~currently reviewing that amended complaint and will vigorously defend our action. The case is currently~~to be filed in ~~discovery; a~~January 2008. No trial date has ~~not~~ been ~~set.~~set yet.

Item ~~1A.~~ 1a – Risk Factors

A comprehensive listing of risk factors that we consider to be the most significant to your decision to invest in usour stock is provided in our most recent Annual Report on Form 10-K and is incorporated herein by reference. The Form 10-K may be obtained as discussed on ~~page 2, ‘Available Information.~~Page 4, ‘Website Access to Reports.’ If any of these events occur, our business, financial position or results of operation could be materially affected. The following risk factors ~~are additions to~~included in our ~~2005 Annual Report on~~2006 Form 10-K ~~discussion~~for year ended December 31, 2006 has been updated as follows:

Reliance on ~~risk factors.~~Third Parties

We rely on many third party suppliers and contractors in our energy production, transmission and distribution functions, including the purchase and delivery of coal and other inventory, the construction of capital assets, and waste disposal management associated with our production processes (such as bottom ash, fly ash, gypsum). Unanticipated changes in our purchasing processes, supplier availability, supplier performance and pricing may affect our business and operating results. In addition, we rely on others to provide professional services, such as, but not limited to, actuarial calculations, internal audit services, payroll processing and various consulting services.

Employees

Approximately 53% our employees are under a collective bargaining agreement. If we are unable to negotiate future collective bargaining agreements, we could experience work stoppages which may affect its business and operating results.

Item 2 – Unregistered Sale of Equity Securities and Use of Proceeds

None

Item 3 – Defaults Upon Senior Securities

None

Item 4 – Submission of Matters to a Vote of Security Holders

DPL held its Annual Meeting of Shareholders on April 27, 2007 at which security holders elected three directors nominated for three-year terms expiring 2010. The results of the voting were as follows:

	FOR	WITHHELD	BROKER NO-VOTE
Robert D. Biggs	96,810,176	1,798,891	—
W August Hillenbrand	96,824,955	1,784,112	—
Ned J. Sifferlen	97,139,872	1,469,195	—

~~Greenhouse gas (GHG) emissions, consisting primarily~~The other directors whose terms of ~~carbon dioxide emissions,~~office continued after the Annual Meeting are ~~presently unregulated. Numerous bills have been introduced~~Paul M. Barbas, Barbara S. Graham and Glenn E. Harder (each in ~~Congress to regulate GHG emissions, but to date none have passed. Future regulation~~the Class of ~~GHG emissions is uncertain. However, such regulation would be expected to impose costs~~2008) and Paul R. Bishop, Ernie Green and General Lester L. Lyles (Ret.) (each of the class of 2009). On May 29, 2007, Ernie Green retired from the Board of Directors of DPL Inc.

Shareholders also voted on ~~our operations. Such costs could include measures as advanced by various constituencies, including a carbon tax; investments in energy efficiency; installation of CO~~2 ~~emissions control technology,~~an amendment to the ~~extent such technology exists; purchase~~Regulations of ~~emission allowances, should~~DPL Inc. to provide a ~~trading mechanism be developed; or~~majority vote alternative for the ~~use~~election of ~~higher-cost, lower CO~~2 ~~emitting fuels. We will continue to make prudent investments in energy efficiency that reduces our GHG emissions intensity.~~

Wright Patterson Air Force Base (WPAFB) represents approximately 1% of our annual revenues. WPAFB has the right to select another competitive retail electric supplier to meet its generationg needs. Effective August 2006, WPAFB secures its generation under our standard offer rate until such time as they choose to contract with an alternative supplier. If this occurs, this could impact ourdirectors. The results of ~~operations.~~the voting were as follows:

FOR		AGAINST		ABSTAIN		BROKER NO-VOTE
74,499,396		3,374,009		1,104,999		19,630,663

~~We are currently constructing flue gas desulfurization (FGD) facilities at five units located at our J. M. Stuart and Killen Electric Generating Stations. Construction~~Shareholders also voted on two shareholder proposals. The first shareholder proposal covered a recommendation on executive bonuses. The results of the FGD facilities at each unit is scheduled to be completed in phases commencing mid-year 2007 through 2008. We are also co-owners of electric generating stations operated by other investor-owned utilities, who are in various stages of constructing FGD facilities at these stations. Significant construction delays could adversely affect our ability to operate or may substantially increase our costs to operate these electric generating stations under federal environmental laws and regulations that become effective in 2010. For those electric generating stations where we are co-owners but do not operate, significant construction delays may substantially increase our pro rata sharevoting were as follows:

FOR		AGAINST		ABSTAIN		BROKER NO-VOTE
15,607,538		61,329,703		2,041,164		19,630,662

The second shareholder proposal covered majority vote reincorporation. The results of the ~~cost~~voting were as follows:

FOR		AGAINST		ABSTAIN		BROKER NO-VOTE
25,101,148		51,864,501		2,012,756		19,630,662

Shareholders also voted to ~~operate those facilities beginning in 2010.~~

~~Annually, PJM,~~ratify the ~~regional transmission organization that provides transmission services~~selection of KPMG LLP as the Company’s independent auditor for ~~a large portion~~2007. The results of the midwest United States, performs a review of the capital additions required to provide reliable electric transmission services throughout its territory. PJM allocates the costs of constructing these facilities to the applicable entity that will benefit from the new construction. FERC is authorized to provide rate recovery to utilities for the costs they incur to construct these transmission facilities. To date, we have not been required to construct any new facilities nor have we been assigned any costsvoting were as ~~a result of PJM’s annual review, but there is no guarantee that we will not be assigned some costs or be required to construct facilities in the future.~~follows:

FOR		AGAINST		ABSTAIN		BROKER NO-VOTE
96,680,131		1,055,580		873,354		—

Item 5 – Other Information

None

Item 6. 6 – Exhibits

~~4.1~~DPL Inc.	DP&L	Exhibit Number	Exhibit	Location
X	Loan Agreement, dated as of September 1, 2006, by and between Ohio Air Quality Development Authority and The Dayton Power and Light Company (Filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on September 19, 2006, File #1-2385)
X
~~4.2~~	44th Supplemental Indenture to the First and Refunding Mortgage, dated as of September 1, 2006, by and between the Bank of New York, as trustee and The Dayton Power and Light Company (Filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on September 19, 2006, File #1-2385)

~~10.1~~	~~Non-Employee Director Compensation Summary dated as of September 19, 2006 (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 25, 2006, File #1-2385)~~

~~31.1~~31(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)

~~31.2~~X	X	31(b)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)

X	X	32(a)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)

X	X	32(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, DPL Inc. and The Dayton Power and Light Company has duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.

					DPL INC.
					The Dayton Power and Light Company
					(Registrants)

32					~~Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002~~

~~SIGNATURES~~

~~Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.~~

Date:		~~THE DAYTON POWER AND LIGHT COMPANY~~July 26, 2007			/s/ Paul M. Barbas
		~~(Registrant)~~			Paul M. Barbas
					President and Chief Executive Officer
					(principal executive officer)


		July 26, 2007			/s/ John J. Gillen

~~Date:~~	~~October 31, 2006~~		~~/s/ Paul M. Barbas~~	John J. Gillen
		~~Paul M. Barbas~~			Senior Vice President and Chief Financial Officer
		~~President and Chief Executive Officer~~
		(principal ~~executive~~financial officer)



	~~October 31, 2006~~		~~/s/ John J. Gillen~~
		~~John J. Gillen~~July 26, 2007
		~~Senior Vice President and Chief Financial Officer~~
			~~(principal financial officer)~~	/s/ Frederick J. Boyle
					Frederick J. Boyle

	~~October 31, 2006~~		~~/s/ Frederick J. Boyle~~
			~~Frederick J. Boyle~~
		Controller and Chief Accounting Officer

				(principal accounting officer)

3661

~~OHIO~~Commission File Number	~~31-0258470~~Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
~~(State or other jurisdiction of~~	~~(I.R.S. Employer~~
~~incorporation or organization)~~	~~Identification No.)~~

~~1065 Woodman Drive, Dayton,~~1-9052	DPL INC.	31-1163136
	(An Ohio Corporation)
	1065 Woodman Drive Dayton, Ohio 45432
~~(Address of principal executive offices)~~	937-224-6000

1-2385	THE DAYTON POWER AND LIGHT COMPANY	31-0258470
	(~~Zip Code)~~An Ohio Corporation)
	1065 Woodman Drive Dayton, Ohio 45432
	937-224-6000

~~Yes~~ x	DPL Inc.		Yes xNo o
	The Dayton Power and Light Company		Yes x No o

~~Large accelerated filer~~ o		~~Accelerated~~	Large accelerated filero	Accelerated filer	Non-accelerated filer
	DPL Inc.		x	o	o
	The Dayton Power and Light Company		o	o	x

~~Yes~~ o	DPL Inc.		Yes oNo x
	The Dayton Power and Light Company		Yes o No x

	Registrant				~~Page No.~~
~~Part I.~~Description	~~Financial Information~~		Shares Outstanding

DPL Inc.		~~Item 1.~~Common Stock, $0.01 par value		~~Financial Statements~~113,553,444

The Dayton Power and Light Company		Common Stock		41,172,173

Part I Financial Information
				3
		Item 1	~~Consolidated~~Financial Statements ~~of Results of Operations~~– DPL and DP&L
				4
			~~Consolidated Statements of Cash Flows~~

			~~Consolidated Balance Sheets~~	5

			~~Notes to Consolidated Financial Statements~~	7

	~~Item 2.~~Condensed Consolidated Statement of Results of Operations – DPL	4

	Condensed Consolidated Statement of Cash Flows – DPL	5

	Condensed Consolidated Balance Sheet – DPL	6

	Condensed Consolidated Statement of Results of Operations – DP&L	8

	Condensed Consolidated Statement of Cash Flows – DP&L	9

	Condensed Consolidated Balance Sheet – DP&L	10

	Notes to Condensed Consolidated Financial Statements	12

Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		2036

			~~Operating Statistics~~	32

	~~Item 3.~~Operating Statistics	57

Item 3	Quantitative and Qualitative Disclosures about Market Risk		3257

	Item 4.4		Controls and Procedures	3257

Part ~~II.~~II Other Information

Item 1	Legal Proceedings	58

Item 1A	Risk Factors	59

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	59

Item 3	Defaults Upon Senior Securities	59

Item 4	Submission of Matters to a Vote of Security Holders	59

Item 5	Other Information	60

Item 6	Exhibits	60

Other

	~~Item 1.~~Signatures		~~Legal Proceedings~~	3361

	~~Item 1A.~~		~~Risk Factors~~	34

	~~Item 6.~~		~~Exhibits~~	35

~~Other~~

	~~Signatures~~			36

	Certifications

	Three Months Ended June 30,						Six Months Ended June 30,
$ in millions except per share amounts	2007			2006			2007			2006

Revenues	$	343.1		$	309.0		$	722.8		$	650.1

Cost of revenues:
Fuel	63.5			78.6			153.8			162.8
Purchased power	83.2			37.0			135.4			62.3
Total cost of revenues	146.7			115.6			289.2			225.1

Gross margin	196.4			193.4			433.6			425.0

Operating expenses:
Operation and maintenance	61.5			70.6			130.8			133.0
Depreciation and amortization	35.5			38.2			69.0			75.1
General taxes	27.5			27.0			55.5			55.0
Amortization of regulatory assets	2.5			1.7			5.4			2.8
Total operating expenses	127.0			137.5			260.7			265.9

Operating income	69.4			55.9			172.9			159.1

Other income / (expense), net
Net gain on settlement of executive litigation	31.0			—			31.0			—
Investment income	5.3			4.5			8.3			10.9
Interest expense	(19.4		)	(25.9		)	(42.5		)	(52.2		)
Other income (deductions)	(0.2		)	0.6			0.6			0.3
Total other income / (expense), net	16.7			(20.8		)	(2.6		)	(41.0		)

Earnings from continuing operations before income tax	86.1			35.1			170.3			118.1

Income tax expense	32.5			12.5			65.5			44.2

Earnings from continuing operations	53.6			22.6			104.8			73.9

Earnings from discontinued operations, net of tax	5.1			—			10.0			7.6

Net Income	$	58.7		$	22.6		$	114.8		$	81.5

Average number of common shares outstanding (millions)
Basic	107.9			114.1			107.7			117.1
Diluted	119.5			123.4			119.4			126.3

Earnings per share of common stock
Basic:
Earnings from continuing operations	$	0.50		$	0.20		$	0.98		$	0.63
Earnings from discontinued operations	0.04			—			0.09			0.07
Total Basic	$	0.54		$	0.20		$	1.07		$	0.70

Diluted:
Earnings from continuing operations	$	0.45		$	0.18		$	0.88		$	0.59
Earnings from discontinued operations	0.04			—			0.08			0.06
Total Diluted	$	0.49		$	0.18		$	0.96		$	0.65

Dividends paid per share of common stock	$	0.26		$	0.25		$	0.52		$	0.50

Preferred Stock	Rate	Current Redemption Price		Current Shares Outstanding at September 30, 2006	Par Value At September 30, 2006		Par Value At December 31, 2005
					($ in millions)		($ in millions)
Series A	3.75%	$	102.50	93,280	$	9.3	$	9.3
Series B	3.75%	$	103.00	69,398	7.0		7.0
Series C	3.90%	$	101.00	65,830	6.6		6.6
Total				228,508	$	22.9	$	22.9

$ in millions	Number of Options		Weighted-Average Grant Date Fair Value
Non-vested at January 1, 2006		510,000		$	2.2
Granted in 1st nine months 2006		—		—
Vested in 1st nine months 2006		450,000		$	2.0
Forfeited in 1st nine months 2006		40,000		$	0.1
Non-vested at September 30, 2006		20,000		$	0.1

		Options Outstanding			Options Exercisable
Range of Exercise Prices	Outstanding	Weighted- Average Contractual Life	Weighted- Average Exercise Price		Exercisable	Weighted- Average Exercise Price

$14.95-$21.00	4,650,000	3.7 years	$	20.43	4,650,000	$	20.47
$21.01-$29.63	786,500	3.0 years	$	28.01	766,000	$	28.08

Volatility	10.3	–	29.1	%
Expected life (years)	0.8	–	8.0
Dividend yield rate	3.7	–	4.8	%
Risk-free interest rate	3.7	–	4.9	%

$ in millions	Number of Performance Shares			Weighted-Average Grant Date Fair Value
Non-vested at January 1, 2006		—			—
Granted in 1st nine months 2006		223,289			$ 5.9
Vested in 1st nine months 2006		—			—
Forfeited in 1st nine months 2006		(89,655	)		(2.4)
Non-vested at September 30, 2006		133,634			$ 3.5