10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2006

Commission file number:  1-2385

THE DAYTON POWER AND LIGHT COMPANY

 (Exact name of registrant as specified in its charter)

OHIO	31-0258470
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
1065 Woodman Drive, Dayton, Ohio	45432
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 937-224-6000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

As of August 1, 2006, there were 41,172,173 shares of common stock outstanding, all of which were held by DPL Inc.

THE DAYTON POWER AND LIGHT COMPANY
INDEX

			Page No.
Part I. Financial Information
Item 1.	Financial Statements	3
	Consolidated Statements of Results of Operations	3
	Consolidated Statements of Cash Flows	4
	Consolidated Balance Sheets	5
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
	Operating Statistics	28
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28
Item 4.	Controls and Procedures	29
Part II. Other Information
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	31
Item 5.	Other Information	31
Item 6.	Exhibits	31
Other
Signatures		32
Certifications

Available Information:

The Dayton Power and Light Company (DP&L, the Company, we, us, our, or ours unless the context indicates otherwise) files current, annual and quarterly reports, and other information required by the Securities Exchange Act of 1934, as amended, with the Securities and Exchange Commission (SEC).  You may read and copy any document we file at the SEC’s public reference room located at 100 F Street N.E., Washington, D.C. 20549, USA.  Please call the SEC at (800) SEC-0330 for further information on the public reference rooms.  Our SEC filings are also available to the public from the SEC’s web site at http://www.sec.gov.

Our public Internet site is http://www.dplinc.com.  We make available, free of charge, through our internet site, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

In addition, our public Internet site includes other items related to corporate governance matters, including, among other things, our governance guidelines, charters of various committees of the Board of Directors and our code of business conduct and ethics applicable to all employees, officers and directors.  You may obtain copies of these documents, free of charge, by sending a request, in writing, to DP&L Investor Relations, 1065 Woodman Drive, Dayton, Ohio 45432.

2

Part I.  Financial Information

Item 1.  Financial Statements

THE DAYTON POWER AND LIGHT COMPANY

CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
$ in millions	2006			2005			2006			2005
Revenues	$	306.7		$	291.4		$	645.8		$	596.5
Cost of revenues:
Fuel	76.2			69.5			160.1			147.2
Purchased power	38.4			38.4			64.0			67.7
Total cost of revenues	114.6			107.9			224.1			214.9
Gross margin	192.1			183.5			421.7			381.6
Operating expenses:
Operation and maintenance	59.6			50.6			113.8			99.4
Depreciation and amortization	32.5			31.1			63.8			61.1
General taxes	25.6			25.4			53.1			52.8
Amortization of regulatory assets, net	1.7			0.4			2.8			0.9
Total operating expenses	119.4			107.5			233.5			214.2
Operating income	72.7			76.0			188.2			167.4
Investment income	1.3			1.0			3.2			2.1
Other income (deductions)	0.8			(2.6		)	0.3			4.1
Interest expense	(5.3		)	(9.3		)	(12.0		)	(20.6		)
Income before income taxes	69.5			65.1			179.7			153.0
Income tax expense	25.5			29.2			68.8			63.8
Net income	44.0			35.9			110.9			89.2
Preferred dividends	0.2			0.2			0.4			0.4
Earnings on common stock	$	43.8		$	35.7		$	110.5		$	88.8

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

3

THE DAYTON POWER AND LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended
	June 30,
$ in millions	2006			2005
Cash flows from operating activities:
Net income	$	110.9		$	89.2
Adjustments:
Depreciation and amortization	63.8			61.1
Amortization of regulatory assets, net	2.8			0.9
Deferred income taxes	(4.0		)	(5.6		)
Changes in certain assets and liabilities:
Accounts receivable	(7.5		)	(13.2		)
Accounts payable	65.5			9.4
Accrued taxes payable	(42.8		)	30.7
Accrued interest payable	1.3			(0.2		)
Prepayments	1.9			5.6
Inventories	(16.2		)	(17.4		)
Deferred compensation assets	4.3			2.5
Deferred compensation obligations	(3.6		)	6.9
Other	(1.2		)	(7.0		)
Net cash provided by operating activities	175.2			162.9
Cash flows from investing activities:
Capital expenditures	(199.3		)	(80.6		)
Net cash (used for) investing activities	(199.3		)	(80.6		)
Cash flows from financing activities:
Retirement of long-term debt	—			(0.4		)
Dividends paid on common stock	—			(75.0		)
Dividends paid on preferred stock	(0.4		)	(0.4		)
Net cash (used for) financing activities	(0.4		)	(75.8		)
Cash and cash equivalents:
Net change	(24.5		)	6.5
Balance at beginning of period	46.2			17.2
Cash and cash equivalents at end of period	$	21.7		$	23.7
Supplemental cash flow information:
Interest paid, net of capitalized interest	$	9.2		$	19.2
Income taxes paid, net	$	91.5		$	36.8

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

4

THE DAYTON POWER AND LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS

	At			At
	June 30,			December 31,
$ in millions	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	21.7		$	46.2
Accounts receivable, less provision for uncollectible accounts of $1.6 and $1.0, respectively	187.4			182.7
Inventories, at average cost	93.9			77.7
Taxes applicable to subsequent years	22.9			45.9
Other current assets	24.2			19.3
Total current assets	350.1			371.8
Property, plant and equipment:
Property, plant and equipment	4,296.4			4,118.0
Less: Accumulated depreciation and amortization	(2,029.5		)	(1,973.3		)
Net property	2,266.9			2,144.7
Other noncurrent assets:
Regulatory assets	80.5			83.8
Other deferred assets	135.5			138.3
Total other noncurrent assets	216.0			222.1
Total Assets	$	2,833.0		$	2,738.6

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

5

THE DAYTON POWER AND LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS

	At		At
	June 30,		December 31,
$ in millions	2006		2005
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	166.4	$	116.2
Accrued taxes	93.2		167.7
Accrued interest	11.4		9.8
Other current liabilities	32.7		28.4
Total current liabilities	303.7		322.1
Noncurrent liabilities:
Long-term debt	685.6		685.9
Deferred taxes	322.6		323.2
Unamortized investment tax credit	45.0		46.4
Other deferred credits	264.5		258.7
Total noncurrent liabilities	1,317.7		1,314.2
Cumulative preferred stock not subject to mandatory redemption	22.9		22.9
Commitments and contingencies (Note 7)
Common shareholders’ equity:
Common stock, at par value of $0.01 per share	0.4		0.4
Other paid-in capital	781.3		783.4
Retained earnings	400.9		290.5
Accumulated other comprehensive income	6.1		5.1
Total common shareholders’ equity	1,188.7		1,079.4
Total Liabilities and Shareholders’ Equity	$	2,833.0	$	2,738.6

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

6

Notes to Consolidated Financial Statements

1.Basis of Presentation

Description of Business

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).  We are 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 electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  Electricity for our 24-county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers.  We also purchase retail peak load requirements from DPL Energy LLC (DPLE), a wholly-owned subsidiary of DPL Inc.  Principal industries served include automotive, food processing, paper, plastic manufacturing, and defense.  Our sales reflect the general economic conditions and seasonal weather patterns of the area.  We sell any excess energy and capacity into the wholesale market.

Financial Statement Presentation

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP).  The consolidated financial statements include the accounts of DP&L and our 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 months ended June 30, 2006 may not be indicative of our results that will be realized for the full year ending December 31, 2006.

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.  In the opinion of our management, the consolidated financial statements contain all adjustments (which are all of a normal recurring nature) necessary to fairly state our financial condition as of June 30, 2006, our results of operations for the three months ended June 30, 2006, and our cash flows for the three months ended June 30, 2006 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; valuation allowances for receivables and deferred income taxes; reserves recorded for income tax exposures; litigation; regulatory proceeding 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.

Recently Issued Accounting Standards

Stock-Based Compensation

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard No. 123 (revised 2004), “Share-Based Payment” (SFAS 123R).  SFAS 123R replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (APB) Opinion No. 25 (Opinion 25), “Accounting for Stock Issued 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 in results of operations over the period in which employees are required to provide service.  Liabilities initially incurred are based on the fair-value 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 excess tax benefits are recognized as an addition to paid-in capital.  Cash retained from the excess tax benefits is presented in the statement of cash flows as financing cash inflows.  The provisions of this Statement became effective as of January 1, 2006.  Our June 30, 2006 year-to-date pre-tax results of operations were increased by

7

approximately $0.4 million as a result of the adoption of SFAS 123R, which we apply to stock-based transactions related to DPL Inc. common stock.  See Note 5 of Notes to Consolidated Financial Statements.

Accounting Changes and Error Corrections

In June 2005, the FASB issued Statement of Financial Accounting Standards No. 154 (SFAS 154), “Accounting Changes and Error Corrections.”  This Statement replaces APB Opinion No. 20, “Accounting Changes,” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements,” and changes the requirements for the accounting for and reporting of a change in accounting principle.  This Statement applies to all voluntary changes in accounting principle.  It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  When a pronouncement includes specific transition provisions, those provisions should be followed.  This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.  The adoption of this new accounting standard had no impact on the Company.

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 requires a two-step approach to determine how to recognize tax benefits in the financial statements where recognition and measurement 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, 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, and have not yet determined the significance of this new rule to our overall results of operations, cash flows or financial position.

8

2.  Supplemental Financial Information

	At			At
Balance Sheet	June 30,			December 31,
$ in millions	2006			2005
Accounts receivable, net:
Retail customers	$	63.3		$	71.1
Unbilled revenue	53.0			57.5
Partners in commonly-owned plants	52.6			37.7
Wholesale customers and subsidiary customers	8.3			3.4
Financial transmission rights	6.0			—
Refundable franchise tax	3.1			11.8
Other	2.7			2.2
Provision for uncollectible accounts	(1.6		)	(1.0		)
Total accounts receivable, net	$	187.4		$	182.7
Inventories, at average cost:
Fuel and emission allowances	$	64.5		$	48.6
Plant materials and supplies	29.4			29.1
Total inventories, at average cost	$	93.9		$	77.7
Other current assets:
Prepayments	$	8.1		$	7.6
Deposits and other advances	5.9			5.8
Current deferred income taxes	5.1			4.9
Derivatives	4.3			—
Other	0.8			1.0
Total other current assets	$	24.2		$	19.3
Other deferred assets:
Master Trust assets	$	103.9		$	107.7
Unamortized loss on reacquired debt	21.2			22.0
Unamoritized debt expense	7.2			7.4
Other	3.2			1.2
Total other deferred assets	$	135.5		$	138.3
Accounts payable:
Trade payables	$	83.1		$	26.1
Fuel accruals	38.6			39.5
Other	44.7			50.6
Total accounts payable	$	166.4		$	116.2
Other current liabilities:
Customer security deposits	$	19.8		$	19.2
Financial transmission rights - future proceeds	6.0			—
Current portion of long-term debt	1.0			0.9
Payroll taxes payable	0.9			2.3
Unearned revenues	0.1			0.4
Other	4.9			5.6
Total other current liabilities	$	32.7		$	28.4
Other deferred credits:
Asset retirement obligations - regulated property	$	84.2		$	81.7
Trust obligations	73.0			74.5
Retirees’ health and life benefits	32.6			32.9
Pension liability	25.8			23.5
SECA net revenue subject to refund	21.5			20.5
Asset retirement obligations - generation	13.1			13.2
Litigation and claims pending	3.6			3.0
Environmental reserves	0.1			0.1
Other	10.6			9.3
Total other deferred credits	$	264.5		$	258.7

9

	Six Months Ended June 30,
$ in millions	2006			2005
Cash flows - other:
Payroll taxes payable	$	(1.4	)	$	(0.1	)
Deposits and other advances	(1.8		)	(1.1		)
Deferred storm costs	—			(11.4		)
FERC transitional payment deferral	1.0			9.9
Other	1.0			(4.3		)
Total cash flows - other	$	(1.2	)	$	(7.0	)

	Three Months Ended June 30,						Six Months Ended June 30,
$ in millions	2006			2005			2006			2005
Comprehensive income:
Net income	$	44.0		$	35.9		$	110.9		$	89.2
Net change in unrealized gains on financial instruments	(0.2		)	6.8			0.6			5.5
Net change in deferred gains (losses) on cash flow hedges	2.2			(1.5		)	2.8			(2.8		)
Deferred income taxes related to unrealized gains and (losses)	(1.0		)	(2.1		)	(2.4		)	(1.2		)
Total comprehensive income	$	45.0		$	39.1		$	111.9		$	90.7

3.    Preferred Stock

$25 par value, 4,000,000 shares authorized, no shares outstanding; and $100 par value, 4,000,000 shares authorized, 228,508 shares without mandatory redemption provisions outstanding.

Preferred Stock	Rate		Current Redemption Price		Current Shares Outstanding at June 30, 2006	Par Value At June 30, 2006 ($ in millions)		Par Value At December 31, 2005 ($ 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 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 the payment of cash dividends 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 June 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.

4.    Pension and Postretirement Benefits

We sponsor a defined benefit plan for substantially all 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 (ERISA).

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.

10

The net periodic benefit cost of the pension and postretirement benefit plans for the three months ended June 30, 2006 and 2005 was:

Net periodic benefit cost

$ in millions	Pension						Postretirement
	2006			2005			2006			2005
Service cost	$	1.1		$	1.0		$	—		$	—
Interest cost	4.1			3.9			0.4			0.5
Expected return on assets	(5.4		)	(5.4		)	(0.1		)	(0.2		)
Amortization of unrecognized:
Actuarial (gain) loss	1.0			1.0			(0.2		)	(0.2		)
Prior service cost	0.6			0.6			—			—
Transition obligation	—			—			—			—
Net periodic benefit cost	$	1.4		$	1.1		$	0.1		$	0.1

The net periodic benefit cost of the pension and postretirement benefit plans for the six months ended June 30 was:

Net periodic benefit cost

$ in millions	Pension						Postretirement
	2006			2005			2006			2005
Service cost	$	2.2		$	2.0		$	—		$	—
Interest cost	8.2			7.8			0.8			0.9
Expected return on assets	(10.8		)	(10.8		)	(0.2		)	(0.3		)
Amortization of unrecognized:
Actuarial (gain) loss	2.0			1.9			(0.4		)	(0.5		)
Prior service cost	1.2			1.2			—			—
Transition obligation	—			—			0.1			0.1
Net periodic benefit cost before adjustments	2.8			2.1			0.3			0.2
Special termination benefit cost (a)	0.3			—			—			—
Net periodic benefit cost after adjustments	$	3.1		$	2.1		$	0.3		$	0.2

(a)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 as of April 1, 2006.

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

Estimated Future Benefit Payments

$ in millions	Pension		Postretirement
2006	$	9.9	$	1.5
2007	$	20.0	$	3.1
2008	$	20.2	$	3.0
2009	$	20.5	$	3.0
2010	$	21.0	$	2.9
2011	$	21.4	$	2.7
2012 – 2016	$	114.6	$	10.7

11

5.Stock-Based Compensation

We adopted Statement of Financial Accounting Standard 123 Revised (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 of SFAS 123R, we recognized $0.4 million less compensation expense for the six months ended June 30, 2006, as compared to what we would have recognized under SFAS 123.

In 2000, our Board of Directors adopted and our 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 December 31, 2005, there were 1,488,500 options available for grant.  On April 26, 2006, DPL shareholders approved the DPL Inc. 2006 Equity and Performance Incentive Plan (EPIP).  With the approval of EPIP, no further awards will be made under the DPL Inc. Stock Option Plan.

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

$ in millons	Number of Options	Weighted-Average Grant Date Fair Value
Non-vested at January 1, 2006	510,000	$	1.9
Granted in 1st half 2006	—	—
Vested in 1st half 2006	450,000	$	1.7
Forfeited in 1st half 2006	—	—
Non-vested at June 30, 2006	60,000	$	0.2

Summarized stock option activity was as follows:

	Six months ended June 30, 2006			Twelve months ended December 31, 2005
Options:
Outstanding at beginning of year (a)	5,486,500			6,165,500
Granted	0			350,000
Exercised	(10,000		)	(1,025,000		)
Forfeited	0			(4,000		)
Outstanding at end of period	5,476,500			5,486,500
Exercisable at end of period	5,416,000			4,100,000
Weighted average exercise prices per share:
Outstanding at beginning of year	$	21.86		$	21.39
Granted	—			$	26.82
Exercised	$	21.00		$	21.18
Forfeited	—			$	29.63
Outstanding at end of period	$	21.90		$	21.86
Exercisable at end of period	$	20.98		$	20.98

a)In dispute with certain former executives, among other things, are approximately 1 million forfeited options and 3.6 million outstanding options that are included above (see Note 7 of Notes to Consolidated Financial Statements).

No stock options were granted in the first two 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.

12

In the first quarter of 2006, 10,000 stock options were exercised.  No stock options were exercised in the second quarter of 2006.  The market value of options that were vested at June 30, 2006 was $145.1 million.  Shares issued upon share option exercise are issued from treasury stock.  We have sufficient treasury stock to satisfy outstanding options.

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

		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	4,690,000	4.0 years	$	20.44	4,650,000	$	20.47
$21.01-$29.63	786,500	3.2 years	$	28.08	766,000	$	28.08

As of June 30, 2006, there was $0.2 million of total unrecognized compensation cost related to non-vested stock options granted under the Plan.  We expect to recognize $0.1 million of this cost over the remainder of 2006 and $0.1 million in 2007.

In addition, RSUs were granted to certain key employees prior to 2001.  There were 1.4 million RSUs outstanding as of June 30, 2006, of which 1.3 million were 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:  24,891 in 2006; 21,978 in 2007; 15,904 in 2008; 11,199 in 2009; and 5,560 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 model to determine the amount of compensation expense to be recognized.  Non-vested RSUs do not earn dividends.

The following assumptions were used in the Black Scholes model to calculate the fair value of the non-vested stock options and RSUs:

Volatility	24.0  – 29.1	%
Expected life (years)	0.3  –   8.0
Dividend yield rate	3.7  –   4.8	%
Risk-free interest rate	3.7  –   5.2	%

At the 2006 Annual Shareholder’s Meeting, the shareholders approved the DPL Inc. 2006 Equity Performance Incentive Plan (EPIP).  Under the EPIP, the Board adopted a Long-Term Incentive Plan (LTIP) under which DPL will award a targeted number of performance shares of common stock to executives.  Awards under the LTIP will be awarded based on a Total Shareholder Return Relative to Peers parameter.  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 condition under FAS123R.  The requisite service period for each tranche of the Performance Shares is:

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

13

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

$ in millions	Number of Performance Shares		Weighted-Average Grant Date Fair Value ($ millions)
Non-vested at January 1, 2006	—		—
Granted in 1st half 2006	223,289		$	5.9
Vested in 1st half 2006	—		—
Forfeited in 1st half 2006	—	*	—
Non-vested at June 30, 2006	223, 289		$	5.9

*      On August 1, 2006, James V. Mahoney, President and Chief Executive Officer, signed an amendment to his Employment Agreement, dated May 18, 2006, in which he agreed generally to extend his service to the Company until a successor is appointed. Under that amendment, Mr. Mahoney acknowledged he is not entitled to participate in the Company’s Long Term Incentive Program or the Performance Shares Agreement dated March 7, 2006.

	Six months	Twelve months
	ended	ended
	June 30, 2006	December 31, 2005
Performance Shares:
Outstanding at beginning of year	—	—
Granted	223,289	—
Exercised	—	—
Forfeited	—	—
Outstanding at end of period	223,289	—
Exercisable at end of period	—	—

There are no exercise prices associated with performance shares.

As of June 30, 2006, there was $3.9 million of total unrecognized compensation cost related to non-vested performance shares granted under the LTIP.  We expect to recognize $2.1 million of this cost over the remainder of 2006 and $1.8 million in 2007 and 2008.  A forfeiture rate of 20% was estimated in calculating the compensation expense.

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.

The following assumptions were used in a Monte Carlo simulation calculated by  a bonded consultant to estimate the fair value of the performance shares:

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

Compensation expense for the first half of 2006 was $3.3 million for all share-based compensation (stock options, RSUs, and performance shares) and the tax benefit associated with these expenses was $1.2 million.

Operating income was $0.4 million higher under SFAS 123R than under SFAS 123.  The impact on net income was $0.3 million due to a decrease in the tax benefit of $0.1 million.  There was no impact on basic or diluted earnings per share.

14

6.Long-term Debt  

	At			At
	June 30,			December 31,
$ in millions	2006			2005
First Mortgage Bonds maturing 2013 - 5.125%	$	470.0		$	470.0
Pollution Control Series maturing through 2034 - 4.78% (a)	214.4			214.4
	684.4			684.4
Obligation for capital leases	2.4			3.0
Unamortized debt discount	(1.2		)	(1.5		)
Total	$	685.6		$	685.9

(a)  Weighted average interest rates for 2006 and 2005.

The amounts of maturities and mandatory redemptions for first mortgage bonds and capital leases are $0.5 million for the remainder of 2006, $0.9 million in 2007, $0.7 million in 2008, $0.7 million in 2009 and $0.6 million in 2010.  Substantially all of our property is subject to the mortgage lien securing the first mortgage bonds and the pollution control series.

We have a $100 million unsecured revolving credit agreement that is renewable annually and expires on May 30, 2010.  This facility may be increased up to $150 million.  The facility contains one financial covenant:  our total debt to total capitalization ratio is not to exceed 0.65 to 1.00.  This covenant is currently met.  We had no outstanding borrowings under this credit facility at June 30, 2006.  Fees associated with this credit facility are approximately $0.2 million per year.  Changes in credit ratings, however, may affect the applicable interest rate for our revolving credit agreement.

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 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 June 30, 2006, we had two outstanding letters of credit for a total of $2.2 million.

During the first quarter of 2006, the Ohio Air Quality Development Authority (OAQDA) awarded us the ability to issue over the next three years up to $200 million of qualified tax-exempt financing from the OAQDA’s 2005 volume cap carryforward.  The financing is expected to be used to partially fund the ongoing flue gas desulphurization (FGD) projects.  The PUCO approved our application for this additional financing on July 26, 2006.

There are no inter-company debt collateralizations or debt guarantees between us and our parent.  None of our debt obligations are guaranteed or secured by affiliates and no cross-collateralization exists between any subsidiaries.

7.     Commitments and Contingencies

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 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 Consolidated Financial Statements.

Environmental Matters

Our 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

15

and federal laws.  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 potential liabilities could have a material effect on our results of operations and financial position.

Legal Matters

In the normal course of business, we have been named a defendant in various legal actions, including arbitrations, class actions and other litigation. Certain of 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 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 matters 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.

Certain legal proceedings in which we are involved are discussed in Note 14 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 8 to the consolidated financial statements and Part II, Item 1, included in our Form 10-Q for the quarterly period ended March 31, 2006. The following discussion is limited to recent developments concerning our legal proceedings and should be read in conjunction with those earlier reports.

Regarding our litigation with three former executives of the Company, on July 24, 2006 the trial court set a new trial date commencing April 30, 2007.

On June 24, 2004, the Internal Revenue Service (IRS) began an audit of tax years 1998 through 2003 and issued a series of data requests to us including issues raised in the Memorandum.  The staff of the IRS requested that we provide certain documents, including but not limited to, matters concerning executive/director deferred compensation plans, management stock incentive plans and MVE financial statements.  On September 1, 2005, the IRS issued an audit report for tax years 1998 through 2003 that showed proposed changes to our federal income tax liability for each of those years.  The proposed changes resulted in a total tax deficiency, penalties and interest of approximately $23.9 million as of December 31, 2005.  On November 4, 2005, we filed a written protest to one of the proposed changes.  On April 3, 2006, the IRS conceded the proposed changes that we filed a written protest to and issued a revised audit report for tax years 1998 through 2003.  The revised audit report resulted in a total tax deficiency, penalties and interest of approximately $1.2 million.  We had previously made a deposit with the IRS of approximately $1.3 million that we requested on April 14, 2006 be applied to offset the $1.2 million tax deficiency, penalties and interest for tax years 1998 through 2003.  The Joint Committee on Taxation completed its review of the revised audit report for tax years 1998 through 2003 and sent us a letter dated June 16, 2006 stating that it took no exception to the revised audit report.

In November 2005, AMP-Ohio, a wholesale supplier of electricity to its thirteen member municipalities, requested arbitration of its power supply agreement with DP&L.  AMP-Ohio alleged it had a right to receive certain capacity credits.  DP&L disagreed with this position and agreed to arbitrate the dispute.  The arbitration was concluded in May 2006, thus ending any potential negative exposure to our results of operations, cash flows and financial position.

On January 13, 2006, we filed a claim against one of our insurers, AEGIS, under a fiduciary policy to recoup legal fees associated with our litigation against three former executives.  An arbitration of this matter is set to begin on August 4, 2006.  We cannot predict the timing or outcome of this arbitration.

16

Contractual Obligations and Commercial Commitments

We enter into various contractual and other long-term obligations that may affect the liquidity of our operations.  At June 30, 2006, these 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	$	683.2	$	—	$	—	$	—	$	683.2
Interest payments	446.7		34.3		68.7		68.7		275.0
Pension and postretirement payments	254.5		23.0		46.6		47.7		137.2
Capital leases	3.4		1.0		1.5		0.9		—
Operating leases	0.9		0.5		0.4		—		—
Fuel and limestone contracts (a)	646.4		174.4		287.4		97.5		87.1
Other long-term obligations	34.1		12.0		14.8		7.3		—
Total contractual obligations	$	2,069.2	$	245.2	$	419.4	$	222.1	$	1,182.5

(a) DP&L operated units

Long-term debt:

Long-term debt as of June 30, 2006, consists 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.

Pension and postretirement payments:

As of June 30, 2006, we had estimated future benefit payments as outlined in Note 4 of Notes to Consolidated Financial Statements.  These estimated future benefit payments are projected through 2016.

Capital leases:

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

Operating leases:

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

Fuel and limestone contracts:

We have entered into various long-term coal contracts to supply portions of our coal requirements for our generating plants and a long-term contract to supply limestone for the operation of our flue gas desulfurization units (FGDs).  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 beginning September 2006.

Other long-term obligations:

As of June 30, 2006, we had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

17

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

Credit facilities:

We have a $100 million, 364-day unsecured credit facility that is renewable annually and expires on May 30, 2010.  At June 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 ownership interest in an electric generation company.  As of 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.

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

Certain statements contained in this discussion 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.  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 control, including but not limited to:  abnormal or severe weather; unusual maintenance or repair requirements; changes in fuel costs and purchased power, coal, environmental emissions, gas and other commodity prices; increased competition; regulatory changes and decisions; changes in accounting rules; financial market conditions; and general economic conditions.

Forward-looking statements speak only as of the date of the document in which they are made.  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.

OTHER MATTERS

Peaking Generating Facilities

DPL is reviewing its peaking generation portfolio.  As a part of that process, the Company is soliciting bids for three peaking generating sites, representing a combined capacity of 872 megawatts.  DPL will determine the number of sites it may sell, if any, after it receives the bids, which are expected in early September.

Updates on Competition and Regulation

On April 4, 2005, we filed a request at the Public Utilities Commission of Ohio (PUCO) to implement a new rate stabilization surcharge effective January 1, 2006 to recover cost increases 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 provide 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:

·A rate stabilization surcharge equal to 11% 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, 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 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 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 rehearing were denied, and the case was appealed to the Ohio Supreme Court by the OCC on April 21, 2006.

18

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 to Competitive Retail Electric Service (CRES) providers who were registered in our 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.  The first round of bids, due July 10, 2006, resulted in no bids being received.  There will be three additional rounds of bids during the third and fourth quarters of 2006.  The magnitude of any customer switching and the financial impact of this program cannot be determined at this time.

As of June 30, 2006, four unaffiliated marketers were registered as CRES providers in our service territory; to date, there has been no significant activity from these suppliers.  DPL Energy Resources, Inc. (DPLER), one of our parent’s significant subsidiaries, is also a registered CRES provider and accounted for nearly all load served by CRES providers within our service territory in 2005.  In addition, several communities in our 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.

On September 1, 2005, DP&L filed an application requesting the PUCO grant it 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, DP&L filed updated schedules in support of its application.  On July 12, 2006, the PUCO approved DP&L’s filing, allowing the Company to recover approximately $8.6 million in additional revenues over a two-year period.

On July 23, 2003, the FERC issued an Order that the rates for transmission service of seven companies, including us, may be unjust, unreasonable, or unduly discriminatory or preferential.  In addition, the FERC ordered transitional payments, 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.  Several parties have sought rehearing of the FERC orders, and there likely will be appeals filed in the matter.  All motions for rehearing are pending.  The hearing was held in May 2006, with an initial decision expected in August 2006.  Beginning May 2005, we began receiving these FERC ordered transitional payments and have received over $24.8 million of SECA collections, net of SECA charges, through June 2006.  We have entered into a significant number of bi-lateral settlement agreements with certain parties to resolve the matter, although several SECA claims are still outstanding.  Our management believes that appropriate reserves have been established in the event that SECA collections are required to be refunded.  The ultimate outcome of the proceeding establishing SECA rates is uncertain at this time. However, based on the amount of reserves established for this item, the results of this proceeding are not expected to have a material effect on our results of operations.

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 Commission order on this issue later this year.  Due to the comment and appeal process, we cannot determine what effect the final outcome of this proceeding may have on our future recovery of transmission revenues.

Updates on Environmental Considerations

Air and Water Quality

On December 17, 2003, the USEPA proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap sulfur dioxide (SO2) 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 a material effect on our operations, requiring the installation of FGD equipment and continual operation of the

19

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 SO2, 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

This quarterly report and other documents that we file with the SEC and other regulatory agencies, as well as other oral or written statements we may make from time to time, contain information based on management’s beliefs and include forward-looking statements (within the meaning of the Private Securities Litigation Reform Act of 1995) that involve a number of known and unknown risks, uncertainties and assumptions. These forward-looking statements are not guarantees of future performance, and there are a number of factors which could cause actual outcomes and results to differ materially from the results contemplated by such forward-looking statements. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  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.

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 10-K and 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.  If any of these events occur, our business, financial position or results of operation could be materially affected.

RESULTS OF OPERATIONS

Income Statement Highlights

	Three Months Ended June 30,						Six Months Ended June 30,
$ in millions	2006			2005			2006			2005
Revenues	$	306.7		$	291.4		$	645.8		$	596.5
Less:  Fuel	76.2			69.5			160.1			147.2
Purchased power	38.4			38.4			64.0			67.7
Gross margin	$	192.1		$	183.5		$	421.7		$	381.6
Gross margin as a percentage of revenues	62.6		%	63.0		%	65.3		%	64.0		%
Operating income	$	72.7		$	76.0		$	188.2		$	167.4

20

Revenues

Revenues increased 5% to $306.7 million in the second quarter of 2006 compared to $291.4 million for the second quarter of 2005 reflecting higher average rates for retail sales and greater wholesale sales volume.  These increases were partially offset by lower retail sales volume, lower wholesale average rates and slightly decreased ancillary revenues associated with participation in a RTO.

Retail revenues increased $8.1 million in the second quarter of 2006 compared to 2005, primarily resulting from $14.4 million in higher average rates and $0.1 million of higher miscellaneous revenues, offset by decreased sales volume of $6.4 million.  The higher average rates were primarily the result of rate stabilization plan increases, regulated asset recovery riders, and changes in the customer mix of sales.  Wholesale revenue increased $7.3 million, primarily related to a $10.2 million increase related to higher sales volume, offset by a $2.9 million decrease in average market rates.  During the second quarter of 2006, RTO ancillary revenues remained relatively flat, decreasing $0.1 million to $17.4 million from $17.5 million in the second quarter 2005.  Heating degree-days were down 10% to 554 for the second quarter of 2006 compared to 618 for the same period in 2005.  Cooling degree-days were down 26% to 206 for the second quarter of 2006 compared to 278 for the same period in 2005.

Revenues increased 8% to $645.8 million in the first half of 2006 compared to $596.5 million for 2005, reflecting higher average rates for retail revenues, greater wholesale sales volume and increased ancillary revenues associated with participation in an RTO.  These increases were partially offset by lower retail sales volume and lower wholesale average rates.

Retail revenues increased $24.6 million in the first half of 2006 compared to the first half of 2005, primarily resulting from $35.2 million in higher average rates and $0.4 million of higher miscellaneous revenues, offset by decreased sales volume of $11.0 million.  The higher average rates were primarily the result of rate stabilization plan increases, regulated asset recovery riders, and a change in the customer mix of sales.  Wholesale revenues increased $22.6 million, primarily related to a $28.6 million increase related to higher sales volume, offset by a $6.0 million decrease in average market rates.  During the first half of 2006, RTO ancillary revenues increased $2.1 million to $35.1 million from $33.0 million in the first half of 2005.  Heating degree-days were down 13% to 3,068 for the first half of 2006 compared to 3,515 for the same period in 2005.   Cooling degree-days were down 26% to 206 for the first half of 2006 compared to 278 for the same period in 2005.

Gross Margin, Fuel and Purchased Power

Gross margin of $192.1 million in the second quarter of 2006 increased by $8.6 million from $183.5 million in the second quarter of 2005.   As a percentage of total revenues, however, gross margin remained relatively stable, decreasing only 0.4 percentage points to 62.6% from 63.0%.  The dollar increase in gross margin was primarily the result of greater revenues, partially offset by increased fuel costs.  Fuel costs increased by $6.7 million or 10% in the three months ended June 30, 2006, as compared to the same period in 2005, primarily resulting from higher market prices.  Purchased power costs remained flat in the second quarter of 2006 compared to 2005.

Gross margin of $421.7 million in the first half of 2006 increased by $40.1 million from $381.6 million in the first half of 2005.   As a percentage of total revenues, gross margin increased by 1.3 percentage points to 65.3% from 64.0%.  This improvement is primarily the result of increased revenues and a slight decline in purchase power costs, offset by increased fuel costs.  Fuel costs rose by $12.9 million or 9% in the six months ended June 30, 2006,  as a result of higher market prices and higher generation output as compared to 2005.  Purchased power costs decreased by $3.7 million or 5% in the first half of 2006 compared to prior year primarily resulting from lower purchased power volume, offset slightly by increased average RTO ancillary charges.

Operation and Maintenance Expense

Operation and maintenance expense increased $9.0 million or 18% in the second quarter of 2006 compared to the same period in 2005, primarily resulting from $3.3 million in PJM administrative fees including $2.5 million deferred in 2005 by PUCO authority until rate relief was granted in February 2006; increased employee compensation and benefit expenses in the amount of $2.6 million, including group medical, pension, ESOP and stock option compensation costs; a $2.0 million increase in power production costs primarily related to increased operating expenses; and increased Low-Income Payment Program costs of $0.8 million. These increases were partially offset by a $1.2 million decrease in mark-to-market adjustments for restricted stock units (RSUs). 

Operation and maintenance expense increased $14.4 million or 14% of the first half of 2006 compared to prior year primarily resulting from increased employee compensation and benefit expenses in the amount of $4.5 million, including group medical, pension, ESOP and stock option compensation costs; $2.8 million in PJM administrative fees including $2.5 million deferred in 2005 by PUCO authority until rate relief was granted in February 2006; a $2.5 million increase in power production costs related to increased operating expenses; increased Low-Income Payment Program costs of $2.1 million; a $2.0 million increase in reserves for injuries and damages; and increased service operations costs of $1.9 million primarily related to greater line clearance activity. These increases were partially offset by a $1.1 million decrease in Directors’ and Officers’ liability insurance costs and a $0.4 million decrease in mark-to-market adjustments for RSUs.

We have filed insurance claims for recovery of legal fees associated with the former executives litigation.  The amount and timing of any insurance recovery cannot be determined.

Depreciation and Amortization

Depreciation and amortization increased $1.4 million and $2.7 million in the second quarter and in the first half of 2006, respectively, compared to the same periods in 2005 primarily reflecting a higher amount of property, plants and equipment.

General Taxes

General taxes for the second quarter and the first half of 2006 were relatively flat compared to prior year.

Amortization of Regulatory Assets, Net

For the three months ended June 30, 2006 compared to the three months ended June 30, 2005, amortization of regulatory assets, net increased $1.3 million primarily reflecting $0.7 million for the amortization of costs incurred to modify the customer billing system for unbundled rates and electric choice bills and $0.3 million for the amortization of PJM administrative fees deferred for the period October 2004 through January 2006.

Amortization of regulatory assets, net increased $1.9 million for the six months ended June 30, 2006 compared to the prior year primarily reflecting $1.0 million for the amortization of costs incurred to modify the customer billing system to accommodate unbundled rates and electric choice bills and $0.5 million for the amortization of deferred PJM administrative fees.  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.  The customer billing costs rate rider is expected to be in place for five years and the PJM administrative fee rate rider is expected to continue for three years.

Investment Income

Investment income increased $0.3 million during the second quarter of 2006 compared to 2005 primarily due to increased interest income earned from cash on deposit.

Investment income increased $1.1 million during the first half of 2006 as compared to prior year primarily resulting from a $0.7 million net gain on Master Trust investments (related to deferred compensation) and a $0.6 increase in interest income earned from cash on deposit.

Other Income (Deductions)

Other income (deductions) for the second quarter ended June 30, 2006 increased $3.4 million compared to the second quarter ended June 30, 2005 primarily reflecting $2.3 million in reduced investment management fees and $0.7 million from an IRS refund of a prior year penalty.

Other income (deductions) for the six months ended June 30, 2006 decreased $3.8 million compared to the same period in 2005.  This decrease is primarily attributable to a $12.3 million gain recognized on the sale of pollution control emission allowances during the first half of 2005 (there were no such sales in 2006), partially offset by $7.0 million in reduced investment management fees, a $0.7 million refund of a prior year IRS penalty and lower revolving credit facility fees of $0.4 million.

Interest Expense

Interest expense decreased $4.0 million or 43% for the three months ended June 30, 2006 compared to the same period in 2005, primarily relating to $2.0 million of greater capitalized interest resulting from increased capital expenditures for pollution control equipment at the generating plants and $1.5 million of lower interest expense reflecting the 2005 refinancing of pollution control bonds at reduced interest rates, the elimination of the interest penalty resulting from the delayed exchange offer of the $470 million 5.125% Series First Mortgage Bonds due 2013 that was completed during the second quarter of 2005 and lower debt service charges

21

associated with DPL Inc.’s early retirement of ESOP debt.

Interest expense decreased $8.6 million or 42% in the first half of 2006 compared to the first half of 2005, primarily relating to $4.3 million of increased capitalized interest resulting from higher pollution control capital expenditures at the generating plants and $3.6 million of lower interest expense reflecting the refinancing of pollution control bonds at reduced interest rates in 2005, lower debt service charges associated with DPL Inc.’s early retirement of ESOP debt, and the elimination of the interest penalty resulting from the delayed exchange offer of the $470 million 5.125% Series First Mortgage Bonds.  See Note 6 of Notes to Consolidated Financial Statements.

Income Tax Expense

Income taxes decreased $3.7 million for the second quarter of 2006 compared to 2005 reflecting a decrease in the effective tax rate due primarily to the phase-out of the Ohio Franchise Tax and a decrease in the tax reserve, partially offset by higher book income.

Income taxes increased $5.0 million for the first half of 2006 compared to the first half 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.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES

Our cash and cash equivalents totaled $21.7 million at June 30, 2006, compared to $46.2 million at December 31, 2005, a decrease of $24.5 million. This decrease was attributed to $199.3 million in capital expenditures and $0.4 million in dividends paid on preferred stock, offset by $175.2 million in cash generated from operating activities.

We generated net cash from operating activities of $175.2 million and $162.9 million for the first half of 2006 and 2005, respectively. The 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.  The tariff-based revenue from our 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 provides us with a reasonably predictable cash flow from utility operations.

Net cash flows used for investing activities were $199.3 million in the first half of 2006 and $80.6 million in the first half of 2005 to provide funding for capital expenditures.

Net cash flows used for financing activities were $0.4 million in the first half of 2006 compared to $75.8 million in the first half of 2005.  Net cash flows used for financing activities for each of these periods were to pay dividends on preferred stock and, for 2005, to pay dividends on common stock to our parent company and to retire long-term debt.

We 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.  We believe our cash flows from operations, the credit facilities (existing or future arrangements), 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.  If we are unable to generate sufficient cash flows from operations, or otherwise comply with the terms of our credit facilities and 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 were $199.3 million and $80.6 million for the first half of 2006 and 2005, respectively, and are expected to approximate an aggregate amount of $360 million in 2006.  Planned construction additions for 2006 primarily relate to our environmental compliance program, power plant equipment, and our 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.  Over the next three years, we are projecting to spend an estimated $810 million in capital projects (previously $745 million), approximately 55% of which is to meet changing environmental standards.

22

Our ability to complete our capital projects and the reliability of future service will be affected by our financial condition, the availability of internal and external funds at reasonable cost, and adequate and timely return on these capital investments.  We expect to finance our construction additions in 2006 with a combination of cash and short-term investments on hand, tax-exempt debt and internally-generated funds.

Debt and Debt Covenants

At June 30, 2006, our scheduled maturities of long-term debt, including capital lease obligations, over the next five years are $0.5 million for the remainder of 2006, $0.9 million in 2007, $0.7 million in 2008, $0.7 million in 2009 and $0.6 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 June 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 bonds to satisfy our requirements in connection with our construction programs.  The amounts and timing of future financings will depend upon market and other conditions, interest rate increases, levels of electric sales and construction plans.

We have a $100 million unsecured revolving credit agreement that is renewable annually and expires on May 30, 2010.  This facility may be increased up to $150 million.  The facility contains one financial covenant:  our total debt to total capitalization ratio is not to exceed 0.65 to 1.00.  This covenant is currently met.  We had no outstanding borrowings under this credit facility at June 30, 2006.  Fees associated with this credit facility are approximately $0.2 million per year.  Changes in credit ratings, however, may affect the applicable interest rate for our revolving credit agreement.

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

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 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 June 30, 2006, we had two outstanding letters of credit for a total of $2.2 million.

There are no inter-company debt collateralizations or debt guarantees between us and our parent.  None of our debt obligations are guaranteed or secured by affiliates and no cross-collateralization exists between any subsidiaries.

Credit Ratings

Currently, our senior secured debt credit ratings are as follows:

	Rating	Outlook	Effective
Fitch Ratings	A	Stable	April 2006
Moody’s Investors Service	A3	Positive	June 2006
Standard & Poor’s Corp. (a)	BBB	Positive	August 2006

*(a) Upgraded on August 1, 2006.

Off-Balance Sheet Arrangements

We 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 and other long-term obligations that may affect the liquidity of our operations.  At June 30, 2006, these include:

23

Contractual Obligations

			Payment Year
$ in millions	Total		Less Than 1 Year		2 - 3 Years		4 - 5 Years		More than 5 Years
Long-term debt	$	683.2	$	—	$	—	$	—	$	683.2
Interest payments	446.7		34.3		68.7		68.7		275.0
Pension and postretirement payments	254.5		23.0		46.6		47.7		137.2
Capital leases	3.4		1.0		1.5		0.9		—
Operating leases	0.9		0.5		0.4		—		—
Fuel and limestone contracts (a)	646.4		174.4		287.4		97.5		87.1
Other long-term obligations	34.1		12.0		14.8		7.3		—
Total contractual obligations	$	2,069.2	$	245.2	$	419.4	$	222.1	$	1,182.5

(a) DP&L operated units

Long-term debt:

Long-term debt as of June 30, 2006, consists 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.

Pension and postretirement payments:

As of June 30, 2006, we had estimated future benefit payments as outlined in Note 4 of Notes to Consolidated Financial Statements.  These estimated future benefit payments are projected through 2016.

Capital leases:

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

Operating leases:

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

Fuel and limestone contracts:

We have entered into various long-term coal contracts to supply portions of our coal requirements for our generating plants and a long-term contract to supply limestone for the operation of our FGDs.  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 beginning September 2006.

Other long-term obligations:

As of June 30, 2006, we 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, 2006, these include:

Credit facilities:

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

24

Guarantee:

We own a 4.9% equity ownership interest in an electric generation company.  As of 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.

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.  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 to quantify potential impacts of market rate changes on the results of operations.  The sensitivity analyses represent hypothetical changes in market values that may or may not occur in the future.

Commodity Pricing Risk

Approximately 21% of our first half 2006 revenues 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 in the wholesale market when we can identify opportunities with positive margins.  As of June 30, 2006, a hypothetical increase or decrease of 10% in annual wholesale revenues could result in approximately a $17 million increase or decrease to net income, assuming no increases or decreases in fuel and purchased power costs.

We have approximately 95% and 83% of the total expected coal volume needed 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 (SO2  and NOx) consumption is expected to be similar to 2005.  Our holdings of SO2 and NOx allowances are approximately equal to our expected needs from 2006 through 2010.  There may be exchanges of allowances between future years to balance our 2006-2010 position.  We do not expect to purchase allowances outright for 2006.  The exact consumption of SO2 and NOx allowances will depend on market prices for power and availability of our generating units.  The utilization of SO2 allowances will depend upon actual sulfur content of the coal burned.  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 be flat in 2007 compared to 2006. This is primarily due to a delay in planned outage for a co-owner plant from 2006 to 2007. This forecast assumes coal prices will increase approximately 10% in 2006 as compared to 2005 and remain flat 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 June 30, 2006, a hypothetical increase or decrease of 10% in annual fuel and purchased power costs, excluding Regional Transmission Organization (RTO) services, could result in approximately a $25 million increase or decrease to net income.

We have entered into an agreement with Merrill Lynch Commodities Inc. (MLCI) intended to expand our ability to manage our coal portfolio and long-term coal procurement strategy.  We will use MLCI’s analytical, optimization, marketing, and risk control capabilities to enhance our ability to manage our coal portfolio.  MLCI will assist us in the development of our future requirements, management of existing commitments, and the overall management of coal issues.

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 interest rate fluctuations.  Our long-term debt represents publicly-held secured notes with fixed interest rates.  At June 30, 2006, we had no short-term borrowings.

The carrying value of our debt was $686.6 million at June 30, 2006, consisting of our first mortgage bonds, our tax-exempt pollution control bonds and our capital leases.  The fair value of this debt was $661.2 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, 2006 are as follows:

25

	Long-term Debt
Expected Maturity	Amount
Date	($ in millions)		Average Rate
2006	$	0.5		6.1	%
2007	0.9			6.2	%
2008	0.7			6.9	%
2009	0.7			6.9	%
2010	0.6			6.9	%
Thereafter	683.2			5.0	%
Total	$	686.6		5.0	%
Fair Value	$	661.2

Debt maturities in 2006 are expected to be financed with internal funds.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP).  The consolidated financial statements include the accounts of DP&L and our 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.

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; valuation allowances for receivables and deferred income taxes; 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.  Refer to our 2005 Annual Report filed on Form 10-K for a complete listing of our critical accounting policies and estimates.

26

THE DAYTON POWER AND LIGHT COMPANY

OPERATING STATISTICS

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Sales (millions of kWh)
Residential	1,039		1,101		2,507		2,636
Commercial	938		966		1,831		1,851
Industrial	1,097		1,097		2,085		2,107
Other retail	351		366		689		697
Other miscellaneous revenues	—		—		—		—
Total retail	3,425		3,530		7,112		7,291
Wholesale	681		577		1,500		1,194
Total sales	4,106		4,107		8,612		8,485
Revenues ($ in thousands)
Residential	$	101,464	$	100,025	$	232,095	$	225,957
Commercial	67,630		62,323		133,520		119,497
Industrial	32,537		31,931		63,372		61,715
Other retail	21,626		20,979		42,295		39,863
Other miscellaneous revenues	2,427		2,283		5,411		5,065
Total retail	225,684		217,541		476,693		452,097
Wholesale	63,671		56,400		134,031		111,462
RTO ancillary revenues	17,339		17,451		35,043		32,952
Total revenues	$	306,694	$	291,392	$	645,767	$	596,511
Electric customers at end of period	513,965		511,393		513,965		511,393

Item 3.  Quantitative and Qualitative Disclosures about Market Risk 

See the “Market Risk” section of Item 2.

28

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 (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.

29

Part II.  Other Information

Item 1. Legal Proceedings

In the normal course of business, the Company has been named a defendant in various legal actions, including arbitrations, class actions and other litigation. Certain of the legal actions include claims for substantial compensatory and/or punitive damages or claims for indeterminate amounts of damages. The Company is also involved in other reviews, investigations and proceedings by governmental and self-regulatory organizations regarding the Company’s 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, the Company 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, the Company 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, it is the opinion of management, that the resolution of the foregoing matters will not have a material adverse effect on the financial condition of the Company, 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.

Certain legal proceedings in which we are involved are discussed in Note 14 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 8 to the consolidated financial statements and Part II, Item 1, included in our Form 10-Q for the quarterly period ended March 31, 2006. The following discussion is limited to recent developments concerning our legal proceedings and should be read in conjunction with those earlier reports.

Regarding our litigation with three former executives of the Company, on July 24, 2006, the trial court set a new trial date commencing April 30, 2007.

On June 24, 2004, the Internal Revenue Service (IRS) began an audit of tax years 1998 through 2003 and issued a series of data requests to us including issues raised in the Memorandum.  The staff of the IRS requested that we provide certain documents, including but not limited to, matters concerning executive/director deferred compensation plans, management stock incentive plans and MVE financial statements.  On September 1, 2005, the IRS issued an audit report for tax years 1998 through 2003 that showed proposed changes to our federal income tax liability for each of those years.  The proposed changes resulted in a total tax deficiency, penalties and interest of approximately $23.9 million as of December 31, 2005.  On November 4, 2005, we filed a written protest to one of the proposed changes.  On April 3, 2006, the IRS conceded the proposed changes that we filed a written protest to and issued a revised audit report for tax years 1998 through 2003.  The revised audit report resulted in a total tax deficiency, penalties and interest of approximately $1.2 million.  We had previously made a deposit with the IRS of approximately $1.3 million that we requested on April 14, 2006 be applied to offset the $1.2 million tax deficiency, penalties and interest for tax years 1998 through 2003.  The Joint Committee on Taxation completed its review of the revised audit report for tax years 1998 through 2003 and sent us a letter dated June 16, 2006 stating that it took no exception to the revised audit report.

In November 2005, AMP-Ohio, a wholesale supplier of electricity to its thirteen member municipalities, requested arbitration of its power supply agreement with DP&L.  AMP-Ohio alleged it had a right to receive certain capacity credits.  DP&L disagreed with this position and agreed to arbitrate the dispute.  The arbitration was concluded in May 2006, thus ending any potential negative exposure to our results of operations, cash flows and financial position.

On January 13, 2006, we filed a claim against one of our insurers, AEGIS, under a fiduciary policy to recoup legal fees associated with our litigation against three former executives.  An arbitration of this matter is set to begin on August 4, 2006.  We cannot predict the timing or outcome of this arbitration.

30

Item 1A. 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 Annual Report on Form 10-K and may be obtained as discussed on page 2, ‘Available Information.’  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 our 2005 Annual Report on Form 10-K discussion on risk factors.

Greenhouse gas (GHG) emissions, consisting primarily of carbon dioxide emissions, are presently unregulated.  Numerous bills have been introduced in Congress to regulate GHG emissions, but to date none have passed.  Future regulation of GHG emissions is uncertain.  However, such regulation would be expected to impose costs on our operations.  Such costs could include measures as advanced by various constituencies, including a carbon tax; investments in energy efficiency; installation of CO2 emissions control technology, to the extent such technology exists; purchase of emission allowances, should a trading mechanism be developed; or the use of higher-cost, lower CO2 emitting fuels.  We will continue to make prudent investments in energy efficiency that reduces our GHG emissions intensity.

In August of 2006, an electric supply contract with Wright Patterson Air Force Base (WPAFB) is set to expire.  WPAFB represents approximately 1% of our annual revenues.  At this time, WPAFB will revert to our standard offer rate until such time as they choose to contract with an alternative supplier.  We are not anticipating a material impact on our results of operations if they choose another supplier.

Item 5.  Other Information

On August 1, 2006, the Board of Directors of the Company and DP&L amended the Employment Agreement dated as of May 18, 2006 with James V. Mahoney to extend his employment with the Company and DP&L at the pleasure of the Company and DP&L or until Mr. Mahoney provides fourteen (14) days written notice of his intent to terminate his employment. Except for the changes noted here, the Employment Agreement dated as of May 18, 2006 remains in full force and effect.

Item 6.  Exhibits

10.1	Employment Agreement with James V. Mahoney, DPL Inc. and The Dayton Power and Light Company, dated as of May 18, 2006 (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 24, 2006, file #1-9052)
10.2	Letter Agreement between Glenn E. Harder DPL Inc. and the Dayton Power and Light Company dated as of June 20, 2006 (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 21, 2006, file #1-9052)
10.3	Participation Agreement dated as of June 30, 2006 between DPL Inc., The Dayton Power and Light Company and Frederick J. Boyle (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 3, 2006, File #1-9052)
10.4	Participation Agreement dated as of June 20, 2006 between DPL Inc., Dayton Power and Light Company and John J. Gillen (Filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on July 3, 2006, file #1-9052)
10.5	Amendment of Employment Agreement dated as of July 31, 2006 between James V. Mahoney, DPL Inc. and The Dayton Power and Light Company (Filed herewith as Exhibit 10.5)
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
32	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

31

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.

THE DAYTON POWER AND LIGHT COMPANY

(Registrant)

Date:	August 1, 2006	/s/ James V. Mahoney
		James V. Mahoney President and Chief Executive Officer (principal executive officer)
	August 1, 2006	/s/ John  J. Gillen
		John J. Gillen Senior Vice President and Chief Financial Officer (principal financial officer)
	August 1, 2006	/s/ Frederick J. Boyle
		Frederick J. Boyle Controller and Chief Accounting Officer
		(principal accounting officer)

32

EX-10.5

Exhibit 10.5

[DPL Letterhead]

July 31, 2006

Mr. James V. Mahoney

3600 Wood Hollow Road

Dayton, Ohio 45429

Dear Jim:

Reference is made to the Employment Agreement, dated May 18, 2006, by and between you, DPL Inc. and The Dayton Power and Light Company (together with DPL Inc., the “Company”), which provided that your resignation from the Company and the Boards of the Directors of the Company would be effective on July 31, 2006.

This letter agreement amends the Employment Agreement to provide that you will continue your employment with the Company and your service on the Boards of Directors until such date as may be determined by the Boards of Directors, provided you may elect to terminate your employment on a date specified by you in a written notice provided to the Boards of Directors at least 14 days in advance of such date (the earlier of the date specified by the Boards or the date specified by you in such written notice, “New Effective Date”).  In consideration for your continued employment, you will receive your base salary through the New Effective Date and you will be eligible to participate in the Executive Incentive Compensation Program (the “EICP”) for 2006 through the New Effective Date; provided that any payment you may receive under the EICP will be pro rated for the period you are employed by the Company.

Notwithstanding anything herein to the contrary, this letter agreement also confirms that the Company shall pay to you on July 31, 2006 (or promptly thereafter) a lump sum cash payment of (i) five hundred and fifty thousand dollars ($550,000), less any applicable withholding taxes and payroll deductions, and (ii) your unpaid base salary, if any, through July 31, 2006 pursuant to Section 2(a) of the Employment Agreement.  In addition, the following Sections of the Employment Agreement shall continue in full force and effect in accordance with their terms: Section 2(c) (health insurance program), Section 2(d) (out-of-pocket business expenses), Section 3 (waiver of certain compensation/benefits), Section 4 (indemnification), Sections 5 and 6 (release and Directors and Officers Insurance Policy), Section 7 (return of property), Section 8 (confidentiality), Section 9 (non-disparagement), Section 10 (non-compete), Section 11 (amendment), Section 12 (entire agreement), Section 13 (severability) and Section 14 (governing law).

Please indicate your agreement to the terms of this letter agreement by signing below.

	Very truly yours,
	DPL Inc.
	By:
		Glenn E. Harder
		Chairman of the Board
	The Dayton Power and Light Company
	By:
		Glenn E. Harder
		Chairman of the Board
Acknowledged and Agreed to:
James V. Mahoney
Dated: ______________________

2

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, James V. Mahoney, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Dayton Power and Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 1, 2006
Signature:	/s/ James V. Mahoney
Print Name:	James V. Mahoney
Title:	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, John J. Gillen, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Dayton Power and Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 1, 2006
Signature:	/s/ John J. Gillen
Print Name:		John J. Gillen
Title:		Senior Vice President and Chief Financial Officer

EX-32

Exhibit 32

THE DAYTON POWER AND LIGHT COMPANY.

CERTIFICATION PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officers of The Dayton Power and Light Company (the “Issuer”) hereby certify that the Issuer’s Quarterly Report on Form 10-Q for the period ended June 30, 2006, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Issuer.

A signed original of this written statement required by Section 906 has been provided to the Issuer and will be retained by the Issuer and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:
/s/	James V. Mahoney
James V. Mahoney
/s/		John J. Gillen
John J. Gillen
Date: August 1, 2006