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 September 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 October 30, 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
			4
		Consolidated Statements of Cash Flows
		Consolidated Balance Sheets	5
		Notes to Consolidated Financial Statements	7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
		Operating Statistics	32
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
	Item 4.	Controls and Procedures	32
Part II.	Other Information
	Item 1.	Legal Proceedings	33
	Item 1A.	Risk Factors	34
	Item 6.	Exhibits	35
Other
	Signatures		36
	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						Nine months ended
	September 30,						September 30,
$ in millions	2006			2005			2006			2005
Revenues	$	390.3		$	355.5		$	1,036.1		$	952.0
Cost of revenues:
Fuel	91.0			87.9			251.1			235.1
Purchased power	70.7			48.3			134.7			116.0
Total cost of revenues	161.7			136.2			385.8			351.1
Gross margin	228.6			219.3			650.3			600.9
Operating expenses:
Operation and maintenance	58.9			46.2			172.7			145.6
Depreciation and amortization	33.0			31.8			96.8			92.9
General taxes	27.2			28.6			80.3			81.4
Amortization of regulatory assets	2.4			0.6			5.2			1.5
Total operating expenses	121.5			107.2			355.0			321.4
Operating income	107.1			112.1			295.3			279.5
Investment income	1.6			2.5			4.8			4.6
Other income (deductions)	(0.2		)	0.4			0.1			4.5
Charge for early redemption of debt	—			(4.1		)	—			(4.1		)
Interest expense	(5.5		)	(10.1		)	(17.5		)	(30.7		)
Income before income taxes	103.0			100.8			282.7			253.8
Income tax expense	39.0			37.7			107.8			101.5
Net income	64.0			63.1			174.9			152.3
Preferred dividends	0.2			0.2			0.6			0.6
Earnings on common stock	$	63.8		$	62.9		$	174.3		$	151.7

See Notes to Consolidated Financial Statements.
These interim statements are unaudited.

3

THE DAYTON POWER AND LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine months ended
	September 30,
$ in millions	2006			2005
Cash flows from operating activities:
Net income	$	174.9		$	152.3
Adjustments:
Depreciation and amortization	96.8			92.9
Amortization of regulatory assets	5.2			1.5
Deferred income taxes	(13.0		)	(11.4		)
Charge for early redemption of debt	—			4.1
Changes in certain assets and liabilities:
Accounts receivable	(25.7		)	(7.5		)
Accounts payable	41.2			(2.8		)
Net receivable/payable from/to parent	(2.3		)	(0.9		)
Accrued taxes payable	1.5			37.6
Accrued interest payable	4.8			3.1
Prepayments	5.4			3.9
Inventories	(7.5		)	(9.4		)
Deferred compensation assets	3.4			1.6
Deferred compensation obligations	(2.5		)	7.9
Other	(11.5		)	0.6
Net cash provided by operating activities	270.7			273.5
Cash flows from investing activities:
Capital expenditures	(281.7		)	(137.1		)
Net cash (used for) investing activities	(281.7		)	(137.1		)
Cash flows from financing activities:
Issuance of long-term debt, net	—			211.2
Issuance of pollution control bonds	100.0			—
Pollution control bond proceeds held in trust	(100.0		)	—
Withdrawal of restricted funds held in trust	23.1			—
Retirement of long-term debt	—			(218.9		)
Dividends paid on common stock	—			(75.0		)
Dividends paid on preferred stock	(0.6		)	(0.6		)
Net cash provided by/(used for) financing activities	22.5			(83.3		)
Cash and cash equivalents:
Net change	11.5			53.1
Balance at beginning of period	46.2			17.2
Cash and cash equivalents at end of period	$	57.7		$	70.3
Supplemental cash flow information:
Interest paid, net of amounts capitalized	10.3			25.3
Income taxes paid, net	108.3			67.2
Non-cash financing and investing activities:
Restricted funds held in trust (see Note 6 of Notes to Consolidated Financial Statements)	75.5			—

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

4

THE DAYTON POWER AND LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	57.7		$	46.2
Restricted funds held in trust	75.5			—
Accounts receivable, less provision for uncollectible accounts of $1.7 and $1.0, respectively	204.0			182.7
Net intercompany receivable from parent	2.4			—
Inventories, at average cost	85.2			77.7
Taxes applicable to subsequent years	11.5			45.9
Other current assets	36.1			19.3
Total current assets	472.4			371.8
Property, plant and equipment:
Property, plant and equipment	4,363.1			4,118.0
Less: Accumulated depreciation and amortization	(2,050.2		)	(1,973.3		)
Net property	2,312.9			2,144.7
Other noncurrent assets:
Regulatory assets	78.8			83.8
Other deferred assets	136.5			138.3
Total other noncurrent assets	215.3			222.1
Total Assets	$	3,000.6		$	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
	September 30,		December 31,
$ in millions	2006		2005
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	137.8	$	116.2
Accrued taxes	126.1		167.7
Accrued interest	15.2		9.8
Other current liabilities	32.1		28.4
Total current liabilities	311.2		322.1
Noncurrent liabilities:
Long-term debt	785.3		685.9
Deferred taxes	314.7		323.2
Unamortized investment tax credit	44.3		46.4
Other deferred credits	268.9		258.7
Total noncurrent liabilities	1,413.2		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	781.6		783.4
Retained earnings	464.7		290.5
Accumulated other comprehensive income	6.6		5.1
Total common shareholders’ equity	1,253.3		1,079.4
Total Liabilities and Shareholders’ Equity	$	3,000.6	$	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 and nine months ended September 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 and our quarterly reports on Form 10-Q ended March 31, 2006 and June 30, 2006.  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 September 30, 2006, our results of operations for the three and nine months ended September 30, 2006, and our cash flows for the nine months ended September 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 proceedings and orders; and assets and liabilities related to employee benefits.  Actual results may differ from those estimates.  Certain amounts from prior periods have been reclassified to conform to the current reporting presentation.

7

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 September 30, 2006 year-to-date pre-tax results of operations were increased by approximately $0.6 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.

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

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

Accounting for Uncertainty in Income Taxes

In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), effective for fiscal years beginning after December 15, 2006.  FIN 48 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, financial position or cash flows.

Accounting for Fair Value Measurements

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

8

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

In September 2006, the FASB issued Financial Accounting Standards No. 158:  “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS158).  This Statement requires an employer that is a business entity and sponsors one or more single-employer defined benefit plans to:  a.) recognize the funded status of a benefit plan; b.) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost; c.) measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position; d.) disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation. This Statement is effective for fiscal years ending after December 15, 2006 except for the measuring of plan assets at the employer’s fiscal year end which is effective for fiscal years ending after December 15, 2008.  We are currently evaluating the impact of this Statement and have not yet determined the significance of this new rule to our overall results of operations, cash flows or financial position.

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

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

Accounting for Planned Major Maintenance Activity

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

9

2.  Supplemental Financial Information

	At			At
Balance Sheet	September 30,			December 31,
$ in millions	2006			2005
Accounts receivable, net:
Retail customers	$	72.6		$	60.8
Unbilled revenue	46.0			57.5
Partners in commonly-owned plants	56.6			37.7
Wholesale customers and subsidiary customers	8.6			2.8
PJM including financial transmission rights	13.6			11.0
Refundable franchise tax	3.1			11.8
Other	5.2			2.1
Provision for uncollectible accounts	(1.7		)	(1.0		)
Total accounts receivable, net	$	204.0		$	182.7
Inventories, at average cost:
Fuel and emission allowances	$	55.4		$	48.6
Plant materials and supplies	29.8			29.1
Total inventories, at average cost	$	85.2		$	77.7
Other current assets:
Prepayments	$	8.0		$	7.6
Deposits and other advances	16.7			5.8
Current deferred income taxes	4.7			4.9
Derivatives	5.0			—
Other	1.7			1.0
Total other current assets	$	36.1		$	19.3
Property, plant and equipment:
Construction work in process	$	346.3		$	165.1
Property, plant and equipment	4,016.8			3,952.9
Total property, plant and equipment	$	4,363.1		$	4,118.0
Other deferred assets:
Master Trust assets	$	106.1		$	107.7
Unamortized loss on reacquired debt	20.8			22.0
Unamoritized debt expense	8.5			7.4
Other	1.1			1.2
Total other deferred assets	$	136.5		$	138.3
Accounts payable:
Trade payables	$	57.9		$	26.1
Fuel accruals	40.0			39.5
Other	39.9			50.6
Total accounts payable	$	137.8		$	116.2
Other current liabilities:
Customer security deposits	$	19.7		$	19.2
Deferred revenue - financial transmission rights	4.3			—
Current portion of long-term debt	1.0			0.9
Payroll taxes payable	0.3			2.3
Unearned revenues	0.1			0.4
Other	6.7			5.6
Total other current liabilities	$	32.1		$	28.4
Other deferred credits:
Asset retirement obligations - regulated property	$	85.2		$	81.7
Master Trust obligations	73.8			74.5
Retirees’ health and life benefits	32.4			32.9
Pension liability	28.7			23.5
SECA net revenue subject to refund	21.5			20.5
Asset retirement obligations - generation	13.2			13.2
Litigation and claims pending	3.3			3.0
Environmental reserves	0.1			0.1
Other	10.7			9.3
Total other deferred credits	$	268.9		$	258.7

10

2.  Supplemental Financial Information (continued)

	Nine months ended
	September 30,
$ in millions	2006			2005
Cash flows - other:
Payroll taxes payable	$	(2.0	)	$	0.1
Deposits and other advances	(10.5		)	(6.7		)
Deferred storm costs	—			(5.6		)
FERC transitional payment deferral	1.0			15.4
Other	—			(2.6		)
Total cash flows - other	$	(11.5	)	$	0.6

	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2006			2005			2006			2005
Comprehensive income:
Net income	$	64.0		$	63.1		$	174.9		$	152.3
Net change in unrealized gains on financial instruments	1.2			1.1			1.8			6.6
Net change in deferred gains (losses) on cash flow hedges	0.1			(2.0		)	2.9			(4.8		)
Deferred income taxes related to unrealized gains and (losses)	(0.8		)	0.2			(3.2		)	(1.0		)
Total comprehensive income	$	64.5		$	62.4		$	176.4		$	153.1

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

The preferred stock may be redeemed at our option at 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 September 30, 2006, all earnings were available for common stock dividends.  We expect all 2006 earnings to be available for common stock dividends, payable to DPL.

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.

11

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

Net periodic benefit cost

	Pension						Postretirement
$ in millions	2006			2005			2006			2005
Service cost	$	1.0		$	0.9		$	—		$	—
Interest cost	4.3			3.9			0.5			0.5
Expected return on assets	(5.5		)	(5.4		)	(0.2		)	(0.1		)
Amortization of unrecognized:
Actuarial (gain) loss	0.9			1.0			(0.2		)	(0.1		)
Prior service cost	0.7			0.6			—			—
Transition obligation	—			—			0.1			—
Net periodic benefit cost before adjustments	1.4			1.0			0.2			0.3
Settlement cost (a)	2.6			—			—			—
Curtailment cost (b)	—			0.1			—			—
Net periodic benefit cost after adjustments	$	4.0		$	1.1		$	0.2		$	0.3

(a)The settlement cost relates to a former officer (not related to our ongoing litigation with three former executives) who has elected to receive a lump sum distribution in 2007 from the Supplemental Executive Retirement Plan.

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

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

Net periodic benefit cost

	Pension						Postretirement
$ in millions	2006			2005			2006			2005
Service cost	$	3.2		$	2.9		$	—		$	—
Interest cost	12.5			11.8			1.3			1.4
Expected return on assets	(16.3		)	(16.1		)	(0.4		)	(0.4		)
Amortization of unrecognized:
Actuarial (gain) loss	2.9			2.9			(0.6		)	(0.6		)
Prior service cost	1.9			1.7			—			—
Transition obligation	—			—			0.2			0.1
Net periodic benefit cost before adjustments	4.2			3.2			0.5			0.5
Settlement cost (a)	2.6			—			—			—
Special termination benefit cost (b)	0.3			—			—			—
Curtailment cost (c)	—			0.1			—			—
Net periodic benefit cost after adjustments	$	7.1		$	3.3		$	0.5		$	0.5

(a)The settlement cost relates to a former officer (not related to our ongoing litigation with three former executives) who has elected to receive a lump sum distribution in 2007 from the Supplemental Executive Retirement Plan.

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

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

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

Estimated Future Benefit Payments

$ in millions	Pension		Postretirement
2006	$	4.9	$	0.8
2007	$	24.6	$	3.1
2008	$	19.8	$	3.0
2009	$	20.2	$	3.0
2010	$	20.7	$	2.9
2011	$	20.9	$	2.7
2012 – 2016	$	111.9	$	10.7

5.Stock-Based Compensation

We adopted SFAS 123R on January 1, 2006 using the modified prospective approach for stock options and restricted stock units (RSUs).  As a result of our adoption of SFAS 123R, we recognized $0.6 million less compensation expense for the nine months ended September  30, 2006, as compared to what we would have recognized under SFAS 123.

In 2000, our Board of Directors adopted and DPL shareholders approved The DPL Inc. Stock Option Plan.  The plan provides that “no single Participant shall receive Options with respect to more than 2,500,000 shares.”  Options granted in 2000, 2001 and 2002 were fully vested as of December 31, 2005 and expire ten years from the grant date.  In 2003, 100,000 options were granted which vested equitably over five years and expire ten years from the grant date.  In 2004, 200,000 options were granted that vest over nineteen months and expire approximately 6.5 years from the grant date; 100,000 of these options vested in May of 2005 and the remaining 100,000 vested in May 2006.  Another 20,000 options were granted in 2004 that vested in five months and expire ten years from the grant date.  In December 2004, 30,000 options were granted that vest equitably over three years and expire ten years from the grant date.  In 2005, 350,000 options were granted that vested in June 2006 and expire three years from the grant date.  At September 30, 2006, there were 1,528,500 options available for grant.  On April 26, 2006, DPL 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 nine months ended September 30, 2006 was as follows:

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

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Summarized stock option activity was as follows:

	Nine months ended September 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	(40,000		)	(4,000		)
Outstanding at end of period	5,436,500			5,486,500
Exercisable at end of period	5,416,000			4,100,000
Weighted average exercise prices per share:
Outstanding at beginning of year	$	21.86		$	21.39
Granted	—			$	26.82
Exercised	$	21.00		$	21.18
Forfeited	$	15.88		$	29.63
Outstanding at end of period	$	22.02		$	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 not included above 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 three quarters of 2006.  The weighted-average fair value of options granted was $3.80 per share in 2005.  The fair values of the options were estimated as of the dates of grant using a Black-Scholes option pricing model.

In the first quarter of 2006, 10,000 stock options were exercised.  No stock options were exercised in the second or third quarter of 2006.  The market value of options that were vested at September 30, 2006 was approximately $31 million.  Shares issued upon share option exercise are issued from treasury stock.  We have sufficient treasury stock to satisfy outstanding options.

The following table reflects information about stock options outstanding at September 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	4,650,000	3.7 years	$	20.43	4,650,000	$	20.47
$21.01-$29.63	786,500	3.0 years	$	28.01	766,000	$	28.08

As of September 30, 2006, there was $0.1 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 in 2007.

In addition, Restricted Stock Units (RSUs) were granted to certain key employees prior to 2001.  There were 1.3 million RSUs outstanding as of September 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:  20,097 in 2007; 14,688 in 2008; 10,205 in 2009; and 5,008 in 2010.

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

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

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

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

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

Summarized performance shares activity was as follows:

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

There are no exercise prices associated with performance shares.

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

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.

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The following assumptions were used in a Monte Carlo simulation calculated by an actuarial 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	%

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

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

On October 2, 2006, Paul M. Barbas (President and Chief Executive Officer) was granted 19,000 shares of DPL Inc. Restricted Stock (Restricted Shares), granted under the 2006 Equity and Performance Incentive Plan.  These shares were not included in the above calculations as the shares were issued subsequent to September 30, 2006.  The Restricted Shares are to be registered in Mr. Barbas’ name, receive dividends as declared and paid on all DPL common stock and will vest in two tranches.  A total of 9,000 Restricted Shares shall become nonforfeitable on December 31, 2009 if Mr. Barbas remains in the continuous employ of the Company until such date.  The remaining 10,000 Restricted Shares will become nonforfeitable on December 31, 2011 if Mr. Barbas remains a Company employee.

6.     Long-term Debt

	At			At
	September 30,			December 31,
$ in millions	2006			2005
First Mortgage Bonds maturing 2013 - 5.125%	$	470.0		$	470.0
Pollution Control Series maturing through 2036 - 4.79% and 4.78% (a)	314.4			214.4
	$	784.4		$	684.4
Obligation for capital leases	2.2			3.0
Unamortized debt discount	(1.3		)	(1.5		)
Total	$	785.3		$	685.9

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

The amounts of maturities and mandatory redemptions for first mortgage bonds and capital leases are $0.2 million for the remainder of 2006, $0.9 million in 2007, $0.7 million in 2008, $0.7 million in 2009 and $0.7 million in 2010.  Substantially all of our property is subject to the mortgage lien securing the first mortgage bonds 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 September 30, 2006.  Fees associated with this credit facility are approximately $0.2 million per year.  Changes in credit ratings, however, may affect fees and the applicable interest rate for our revolving credit agreement.

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

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

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

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

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 and federal laws. Our units are subject to the acid rain provisions of the Clean Air Act and the NOx and Ozone Transport rule. All of the SO2 and NOx emissions data submitted to the EPA pursuant to these provisions for 2005 and the first quarter 2006 were recorded and reported in compliance with EPA regulations. Subsequently we detected a malfunction with its emission monitoring system at one of its generation stations and ultimately determined its SO2 and NOx emissions data was under reported. We have petitioned the EPA to accept an alternative methodology for calculating actual emissions for 2005 and the first quarter 2006. The Company has sufficient allowances in its general account to cover the understatement and is working with the EPA to resolve the matter. Management does not believe the ultimate resolution of this matter will have a material impact on operating results or financial position. We record liabilities for probable estimated loss in accordance with Statement of Financial Accounting Standards No. 5 (SFAS 5), “Accounting for Contingencies.” To the extent a probable loss can only be estimated by reference to a range of equally probable outcomes, and no amount within the range appears to be a better estimate than any other amount, we accrue for the low end of the range. Because of uncertainties related to these matters, accruals are based on the best information available at the time. We evaluate the potential liability related to probable losses quarterly and may revise our estimates. Such revisions in the estimates of 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,

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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 11 to the Consolidated Financial Statements and, Part I, Item 3, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2005; and Note 7 to the Consolidated Financial Statements and Part II, Item 1, included in our Form 10-Q for the quarterly periods ended March 31, 2006 and June 30, 2006. The following discussion is limited to recent developments concerning our legal proceedings and should be read in conjunction with those earlier reports.

On January 13, 2006, we filed a claim against one of our insurers, Associated Electric & Gas Insurance Services Limited (AEGIS), under a fiduciary liability policy to recoup legal fees associated with our litigation against three former executives.  An arbitration of this matter was held on August 4, 2006.  The arbitration panel ruled on or about September 12, 2006 that the AEGIS policy does not require an advance of defense expenses to us.  Rather, the arbitration panel stated that we are required to file a written undertaking as a condition precedent to repay expenses finally established not to be insured.  We have filed a written undertaking with AEGIS and will continue to pursue resolution of the claim through mediation and arbitration in 2007.

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

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

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

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Contractual Obligations and Commercial Commitments

We enter into various contractual and other long-term obligations that may affect the liquidity of our operations.  At September 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	$	783.1	$	—	$	—	$	—	$	783.1
Interest payments	581.7		39.1		78.3		78.3		386.0
Pension and postretirement payments	249.2		33.4		46.0		47.2		122.6
Capital leases	3.2		1.1		1.4		0.7		—
Operating leases	0.5		0.3		0.2		—		—
Fuel and limestone contracts (a)	586.8		86.7		315.5		97.5		87.1
Other long-term obligations	27.5		14.6		9.8		3.1		—
Total contractual obligations	$	2,232.0	$	175.2	$	451.2	$	226.8	$	1,378.8

(a)DP&L operated units.

Long-term debt:

Long-term debt as of September 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 September 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 September 30, 2006, we had two capital leases that expire in November 2007 and September 2010.

Operating leases:

As of September 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 (FGD) units.  Coal contract prices are subject to periodic adjustment, and have features that limit price escalation in any given year.

A new long-term barge agreement was executed for five years beginning September 2006.

Other long-term obligations:

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

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We enter into various commercial commitments, which may affect the liquidity of our operations.  At September 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 September 30, 2006, there were no borrowings outstanding under this credit agreement.  The new facility may be increased up to $150 million.

Guarantee:

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

8.Peaking Generating Facilities

Through DPL Energy, DPL owns peaking facilities to which DP&L has rights to the capacity, energy and ancillary service output.  DPL has received and is evaluating purchase offers for three of its peaking generation sites. The sites represent a combined capacity of 872 megawatts and a net book value of approximately $300 million.  A decision about whether to sell these assets has not been made or approved. The Company believes that if terms could be reached with potential buyers a transaction could be taken to its Board for approval during the fourth quarter of 2006. If approved, a transaction is not expected to close until the first half of 2007.

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

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UPDATES/OTHER MATTERS

Peaking Generating Facilities

Through DPL Energy, DPL owns peaking facilities to which DP&L has rights to the capacity, energy and ancillary service output.  DPL has received and is evaluating purchase offers for three of its peaking generation sites. The sites represent a combined capacity of 872 megawatts and a net book value of approximately $300 million.  A decision about whether to sell these assets has not been made or approved. The Company believes that if terms could be reached with potential buyers a transaction could be taken to its Board for approval during the fourth quarter of 2006. If approved, a transaction is not expected to close until the first half of 2007.

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 in annual new revenues by 2010.

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

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

We agreed to implement a Voluntary Enrollment Process that would provide residential customers with an option to choose a competitive supplier to provide their retail generation service should switching not reach 20% in each customer class.  During 2005, approximately 51 thousand residential customers that volunteered for the program were bid out 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.  As of October 16, 2006, all four rounds of bids were complete, which resulted in no bids being received.  The magnitude of any customer switching and the financial impact of this program in 2007 cannot be determined at this time.

As of September 30, 2006, four unaffiliated marketers were registered as CRES providers in our service territory; to date, there has been little 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 substantially all of the load served by CRES providers within our service territory in 2006.  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.

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

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

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

On August 28, 2006, the Staff of the PUCO issued a report relating to compliance with the Federal Energy Policy Act of 2005.  In that report the Staff makes recommendations to the Commission to implement new rules and procedures relating to net metering, customer generator interconnection, stand by power, time-of-use rates, and renewable energy portfolio standards.  We, among others, filed comments on September 18, 2006, and reply comments on October 6, 2006.  If adopted by the Commission, these recommendations may result in new regulatory requirements for Ohio investor-owned utilities related to renewable energy standards, fuel sources, automated meter infrastructure, and time differentiated rate options for customers.  The financial implications of this matter cannot be determined at this time.

On July 23, 2003, the Federal Energy Regulatory Commission (FERC) issued an Order that the rates for transmission service of seven companies, including us, may be unjust, unreasonable, or unduly discriminatory or preferential.  A number of orders have since been issued on the subject of how best to modify rates.  As a result, the FERC ordered utilities to eliminate certain charges and to implement transitional charges, known as Seams Elimination Charge Adjustment (SECA), effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, we are obligated to pay SECA charges to other utilities, but we receive a net benefit from these transitional payments.  Beginning May 2005, we began receiving SECA payments and have received over $24.8 million, net of SECA charges, through September 2006.  Several parties have sought rehearing of the FERC orders which are still pending.  The hearing was held in May 2006 and an initial decision was issued on August 10, 2006 that, if upheld by the FERC, would reduce the amount of SECA charges we and other parties are permitted to recover.  We, among others, have taken exception to the initial decision.  A final FERC order on this issue is expected later this year.  We have entered into a significant number of bi-lateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the FERC’s decision to affirm, modify, or reject the initial decision.  We believe we have recorded adequate reserves related to the proposed adjustments; however, we cannot predict the outcome.

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

PJM has a proposal before FERC that may affect the value of our generation capacity.  The proposal introduces a new Reliability Pricing Model (RPM) that would change the way generation capacity is priced and planned for by PJM.  On September 29, 2006, a settlement agreement executed by us along with most of the parties to the case was filed that generally retains the RPM concept as proposed by PJM, with certain modifications.  If approved by the FERC, the economic effects of the settlement will vary depending on future market conditions.

Updates on Environmental Considerations

Air and Water Quality

On December 17, 2003, the United States Environmental Protection Agency (USEPA) proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap sulfur dioxide (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

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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 flue gas desulfurization (FGD) equipment and continual operation of the currently installed Selective Catalytic Reduction (SCR) equipment.  As a result, we are proceeding with the installation and have begun the construction of FGD equipment at various generating units.

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

Under the CAIR and CAM-R cap and trade programs for 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

A comprehensive listing of risk factors that we consider to be the most significant to your decision to invest in us is provided in our most recent Form 10-K and is incorporated herein by reference.  The Form 10-K may be obtained as discussed on page 2, ‘Available Information.’  Any updates are provided in Part II, Item 1A “Risk Factors” of this quarterly report and the quarterly reports for March 31, 2006 and June 30, 2006.  If any of these events occur, our business results of operations, financial position or cash flow could be materially affected.

RESULTS OF OPERATIONS

Income Statement Highlights

		Three months ended						Nine months ended
		September 30,						September 30,
$ in millions		2006			2005			2006			2005
Revenues		$	390.3		$	355.5		$	1,036.1		$	952.0
Less:	Fuel	91.0			87.9			251.1			235.1
	Purchased power	70.7			48.3			134.7			116.0
Gross margin		$	228.6		$	219.3		$	650.3		$	600.9
Gross margin as a percentage of revenues		58.6		%	61.7		%	62.8		%	63.1		%
Operating income		$	107.1		$	112.1		$	295.3		$	279.5

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Revenues

Revenues increased 10% to $390.3 million in the third quarter of 2006 compared to $355.5 million in the third quarter of 2005 reflecting higher average rates for retail sales and greater wholesale sales volume.  These increases were partially offset by lower retail sales volume, lower average rates for wholesale sales and decreased ancillary revenues associated with participation in a RTO.

Retail revenues increased $13.5 million in the third quarter of 2006 compared to 2005, primarily resulting from $21.0 million in higher average rates and $0.5 million of higher miscellaneous revenues, partially offset by decreased sales volume of $8.0 million relating to milder weather experienced in 2006 compared to 2005.  The higher average rates were primarily the result of the rate stabilization plan surcharge and regulated asset recovery riders, most of which were implemented early in 2006.  Wholesale revenues increased $22.9 million, primarily resulting from a $44.6 million increase in sales volume, partially offset by a $21.7 million decrease in average market rates.  During the third quarter of 2006, RTO ancillary revenues decreased $1.6 million to $20.6 million from $22.2 million in the third quarter of 2005.  Cooling degree-days were down 17% to 639 for the third quarter of 2006 compared to 772 for the same period in 2005.  Heating degree-days increased to 105 for the third quarter of 2006 compared to 23 for the same period in 2005.

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

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

Gross Margin, Fuel and Purchased Power

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

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

Operation and Maintenance Expense

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

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

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

Depreciation and Amortization

Depreciation and amortization increased $1.2 million and $3.9 million in the third quarter and in the first nine months of 2006, respectively, compared to the same periods in 2005 primarily reflecting a higher plant base.

General Taxes

General taxes decreased $1.4 million in the third quarter of 2006 compared to the third quarter of 2005 primarily due to a decrease in the Ohio kWh tax related to lower retail customer sales resulting from the milder weather experienced in 2006 compared to 2005 and a 2006 adjustment to payroll taxes.

General taxes decreased $1.1 million in the first nine months of 2006 as compared to the same period in 2005 primarily due to an Ohio kWh tax decrease related to lower retail customer sales resulting from the milder weather experienced in 2006 compared to 2005 and a payroll tax adjustment in 2006.  These decreases were partially offset by higher taxes from the new State of Ohio Commercial Activities Tax that began in July 2005.

Amortization of Regulatory Assets

For the quarter ended September 30, 2006, amortization of regulatory assets was $1.8 million higher than the same period in 2005 primarily reflecting $0.9 million for the amortization of costs incurred to modify the customer billing system for unbundled rates and electric choice bills; $0.4 million for the amortization of PJM administrative fees deferred for the period October 2004 through January 2006; and $0.4 million for the amortization of incremental costs incurred in 2004 and 2005 for severe storms.

Amortization of regulatory assets increased $3.7 million for the nine months ended September 30, 2006 compared to the same period in the prior year primarily reflecting $1.8 million for the amortization of costs incurred to modify the customer billing system to accommodate unbundled rates and electric choice bills; $1.0 million for the amortization of deferred PJM administrative fees; $0.4 million for the amortization of deferred severe storm costs incurred in 2004 and 2005; and $0.3 million for the amortization of costs incurred to integrate us into the PJM system.  We received orders from the PUCO in the first quarter of 2006 approving the recovery of the customer billing costs and PJM administrative fees through rate riders beginning March 2006 and February 2006, respectively.  In July 2006, we received a PUCO order approving the recovery of the incremental storm costs through a rate rider beginning in August 2006.  The customer billing costs rate rider is expected to be in place for five years, the PJM administrative fee rate rider is expected to collect deferred costs over a three-year period, and the storm costs rate rider is expected to be in place for two years.

Investment Income

Investment income decreased $0.9 million during the third quarter of 2006 compared to the third quarter of 2005 primarily due to lower interest income earned from cash on deposit.

Investment income remained stable for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, increasing only $0.2 million or 4%.

Other Income (Deductions)

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

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

Charge for Early Redemption of Debt

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

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Interest Expense

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

Interest expense decreased $13.2 million or 43% in the first nine months of 2006 compared to the first nine months of 2005, primarily relating to $8.0 million of increased capitalized interest resulting from higher pollution control capital expenditures at the generating plants and $5.3 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 increased $1.3 million for the third quarter of 2006 compared to the same period in 2005 reflecting higher book income offset by a decrease in the effective tax rate related to the phase-out of the Ohio Franchise Tax.

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

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FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES

Our cash and cash equivalents totaled $57.7 million at September 30, 2006, compared to $46.2 million at December 31, 2005, an increase of $11.5 million. This increase was attributed to $270.7 million in cash generated from operating activities and $23.1 million of pollution control restricted funds, partially offset by $281.7 million in capital expenditures and $0.6 million in dividends paid on preferred stock.

We generated net cash from operating activities of $270.7 million and $273.5 million for the first nine months of 2006 and 2005, respectively. The net cash 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 $281.7 million and $137.1 million in the nine months ended September 30, 2006 and 2005, respectively, to provide funding for capital expenditures.

Net cash flows provided by financing activities were $22.5 million in the first nine months of 2006 compared to cash used for financing activities of $83.3 million in the first nine months of 2005.  Net cash flows provided by financing activities for the nine months ended September 30, 2006 were primarily the result of $23.1 million of draws from funds held by the trustee to finance our solid waste pollution control capital expenditures, partially offset by $0.6 million of dividends on preferred stock.  Net cash flows used for financing activities for the nine months ended September 30, 2005 were used to retire long-term debt and pay dividends on common and preferred stock.  These uses of cash were partially offset by the issuance of 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 $281.7 million and $137.1 million for the first nine months 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.  For the period 2006 through 2008, we are projecting to spend an estimated $820 million in capital projects (previously $810 million), approximately 57% of which is to meet changing environmental standards.  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 on hand, tax-exempt debt and internally-generated funds.

Debt and Debt Covenants

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

Issuance of additional amounts of first mortgage bonds is limited by the provisions of our mortgage; however, management believes that we continue to have sufficient capacity to issue first mortgage bonds to satisfy our requirements in connection with our construction programs.  The amounts and timing of future financings will

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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 September 30, 2006.  Fees associated with this credit facility are approximately $0.2 million per year.  Changes in credit ratings, however, may affect fees and the applicable interest rate for our revolving credit agreement.

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

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

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

On February 17, 2006, we renewed our $10 million Master Letter of Credit Agreement for one year with a financial lending institution.  This agreement supports performance assurance needs in the ordinary course of business.  We have certain contractual agreements for the sale and purchase of power, fuel and related energy services that contain credit rating related clauses allowing the counter parties to seek additional surety under certain conditions.  As of September 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.	BBB	Positive	August 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.

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Contractual Obligations and Commercial Commitments

We enter into various contractual and other long-term obligations that may affect the liquidity of our operations.  At September 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	$	783.1	$	—	$	—	$	—	$	783.1
Interest payments	581.7		39.1		78.3		78.3		386.0
Pension and postretirement payments	249.2		33.4		46.0		47.2		122.6
Capital leases	3.2		1.1		1.4		0.7		—
Operating leases	0.5		0.3		0.2		—		—
Fuel and limestone contracts (a)	586.8		86.7		315.5		97.5		87.1
Other long-term obligations	27.5		14.6		9.8		3.1		—
Total contractual obligations	$	2,232.0	$	175.2	$	451.2	$	226.8	$	1,378.8

(a) DP&L operated units.

Long-term debt:

Long-term debt as of September 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 September 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 September 30, 2006, we had two capital leases that expire in November 2007 and September 2010.

Operating leases:

As of September 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 (FGD) units.  Coal contract prices are subject to periodic adjustment, and have features that limit price escalation in any given year.

A new long-term barge agreement was executed for five years beginning September 2006.

Other long-term obligations:

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

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We enter into various commercial commitments, which may affect the liquidity of our operations.  At September 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 September 30, 2006, there were no borrowings outstanding under this credit agreement.  The facility may be increased up to $150 million.

Guarantee:

We own a 4.9% equity ownership interest in an electric generation company.  As of September 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 22% of our first nine months 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 September 30, 2006, a hypothetical increase or decrease of 10% in annual wholesale revenues could result in approximately a $19 million increase or decrease to net income, assuming no increases or decreases in fuel and purchased power costs.

We have approximately 100% 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 increase approximately 5% in 2007 compared to 2006.  This forecast assumes coal prices will increase approximately 10% in 2006 as compared to 2005 and increase approximately 5% in 2007 as compared to 2006.

Purchased power costs depend, in part, upon the timing and extent of planned and unplanned outages of our generating capacity.  We will purchase power on a discretionary basis when wholesale market conditions provide opportunities to obtain power at a cost below our internal production costs. As of September 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 $29 million increase or decrease to net income.

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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 September 30, 2006, we had no short-term borrowings.

The carrying value of our debt was $786.3 million at September 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 $789.5 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities.  The principal cash repayments and related weighted average interest rates by maturity date for long-term, fixed-rate debt at September 30, 2006 are as follows:

	Long-term Debt
Expected Maturity	Amount
Date	($ in millions)		Average Rate
2006	$	0.2	6.0	%
2007	0.9		6.1	%
2008	0.7		6.9	%
2009	0.7		6.9	%
2010	0.7		6.9	%
Thereafter	783.1		5.0	%
Total	$	786.3	5.0	%
Fair Value	$	789.5

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 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.

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THE DAYTON POWER AND LIGHT COMPANY

OPERATING STATISTICS

	Three months ended				Nine months ended
	September 30,				September 30,
	2006		2005		2006		2005
Sales (millions of kWh)
Residential	1,432		1,546		3,939		4,182
Commercial	1,075		1,086		2,906		2,937
Industrial	1,169		1,174		3,254		3,281
Other retail	380		380		1,069		1,077
Other miscellaneous revenues	—		—		—		—
Total retail	4,056		4,186		11,168		11,477
Wholesale	1,149		719		2,649		1,913
Total sales	5,205		4,905		13,817		13,390
Revenues ($ in thousands)
Residential	$	137,317	$	136,337	$	369,412	$	362,294
Commercial	73,672		64,875		207,192		184,372
Industrial	35,214		33,887		98,586		95,602
Other retail	22,779		20,844		65,074		60,707
Other miscellaneous revenues	3,289		2,771		8,700		7,836
Total retail	272,271		258,714		748,964		710,811
Wholesale	97,438		74,567		231,469		186,029
RTO ancillary revenues	20,653		22,239		55,696		55,191
Total revenues	$	390,362	$	355,520	$	1,036,129	$	952,031
Electric customers at end of period	513,469		511,948		513,469		511,948

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

See the “Market Risk” section of Item 2.

Item 4.  Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures.  These controls and procedures were designed to ensure that material information relating to us and our subsidiaries is communicated to the CEO and CFO.  We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO.  Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective (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.

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Part II.  Other Information

Item 1.  Legal Proceedings

In the normal course of business, we have 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. We are is also involved in other reviews, investigations and proceedings by governmental and self-regulatory organizations regarding our business. Certain of the foregoing could result in adverse judgments, settlements, fines, penalties or other relief.

Because litigation is inherently unpredictable, particularly in cases where claimants seek substantial or indeterminate damages or where investigations and proceedings are in the early stages, we cannot predict with certainty the loss or range of loss related to such matters, how such matters will be resolved, when they will be ultimately resolved, or what the eventual settlement, fine, penalty or other relief might be. Consequently, we cannot estimate losses or ranges of losses for matters where there is only a reasonable possibility that a loss may have been incurred. Although the ultimate outcome of these 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 11 to the Consolidated Financial Statements and, Part I, Item 3, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2005; and Note 7 to the Consolidated Financial Statements and Part II, Item 1, included in our Form 10-Q for the quarterly period ended March 31, 2006 and June 30, 2006. The following discussion is limited to recent developments concerning our legal proceedings and should be read in conjunction with those earlier reports.

On January 13, 2006, we filed a claim against one of our insurers, Associated Electric & Gas Insurance Services (AEGIS), under a fiduciary liability policy to recoup legal fees associated with our litigation against three former executives.  An arbitration of this matter was held on August 4, 2006.  The arbitration panel ruled on or about September 12, 2006 that the AEGIS policy does not require an advance of defense expenses to us.  Rather, the arbitration panel stated that we are required to file a written undertaking as a condition precedent to repay expenses finally established not to be insured.  We have filed a written undertaking with AEGIS and will continue to pursue resolution of the claim through mediation and arbitration in 2007.

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

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

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

On September 21, 2004, the Sierra Club filed a lawsuit against us and the other owners of the Stuart Generating Station in the United States District Court for the Southern District of Ohio for alleged violations of the Clean Air Act (CAA). On October 13, 2006, and pursuant to an approved procedural schedule, the Sierra Club filed an amended complaint setting forth additional actions taken by us that the Sierra Club alleges were also in violation of the CAA. We are currently reviewing that amended complaint and will vigorously defend our action. The case is currently in discovery; a trial date has not been set.

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 is incorporated herein by reference.  The Form 10-K 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.

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

We are currently constructing flue gas desulfurization (FGD) facilities at five units located at our J. M. Stuart and Killen Electric Generating Stations.  Construction of the FGD facilities at each unit is scheduled to be completed in phases commencing mid-year 2007 through 2008.  We are also co-owners of electric generating stations operated by other investor-owned utilities, who are in various stages of constructing FGD facilities at these stations.  Significant construction delays could adversely affect our ability to operate or may substantially increase our costs to operate these electric generating stations under federal environmental laws and regulations that become effective in 2010.  For those electric generating stations where we are co-owners but do not operate, significant construction delays may substantially increase our pro rata share of the cost to operate those facilities beginning in 2010.

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

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Item 6.  Exhibits

4.1	Loan Agreement, dated as of September 1, 2006, by and between Ohio Air Quality Development Authority and The Dayton Power and Light Company (Filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on September 19, 2006, File #1-2385)
4.2	44th Supplemental Indenture to the First and Refunding Mortgage, dated as of September 1, 2006, by and between the Bank of New York, as trustee and The Dayton Power and Light Company (Filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on September 19, 2006, File #1-2385)
10.1	Non-Employee Director Compensation Summary dated as of September 19, 2006 (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 25, 2006, File #1-2385)
31.1	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 Sarbanes-Oxley Act of 2002

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

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