0001104659-06-070009.txt : 20061101 0001104659-06-070009.hdr.sgml : 20061101 20061031190416 ACCESSION NUMBER: 0001104659-06-070009 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20060930 FILED AS OF DATE: 20061101 DATE AS OF CHANGE: 20061031 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DPL INC CENTRAL INDEX KEY: 0000787250 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 311163136 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-09052 FILM NUMBER: 061176841 BUSINESS ADDRESS: STREET 1: 1065 WOODMAN DRIVE CITY: DAYTON STATE: OH ZIP: 45432 BUSINESS PHONE: 937 259 7142 MAIL ADDRESS: STREET 1: 1065 WOODMAN DRIVE CITY: DAYTON STATE: OH ZIP: 45432 10-Q 1 a06-21527_110q.htm QUARTERLY REPORT PURSUANT TO SECTIONS 13 OR 15(D)

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: 1-9052

DPL INC.

(Exact name of registrant as specified in its charter)

OHIO		31-1163136
(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 x

Accelerated filer o

Non-accelerated filer o

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 113,003,972 shares outstanding of the registrant’s common stock, par value $0.01 per share.

DPL INC.

INDEX

			Page No.
Part I.	Financial Information

	Item 1.	Financial Statements

		Consolidated Statements of Results of Operations	3

		Consolidated Statements of Cash Flows	4

		Consolidated Balance Sheets	5

		Notes to Consolidated Financial Statements	7

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

		Operating Statistics	35

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36

	Item 4.	Controls and Procedures	36

Part II.	Other Information

	Item 1.	Legal Proceedings	37

	Item 1A.	Risk Factors	38

	Item 6.	Exhibits	39

Other

	Signatures		40

	Certifications

Available Information:

DPL Inc. (DPL, the Company, we, us, our, or ours unless the context indicates otherwise) files current, annual and quarterly reports, proxy statements 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 Forms 3, 4 and 5 filed on behalf of our directors and executive officers 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 DPL Investor Relations, 1065 Woodman Drive, Dayton, Ohio 45432.

Part I. Financial Information

Item 1. Financial Statements

DPL INC.

CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions except per share amounts	2006			2005			2006			2005

Revenues	$	392.5		$	357.4		$	1,042.6		$	957.9

Cost of revenues:
Fuel	99.5			101.4			262.3			251.1
Purchased power	61.1			37.4			123.4			103.7
Total cost of revenues	160.6			138.8			385.7			354.8

Gross margin	231.9			218.6			656.9			603.1

Operating expenses:
Operation and maintenance	64.4			52.0			197.4			164.6
Depreciation and amortization	39.1			37.6			114.2			110.4
General taxes	27.5			28.8			82.5			82.8
Amortization of regulatory assets	2.4			0.6			5.2			1.5
Total operating expenses	133.4			119.0			399.3			359.3

Operating income	98.5			99.6			257.6			243.8

Investment income	3.0			33.8			13.9			44.6
Interest expense	(24.9		)	(34.1		)	(77.1		)	(110.5		)
Charge for early redemption of debt	—			(59.1		)	—			(61.2		)
Other income (deductions)	(0.2		)	0.4			0.1			11.6

Earnings from continuing operations before income tax	76.4			40.6			194.5			128.3

Income tax expense	29.0			14.9			73.2			49.8

Earnings from continuing operations	47.4			25.7			121.3			78.5

Earnings from discontinued operations, net of tax	3.4			0.2			11.0			43.0

Net Income	$	50.8		$	25.9		$	132.3		$	121.5

Average number of common shares outstanding (millions)
Basic	107.7			121.2			113.9			120.8
Diluted	117.4			130.5			123.3			128.9

Earnings per share of common stock
Basic:
Earnings from continuing operations	$	0.44		$	0.21		$	1.06		$	0.65
Earnings from discontinued operations	0.03			—			0.10			0.36
Total Basic	$	0.47		$	0.21		$	1.16		$	1.01

Diluted:
Earnings from continuing operations	$	0.40		$	0.20		$	0.98		$	0.61
Earnings from discontinued operations	0.03			—			0.09			0.33
Total Diluted	$	0.43		$	0.20		$	1.07		$	0.94

Dividends paid per share of common stock	$	0.25		$	0.24		$	0.75		$	0.72

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

DPL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
$ in millions	2006			2005
Cash flows from operating activities:
Net income	$	132.3		$	121.5
Less: Earnings from discontinued operations	(11.0		)	(43.0		)
Earnings from continuing operations	121.3			78.5

Adjustments:
Depreciation and amortization	114.2			110.4
Amortization of regulatory assets	5.2			1.5
Deferred income taxes	(4.7		)	(6.7		)
Charge for early redemption of debt	—			61.2
Captive insurance provision	—			3.8
Gain on sale of other investments	(2.2		)	(28.2		)
Changes in certain assets and liabilities:
Accounts receivable	(32.8		)	(12.5		)
Accounts payable	38.4			(21.1		)
Accrued taxes payable	(11.8		)	(7.1		)
Accrued interest payable	(7.3		)	(21.4		)
Prepayments	6.0			4.2
Inventories	(7.6		)	(9.7		)
Deferred compensation assets	1.3			3.1
Deferred compensation obligations	(0.3		)	8.6
Other	(7.3		)	15.3
Net cash provided by operating activities	212.4			179.9

Cash flows from investing activities:
Capital expenditures	(283.9		)	(138.2		)
Purchases of short-term investments and securities	(856.0		)	(215.6		)
Sales of short-term investments and securities	984.0			294.5
Cash flow from discontinued operations	—			868.4
Net cash provided by/(used for) investing activities	(155.9		)	809.1

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			—
Purchase of treasury shares	(400.0		)	—
Exercise of stock options	0.2			18.7
Retirement of long-term debt	—			(673.8		)
Premiums paid for early redemption of debt	—			(54.7		)
Retirement of preferred securities	—			(0.1		)
Dividends paid on common stock	(85.7		)	(86.3		)
Net cash (used for) financing activities	(462.4		)	(585.0		)

Cash and cash equivalents:
Net change	(405.9		)	404.0
Balance at beginning of period	595.8			202.1
Cash and cash equivalents at end of period	$	189.9		$	606.1

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	80.4		$	127.9
Income taxes paid, net	$	79.7		$	55.3
Non-cash financing and investing activities:
Restricted funds held in trust (see Note 7 of Notes to Consolidated Financial Statements)	$	75.5		$	—

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

DPL INC.

CONSOLIDATED BALANCE SHEETS

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

ASSETS

Current assets:
Cash and cash equivalents	$	189.9		$	595.8
Short-term investments available for sale	—			125.8
Restricted funds held in trust	75.5			—
Accounts receivable, less provision for uncollectible accounts of $1.7 and $1.0, respectively	223.0			194.9
Inventories, at average cost	87.7			80.2
Taxes applicable to subsequent years	11.5			45.9
Other current assets	34.9			20.2

Total current assets	622.5			1,062.8

Property:
Property, plant and equipment	4,913.9			4,667.7
Less: Accumulated depreciation and amortization	(2,188.0		)	(2,094.8		)

Net property	2,725.9			2,572.9

Other noncurrent assets:
Regulatory assets	78.8			83.8
Other deferred assets	79.5			72.2

Total other noncurrent assets	158.3			156.0

Total Assets	$	3,506.7		$	3,791.7

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

DPL INC.
CONSOLIDATED BALANCE SHEETS

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

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Current portion - long-term debt	$	226.0	$	0.9
Accounts payable	139.1		130.2
Accrued taxes	122.9		178.5
Accrued interest	22.2		28.9
Other current liabilities	34.1		31.1
Total current liabilities	544.3		369.6

Noncurrent liabilities:
Long-term debt	1,551.9		1,677.1
Deferred taxes	335.0		327.0
Unamortized investment tax credit	44.3		46.4
Insurance and claims costs	24.3		24.3
Other deferred credits	277.1		286.3
Total noncurrent liabilites	2,232.6		2,361.1

Cumulative preferred stock not subject to mandatory redemption	22.9		22.9

Commitments and contingencies (Note 8)

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

	September 2006	December 2005
Shares authorized	250,000,000	250,000,000
Shares issued	163,724,211	163,724,211
Shares outstanding	112,673,972	127,526,404	1.1			1.3
Other paid-in capital, net of treasury stock			—			25.1
Warrants			50.0			50.0
Common stock held by employee plans			(75.1		)	(86.1		)
Retained earnings			744.6			1,062.0
Accumulated other comprehensive loss			(13.7		)	(14.2		)

Total common shareholders’ equity			706.9			1,038.1

Total Liabilities and Shareholders’ Equity			$	3,506.7		$	3,791.7

See Notes to Consolidated Financial Statements.

These interim statements are unaudited.

Notes to Consolidated Financial Statements

1. Basis of Presentation

Description of Business

We are a regional energy company organized in 1985 under the laws of Ohio. We conduct our principal business in one business segment – Electric Utility.

Our principal subsidiary is The Dayton Power and Light Company (DP&L). DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24-county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. DP&L also purchases retail peak load requirements from DPL Energy LLC (DPLE). Principal industries served include automotive, food processing, paper, plastic manufacturing, and defense. DP&L’s sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market.

Our other significant subsidiaries (all of which are wholly-owned) include DPLE, which engages in the operation of peaking generating facilities; DPL Energy Resources, Inc. (DPLER), which sells retail electric energy under contract to industrial and commercial customers in West Central Ohio; DPL Finance Company, Inc. which provides financing opportunities to us and to our subsidiaries; and Miami Valley Insurance Company (MVIC), a captive insurance company for us and our subsidiaries.

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 DPL and its 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; the valuation of insurance and claims costs; 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.

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. See Note 6 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. This 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.

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)” (SFAS 158). 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 SFAS 158 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 Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108 (Topic 1N): “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB 108). 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 SAB 108 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 operations, financial position or cash flows.

2. Discontinued Operations

	Three months ended September 30						Nine months ended September 30
$ in millions	2006			2005			2006			2005
Reconciliation Detail:
Investment income	$	—		$	—		$	—		$	41.3
Investment expenses	(0.3		)	(1.6		)	(0.8		)	(9.0		)
(Loss) Income from discontinued operations	(0.3		)	(1.6		)	(0.8		)	32.3

Gain realized from sale	5.7			—			18.9			53.1
Broker fees and other expenses	—			(0.1		)	—			(6.9		)
Net gain (loss) on sale	5.7			(0.1		)	18.9			46.2

Loss on transfer of fund	—			—			—			(5.6		)
Earnings before income taxes	5.4			(1.7		)	18.1			72.9

Income tax expense (benefit)	2.0			(1.9		)	7.1			29.9
Earnings from discontined operations, net	$	3.4		$	0.2		$	11.0		$	43.0

On February 13, 2005, our subsidiaries, MVE and MVIC, entered into an agreement to sell their respective interests in forty-six private equity funds to AlpInvest/Lexington 2005, LLC, a joint venture of AlpInvest Partners and Lexington Partners, Inc. Sales proceeds and any related gains or losses were recognized as the sale of each fund closed. Among other closing conditions, each fund required the transaction to be approved by the respective general partner of each fund. During the first quarter of 2005, MVE and MVIC completed the sale of their interests in forty of those private equity funds resulting in a $28.8 million pre-tax gain ($33 million less $4.2 million professional fees) from discontinued operations and provided approximately $747 million in net proceeds, including approximately $56 million in net distributions from funds while held for sale. As part of this pre-tax gain, we realized $30 million that was previously recorded as an unrealized gain as part of other comprehensive income. During the second quarter of 2005, MVE and MVIC sold three and a portion of one private equity funds resulting in a $17.5 million pre-tax gain ($20.1 million less $2.6 million professional fees) from discontinued operations and provided approximately $49 million in net proceeds, including approximately $4.4 million in net cash calls from funds while held for sale.

During 2005, MVE also entered into an alternative closing arrangement with AlpInvest/Lexington 2005, LLC for funds where legal title to said funds could not be transferred until a later time. Pursuant to these arrangements, MVE transferred the economic aspects of the remaining private equity funds, consisting of two funds and a portion of one fund, to AlpInvest/Lexington 2005, LLC without a change in ownership of the interests. The terms of the alternative arrangements did not meet the criteria for recording a sale. We are obligated to remit to AlpInvest/Lexington 2005, LLC any distributions MVE receives from these funds, and AlpInvest/Lexington 2005, LLC is obligated to provide funds to us to pay any contribution notice, capital call or other payment notice or bill for which MVE receives notice with respect to such funds. The alternative arrangements resulted in a 2005 deferred gain of $27.1 million until such terms of a sale would be completed (contingent upon receipt of general partner approvals of the transfer) and in 2005 provided approximately $72 million in net proceeds on these funds. We recorded an impairment loss of $5.6 million in the second quarter of 2005 to write down assets transferred pursuant to the alternative arrangements to estimated fair value. Ownership of these funds transfer after the general partners of each of the separate funds consent to the transfer.

On March 31, 2006, MVE completed the sale of the remaining portion of one private equity fund, for which MVE had previously entered into an alternative closing arrangement resulting in the recognition of $13.2 million of the deferred gain. On August 31, 2006, MVE completed the sale of a portion of one of the two remaining private equity funds resulting in recognition of $5.7 million of the deferred gain. The transfer of the remaining funds is expected to be completed in 2007.

There was no investment income from discontinued operations (pre-tax) in the first three quarters of 2006 due to the 2005 sale and the economic transfer of the funds. Investment income from discontinued operations (pre-tax) in the first three quarters of 2005 of $32.3 million is comprised of $41.3 million of investment income less $9.0 million of associated management fees and other expenses. The gain on the sale of the portfolio (pre-tax) in the nine months ended September 30, 2005 of $46.2 million was comprised of $53.1 million of gains less $6.9 million of broker fees and other related expenses.

3. Supplemental Financial Information

Balance Sheet

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

Accounts receivable, net:
Retail customers	$	72.6		$	60.8
Partners in commonly-owned plants	56.6			37.7
Unbilled revenue	53.1			63.6
Wholesale and subsidiary customers	14.3			6.0
PJM including financial transmission rights	13.6			11.0
Refundable franchise tax	5.2			14.3
Other	9.3			2.5
Provision for uncollectible accounts	(1.7		)	(1.0		)

Total accounts receivable, net	$	223.0		$	194.9

Inventories, at average cost:
Fuel and emission allowances	$	55.4		$	48.6
Plant materials and supplies	32.3			31.4
Other	—			0.2

Total inventories, at average cost	$	87.7		$	80.2

Other current assets:
Deposits and other advances	$	17.5		$	9.2
Current deferred income taxes	6.1			5.5
Prepayments	4.7			5.0
Derivatives	5.0			—
Other	1.6			0.5

Total other current assets	$	34.9		$	20.2

Property, plant and equipment:
Construction work in process	$	349.0		$	168.0
Property, plant and equipment	4,564.9			4,499.7

Total property, plant and equipment	$	4,913.9		$	4,667.7

Other deferred assets:
Master Trust assets	$	33.6		$	32.0
Unamortized loss on reacquired debt	20.8			22.0
Unamoritized debt expense	10.7			10.2
Commercial activities tax benefit	6.8			—
Investments	6.6			6.8
Other	1.0			1.2

Total other deferred assets	$	79.5		$	72.2

Accounts payable:
Trade payables	$	58.4		$	26.1
Fuel accruals	40.5			39.5
Other	40.2			64.6

Total accounts payable	$	139.1		$	130.2

Other current liabilities:
Customer security deposits	$	19.7		$	19.2
Deferred revenue - financial transmission rights	4.3			—
Payroll taxes payable	0.3			2.3
Other	9.8			9.6

Total other current liabilities	$	34.1		$	31.1

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
Deferred gain on sale of portfolio	8.2			27.1
Litigation and claims pending	3.3			3.0
Environmental reserves	0.1			0.1
Other	10.7			9.8

Total other deferred credits	$	277.1		$	286.3

3. Supplemental Financial Information (continued)

	Nine months ended
	September 30,
$ in millions	2006			2005

Cash flows - Other:
Payroll taxes payable	$	(1.7	)	$	0.1
Deferred management fees	—			7.9
Deposits and other advances	(9.9		)	(8.1		)
Deferred storm costs	—			(5.6		)
FERC transitional payment deferral	1.0			15.4
Other	3.3			5.6
Total cash flows - Other	$	(7.3	)	$	15.3

	Three months ended						Nine months ended
	September 30,						September 30,
	2006			2005			2006			2005
Comprehensive Income:
Net income	$	50.8		$	25.9		$	132.3		$	121.5
Net change in unrealized gains (losses) on financial instruments	0.3			(19.0		)	1.1			(15.4		)
Net change in unrealized losses on foreign currency translation adjustments	—			(0.4		)	—			(46.3		)
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)	(0.4		)	7.4			(3.5		)	22.2
Comprehensive income	$	50.8		$	11.9		$	132.8		$	77.2

4. Earnings per Share

Basic earnings per share (EPS) are based on the weighted-average number of common shares outstanding during the year. Diluted earnings per share are based on the weighted-average number of common and common equivalent shares outstanding during the year, except in periods where the inclusion of such common equivalent shares is anti-dilutive. We adopted FAS 123R effective January 1, 2006, which changed the calculation of diluted shares as it relates to stock options. This change resulted in diluted shares increasing from the previous methodology by 0.4 million shares for the three months ended September 30, 2006 and 0.5 million shares for the nine months ended September 30, 2006.

Approximately 0.4 million stock options in the third quarter of 2006 and in the third quarter of 2005, respectively, were excluded from the computation of diluted earnings per share because they were anti-dilutive. Approximately 0.4 million stock options for the nine months ending September 30, 2006 and 2005, respectively, were excluded from the computation of diluted earnings per share because they were anti-dilutive. These stock options could be dilutive in the future.

The following table illustrates the reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for net income:

Three months ended September 30,

2006

2005

Per

$ in millions except per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

50.8

107.7

0.47

25.9

121.2

0.21

Effect of Dilutive Securities:

Restricted stock units (a)

1.2

1.2

Warrants

7.3

7.3

Stock options and performance shares (a)

1.2

0.8

Diluted EPS

50.8

117.4

0.43

25.9

130.5

0.20

Nine months ended September 30,

2006

2005

Per

$ in millions except per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

132.3

113.9

1.16

121.5

120.8

1.01

Effect of Dilutive Securities:

Restricted stock units (a)

1.3

1.2

Warrants

6.9

6.2

Stock options and performance shares (a)

1.2

0.7

Diluted EPS

132.3

123.3

1.07

121.5

128.9

0.94

a) We are disputing, among other things, approximately 3.6 million stock options and approximately 1.3 million restricted stock units that were outstanding at September 30, 2006 due to our ongoing litigation with certain former executives and that are included above (see Note 8 of Notes to Consolidated Financial Statements).

5. 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.

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

(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.

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

6. 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 our shareholders approved The DPL Inc. Stock Option Plan. The plan provides that “no single Participant shall receive Options with respect to more than 2,500,000 shares.” Options granted in 2000, 2001 and 2002 were fully vested as of December 31, 2005 and expire ten years from the grant date. In 2003, 100,000 options were granted which vest equitably over five years and expire ten years from the grant date. In 2004, 200,000 options were granted that vested 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 of 2006. Another 20,000 options were granted in 2004 that vested in five months and expire ten years from the grant date. In December of 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 of 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, our 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

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 8 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. 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, our 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 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

	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.

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 quarter ended September 30, 2006, total compensation expense was $0.8 million with an associated tax benefit of $0.3 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.

7. Long-term Debt and Notes Payable

	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

Note to Capital Trust II 8.125% due 2031	195.0			195.0
Senior Notes 6.875% Series due 2011	297.4			297.4
Senior Notes 8.0% Series due 2009	175.0			175.0
Senior Notes 6.25% Series due 2008	100.0			100.0
Senior Notes 8.25% Series due 2007	—			225.0
Obligation for capital leases	2.2			3.0
Unamortized debt discount	(2.1		)	(2.7		)

Total	$	1,551.9		$	1,677.1

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

The amounts of maturities and mandatory redemptions for first mortgage bonds, notes and capital leases are $0.2 million for the remainder of 2006, $225.9 million in 2007, $100.7 million in 2008, $175.7 million in 2009 and $0.7 million in 2010. Substantially all property of DP&L is subject to the mortgage lien securing the first mortgage bonds and the pollution control series.

DP&L has 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: DP&L total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This covenant is currently met. DP&L 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 DP&L’s revolving credit agreement.

On February 17, 2006, DP&L renewed its $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. DP&L has certain contractual agreements for the sale and purchase of power, fuel and related energy services that contain credit rating related clauses allowing the counter parties to seek additional surety under certain conditions. As of September 30, 2006, DP&L had two outstanding letters of credit for a total of $2.2 million.

In March 2004, we completed a $175 million private placement of unsecured 8% series Senior Notes due March 2009. The Senior Notes will not be redeemable prior to maturity except that we have the right to redeem the notes for a make-whole payment at the adjusted treasury rate plus 0.25%. The 8% series Senior Notes were issued pursuant to our indenture dated as of March 1, 2000, and pursuant to authority granted in our Board resolutions dated March 25, 2004. The notes impose a limitation on the incurrence of liens on the capital stock of any of our significant subsidiaries and require us and our subsidiaries to meet a consolidated coverage ratio of 2 to 1 prior to incurring additional indebtedness. The limitation on the incurrence of additional indebtedness does not apply to (i) indebtedness incurred to refinance existing indebtedness, (ii) subordinated indebtedness and (iii) up to $150 million of additional indebtedness. In addition to the events of default specified in the indenture, an event of default under the notes includes a payment default or acceleration of indebtedness under any other indebtedness of ours or any of our subsidiaries which aggregates $25 million or more. The purchasers were granted registration rights in connection with the private placement under an Exchange and Registration Rights Agreement. Pursuant to this agreement, we were obligated to file an exchange offer registration statement by July 22, 2004, have the registration statement declared effective by September 20, 2004 and consummate the exchange offer by October 20, 2004. We failed (1) to have a registration statement declared effective and (2) to complete the exchange offer according to this timeline. As a result, we had been accruing additional interest at a rate of 0.5% per year for each of these two violations, up to an additional interest rate not to exceed in the aggregate 1.0% per year. As each violation is cured, the additional interest rate decreases by 0.5% per annum. Our exchange offer registration statement for these securities was declared effective by the SEC on June 27, 2006. As a result, on June 27, 2006, we ceased accruing 0.5% of the additional interest. On July 31, 2006, we ceased accruing the other 0.5% of additional interest when the exchange of registered notes for the unregistered notes was completed. By completing the exchange, we reduced the annual interest expense by $1.8 million.

During the first quarter of 2006, the Ohio Department of Development (ODOD) awarded DP&L the ability to issue over the next three years up to $200 million of qualified tax-exempt financing from the ODOD’s 2005 volume cap carryforward. The financing is to be used to partially fund the ongoing flue gas desulfurization (FGD) capital projects. The PUCO approved DP&L’s 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 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. DP&L is using the proceeds from these borrowings to assist in financing its 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 borrowing 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, DP&L would eventually be required to return the unused proceeds to bondholders. DP&L expects to draw down all of the proceeds from this borrowing over the next year.

DP&L expects to use the remaining $100 million of 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.

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

8. 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

We and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and law. In the normal course of business, DP&L has investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. DP&L has 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. DP&L’s 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 DP&L 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. DP&L has 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. DP&L records 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, DP&L accrues 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. DP&L evaluates the potential liability related to probable losses quarterly and may revise its estimates. Such revisions in the estimates of the potential liabilities could have a material effect on our results of operations, financial position or cash flows.

Legal Matters

In the normal course of business, we have been named a defendant in various legal actions, including arbitrations, class actions and other litigation. Certain of the legal actions include claims for substantial compensatory and/or punitive damages or claims for indeterminate amounts of damages. We are also involved in other reviews, investigations and proceedings by governmental and self-regulatory organizations regarding our business. Certain of the foregoing could result in adverse judgments, settlements, fines, penalties or other relief.

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

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

Certain legal proceedings in which we are involved are discussed in Note 14 to the Consolidated Financial Statements and, Part I, Item 3, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2005; and Note 8 to the Consolidated Financial Statements and Part II, Item 1, included in our Form 10-Q for the quarterly period ended March 31, 2006 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.

petitions for reassessment with the ODT to protest each assessment as well as request corrected assessments for each tax year. On October 12, 2006, we signed a Memorandum of Understanding with the ODT that stated if the ODT’s positions are ultimately sustained in judicial proceedings, the total additional tax liability that we would be subject to for tax years 2002 through 2004 would be no more than $50.7 million before interest as opposed to the $90.8 million stated in the ODT’s correspondence of February 13, 2006. We believe we have recorded adequate tax reserves related to the proposed adjustments; however, we cannot predict the outcome, which could be material to our results of operations and cash flows.

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

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

Contractual Obligations and Commercial Commitments

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	$	1,774.7	$	225.0	$	275.0	$	297.4	$	977.3
Interest payments	1,129.9		103.4		175.8		149.2		701.5
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	$	3,771.8	$	464.5	$	823.7	$	595.1	$	1,888.5

(a) DP&L operated units.

Long-term debt:

Long-term debt as of September 30, 2006, consists of DP&L’s first mortgage bonds and tax-exempt pollution control bonds, our unsecured notes and includes current maturities and unamortized debt discounts. See Note 7 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 5 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:

DP&L has entered into various long-term coal contracts to supply portions of its coal requirements for its generating plants and a long-term contract to supply limestone for the operation of its 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.

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

Credit facilities:

DP&L has 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:

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

Other:

We completed the sale of or entered into alternative closing arrangements for all private equity funds in our financial asset portfolio as of June 20, 2005. We have an obligation to fund any cash calls or other commitments in which the purchaser of the private equity funds defaults with respect to the funds for which we entered into an alternative closing arrangement. As of September 30, 2006, this obligation is estimated not to exceed $0.1 million.

9. Peaking Generating Facilities

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.

UPDATES/OTHER MATTERS

Peaking Generating Facilities

Updates on Competition and Regulation

On April 4, 2005, DP&L 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 DP&L’s rate stabilization period through December 31, 2010. During this time, DP&L 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 net 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.

DP&L 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 DP&L’s service territory; however, no bids were received and the 2005 program ended. As part of the RSS Stipulation, DP&L 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 DP&L’s service territory; to date, there has been little activity from these suppliers. DPL Energy Resources, Inc. (DPLER), one of our significant subsidiaries, is also a registered CRES provider and accounted for substantially all of the load served by CRES providers within DP&L’s service territory in 2006. In addition, several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date, none of these communities have aggregated their generation load.

In early 2004, there was a complaint filed at the PUCO concerning the pricing of our billing services. The parties reached a settlement on the price we charge CRES providers for performing billing services. The PUCO issued an Order approving the settlement with minor modifications. This Order gave DP&L 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, DP&L filed a subsequent case, requesting PUCO approval for recovery of the deferred billing costs plus carrying charges. On March 1, 2006, the PUCO approved DP&L’s 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 DP&L’s 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, DP&L filed an application requesting the PUCO grant it authority to recover distribution costs associated with storm restoration efforts for ice storms that took place in December 2004 and January 2005. In February 2006, DP&L filed updated schedules in support of its application. On July 12, 2006, the PUCO approved DP&L’s filing, allowing the Company to recover approximately $8.6 million in additional revenues over a two-year period. 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. DP&L, 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 DP&L, 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, DP&L began receiving SECA payments and has 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 DP&L and other parties are permitted to recover. DP&L, among others, has taken exception to the initial decision. A final FERC order on this issue is expected later this year. DP&L has 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. DP&L has recorded adequate reserves related to the proposed adjustments; however, DP&L 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 includes DP&L, address the justness and reasonableness of the current rate design. On November 22, 2005, DP&L, 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. DP&L expects 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, DP&L cannot determine what effect the final outcome of this proceeding may have on its future recovery of transmission revenues.

PJM has a proposal before FERC that may effect 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 DP&L, 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 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, DP&L is proceeding with the installation and has 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 our stock 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 operation, financial position or cash flow could be materially affected.

OVERVIEW

	Basic Earnings Per Share
	Three months ended				Nine months ended
	September 30,				September 30,
	2006		2005		2006		2005

Earnings from Continuing Operations	$	0.44	$	0.21	$	1.06	$	0.65
Earnings from Discontinued Operations	0.03		—		0.10		0.36
Net Income	$	0.47	$	0.21	$	1.16	$	1.01

2006 Compared to 2005

Basic earnings per share of $0.47 for the third quarter of 2006 was $0.26 higher compared to the third quarter of 2005, primarily due to a $0.23 per share increase in Earnings from Continuing Operations. This increase reflects, in large part, a higher gross margin resulting from the revenue impact of the rate stabilization plan and the regulatory asset recovery riders, no early redemption charges for debt, and lower interest expense, offset partially by higher operation and maintenance expenses and lower investment income. This increase was also attributed to a $0.03 per share rise in Earnings from Discontinued Operations, resulting from the third quarter 2006 sale completion of a portion of one of the remaining private equity funds. For the nine months ended September 30, 2006, basic earnings per share of $1.16 was $0.15 higher compared to the same period of the prior year. This increase was due to a $0.41 per share increase in Earnings from Continuing Operations reflecting a higher gross margin resulting from the revenue impact of the rate stabilization plan and the regulatory asset recovery riders, no early redemption charges for debt, and lower interest expense, partially offset by higher operation and maintenance expenses, lower investment income and lower other income. This increase was largely offset by a $0.26 per share decrease in Earnings from Discontinued Operations, resulting from the sale of most of the private equity funds in 2005.

RESULTS OF OPERATIONS

Income Statement Highlights

	Three months ended						Nine months ended
	September 30,						September 30,
$ in millions	2006			2005			2006			2005

Revenues	$	392.5		$	357.4		$	1,042.6		$	957.9
Less: Fuel	99.5			101.4			262.3			251.1
Purchased power	61.1			37.4			123.4			103.7
Gross margin	$	231.9		$	218.6		$	656.9		$	603.1

Gross margin as a percentage of revenues	59.1		%	61.2		%	63.0		%	63.0		%

Operating income	$	98.5		$	99.6		$	257.6		$	243.8

Revenues

Revenues increased 10% to $392.5 million in the third quarter of 2006 compared to $357.4 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 lower ancillary revenues associated with participation in a Regional Transmission Organization (RTO).

Retail revenues increased $15.1 million in the third quarter of 2006 compared to the third quarter of 2005 primarily resulting from $23.7 million related to higher average rates and increased miscellaneous revenues of $0.5 million, partially offset by decreased sales volume of $9.1 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 $21.3 million, primarily related to a $24.3 million increase in sales volume relating to higher prescheduled sales and more generation available to sell in the wholesale market due to the reduced retail sales volume. This increase was partially offset by a $3.0 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.

In the first nine months of 2006, revenues increased 9% to $1,042.6 million compared to $957.9 million in the first nine months of 2005 primarily reflecting higher average rates for retail and wholesale sales as well as 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.

In the first nine months of 2006, retail revenues increased $44.1 million compared to the first nine months of 2005, primarily resulting from $64.7 million related to higher average rates and increased miscellaneous revenues of $0.9 million, partially offset by decreased sales volume of $21.5 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 $39.4 million, primarily related to a $34.7 million increase from higher sales volume reflecting more generation available to sell in the wholesale market due to reduced retail sales volume and better plant availability. A $4.7 million increase in average market rates also contributed to the increase in wholesale revenues. 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. 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 $13.3 million, or 6%, to $231.9 million from $218.6 million in the third quarter of 2005. As a percentage of total revenues, however, gross margin decreased 2.1 percentage points to 59.1% from 61.2%. Fuel costs remained relatively stable in the third quarter of 2006 compared to the same period of the prior year, decreasing only $1.9 million or 2%. Purchased power costs, however, were $23.7 million or 63% higher in the third quarter of 2006 compared to the same period in 2005 resulting from higher purchased power volume due to less generation being available to source power sales resulting from scheduled maintenance and forced outages, partially offset by lower average market rates and lower RTO ancillary costs.

Gross margin in the first nine months of 2006 increased $53.8 million, or 9%, to $656.9 million from $603.1 million in the first nine months of 2005. As a percentage of total revenues, gross margin remained stable at 63% for both 2006 and 2005. Fuel costs increased by $11.2 million or 4% in the first nine months ending September 30, 2006 compared to the same period in 2005 as a result of higher generation output reflecting better plant availability in addition to higher market prices. Purchased power costs increased by $19.7 million or 19% in the first nine months of 2006 compared to the same period in 2005 resulting from higher purchased power volume, increased average market rates, and greater RTO ancillary costs.

Operation and Maintenance Expense

Operation and maintenance expense increased $12.4 million or 24% in the third quarter of 2006 compared to the same period in 2005 primarily resulting from increased legal costs of $4.9 million; a $3.7 million increase in employee compensation and benefit expenses, the majority of which is pension related; increased service operations costs of $2.8 million, most of which 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; increased low-income assistance program costs of $1.6 million; and $1.4 million in PJM administrative fees. These increases were partially offset by a $5.0 million decrease in reserves for insurance, injuries and damages.

Operation and maintenance expense increased $32.8 million or 20% in the first nine months of 2006 compared to the same period in the prior year primarily resulting from a $11.0 million increase in legal costs; an $8.6 million increase in employee compensation and benefit expenses, most of which related to pension expense and incentive accruals; increased service operations costs of $4.9 million, the majority of which was related to greater line clearance activity; a $4.7 million increase in power production costs consisting of $3.0 million of credits received in 2005 that were not received in 2006 and increased operating expenses; $4.2 million in PJM administrative fees, including $2.5 million deferred in 2005 by PUCO authority until rate relief was granted in February 2006; and increased low-income assistance program costs of $3.7 million. These increases were partially offset by a $3.1 million decrease in Directors’ and Officers’ liability insurance premiums; a $2.0 million decrease in reserves for insurance, injuries and damages; and a $1.2 million decrease in mark-to-market adjustments and forfeitures of restricted stock units.

Depreciation and Amortization

Depreciation and amortization increased $1.5 million in the third quarter of 2006 and $3.8 million in the first nine months of 2006 compared to the same periods in 2005 primarily reflecting a higher plant base.

General Taxes

General taxes decreased $1.3 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 $0.3 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 largely offset by higher property taxes resulting from a property tax assessment related to property previously treated as abated under an Enterprise Zone agreement, as well as 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.

For the nine months ended September 30, 2006, amortization of regulatory assets increased $3.7 million from 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 DP&L into the PJM system. DP&L 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, DP&L 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 $30.8 million during the third quarter of 2006 as compared to the same period in 2005 resulting from a $23.4 million decline in gains on investments reflecting the sale of the public equity and income funds in 2005, and a $7.1 million decrease in interest income resulting from lower cash and cash equivalents.

Investment income decreased $30.7 million during the first nine months of 2006 as compared to the same period in the prior year reflecting a $23.8 million decrease in investment income due to the 2005 sale of the public equity and income fund investments, a $4.6 million decrease in foreign currency translation gains following the 2005 liquidation of investments denominated in Euros, and a $2.5 million decrease in interest income resulting from lower cash and cash equivalents.

Interest Expense

Interest expense decreased $9.2 million or 27% for the third quarter of 2006 compared to the same period in 2005 primarily from lower interest of $6.3 million associated with the early redemption of a portion of our long-term debt, the refinancing of DP&L’s pollution control bonds at a lower interest rate, and the elimination of the interest penalty on our $175 million 8% series Senior Notes that resulted from the delayed exchange offer registration of those securities. In addition, we had greater capitalized interest of $3.6 million this year compared to 2005 related to increased pollution control capital expenditures.

For the nine months ended September 30, 2006 compared to the same period in 2005, interest expense declined $33.4 million or 30% primarily from lower interest of $26.1 million associated with the early redemption of a portion of our long-term debt; the refinancing of DP&L’s pollution control bonds at a lower interest rate; and the elimination of the interest penalties on our $175 million 8% series Senior Notes and DP&L’s $470 million 5.125% series First Mortgage Bonds that resulted from the delayed exchange offer registration of those securities, respectively. Greater capitalized interest of $8.0 million related to increased pollution control capital expenditures also contributed to the decrease in interest expense. See Note 7 of Notes to Consolidated Financial Statements.

Charge for Early Redemption of Debt

During the third quarter of 2005, we recorded a $59.1 million charge resulting from premiums paid for the early redemption of debt, including the write-off of unamortized debt expense and debt discounts. For the nine months ended September 30, 2005, the accumulated charge resulting from premiums paid for early redemption of debt, including the write-off of unamortized debt expense and debt discounts, was $61.2 million. There was no such activity in 2006.

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.

For the nine months ended September 30, 2006 compared to the same period in 2005, other income (deductions) declined $11.5 million primarily reflecting gains of $12.3 million realized in 2005 from the sales of pollution control emission allowances. This decrease was partially offset by an IRS refund of $0.7 million related to a prior year penalty, greater capitalized interest (equity portion) of $0.6 million, and $0.4 million in lower revolving credit facility fees incurred by DP&L.

Income Tax Expense

In the third quarter of 2006 compared to the same period in prior year, income taxes increased $14.1 million reflecting higher book income offset by a decrease in the effective tax rate on earnings from continuing operations primarily due to the phase-out of the Ohio Franchise Tax.

In the first nine months of 2006 compared to the first nine months of 2005, income taxes increased $23.4 million reflecting higher book income offset in part by a decrease in the effective tax rate on earnings from continuing operations related to the phase-out of the Ohio Franchise Tax and a decrease in the tax reserve.

Discontinued Operations

Earnings from discontinued operations, net of tax, increased $3.2 million for the third quarter of 2006 compared to the third quarter of 2005 primarily reflecting the completion of the sale of a portion of one of the remaining private equity funds from the financial asset portfolio.

For the nine months ended September 30, 2006 compared to the same period in 2005, earnings from discontinued operations, net of tax, decreased $32.0 million reflecting management’s decision to sell the private equity funds in the financial asset portfolio. Most sales of the private equity funds closed in 2005; a portion of two remaining funds closed in 2006. The remainder of the funds is expected to close in 2007. See Note 2 of Notes to Consolidated Financial Statements.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES

On July 27, 2005, our Board authorized the repurchase of up to $400 million of common stock from time to time in the open market or through private transactions. We completed this share repurchase program on August 21, 2006. During the third quarter of 2006, we repurchased a total of 1.9 million shares at a cost of $51.8 million, including 0.4 million shares purchased in late June that were settled in July 2006 at a cost of $11.1 million. Through August 21, 2006, we repurchased a total of 14.9 million shares at a cost of $400.0 million, including 0.4 million shares at a cost of $10.6 million that were repurchased in December and settled in January 2006. These Board-authorized repurchase transactions resulted in 14.9 million shares being repurchased, or 11.7% of the outstanding stock at December 31, 2005 at an average price of $26.91 per share. These shares are currently held as treasury shares.

The following details the year-to-date activity in treasury shares:

	Number of
	Treasury		Dollar
	Shares Held		Amount
			($ in millions)
Balance at December 31, 2005	36,197,807

Activity:
January	406,000		$	10.6
February	564,000		15.2
March	4,765,700		129.5
April	214,700		5.9
May	2,163,000		57.9
June	4,848,300		129.1
July	417,400		11.1
August	1,483,332		40.7
Total repurchased YTD September 30, 2006	14,862,432		$	400.0
Options exercised first quarter of 2006	(10,000	)
Net activity	14,852,432
Balance at September 30, 2006	51,050,239

Our cash and cash equivalents totaled $189.9 million at September 30, 2006, compared to $595.8 million at December 31, 2005, a decrease of $405.9 million. In addition, we had no short-term investments available for sale at September 30, 2006 in comparison to $125.8 million at December 31, 2005. The decrease in cash and cash equivalents and short-term investments available for sale was primarily attributed to $283.9 million in capital expenditures, $400.0 million used for the purchase of treasury shares and $85.7 million in dividends paid on common stock, partially offset by $212.4 million in cash generated from operating activities.

During the third quarter of 2005, we began investing in Auction Rate Securities (ARS). ARS are variable rate state and municipal bonds that trade at par value. Interest rates on ARS are reset every seven, twenty-eight or thirty-five days through a modified Dutch auction. We have the option to hold at market, re-bid or sell each ARS on the interest reset date. Although ARS are issued and rated as long-term bonds, they are priced and traded as short-term securities available for resale because of the market liquidity provided through the interest rate

reset mechanism. Each ARS purchased by us is tax-exempt, AAA rated and insured by a third-party insurance company. As of June 30, 2006, all of our ARS were sold.

We generated net cash from operating activities of $212.4 million and $179.9 million for the nine months ended September 30, 2006 and 2005, respectively. The net cash provided by operating activities in both years was primarily the result of operating profitability, partially offset by cash used for certain assets and liabilities. The tariff-based revenue from our energy business continues to be the principal source of cash from operating activities. Management believes that the diversified retail customer mix of residential, commercial, and industrial classes provides us with a reasonably predictable cash flow from utility operations.

Net cash flows used for investing activities were $155.9 million for the nine months ended September 30, 2006 compared to net cash provided by investing activities of $809.1 million for the nine months ended September 30, 2005. Net cash flows used for investing activities in 2006 were the result of $283.9 million of capital expenditures, partially offset by $128.0 million of net proceeds from sales and purchases of short-term investments and securities. Net cash flows provided by investing activities for 2005 were the result of $868.4 million of funds provided from discontinued operations and $78.9 million of net proceeds from sales and purchases of short-term investments and securities, partially offset by capital expenditures of $138.2 million.

Net cash flows used for financing activities were $462.4 million and $585.0 million for the nine months ended September 30, 2006 and 2005, respectively. Net cash flows used for financing activities in 2006 were primarily the result of $400.0 million in common stock repurchases related to our stock buyback program and $85.7 million in dividends paid to common shareholders, partially offset by $23.1 million of draws from funds held by the trustee to finance our solid waste pollution control capital expenditures. Net cash flows used for financing activities for 2005 were primarily the result of the retirement of long-term debt of $673.8 million, $86.3 million in dividends paid to common shareholders and $54.7 million used for premiums paid for early debt retirement, partially offset by the issuance of lower interest long-term debt of $211.2 million and $18.7 million received from the exercise of stock options.

Capital Requirements

Capital expenditures were $283.9 million and $138.2 million for the first nine months of 2006 and 2005, respectively, and are expected to approximate an aggregate of $365 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 $830 million in capital projects (previously $820 million), approximately 56% 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 long-term debt, including capital lease obligations, over the next five years are $0.2 million for the remainder of 2006, $225.9 million in 2007, $100.7 million in 2008, $175.7 million in 2009 and $0.7 million in 2010. Substantially all property of DP&L is subject to the mortgage lien securing the first mortgage bonds and the pollution control series. 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 by DP&L is limited by the provisions of its mortgage; however, management believes that DP&L continues to have sufficient capacity to issue first mortgage bonds to satisfy its requirements in connection with its construction programs. The amounts and timing of future financings will depend upon market and other conditions, interest rate increases, levels of electric sales and construction plans.

and (iii) up to $150 million of additional indebtedness. In addition to the events of default specified in the indenture, an event of default under the notes includes a payment default or acceleration of indebtedness under any other indebtedness of ours or any of our subsidiaries which aggregates $25 million or more. The purchasers were granted registration rights in connection with the private placement under an Exchange and Registration Rights Agreement. Pursuant to this agreement, we were obligated to file an exchange offer registration statement by July 22, 2004, have the registration statement declared effective by September 20, 2004 and consummate the exchange offer by October 20, 2004. We failed (1) to have a registration statement declared effective and (2) to complete the exchange offer according to this timeline. As a result, we had been accruing additional interest at a rate of 0.5% per year for each of these two violations, up to an additional interest rate not to exceed in the aggregate 1.0% per year. As each violation is cured, the additional interest rate decreases by 0.5% per annum. Our exchange offer registration statement for these securities was declared effective by the SEC on June 27, 2006. As a result, on June 27, 2006, we ceased accruing 0.5% of the additional interest. On July 31, 2006, we ceased accruing the other 0.5% of additional interest when the exchange of registered notes for the unregistered notes was completed. By completing the exchange, we reduced the annual interest expense by $1.8 million.

During the first quarter of 2006, the Ohio Department of Development (ODOD) awarded DP&L the ability to issue over the next three years up to $200 million of qualified tax-exempt financing from the ODOD’s 2005 volume cap carryforward. The financing is to be used to partially fund the ongoing FGD capital projects. The PUCO approved DP&L’s 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. DP&L is using the proceeds from these borrowings to assist in financing its 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 borrowing 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, DP&L would eventually be required to return the unused proceeds to bondholders. DP&L expects to draw down all of the proceeds from this borrowing over the next year.

Credit Ratings

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

	DPL Inc.	DP&L	Outlook	Effective

Fitch Ratings	BBB	A	Stable	April 2006

Moody’s Investors Service	Baa3	A3	Positive	June 2006

Standard & Poor’s Corp.	BB	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.

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	$	1,774.7	$	225.0	$	275.0	$	297.4	$	977.3
Interest payments	1,129.9		103.4		175.8		149.2		701.5
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	$	3,771.8	$	464.5	$	823.7	$	595.1	$	1,888.5

(a) DP&L operated units.

Long-term debt:

Interest payments:

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

Pension and postretirement payments:

Capital leases:

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

Operating leases:

Fuel and limestone contracts:

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.

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

Credit facilities:

Guarantee:

Other:

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 12.4% of our year-to-date 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 an $11 million increase or decrease to net income, assuming no increases or decreases in fuel and purchased power costs.

Fuel (including coal, gas, oil and emission allowances) and purchased power costs were 37% of total revenues in the first nine months of both 2006 and 2005. 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 compared to 2005 and increase approximately 5% in 2007 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 RTO services, could result in approximately a $29 million increase or decrease to net income.

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 and privately-held secured and unsecured notes and debentures with fixed interest rates. At September 30, 2006, we had no short-term borrowings.

The carrying value of our debt was $1,777.9 million at September 30, 2006, consisting of DP&L’s first mortgage bonds, DP&L’s tax-exempt pollution control bonds, our unsecured notes and DP&L’s capital leases. The fair value of this debt was $1,808.7 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	225.9		8.2	%
2008	100.7		6.3	%
2009	175.7		8.0	%
2010	0.7		6.9	%
Thereafter	1,274.7		5.5	%
Total	$	1,777.9	6.5	%

Fair Value	$	1,808.7

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; the valuation of insurance and claims costs; 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.

DPL INC.

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		381		1,069		1,078
Other miscellaneous revenues	—		—		—		—
Total retail	4,056		4,187		11,168		11,478

Wholesale	1,149		719		2,649		1,913

Total sales	5,205		4,906		13,817		13,391

Revenues ($ in thousands)

Residential	$	137,317	$	136,337	$	369,412	$	362,294
Commercial	79,651		72,655		223,950		205,947
Industrial	64,147		59,495		181,639		168,075
Other retail	22,927		20,934		65,161		60,645
Other miscellaneous revenues	3,276		2,734		8,669		7,718
Total retail	307,318		292,155		848,831		804,679

Wholesale	61,762		40,509		129,704		90,304

RTO ancillary revenues	20,653		22,239		55,696		55,191

Other revenues, net of fuel costs	2,733		2,532		8,356		7,750

Total revenues	$	392,466	$	357,435	$	1,042,587	$	957,924

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.

Part II. Other Information

Item 1. Legal Proceedings

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

Certain legal proceedings in which we are involved are discussed in Note 14 to the Consolidated Financial Statements and, Part I, Item 3, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2005; and Note 8 to the Consolidated Financial Statements and Part II, Item 1, included in our Form 10-Q for the quarterly 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 (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.

In September 2006, we became aware of an unasserted claim 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 the Company 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 actions. The case is currently in discovery; a trial date has not been set.

Item1A. Risk Factors

A comprehensive listing of risk factors that we consider to be the most significant to your decision to invest in our stock is provided in our most recent Annual Report on Form 10-K and is incorporated herein by reference. The Form 10-K may be obtained as discussed on page 2, ‘Available Information.’ 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 generating needs. Effective August 2006, WPAFB secures its generation under the DP&L 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 cost 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.

Item 6. Exhibits

10.1	Form of DPL Inc. Restricted Stock Agreement (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 8, 2006, File #1-9052)

10.2	Participation Agreement dated September 8, 2006 between DPL Inc., The Dayton Power and Light Company and Paul M. Barbas (Filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on September 8, 2006, File #1-9052)

10.3	DPL Inc. Executive Incentive Compensation Plan and Schedule A as amended September 5, 2006 (Filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on September 8, 2006, File #1-9052)

10.4	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 #1-9052)

10.5	DPL Inc. 2006 Deferred Compensation Plan for Executives (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 25, 2006, File #1-9052)

10.6	DPL Inc. Pension Restoration Plan (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 25, 2006, File #1-9052)

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

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.


		DPL INC.
		(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)

EX-31.1 2 a06-21527_1ex31d1.htm EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Paul M. Barbas, certify that:

1. I have reviewed this quarterly report on Form 10-Q of DPL Inc.;

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

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

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

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

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

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

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

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

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

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

Date: October 31, 2006
Signature:	/s/ Paul M. Barbas
Print Name:	Paul M. Barbas
Title:	President and Chief Executive Officer

EX-31.2 3 a06-21527_1ex31d2.htm EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, John J. Gillen, certify that:

1. I have reviewed this quarterly report on Form 10-Q of DPL Inc.;

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

Date: October 31, 2006
Signature:	/s/ John J. Gillen
Print Name:	John J. Gillen
Title:	Senior Vice President and Chief Financial Officer

EX-32 4 a06-21527_1ex32.htm EX-32

Exhibit 32

DPL Inc.

CERTIFICATION PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

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

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

Signed:

/s/ Paul M. Barbas

Paul M. Barbas

/s/ John J. Gillen

John J. Gillen

Date: October 31, 2006