SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2007

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota		41-0462685
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

215 South Cascade Street, Box 496, Fergus Falls, Minnesota		56538-0496
(Address of principal executive offices)		(Zip Code)

866-410-8780

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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 þ 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 (check one):

Large accelerated filer þ           Accelerated filer o           Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). YES o NO þ

Indicate the number of shares outstanding of each of the issuer’s classes of Common Stock, as of the latest practicable date:

October 31, 2007 — 29,847,515 Common Shares ($5 par value)

 

 

OTTER TAIL CORPORATION

INDEX

		Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets — September 30, 2007 and December 31, 2006 (not audited)			2 & 3
Consolidated Statements of Income — Three and Nine Months Ended September 30, 2007 and 2006 (not audited)			4
Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2007 and 2006 (not audited)			5
Notes to Consolidated Financial Statements (not audited)			6-22
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			22-42
Item 3. Quantitative and Qualitative Disclosures About Market Risk			42-44
Item 4. Controls and Procedures			44
Part II. Other Information
Item 1. Legal Proceedings			45
Item 1A. Risk Factors			45-46
Item 6. Exhibits			46-47
Signatures			47
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Otter Tail Corporation

(not audited)

		September 30,				December 31,
		2007				2006
		(Thousands of dollars)
Current assets
Cash and cash equivalents		$	704			$	6,791
Accounts receivable:
Trade—net			161,684				135,011
Other			12,713				10,265
Inventories			97,757				103,002
Deferred income taxes			8,221				8,069
Accrued utility revenues			12,693				23,931
Costs and estimated earnings in excess of billings			44,055				38,384
Other			13,637				9,611
Assets of discontinued operations			—				289
Total current assets			351,464				335,353
Investments and other assets			32,959				29,946
Goodwill—net			99,242				98,110
Other intangibles—net			20,698				20,080
Deferred debits
Unamortized debt expense and reacquisition premiums			5,813				6,133
Regulatory assets and other deferred debits			46,882				50,419
Total deferred debits			52,695				56,552
Plant
Electric plant in service			946,727				930,689
Nonelectric operations			255,913				239,269
Total plant			1,202,640				1,169,958
Less accumulated depreciation and amortization			503,295				479,557
Plant—net of accumulated depreciation and amortization			699,345				690,401
Construction work in progress			86,621				28,208
Net plant			785,966				718,609
Total		$	1,343,024			$	1,258,650

See accompanying notes to consolidated financial statements

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
-Liabilities-

		September 30,				December 31,
		2007				2006
		(Thousands of dollars)
Current liabilities
Short-term debt		$	78,781			$	38,900
Current maturities of long-term debt			3,019				3,125
Accounts payable			111,550				120,195
Accrued salaries and wages			26,660				28,653
Accrued federal and state income taxes			4,308				2,383
Other accrued taxes			10,075				11,509
Other accrued liabilities			13,843				10,495
Liabilities of discontinued operations			—				197
Total current liabilities			248,236				215,457
Pensions benefit liability			42,260				44,035
Other postretirement benefits liability			33,335				32,254
Other noncurrent liabilities			21,581				18,866
Deferred credits
Deferred income taxes			114,843				112,740
Deferred investment tax credit			7,328				8,181
Regulatory liabilities			64,614				63,875
Other			255				281
Total deferred credits			187,040				185,077
Capitalization
Long-term debt, net of current maturities			278,378				255,436
Class B stock options of subsidiary			1,255				1,255
Cumulative preferred shares authorized 1,500,000 shares without par value; outstanding 2007 and 2006 — 155,000 shares			15,500				15,500
Cumulative preference shares — authorized 1,000,000 shares without par value; outstanding — none			—				—
Common shares, par value $5 per share authorized 50,000,000 shares; outstanding 2007 — 29,827,870 and 2006 — 29,521,770			149,139				147,609
Premium on common shares			107,502				99,223
Retained earnings			258,129				245,005
Accumulated other comprehensive income (loss)			669				(1,067	)
Total common equity			515,439				490,770
Total capitalization			810,572				762,961
Total		$	1,343,024			$	1,258,650

See accompanying notes to consolidated financial statements

Otter Tail Corporation

(not audited)

		Three months ended								Nine months ended
		September 30,								September 30,
		2007				2006				2007				2006
		(In thousands, except share								(In thousands, except share
		and per share amounts)								and per share amounts)
Operating revenues
Electric		$	72,052			$	71,134			$	232,403			$	227,062
Nonelectric			230,183				209,408				676,797				591,191
Total operating revenues			302,235				280,542				909,200				818,253
Operating expenses
Production fuel — electric			16,994				15,846				47,496				42,108
Purchased power — electric system use			6,499				8,590				43,531				44,990
Electric operation and maintenance expenses			27,212				26,433				80,738				77,889
Cost of goods sold — nonelectric (excludes depreciation; included below)			179,868				161,148				521,500				449,905
Other nonelectric expenses			30,211				29,543				92,346				85,097
Depreciation and amortization			13,366				12,552				39,406				37,155
Property taxes — electric			2,538				2,260				7,591				7,429
Total operating expenses			276,688				256,372				832,608				744,573
Operating income			25,547				24,170				76,592				73,680
Other income			619				1,060				1,232				2,147
Interest charges			4,927				5,078				14,821				14,622
Income from continuing operations before income taxes			21,239				20,152				63,003				61,205
Income taxes — continuing operations			7,907				6,676				23,160				21,737
Net income from continuing operations			13,332				13,476				39,843				39,468
Discontinued operations
Income from discontinued operations net of taxes of $0; $0; $0 and $28 for the respective periods			—				—				—				26
Net gain on disposition of discontinued operations — net of taxes of $0; $0; $0 and $224 for the respective periods			—				—				—				336
Net income from discontinued operations			—				—				—				362
Net income			13,332				13,476				39,843				39,830
Preferred dividend requirements			184				183				552				551
Earnings available for common shares		$	13,148			$	13,293			$	39,291			$	39,279
Basic earnings per common share:
Continuing operations (net of preferred dividend requirement)		$	0.44			$	0.45			$	1.33			$	1.33
Discontinued operations		$	—			$	—			$	—			$	0.01
		$	0.44			$	0.45			$	1.33			$	1.34
Diluted earnings per common share:
Continuing operations (net of preferred dividend requirement)		$	0.44			$	0.45			$	1.31			$	1.31
Discontinued operations		$	—			$	—			$	—			$	0.01
		$	0.44			$	0.45			$	1.31			$	1.32
Average number of common shares outstanding — basic			29,745,600				29,412,526				29,644,866				29,377,158
Average number of common shares outstanding — diluted			29,995,660				29,805,897				29,887,510				29,764,752
Dividends per common share		$	0.2925			$	0.2875			$	0.8775			$	0.8625

See accompanying notes to consolidated financial statements

Otter Tail Corporation

(not audited)

		Nine months ended
		September 30,
		2007				2006
		(Thousands of dollars)
Cash flows from operating activities
Net income		$	39,843			$	39,830
Adjustments to reconcile net income to net cash provided by operating activities:
Net gain from sale of discontinued operations			—				(336	)
Income from discontinued operations			—				(26	)
Depreciation and amortization			39,406				37,155
Deferred investment tax credit			(852	)			(860	)
Deferred income taxes			2,706				52
Change in deferred debits and other assets			(484	)			(564	)
Discretionary contribution to pension plan			(4,000	)			(4,000	)
Change in noncurrent liabilities and deferred credits			6,116				4,552
Allowance for equity (other) funds used during construction			—				(611	)
Change in derivatives net of regulatory deferral			(163	)			3,364
Stock compensation expense			1,592				1,871
Other — net			(469	)			(123	)
Cash (used for) provided by current assets and current liabilities:
Change in receivables			(26,883	)			(9,063	)
Change in inventories			7,779				(17,663	)
Change in other current assets			3,562				(19,260	)
Change in payables and other current liabilities			(15,194	)			12,248
Change in interest and income taxes payable			4,382				(3,831	)
Net cash provided by continuing operations			57,341				42,735
Net cash provided by discontinued operations			—				1,011
Net cash provided by operating activities			57,341				43,746
Cash flows from investing activities
Capital expenditures			(99,433	)			(53,291	)
Proceeds from disposal of noncurrent assets			8,297				3,623
Acquisitions—net of cash acquired			(6,750	)			—
Increases in other investments			(5,824	)			(3,540	)
Net cash used in investing activities — continuing operations			(103,710	)			(53,208	)
Net proceeds from the sales of discontinued operations			—				1,898
Net cash used in investing activities			(103,710	)			(51,310	)
Cash flows from financing activities
Change in checks written in excess of cash			—				(11	)
Net short-term borrowings			39,881				38,037
Proceeds from issuance of common stock, net of issuance expenses			7,633				1,634
Payments for retirement of common stock			(305	)			(463	)
Proceeds from issuance of long-term debt			25,128				142
Debt issuance expenses			(328	)			(302	)
Payments for retirement of long-term debt			(2,445	)			(2,523	)
Dividends paid			(26,601	)			(25,954	)
Net cash provided by financing activities — continuing operations			42,963				10,560
Net cash provided by financing activities — discontinued operations			—				—
Net cash provided by financing activities			42,963				10,560
Effect of foreign exchange rate fluctuations on cash			(2,681	)			(427	)
Net change in cash and cash equivalents			(6,087	)			2,569
Cash and cash equivalents at beginning of period — continuing operations			6,791				5,430
Cash and cash equivalents at end of period — continuing operations		$	704			$	7,999
Supplemental cash flow information
Cash paid during the year from continuing operations for:
Interest (net of amount capitalized)		$	11,899			$	11,419
Income taxes		$	18,896			$	28,967
Cash paid during the year from discontinued operations for:
Interest		$	—			$	91
Income taxes		$	—			$	423

See accompanying notes to consolidated financial statements

OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated results of operations for the periods presented. The consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes as of and for the years ended December 31, 2006, 2005 and 2004 included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Because of seasonal and other factors, the earnings for the three-month and nine-month periods ended September 30, 2007 should not be taken as an indication of earnings for all or any part of the balance of the year.

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as the electric utility’s forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

Some of the operating businesses enter into fixed-price construction contracts. Revenues under these contracts are recognized on a percentage-of-completion basis. In the first nine months of 2007, 29.5% of the Company’s revenues were recorded under the percentage-of-completion method. The method used to determine the progress of completion is based on the ratio of labor costs incurred to total estimated labor costs at the Company’s wind tower manufacturer, square footage completed to total bid square footage for certain floating dock projects and costs incurred to total estimated costs on all other construction projects. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized. The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:

		September 30,				December 31,
(in thousands)		2007				2006
Costs incurred on uncompleted contracts		$	311,917			$	257,370
Less billings to date			(338,756	)			(284,273	)
Plus estimated earnings recognized			54,569				35,955
		$	27,730			$	9,052

The following amounts are included in the Company’s consolidated balance sheets. Billings in excess of costs and estimated earnings on uncompleted contracts are included in accounts payable:

		September 30,				December 31,
(in thousands)		2007				2006
Costs and estimated earnings in excess of billings on uncompleted contracts		$	44,055			$	38,384
Billings in excess of costs and estimated earnings on uncompleted contracts			(16,325	)			(29,332	)
		$	27,730			$	9,052

Inventories

Inventories consist of the following:

		September 30,				December 31,
(in thousands)		2007				2006
Finished goods		$	40,789			$	46,477
Work in process			6,203				5,663
Raw material, fuel and supplies			50,765				50,862
		$	97,757			$	103,002

Goodwill and Other Intangible Assets

Goodwill increased $1,132,000 in the first nine months of 2007, primarily as a result of the acquisition of Pro Engineering, LLC (Pro Engineering) by BTD Manufacturing, Inc. (BTD) in May 2007.

The following table summarizes the components of the Company’s intangible assets at September 30, 2007 and December 31, 2006:

		September 30, 2007												December 31, 2006
		Gross								Net				Gross								Net
		Carrying				Accumulated				carrying				Carrying				Accumulated				carrying
(in thousands)		amount				amortization				amount				amount				amortization				amount
Amortized intangible assets:
Covenants not to compete		$	2,637			$	2,045			$	592			$	2,198			$	1,813			$	385
Customer relationships			10,879				1,358				9,521				10,574				1,016				9,558
Other intangible assets including contracts			2,787				1,714				1,073				2,083				1,291				792
Total		$	16,303			$	5,117			$	11,186			$	14,855			$	4,120			$	10,735
Non-amortized intangible assets:
Brand/trade name		$	9,512			$	—			$	9,512			$	9,345			$	—			$	9,345

Intangible assets with finite lives are being amortized over average lives ranging from one to twenty-five years. The amortization expense for these intangible assets was $985,000 for the nine months ended September 30, 2007 compared to $829,000 for the nine months ended September 30, 2006. The estimated annual amortization expense for these intangible assets for the next five years is $1,238,000 for 2007, $889,000 for 2008, $795,000 for 2009, $621,000 for 2010 and $516,000 for 2011.

Comprehensive Income

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
Net income		$	13,332			$	13,476			$	39,843			$	39,830
Other comprehensive income (loss) (net-of-tax)
Foreign currency translation gain (loss)			571				(19	)			1,617				545
Amortization of unrecognized losses and costs related to postretirement benefit programs			43				—				131				—
Unrealized (loss) on cash flow hedges			—				(271	)			—				(271	)
Unrealized gain (loss) on available-for-sale securities			5				45				(12	)			33
Total other comprehensive income (loss)			619				(245	)			1,736				307
Total comprehensive income		$	13,951			$	13,231			$	41,579			$	40,137

New Accounting Standards

FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109, was issued by the Financial Accounting Standards Board (FASB) in June 2006. FIN No. 48 clarifies the accounting for uncertain tax positions in accordance with SFAS No. 109, Accounting for Income Taxes. The Company adopted FIN No. 48 on January 1, 2007 and has recognized, in its consolidated financial statements, the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit based solely on the technical merits of those positions as of September 30, 2007. The term “more-likely-than-not” means a likelihood of more than 50%. FIN No. 48 also provides guidance on new disclosure requirements, reporting and accrual of interest and penalties, accounting in interim periods and transition. Only tax positions that meet the “more-likely-than-not” threshold on the reporting date may be recognized. The cumulative effect of adoption of FIN No. 48, which is reported as an adjustment to the beginning balance of retained earnings, was $119,000. As of the date of adoption, the total amount of unrecognized tax benefits for uncertain tax positions was $1,874,000. The amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate was $575,000 as of January 1, 2007. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes.

The balance of unrecognized tax benefits of $1,874,000 on the date of adoption of FIN No. 48 was reduced by $1,566,000 in September 2007 as a result of the Company’s 2003 U.S. federal and North Dakota tax returns being closed to examination or audit. The adjustment of $1,566,000 resulted in a decrease of $377,000 to income tax expense and an increase of $1,189,000 to deferred taxes payable. The total amount of unrecognized tax benefits as of September 30, 2007 is $506,000, which is not expected to change significantly within the next 12 months.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state and foreign income tax returns. As of September 30, 2007 the Company is no longer subject to U.S. federal income tax examinations by tax authorities for years before 2004. As of September 30, 2007 the Company’s earliest open tax year in which an audit can be initiated by state taxing authorities in the Company’s major operating jurisdictions is 2003 for Minnesota and 2004 for North Dakota.

SFAS No. 157, Fair Value Measurements, was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 will be effective for fiscal years beginning after November 15, 2007. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements where fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. The Company is evaluating the impact that adoption of SFAS No. 157 could have on its consolidated financial statements.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115, was issued by the FASB in February 2007. SFAS No. 159, provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses in earnings at each subsequent reporting date on items for which the fair value option has been elected. This statement also establishes presentation and disclosure requirements to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company is evaluating the impact that adoption of SFAS No. 159 could have on its consolidated financial statements.

Acquisitions

On February 19, 2007 ShoreMaster, Inc. (ShoreMaster) acquired the assets of the Aviva Sports product line for $2.0 million in cash. The Aviva Sports product line will be operated through Aviva Sports, Inc. (Aviva), a newly-formed wholly owned subsidiary of ShoreMaster. The Aviva Sports product line is sold internationally and consists of products for consumer use in the pool, lake and yard, as well as commercial use at summer camps, resorts and large public swimming pools. The acquisition of the Aviva Sports product line fits well with the other product lines of ShoreMaster, a leading manufacturer and supplier of waterfront equipment.

On May 15, 2007 BTD acquired the assets of Pro Engineering for $4.8 million in cash. Pro Engineering specializes in providing metal parts stampings to customers in the Midwest. The acquisition of Pro Engineering by BTD provides expanded growth opportunities for both companies.

Disclosure of pro forma information related to the results of operations of the acquired entities for the periods presented in this report is not required due to immateriality.

Below, are condensed balance sheets, at the dates of the respective business combinations, disclosing the preliminary allocation of the purchase price assigned to each major asset and liability category of Aviva and Pro Engineering:

						Pro
(in thousands)		Aviva				Engineering
Assets
Current assets		$	2,083			$	1,956
Goodwill			—				1,048
Other intangible assets			870				396
Fixed assets			—				1,600
Total assets		$	2,953			$	5,000
Liabilities
Current liabilities		$	988			$	215
Noncurrent liabilities			—				—
Total liabilities		$	988			$	215
Cash paid		$	1,965			$	4,785

Other intangible assets related to the Aviva acquisition include $83,000 for a nonamortizable brand name and $787,000 in intangible assets being amortized over various periods up to 15 years. Other intangible assets related to the Pro Engineering acquisition include $51,000 for a nonamortizable brand name and $345,000 in intangible assets being amortized over various periods up to 20 years.

Segment Information

The Company’s businesses have been classified into six segments based on products and services and reach customers in all 50 states and international markets. The six segments are: electric, plastics, manufacturing, health services, food ingredient processing and other business operations.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota under the name Otter Tail Power Company. In addition, the electric utility is an active wholesale participant in the Midwest Independent Transmission System Operator (MISO) markets. The electric utility operations have been the Company’s primary business since incorporation. The Company’s electric operations, including wholesale power sales, are operated as a division of Otter Tail Corporation.

All of the businesses in the following segments are owned by a wholly owned subsidiary of the Company.

Plastics consists of businesses producing polyvinyl chloride and polyethylene pipe in the Upper Midwest and Southwest regions of the United States.

Manufacturing consists of businesses in the following manufacturing activities: production of waterfront equipment, wind towers, material and handling trays and horticultural containers, contract machining, and metal parts stamping and fabrication. These businesses have manufacturing facilities in Minnesota, North Dakota, South Carolina, Missouri, California, Florida and Ontario, Canada and sell products primarily in the United States.

Health services consists of businesses involved in the sale of diagnostic medical equipment, patient monitoring equipment and related supplies and accessories. These businesses also provide equipment maintenance, diagnostic imaging services and rental of diagnostic medical imaging equipment to various medical institutions located throughout the United States.

Food ingredient processing consists of Idaho Pacific Holdings, Inc. (IPH), which owns and operates potato dehydration plants in Ririe, Idaho; Center, Colorado; and Souris, Prince Edward Island, Canada. IPH produces dehydrated potato products that are sold in the United States, Canada, Europe, the Middle East, the Pacific Rim and Central America.

Other business operations consists of businesses in residential, commercial and industrial electric contracting industries, fiber optic and electric distribution systems, wastewater and HVAC systems construction, transportation and energy services, as well as the portion of corporate general and administrative expenses that are not allocated to other segments. These businesses operate primarily in the Central United States, except for the transportation company which operates in 48 states and 6 Canadian provinces.

No single external customer accounts for 10% or more of the Company’s revenues. Substantially all of the Company’s long-lived assets are within the United States except for a food ingredient processing dehydration plant in Souris, Prince Edward Island, Canada and a wind tower manufacturing plant in Ft. Erie, Ontario, Canada.

The following table presents the percent of consolidated sales revenue by country:

		Three months ended								Nine months ended
		September 30,								September 30,
		2007				2006				2007				2006
United States of America			97.8	%			96.8	%			96.7	%			97.0	%
Canada			0.9	%			1.4	%			1.4	%			1.5	%
All other countries (none greater than 1%)			1.3	%			1.8	%			1.9	%			1.5	%

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information on continuing operations for the business segments for three and nine months ended September 30, 2007 and 2006 and total assets by business segment as of September 30, 2007 and December 31, 2006 are presented in the following tables:

Operating Revenue

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
Electric		$	72,110			$	71,206			$	232,662			$	227,308
Plastics			36,975				45,941				114,319				136,731
Manufacturing			95,330				76,667				286,341				226,555
Health services			31,360				35,432				96,775				100,341
Food ingredient processing			15,714				11,474				53,612				30,635
Other business operations			51,956				40,739				129,012				99,397
Intersegment eliminations			(1,210	)			(917	)			(3,521	)			(2,714	)
Total		$	302,235			$	280,542			$	909,200			$	818,253

Interest Expense

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
Electric		$	2,465			$	2,561			$	7,356			$	7,691
Plastics			242				166				750				642
Manufacturing			2,141				1,799				6,125				5,011
Health services			223				225				683				695
Food ingredient processing			34				157				167				354
Other business operations			5,074				4,920				15,009				14,236
Intersegment eliminations			(5,252	)			(4,750	)			(15,269	)			(14,007	)
Total		$	4,927			$	5,078			$	14,821			$	14,622

Income Taxes

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
Electric		$	3,595			$	3,488			$	9,500			$	10,473
Plastics			940				3,067				5,081				9,273
Manufacturing			2,359				1,690				7,564				5,988
Health services			84				243				1,306				903
Food ingredient processing			942				(690	)			1,891				(1,652	)
Other business operations			(13	)			(1,122	)			(2,182	)			(3,248	)
Total		$	7,907			$	6,676			$	23,160			$	21,737

Earnings Available for Common Shares from Continuing Operations

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
Electric		$	6,309			$	6,311			$	16,939			$	18,934
Plastics			1,384				4,578				7,610				14,177
Manufacturing			3,477				2,456				11,351				8,861
Health services			53				300				1,709				1,141
Food ingredient processing			993				(1,078	)			2,985				(3,504	)
Other business operations*			932				726				(1,303	)			(692	)
Total		$	13,148			$	13,293			$	39,291			$	38,917

Total Assets

		September 30,				December 31,
(in thousands)		2007				2006
Electric		$	727,959			$	689,653
Plastics			80,491				80,666
Manufacturing			260,569				219,336
Health services			63,635				66,126
Food ingredient processing			94,149				94,462
Other business operations			116,221				108,118
Discontinued operations			—				289
Total		$	1,343,024			$	1,258,650

Rate and Regulatory Matters

Minnesota AAA Fuel Clause Filing— In a 2005 Fuel Clause Adjustment (FCA) docket that remains open, the Minnesota Department of Commerce (MNDOC) requested that the Minnesota Public Utilities Commission (MPUC) order Otter Tail Power Company to refund 75% of its 2006 asset-based wholesale margins through the FCA in 2007. The Residential and Small Business Utilities Division of the Minnesota Office of Attorney General (MN RUD-OAG) also filed a request with the MPUC agreeing with the MNDOC that there should be a sharing of wholesale margins with ratepayers, but instead of limiting the sharing to 75% of asset-based margins, the MN RUD-OAG recommended that 100% of asset-based wholesale margins, 25% of non-asset-based wholesale margins and 80% of margins from the sale of wholesale ancillary services should be credited to retail customers through the Otter Tail Power Company’s fuel clause adjustment. The MPUC has not ruled on the MNDOC and MN RUD-OAG requests but has deferred consideration of the matter to the pending Annual Automatic Adjustment Report docket. The MNDOC also raised significant related issues in the FCA docket, including an assertion that Otter Tail Power Company and other Minnesota utilities have not appropriately allocated MISO costs between asset-based and non-asset-based transactions. The MNDOC and Otter Tail Power Company have identified two operational situations which are not covered in the approved method for allocating MISO costs. One relates to plants not expected to be available for retail but that produce energy in certain hours, resulting in wholesale sales. The other situation is the sale of Financial Transmission Rights (FTRs) not needed for retail load. For the period July 1, 2005 through June 30, 2007, Otter Tail Power Company determined its Minnesota customers’ portion of costs associated with these situations to be $765,000. The data has been provided to the MNDOC. Otter Tail Power Company offered to

refund $765,000 to its Minnesota customers to settle the issues raised by the MNDOC, and the MNDOC accepted the offer in October 2007. However, the agreement has not been approved by the MPUC.

2007 Minnesota General Rate Case Filing— Otter Tail Power Company filed a general rate case in Minnesota on October 1, 2007 requesting an interim rate increase of 5.41% effective November 30, 2007 and a final overall rate increase of 6.66%. If approved by the MPUC, interim rates will remain in effect for all Minnesota customers until the MPUC makes a final determination on the request, which is expected by August 1, 2008. If final rates are lower than interim rates, Otter Tail Power Company will refund Minnesota customers the difference with interest.

Capacity Expansion 2020 (CapX) Mega Certificate of Need — On August 16, 2007 the eleven CapX utilities asked the MPUC to determine the need for three 345-kilovolt transmission lines. These lines would help ensure continued reliable electricity service in Minnesota and the surrounding region by upgrading and expanding the high-voltage transmission network and providing capacity for more wind energy resources to be developed in southern and western Minnesota, eastern North Dakota and South Dakota. The proposed lines would span more than 600 miles and represent one of the largest single transmission initiatives in the region in several years. The MPUC is expected to decide if the lines are needed by early 2009. The MPUC would determine routes for the new lines in separate proceedings. Portions of the lines would also require approvals by federal officials and by regulators in North Dakota, South Dakota and Wisconsin. After regulatory need is established and routing decisions are complete (expected in 2009 or 2010), construction will begin. The lines would be expected to be completed three or four years later. Great River Energy and Xcel Energy are leading the project, and Otter Tail Power Company and eight other utilities are involved in permitting, building and financing. The Company’s 2007 - 2011 capital budget included $59 million for CapX expenditures.

North Dakota Fuel Clause/MISO Schedule 16 and 17 Agreement— In August 2007 the North Dakota Public Service Commission (NDPSC) approved a settlement agreement between Otter Tail Power Company and an intervener representing several large industrial customers in North Dakota. When the MISO Day 2 energy market began in April 2005, the characterization of some of Otter Tail Power Company’s energy costs changed, though the essential nature of those costs did not. Fuel and purchased energy costs incurred to serve retail customers are recoverable through the FCA in North Dakota. Under the approved settlement agreement, Otter Tail Power Company will refund to North Dakota customers the schedule 16 and 17 costs collected through the FCA since April 2005. Otter Tail Power Company can defer recognition of these costs and request recovery of them in its next general rate case. Purchase power — system use expense was reduced and an offsetting regulatory asset was established for the amount of the refund. The refund amount of $540,000 will be credited to North Dakota customers through the FCA beginning in October 2007. Also as part of the settlement, Otter Tail Power Company agreed to file a general rate case in North Dakota between November 1 and December 31, 2008.

Big Stone II Project— Otter Tail Power Company’s integrated resource plan (IRP) includes generation from Big Stone II, a proposed coal-fired base-load generation unit, beginning in 2013 to accommodate load growth and to replace expiring purchased power contracts and older coal-fired base-load generation units scheduled for retirement. Approval of this IRP is pending with the MPUC, along with a Certificate of Need for transmission lines located in Minnesota that are required for interconnection of the Big Stone II project to the transmission grid. Additionally, a filing in North Dakota for an advanced determination of prudence of Big Stone II was made in November 2006. In September 2007, two project participants, Great River Energy and Southern Minnesota Municipal Power Agency, announced their intention to withdraw from the project. The five remaining project participants are currently assessing options for downsizing the plant or adding new participants. New procedural schedules are being established in the various project-related proceedings, which will take into consideration the optimal plant configuration decided on by the remaining participants.

In February 2007 the South Dakota Appeals Court issued an opinion affirming the decision of the South Dakota Public Utilities Commission to grant a siting permit for Big Stone II. The permit has now been appealed to the South Dakota Supreme Court, which is expected to hear the appeal during its fall session.

As of September 30, 2007 Otter Tail Power Company had capitalized $8.1 million in costs related to the planned construction of Big Stone II. Should approvals of permits not be received on a timely basis, the project could be at risk. If the project is abandoned for permitting or other reasons, these capitalized costs and others incurred in future periods may be subject to expense and may not be recoverable.

Federal

On April 25, 2006 the Federal Energy Regulatory Commission (FERC) issued an order requiring MISO to refund to customers, with interest, amounts related to real-time revenue sufficiency guarantee (RSG) charges that were not allocated to day-ahead virtual supply offers in accordance with MISO’s Transmission and Energy Markets Tariff (TEMT) going back to the commencement of MISO Day 2 markets in April 2005. On May 17, 2006 the FERC issued a Notice of Extension of Time, permitting MISO to delay compliance with the directives contained in its April 2006 order, including the requirement to refund to customers the amounts due, with interest, from April 1, 2005 and the requirement to submit a compliance filing. The Notice stated that the order on rehearing would provide the appropriate guidance regarding the timing of compliance filing. On October 26, 2006 the FERC issued an order on rehearing of the April 25, 2006 order, stating it would not require refunds related to real-time RSG charges that had not been allocated to day-ahead virtual supply offers in accordance with MISO’s TEMT going back to the commencement of the MISO Day 2 market in April 2005. However, the FERC ordered prospective allocation of RSG charges to virtual transactions consistent with the TEMT to prevent future inequity and directed MISO to propose a charge that assesses RSG costs to virtual supply offers based on the RSG costs that virtual supply offers cause within 60 days of the October 26, 2006 order. On December 27, 2006 the FERC issued an order granting rehearing of the October 26, 2006 order.

On March 15, 2007 the FERC issued an order denying requests for rehearing of the RSG rehearing order dated October 27, 2006. In the March 15, 2007 order on rehearing, the FERC stated that its findings in the April 25, 2006 RSG order that virtual offers should share in the allocation of RSG costs, per the terms of the currently-effective tariff, served as notice to market participants that virtual offers, for those market participants withdrawing energy, were liable for RSG charges. FERC clarified that the RSG rehearing order’s waiver of refunds applies to the period before that order, from market start-up in April 2005 until April 24, 2006. After that date, virtual supply offers are liable for RSG costs and therefore, to the extent virtual supply offers were not assessed RSG costs, refunds are due for the period starting April 25, 2006.

On November 5, 2007, the FERC issued two orders related to the RSG proceeding. In the first order, the FERC accepted the Midwest ISO’s April 17, 2007 RSG Compliance filing to comply with the Commission’s March 15, 2007 RSG Order. The compliance reinserted language requiring the actual withdrawal of energy by market participants, restored the Midwest ISO’s original TEMT language allocating RSG costs to virtual transactions, revised the effective date for allocation to imports, provided an explanation of its efforts to reflect partial-hour revenue determinations in its software development, and revised several definitions.

The second related RSG order issued by FERC on November 5, 2007 was its Order on Rehearing on FERC’s April 25, 2006 Order in which it rejected the Midwest ISO’s proposal to remove references to virtual supply from the TEMT provisions related to calculating RSG charges (FERC Docket Nos. ER04-691-084 and ER04-691-086). In this order, the FERC denied the requests for rehearing of the RSG Second Rehearing Order (Otter Tail Power Company was one of the parties that sought rehearing) and FERC denied all requests for rehearing of the RSG Compliance Order.

In the RSG Compliance Order, the Commission rejected the Midwest ISO’s proposal to allocate costs based on net virtual offers, i.e., virtual offers minus virtual bids, and clarified that the currently-effective tariff, which allocates RSG costs to virtual supply offers, remains in effect.

In the RSG Second Rehearing Order, the Commission clarified that for those market participants withdrawing energy, to the extent virtual supply offers were not assessed RSG costs, refunds were due for the period starting April 25, 2006.

The Company recorded a $1.7 million ($1.0 million net-of-tax) charge to earnings in the first quarter of 2007 based on an internal estimate of the net impact of MISO reallocating RSG charges in response to the FERC order on rehearing. In May 2007, MISO informed affected market participants of the impact of reallocating charges based on its interpretation of the FERC order on rehearing. Based on MISO’s interpretation of the order on rehearing, the Company estimated the reallocation of charges would not have a significant impact on earnings previously recognized by the Company. Accordingly, the Company revised its first quarter estimated charge of $1.7 million ($1.0 million net-of-tax) to zero in the second quarter of 2007. The Company is awaiting MISO’s response to the November 5, 2007 RSG compliance Order and cannot determine, as of the date of this report on Form 10-Q, what financial impact, if any, the order will have on the Company’s 2007 consolidated results of operations.

Regulatory Assets and Liabilities

As a regulated entity the Company and the electric utility account for the financial effects of regulation in accordance with SFAS No. 71, Accounting for the Effect of Certain Types of Regulation. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation.

The following table indicates the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheet:

		September 30,				December 31,
(in thousands)		2007				2006
Regulatory assets:
Unrecognized transition obligation, prior service costs and actuarial losses on pension and other postretirement benefits		$	34,187			$	36,736
Deferred income taxes			10,170				11,712
Accrued cost-of-energy revenue			3,592				10,735
Reacquisition premiums			2,470				2,694
MISO schedule 16 and 17 deferred administrative costs — MN			781				541
MISO schedule 16 and 17 deferred administrative costs — ND			523				—
Deferred marked-to-market losses			451				—
Deferred conservation program costs			331				1,036
Accumulated ARO accretion/depreciation adjustment			321				249
Plant acquisition costs			118				151
Total regulatory assets		$	52,944			$	63,854
Regulatory liabilities:
Accumulated reserve for estimated removal costs		$	59,784			$	58,496
Deferred income taxes			4,684				5,228
Gain on sale of division office building			146				151
Total regulatory liabilities		$	64,614			$	63,875
Net regulatory (liability) position		$	(11,670	)		$	(21	)

The regulatory asset related to the unrecognized transition obligation on postretirement medical benefits and prior service costs and actuarial losses on pension and other postretirement benefits represents benefit costs that will be subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. The regulatory assets and liabilities related to deferred income taxes result from changes in

statutory tax rates accounted for in accordance with SFAS No. 109, Accounting for Income Taxes. Accrued cost-of-energy revenue included in Accrued utility revenues will be recovered over the next nine months. Reacquisition premiums included in Unamortized debt expense and reacquisition premiums are being recovered from electric utility customers over the remaining original lives of the reacquired debt issues, the longest of which is 14.8 years. MISO schedule 16 and 17 deferred administrative costs were excluded from recovery through the FCA in Minnesota in a December 2006 order issued by the MPUC. The MPUC ordered the Company to refund MISO schedule 16 and 17 charges that had been recovered through the FCA since the inception of MISO Day 2 markets in April 2005, but allowed for deferral and possible recovery of those costs through rates established in the Company’s Minnesota general rate case filed on October 1, 2007. MISO schedule 16 and 17 deferred administrative costs were excluded from recovery through the FCA in North Dakota in an August 2007 order issued by the NDPSC. The NDPSC ordered the Company to refund MISO schedule 16 and 17 charges that had been recovered through the FCA since the inception of MISO Day 2 markets in April 2005, but allowed for deferral and possible recovery of those costs through rates established in the Company’s next general rate case in North Dakota scheduled to be filed in November or December of 2008. All deferred marked-to-market losses are related to forward purchases of energy scheduled for delivery in November 2007. Deferred conservation program costs represent mandated conservation expenditures recoverable through retail electric rates over the next 1.5 years. The accumulated reserve for estimated removal costs is reduced for actual removal costs incurred. Plant acquisition costs will be amortized over the next 2.7 years. The remaining regulatory assets and liabilities are being recovered from, or will be paid to, electric customers over the next 30 years.

If for any reason, the Company’s regulated businesses cease to meet the criteria for application of SFAS No. 71 for all or part of their operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an extraordinary expense or income item in the period in which the application of SFAS No. 71 ceases.

Common Shares and Earnings per Share

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2006 through September 30, 2007:

Common shares outstanding, December 31, 2006			29,521,770
Issuances:
Stock options exercised			293,382
Directors’ compensation:
Restricted shares			15,200
Unrestricted shares			885
Vesting of restricted stock units			4,522
Restricted shares issued for employee compensation			600
Retirements:
Shares withheld for individual income tax requirements			(8,409	)
Restricted shares forfeited			(80	)
Common shares outstanding, September 30, 2007			29,827,870

Basic earnings per common share are calculated by dividing earnings available for common shares by the weighted average number of common shares outstanding during the period. Diluted earnings per common share are calculated by adjusting outstanding shares, assuming conversion of all potentially dilutive stock options. Stock options with exercise prices greater than the market price are excluded from the calculation of diluted earnings per common share. Nonvested restricted shares granted to the Company’s directors and employees are considered dilutive for the purpose of calculating diluted earnings per share but are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. Underlying shares related to nonvested

restricted stock units granted to employees are considered dilutive for the purpose of calculating diluted earnings per share. Shares expected to be awarded for stock performance awards granted to executive officers are considered dilutive for the purpose of calculating diluted earnings per share.

Excluded from the calculation of diluted earnings per share are the following outstanding stock options which had exercise prices greater than the average market price for the three and nine month periods ended September 30, 2007 and 2006:

Three months ended September 30,		Options Outstanding		Range of Exercise Prices
2007		—		N/A
2006		213,000		$29.74 - $31.34

Nine months ended September 30,		Options Outstanding		Range of Exercise Prices
2007		—		N/A
2006		213,000		$29.74 - $31.34

Share-based Payments

On April 9, 2007 the Compensation Committee of the Company’s Board of Directors granted 23,450 restricted stock units to key employees under the 1999 Stock Incentive Plan, as amended (Incentive Plan), payable in common shares on April 8, 2011, the date the units vest. The grant date fair value of each restricted stock unit was $30.07 per share, as determined under a Monte Carlo valuation method.

On April 9, 2007 the Compensation Committee of the Company’s Board of Directors granted 15,200 shares of restricted stock to the Company’s nonemployee directors under the Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2008 through 2011. The grant date fair value of each share of restricted stock was $35.045 per share, the average market price on the date of grant.

The Company has six share-based payment programs. As of September 30, 2007 the total remaining unrecognized compensation expense related to share-based compensation was approximately $2.8 million (before income taxes), which will be amortized over a weighted-average period of 2.3 years.

Amounts of compensation expense recognized under the Company’s six share-based payment programs for the three and nine months ended September 30, 2007 and 2006 are presented in the table below:

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
1999 Employee Stock Purchase Plan		$	66			$	54			$	193			$	174
Stock options granted under the Incentive Plan			—				68				90				204
Restricted stock granted to directors			103				80				350				321
Restricted stock granted to employees			43				183				455				625
Restricted stock units granted to employees			103				69				281				358
Stock performance awards granted to executive officers			221				267				662				802
Totals		$	536			$	721			$	2,031			$	2,484

Short-term and Long-term Borrowings

Short-term Debt— At September 30, 2007, the Company had outstanding a $150 million line of credit pursuant to a Credit Agreement dated as of April 26, 2007 among the Company, U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Harris Nesbitt Financing, Inc., Keybank National Association, Union Bank of California, N.A., Bank of America, N.A., Bank Hapoalim B.M., and Bank of the West (the Company Credit Agreement). As of September 30, 2007, $68.0 million of the line of credit was in use and $15.7 million was restricted from use to cover outstanding letters of credit. The Company Credit Agreement was scheduled to expire on April 26, 2009 but was terminated and replaced by a new credit agreement entered into by Varistar Corporation on October 2, 2007, as described under “Subsequent Events.”

On September 1, 2006 Otter Tail Corporation, dba Otter Tail Power Company and U.S. Bank National Association entered into a Credit Agreement (the Otter Tail Power Company Credit Agreement) providing for a separate $25 million line of credit. This line of credit is an unsecured revolving credit facility that Otter Tail Power Company can draw on to support the working capital needs and other capital requirements of its electric operations. Borrowings under this line of credit bear interest at LIBOR plus 0.4%, subject to adjustment based on the ratings of the Company’s senior unsecured debt. The Otter Tail Power Company Credit Agreement contains a number of restrictions on the business of Otter Tail Power Company, including restrictions on its ability to merge, sell assets, incur indebtedness, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The Otter Tail Power Company Credit Agreement also contains certain financial covenants. Specifically, the Company must not permit its debt-to-total capitalization ratio to exceed 60% or permit its interest and dividend coverage ratio to be less than 1.5 to 1.

On April 13, 2007 the parties to the Otter Tail Power Company Credit Agreement entered into a First Amendment to Credit Agreement which increased the commitment from $25 million to $50 million. On August 31, 2007 the parties entered into a Second Amendment to the Credit Agreement which further increased the commitment from $50 million to $75 million, and which extended the termination date from September 1, 2007 to September 1, 2008. As of September 30, 2007, $10.8 million was borrowed under the Otter Tail Power Company Credit Agreement.

Long-term Debt— In February 2007 the Company entered into a note purchase agreement (the Cascade Note Purchase Agreement) with Cascade Investment L.L.C. (Cascade) pursuant to which the Company agreed to issue to Cascade, in a private placement transaction, $50 million aggregate principal amount of the Company’s senior notes due November 30, 2017. Cascade owned approximately 8.7% of the Company’s outstanding common stock as of June 30, 2007. The notes will bear interest at a rate of 5.778% per annum, subject to adjustment in the event certain ratings assigned to the Company’s long-term senior unsecured indebtedness are downgraded below specific levels prior to the closing of the note purchase. The terms of the Cascade Note Purchase Agreement are substantially similar to the terms of the note purchase agreement entered into in connection with the issuance of the Company’s $90 million 6.63% senior notes due December 1, 2011 (the 2001 Note Purchase Agreement). The closing is expected to occur on December 3, 2007 subject to the satisfaction of certain conditions to closing, including: (i) no event or events will have occurred since December 31, 2005 that have had or would reasonably be expected to have a material adverse effect on the Company and its subsidiaries taken as a whole; (ii) certain senior executives will remain in their current positions; (iii) there is no change in control or impermissible sale of assets; (iv) the ratio of the Company’s consolidated debt to earnings before interest, taxes, depreciation and amortization as of September 30, 2007 will be less than 3.5 to 1; (v) certain waivers will have been obtained; and (vi) certain other customary conditions of closing will have been satisfied. The proceeds of this financing will be used to redeem the Company’s $50 million 6.375% Senior Debentures due December 1, 2007.

At closings completed in August 2007 and October 2007, the Company issued $155 million aggregate principal amount of its senior unsecured notes, in a private placement transaction, to the purchasers named in a note purchase agreement (the 2007 Note Purchase Agreement) dated August 20, 2007 between the Company and these purchasers. These notes were issued in four series: $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017 (the Series A Notes); $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022 (the Series B Notes); $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027 (the Series C Notes); and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (the Series D Notes). On August 20, 2007, $12 million aggregate principal amount of the Series C Notes and $13 million aggregate principal amount of the Series D Notes were issued and sold pursuant to the 2007 Note Purchase Agreement. The remaining $30 million aggregate principal amount of the Series C Notes and $37 million aggregate principal amount of the Series D Notes, as well as the Series A Notes and the Series B Notes, were issued and sold by the Company at a second closing on October 1, 2007.

Each of the Cascade Note Purchase Agreement, the 2007 Note Purchase Agreement, and the 2001 Note Purchase Agreement states the Company may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. Each of the Cascade Note Purchase Agreement and the 2001 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require the Company to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the respective note purchase agreement. The 2007 Note Purchase Agreement states the Company must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of the Company.

The 2001 Note Purchase Agreement and the 2007 Note Purchase Agreement contain a number of restrictions on the businesses of the Company and its subsidiaries, and the Cascade Note Purchase Agreement contains similar restrictions that will be effective upon issuance to Cascade of the notes thereunder. In each case these include restrictions on the ability of the Company and certain of its subsidiaries to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements and the Lombard US Equipment Finance loan agreement also contain covenants by the Company not to permit its debt-to-total capitalization ratio to exceed 60% or permit its interest and dividend coverage ratio (or in the case of the Cascade Note Purchase Agreement, its interest charges coverage ratio) to be less than 1.5 to 1, determined as of the end of a fiscal quarter for the preceding twelve-month period. The note purchase agreements further restrict the Company from allowing its priority debt to exceed 20% of total capitalization. The Company was in compliance with all of the covenants under its financing agreements as of September 30, 2007.

The Company’s obligations under the 2001 Note Purchase Agreement are, and its obligations under the Cascade Note Purchase Agreement will be, guaranteed by certain of the Company’s subsidiaries.

Class B Stock Options of Subsidiary

As of September 30, 2007 there were 958 options for the purchase of IPH Class B common shares outstanding with a combined exercise price of $743,000, of which 200 options were “in-the-money” with a combined exercise price of $30,000. In April 2007, 100 options were forfeited as a result of a voluntary termination.

Pension Plan and Other Postretirement Benefits

Pension Plan—Components of net periodic pension benefit cost of the Company’s noncontributory funded pension plan are as follows:

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
Service cost—benefit earned during the period		$	1,102			$	1,373			$	3,628			$	3,793
Interest cost on projected benefit obligation			2,626				2,738				8,092				7,826
Expected return on assets			(3,265	)			(3,086	)			(9,711	)			(9,216	)
Amortization of prior-service cost			187				185				557				557
Amortization of net actuarial loss			200				627				818				1,383
Net periodic pension cost		$	850			$	1,837			$	3,384			$	4,343

The Company made $4.0 million in discretionary contributions to its pension plan in the nine months ended September 30, 2007.

Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
Service cost—benefit earned during the period		$	157			$	107			$	470			$	320
Interest cost on projected benefit obligation			362				325				1,087				977
Amortization of prior-service cost			17				18				51				53
Recognized net actuarial loss			135				118				405				354
Net periodic pension cost		$	671			$	568			$	2,013			$	1,704

Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired electric utility and corporate employees are as follows:

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
Service cost—benefit earned during the period		$	194			$	321			$	824			$	989
Interest cost on projected benefit obligation			528				643				1,924				1,917
Amortization of transition obligation			187				187				561				561
Amortization of prior-service cost			(52	)			(77	)			(155	)			(229	)
Amortization of net actuarial loss			(125	)			151				133				417
Effect of Medicare Part D expected subsidy			(105	)			(571	)			(925	)			(1,157	)
Net periodic postretirement benefit cost		$	627			$	654			$	2,362			$	2,498

Discontinued Operations

In June 2006 OTESCO, the Company’s energy services company, sold its natural gas marketing operations for $0.5 million in cash. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires that OTESCO’s natural gas marketing operations be classified and reported separately as discontinued operations. The results of discontinued operations for the nine months ended September 30, 2006 are summarized as follows:

		Nine months ended
(in thousands)		September 30, 2006
Operating revenues		$	28,234
Income before income taxes			54
Gain on Disposition — pretax			560
Income tax expense			252

At December 31, 2006 the major components of assets and liabilities of discontinued operations at estimated fair market values consisted of deferred taxes of $289,000 and warranty reserves of $197,000 from St. George Steel Fabrication, Inc., which was sold in 2005. These assets and liabilities were disposed of or settled in the second quarter of 2007.

Subsequent Events

On October 1, 2007 the second and final closing under the 2007 Note Purchase Agreement was completed. The Company issued and sold the remaining $30 million aggregate principal amount of its Series C Notes, $37 million aggregate principal amount of its Series D Notes, $33 million aggregate principal amount of its Series A Notes and $30 million aggregate principal amount of its Series B Notes. On October 15, 2007 a portion of the proceeds from the issuance were used to retire $40 million aggregate principal amount of the Company’s 5.625% Series of Insured Senior Notes due October 1, 2017 and $25 million aggregate principal amount of the Company’s 6.80% Series of Senior Notes due October 1, 2032.

On October 2, 2007 Varistar Corporation (Varistar), a wholly-owned subsidiary of the Company, entered into a $200 million Credit Agreement (the Varistar Credit Agreement) with the following banks: U.S. Bank National Association as agent for the Banks and as Lead Arranger, Bank of America, N.A., Keybank National Association, and Wells Fargo Bank, National Association, as Co-Documentation Agents, JPMorgan Chase Bank, N.A., Bank of the West and Union Bank of California, N.A. The Varistar Credit Agreement is an unsecured revolving credit facility that Varistar can draw on to support its operations. The Varistar Credit Agreement expires on October 2, 2010. Borrowings under the line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on Varistar’s adjusted cash flow leverage ratio (as defined in the Varistar Credit Agreement). The Varistar Credit Agreement replaces the Company’s Credit Agreement. The Varistar Credit Agreement contains a number of restrictions on the businesses of Varistar and its material subsidiaries, including restrictions on their ability to merge, sell assets, incur indebtedness, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The Varistar Credit Agreement also contains certain financial covenants. Specifically, Varistar must maintain a fixed charge coverage ratio of not less than 1.25 to 1.00 and must not permit its cash flow leverage ratio to exceed 3.00 to 1.00. The Varistar Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. Varistar’s obligations under the Varistar Credit Agreement are guaranteed by each of its material subsidiaries. Outstanding letters of credit issued by Varistar can reduce the amount available for borrowing under the line by up to $30 million.

On October 29, 2007 the Company’s Board of Directors granted performance share awards to the Company’s executive officers under the Incentive Plan. Under these awards, the Company’s executive officers could earn up to an aggregate of 109,000 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance period of January 1, 2007 through December 31, 2009. The aggregate target share award is 54,500 shares. Actual payment may range from zero to 200 percent of the target amount. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance period. In accordance with SFAS No. 123(R), the Company will estimate the fair value of the common shares projected to be awarded on the date of grant under a Monte Carlo valuation method and record compensation expense over the remaining performance period.

Also on October 29, 2007 the Company’s Board of Directors granted 16,700 shares of restricted stock to the Company’s executive officers under the Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2008 through 2011 and are eligible for full dividend and voting rights. The grant-date fair value of the restricted shares is $35.84 per share, the average market price of the shares on their grant date. The $599,000 fair value of the restricted shares awarded will be recorded as compensation expense over the vesting period.

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

RESULTS OF OPERATIONS

Comparison of the Three Months Ended September 30, 2007 and 2006

Consolidated operating revenues were $302.2 million for the three months ended September 30, 2007 compared with $280.5 million for the three months ended September 30, 2006. Operating income was $25.5 million for the three months ended September 30, 2007 compared with $24.2 million for the three months ended September 30, 2006. The Company recorded diluted earnings per share of $0.44 for the three months ended September 30, 2007 compared to $0.45 for the three months ended September 30, 2006.

Following is a more detailed analysis of our operating results by business segment for the three and nine month periods ended September 30, 2007 and 2006, followed by our outlook for the remainder of 2007 and a discussion of changes in our consolidated financial position during the nine months ended September 30, 2007.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the three month periods ended September 30, 2007 and 2006 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

		Three months ended				Three months ended
(in thousands)		September 30, 2007				September 30, 2006
Operating revenues:
Electric		$	59			$	72
Nonelectric			1,151				845
Cost of goods sold			417				359
Other nonelectric expenses			793				558

Electric

		Three months ended
		September 30,												%
(in thousands)		2007				2006				Change				Change
Retail sales revenues		$	59,896			$	59,694			$	202				0.3
Wholesale revenues			6,779				6,099				680				11.1
Net marked-to-market loss			(751	)			(207	)			(544	)			(262.8	)
Other revenues			6,186				5,620				566				10.1
Total operating revenues		$	72,110			$	71,206			$	904				1.3
Production fuel			16,994				15,846				1,148				7.2
Purchased power — system use			6,499				8,590				(2,091	)			(24.3	)
Other operation and maintenance expenses			27,212				26,433				779				2.9
Depreciation and amortization			6,581				6,430				151				2.3
Property taxes			2,538				2,260				278				12.3
Operating income		$	12,286			$	11,647			$	639				5.5

Retail electric revenues increased $0.2 million, reflecting a $0.5 million increase in revenue before Fuel Clause Adjustment (FCA) revenues related to a 4.1% increase in retail megawatt-hour (mwh) sales, offset by a $0.3 million decrease in FCA revenues related to a 6.6% decrease in fuel and purchased power costs per mwh generated and purchased for system use. Commercial mwh sales increased 3.7% between the quarters mainly due to increased consumption by ethanol producers. Industrial mwh sales increased 15.0% between the quarters mainly due to increased consumption by pipeline customers. Weather did not have a discernable impact on the increase in retail mwh sales between the quarters.

Wholesale electric revenues from company-owned generation were $5.7 million for the quarter ended September 30, 2007 compared with $6.1 million for the quarter ended September 30, 2006. The decrease in wholesale revenues from company-owned generation resulted from an 8.4% decrease in wholesale mwh sales as more company-owned generation was used to serve retail load in the third quarter of 2007 compared with the third quarter of 2006. Net revenues from energy trading activities, including net mark-to-market gains on forward energy contracts, were $0.3 million for the quarter ended September 30, 2007 compared with a $0.2 million net loss for the quarter ended September 30, 2006. The $0.5 million increase in revenue from energy trading activities reflects a $1.1 million increase in profits from purchased power resold and net settlements of forward energy contracts, offset by a $0.5 million increase in net mark-to-market losses on forward energy contracts.

The increase in other electric operating revenues for the three months ended September 30, 2007 compared to the three months ended September 30, 2006 was mainly due to an increase in revenues from contracted work for other companies.

The increase in fuel costs for the three months ended September 30, 2007 compared with the three months ended September 30, 2006 reflects a 6.1% increase in the cost of fuel per mwh generated combined with a 1.1% increase in mwhs generated. Generation used for retail electric sales increased 2.7% while generation for wholesale electric sales decreased 8.4% between the quarters. The increase in the cost of fuel per mwh of generation reflects increases in generation at the electric utility’s higher-fuel-cost generation units.

The decrease in purchased power — system use (to serve retail customers) is due to a 43.7% decrease in the cost per mwh purchased, partially offset by a 34.4% increase in mwhs purchased. Power purchases in the third quarter of 2007 reflect a lower proportion of purchases indexed to lower natural gas prices than purchases in the third quarter of 2006, resulting in the decrease in cost per mwh purchased between the quarters.

The increase in other operation and maintenance expenses for the three months ended September 30, 2007 compared with the three months ended September 30, 2006 reflects an increase in material costs related to an increase in contracted work completed for other companies between the quarters. The increases in depreciation and amortization expense and property taxes are related to an increase in electric plant in service in 2007 compared with 2006.

Plastics

		Three months ended
		September 30,												%
(in thousands)		2007				2006				Change				Change
Operating revenues		$	36,975			$	45,941			$	(8,966	)			(19.5	)
Cost of goods sold			31,910				34,172				(2,262	)			(6.6	)
Operating expenses			1,781				3,284				(1,503	)			(45.8	)
Depreciation and amortization			769				693				76				11.0
Operating income		$	2,515			$	7,792			$	(5,277	)			(67.7	)

Operating revenues for the plastics segment decreased mainly as result of an 18.9% decrease in the price per pound of pipe sold between the quarters. The decreases in pipe prices and cost of goods sold reflect the effect of an 8.6% decrease in polyvinyl chloride (PVC) resin prices between the quarters. The decrease in plastics segment operating expenses is due to a decrease in sales and employee incentives directly related to the decreases in sales and operating income between the quarters.

Manufacturing

		Three months ended
		September 30,												%
(in thousands)		2007				2006				Change				Change
Operating revenues		$	95,330			$	76,667			$	18,663				24.3
Cost of goods sold			75,236				61,315				13,921				22.7
Operating expenses			8,800				6,563				2,237				34.1
Depreciation and amortization			3,341				2,845				496				17.4
Operating income		$	7,953			$	5,944			$	2,009				33.8