e10vq

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 June 30, 2005


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

For the transition period from to

Commission file number 0-368

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)


Minnesota		41-0462685

(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer 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 an accelerated filer (as defined in Rule 12b-2
of the Exchange Act). YES þ NO o

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

July 31, 2005 – 29,219,279 Common Shares ($5 par value)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Otter Tail Corporation

Consolidated Balance Sheets
(not audited)
-Assets-


	June 30,		December 31,
	2005		2004
	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	16,179	$	—
Accounts receivable:
Trade—net		120,232		116,141
Other		9,634		9,872
Inventories		95,808		72,504
Deferred income taxes		4,875		4,852
Accrued utility revenues		19,699		15,344
Costs and estimated earnings in excess of billings		25,120		18,145
Other		16,545		7,800
Assets held for sale from discontinued operations		9,938		30,937

Total current assets		318,030		275,595

Investments and other assets		45,985		42,650
Goodwill—net		97,970		92,196
Other intangibles—net		21,549		19,600

Deferred debits
Unamortized debt expense and reacquisition premiums		6,828		7,291
Regulatory assets and other deferred debits		17,046		16,692

Total deferred debits		23,874		23,983

Plant
Electric plant in service		894,398		890,200
Nonelectric operations		216,045		208,311

Total plant		1,110,443		1,098,511
Less accumulated depreciation and amortization		449,240		436,856

Plant—net of accumulated depreciation and amortization		661,203		661,655
Construction work in progress		22,920		18,469

Net plant		684,123		680,124


Total	$	1,191,531	$	1,134,148

See accompanying notes to consolidated financial statements

- 2 -

Otter Tail Corporation

Consolidated Balance Sheets
(not audited)
-Liabilities-


	June 30,			December 31,
	2005			2004
	(Thousands of dollars)
Current liabilities
Short-term debt	$	78,000		$	39,950
Current maturities of long-term debt		4,834			6,016
Accounts payable		75,294			84,433
Accrued salaries and wages		15,524			17,330
Accrued federal and state income taxes		19,311			3,700
Other accrued taxes		9,535			11,391
Other accrued liabilities		12,335			10,417
Liabilities from discontinued operations		1,835			8,585

Total current liabilities		216,668			181,822

Pensions benefit liability		18,652			16,703
Other postretirement benefits liability		25,957			25,053
Other noncurrent liabilities		13,719			11,874

Deferred credits
Deferred income taxes		119,084			121,301
Deferred investment tax credit		9,901			10,477
Regulatory liabilities		58,020			56,909
Other		4,587			1,662

Total deferred credits		191,592			190,349

Capitalization

Long-term debt, net of current maturities		259,615			261,805

Class B stock options of subsidiary		1,271			1,832
Class B stock of subsidiary		728			—

Cumulative preferred shares authorized 1,500,000 shares without par value; outstanding 2004 and 2003 — 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 2005 — 29,170,703 and 2004 — 28,976,919		145,854			144,885
Premium on common shares		91,233			87,865
Unearned compensation		(2,351	)		(2,577	)
Retained earnings		215,011			199,427
Accumulated other comprehensive loss		(1,918	)		(390	)

Total common equity		447,829			429,210
Total capitalization		724,943			708,347


Total	$	1,191,531		$	1,134,148

See accompanying notes to consolidated financial statements

- 3 -

Otter Tail Corporation

Consolidated Statements of Income
(not audited)


	Three months ended					Six months ended
	June 30,					June 30,
	2005			2004		2005		2004
	(In thousands, except share					(In thousands, except share
	and per share amounts)					and per share amounts)
Operating revenues	$	256,378		$	203,457	$	488,511	$	403,040

Operating expenses
Production fuel		10,549			11,193		25,726		25,790
Purchased power — system use		19,904			9,903		31,442		20,825
Electric operation and maintenance expenses		25,334			22,202		49,252		43,479
Cost of goods sold (excludes depreciation; included below)		140,042			110,941		263,676		213,958
Other nonelectric expenses		25,720			21,259		48,461		41,831
Depreciation and amortization		11,553			10,529		22,938		21,036
Property taxes — electric operations		2,408			2,359		5,081		4,848

Total operating expenses		235,510			188,386		446,576		371,767

Operating income		20,868			15,071		41,935		31,273

Other income		215			755		409		766
Interest charges		4,841			4,324		9,407		8,709

Income from continuing operations before income taxes		16,242			11,502		32,937		23,330
Income taxes — continuing operations		5,275			3,694		10,920		7,264

Income from continuing operations		10,967			7,808		22,017		16,066

Discontinued operations
(Loss) income from discontinued operations net of taxes of ($96); $149; $237 and $153 for the respective periods		(149	)		224		348		225
Net gain on disposition of discontinued operations — net of taxes of $6,820 and $5,769 for the three and six months ended June 30, 2005		11,486			—		9,910		—

Net income from discontinued operations		11,337			224		10,258		225

Net income		22,304			8,032		32,275		16,291

Preferred dividend requirements		183			184		367		368

Earnings available for common shares	$	22,121		$	7,848	$	31,908	$	15,923


Basic earnings per common share:
Continuing operations (net of preferred dividend requirement)	$	0.37		$	0.29	$	0.74	$	0.61
Discontinued operations	$	0.39		$	0.01	$	0.35	$	0.01

	$	0.76		$	0.30	$	1.09	$	0.62

Diluted earnings per common share:
Continuing operations (net of preferred dividend requirement)	$	0.37		$	0.29	$	0.74	$	0.60
Discontinued operations	$	0.39		$	0.01	$	0.35	$	0.01

	$	0.76		$	0.30	$	1.09	$	0.61

Average number of common shares outstanding — basic		29,158,140			25,891,440		29,142,118		25,842,241
Average number of common shares outstanding — diluted		29,263,643			26,013,519		29,244,698		25,969,648

Dividends per common share	$	0.280		$	0.275	$	0.560	$	0.550

See accompanying notes to consolidated financial statements

- 4 -

Otter Tail Corporation

Consolidated Statements of Cash Flows
(not audited)


	Six months ended
	June 30,
	2005			2004
	(Thousands of dollars)
Cash flows from operating activities
Net income	$	32,275		$	16,291
Adjustments to reconcile net income to net cash provided by operating activities:
Net gain from sale of discontinued operations		(9,910	)		—
Income from discontinued operations		(348	)		(225	)
Depreciation and amortization		22,938			21,037
Deferred investment tax credit		(576	)		(576	)
Deferred income taxes		(3,985	)		1,194
Change in deferred debits and other assets		3,766			401
Discretionary contribution to pension plan		(4,000	)		(2,000	)
Change in noncurrent liabilities and deferred credits		5,750			2,594
Allowance for equity (other) funds used during construction		(357	)		(390	)
Change in derivatives net of regulatory deferral		(736	)		(729	)
Other — net		825			988
Cash (used for) provided by current assets and current liabilities:
Change in receivables		(3,198	)		3,409
Change in inventories		(20,414	)		(6,390	)
Change in other current assets		(17,625	)		(6,466	)
Change in payables and other current liabilities		(9,329	)		(15,328	)
Change in interest and income taxes payable		8,214			3,097

Net cash provided by continuing operations		3,290			16,907
Net cash (used in) provided by discontinued operations		(878	)		1,456

Net cash provided by operating activities		2,412			18,363


Cash flows from investing activities
Capital expenditures		(27,145	)		(21,412	)
Proceeds from disposal of noncurrent assets		3,503			2,672
Acquisitions—net of cash acquired		(10,661	)		(393	)
Increases in other investments		(2,269	)		(1,923	)

Net cash used in investing activities — continuing operations		(36,572	)		(21,056	)
Net proceeds from the sales of discontinued operations		33,685			—
Net cash provided by (used in) investing activities — discontinued operations		558			(227	)

Net cash used in investing activities		(2,329	)		(21,283	)


Cash flows from financing activities
Change in checks written in excess of cash		(3,329	)		5,893
Net short-term borrowings		38,050			4,000
Proceeds from issuance of common stock, net of issuance expenses		4,820			5,229
Payments for retirement of common stock		(365	)		(345	)
Proceeds from issuance of long-term debt, net of issuance expenses		157			392
Payments for retirement of long-term debt		(3,948	)		(4,242	)
Dividends paid and other distributions		(16,691	)		(14,576	)

Net cash provided by (used in) financing activities — continuing operations		18,694			(3,649	)
Net cash used in financing activities — discontinued operations		(2,781	)		(1,141	)

Net cash provided by (used in) financing activities		15,913			(4,790	)


Effect of foreign exchange rate fluctuations on cash		183			—

Net change in cash and cash equivalents		16,179			(7,710	)
Cash and cash equivalents at beginning of period		—			7,710

Cash and cash equivalents at end of period	$	16,179		$	—


Supplemental cash flow information
Cash paid during the year from continuing operations for:
Interest (net of amount capitalized)	$	8,779		$	7,937
Income taxes	$	3,286		$	3,229

Cash paid during the year from discontinued operations for:
Interest (net of amount capitalized)	$	67		$	59
Income taxes	$	2,461		$	467

See accompanying notes to consolidated financial statements

- 5 -

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, 2004, 2003 and 2002 included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004. Because of seasonal and other factors, the earnings for the three-month and six-month periods ended June 30, 2005 should not be taken as an indication of earnings for all or any part of the balance of the year.

Acquisitions

On January 3, 2005 the Company’s wholly-owned subsidiary, BTD Manufacturing, Inc. (BTD), acquired the assets of Performance Tool & Die, Inc. (Performance Tool) of Lakeville, Minnesota, for $4.1 million in cash. Performance Tool specializes in manufacturing mid to large progressive dies for customers throughout the Midwest, East and West Coasts, and the southern United States. Performance Tool’s revenues for the year ended December 31, 2004 were $4.1 million. The Company expects this acquisition to provide expanded growth opportunities for both BTD and Performance Tool.

Also, on January 3, 2005 the Company’s wholly-owned subsidiary, ShoreMaster, Inc. (ShoreMaster), acquired the common stock of Shoreline Industries, Inc. (Shoreline), of Pine River, Minnesota, and associated assets for $2.4 million in cash. Shoreline is a manufacturer of boatlift motors and other accessories for lifts and docks with sales throughout the United States, but primarily in Minnesota and Wisconsin. Shoreline’s revenues for the year ended December 31, 2004 were $2.1 million. The acquisition of Shoreline secures a source of components and expands potential markets for ShoreMaster products.

On May 31, 2005 ShoreMaster acquired the assets of Southeast Floating Docks, Inc., of St. Augustine, Florida for $4.0 million in cash. Southeast Floating Docks is a leading manufacturer of concrete floating dock systems for marinas. They have designed custom floating systems and conducted installations mainly in the southeast United States and the Caribbean. Southeast Floating Docks had revenues of $4.5 million in 2004. This acquisition enables ShoreMaster to offer a wider range of products to its customers and expands its geographic reach in the southeast region of the United States.

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 date of the business combinations, disclosing the preliminary allocation of the purchase price assigned to each major asset and liability category of the acquired companies:


	Performance		Shoreline		Southeast
(in thousands)	Tool		Industries		Floating Docks

Assets
Current assets	$	748	$	457	$	2,519
Plant		1,396		260		415
Goodwill		1,794		1,509		2,722
Other intangible assets		800		557		1,150

Total assets	$	4,738	$	2,783	$	6,806


Liabilities and equity
Current liabilities	$	324	$	86	$	318
Deferred revenue		—		—		2,520
Deferred income taxes		—		295		—
Long-term debt		298		—		—

Total liabilities	$	622	$	381	$	2,838

Cash paid	$	4,116	$	2,402	$	3,968

Goodwill and other intangible assets related to the Performance Tool acquisition are deductible for income tax purposes over 15 years. Other intangible assets related to the Performance Tool acquisition includes $239,000 for a nonamortizable trade name and $561,000 in other intangible assets being amortized over 3 to 15 years for book purposes. Goodwill and other intangible assets related to the Shoreline acquisition are not deductible for income tax purposes, except for a $171,000 noncompete agreement being amortized over 15 years for income tax purposes. Other intangible assets related to the Shoreline acquisition includes $149,000 for a nonamortizable brand name and $408,000 in other intangible assets being amortized over 5 to 20 years for book purposes. Goodwill and other intangible assets related to the Southeast Floating Docks acquisition are deductible for income tax purposes over 15 years. Other intangible assets related to the Southeast Floating Docks acquisition includes $1,000,000 for a nonamortizable brand name.

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced or sold. 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 and determinable. In cases where significant obligations remain after delivery, revenue is deferred until such obligations are fulfilled. Provisions for sale returns and warranty costs are recorded at the time of sale based on historical information and current trends. Amounts received in advance under customer service contracts are deferred and recognized on a straight-line basis over the contract period. In the case of derivative instruments, such as the electric utility’s forward energy contracts and the energy services company’s forward natural gas swap transactions, the Company recognizes gains and losses based on changes in the fair market value of derivative instruments over the period held, and also when realized on settlement, on a net basis in revenue in a manner prescribed by Emerging Issues Task Force (EITF) Issue 03-11. Gains and losses subject to regulatory treatment on forward energy contracts are deferred and recognized on a net basis in revenue in the period in which the contract settles.

For those operating businesses recognizing revenue when products are shipped, the operating businesses 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 primarily recognized on a percentage-of-completion basis. The method used to determine the percentage 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. The following summarizes costs incurred, billings and estimated earnings recognized on uncompleted contracts:


	June 30,			December 31,
(in thousands)	2005			2004

Costs incurred on uncompleted contracts	$	129,615		$	99,213
Less billings to date		(121,836	)		(96,413	)
Plus estimated earnings recognized		12,712			12,469

	$	20,491		$	15,269

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:


	June 30,			December 31,
(in thousands)	2005			2004

Costs and estimated earnings in excess of billings on uncompleted contracts	$	25,120		$	18,145
Billings in excess of costs and estimated earnings on uncompleted contracts		(4,629	)		(2,876	)

	$	20,491		$	15,269

The percent of revenue recognized under the percentage-of-completion method compared to total consolidated revenues was 20.5% for the six months ended June 30, 2005 compared with 20.3% for the six months ended June 30, 2004.

Stock-based compensation

The Company has elected to follow the accounting provisions of Accounting Principle Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, for stock-based compensation and to furnish the pro forma disclosures required under Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation.

Had compensation costs for the stock options issued been determined based on estimated fair value at the award dates, as prescribed by SFAS No. 123, the Company’s net income for three and six month periods ended June 30, 2005 and June 30, 2004 would have decreased as presented in the table below. This may not be representative of the pro forma effects for future periods if additional options are granted.


	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2005			2004			2005			2004

Net income
As reported	$	22,304		$	8,032		$	32,275		$	16,291
Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effects		(177	)		(330	)		(283	)		(544	)

Pro forma	$	22,127		$	7,702		$	31,992		$	15,747


Basic earnings per share
As reported	$	0.76		$	0.30		$	1.09		$	0.62
Pro forma	$	0.75		$	0.29		$	1.09		$	0.60
Diluted earnings per share
As reported	$	0.76		$	0.30		$	1.09		$	0.61
Pro forma	$	0.75		$	0.29		$	1.08		$	0.59

Adjustments and Reclassifications

Net income for the three and six months ended June 30, 2004 has been adjusted to reflect the effects of applying FASB Staff Position No. FAS 106-2 (FSP 106-2), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act), retroactive to the beginning of 2004 on adoption in the third quarter of 2004. The adoption of FSP 106-2 had the effect of reducing operating expenses and increasing net income for the three and six months ended June 30, 2004 by $165,000 and $329,000, respectively. In accordance with the provisions of the Act, the expected subsidy has no effect on income tax expense.

Certain prior year amounts reported on the Company’s consolidated balance sheet have been reclassified to conform to 2005 presentation. On the Company’s consolidated balance sheets, regulatory assets and other deferred debits, previously disclosed on separate lines, have been combined on a single line. December 31, 2004 balance sheet amounts reflect the reclassification of certain assets and liabilities of both St. George Steel Fabrication, Inc. (SGS) and Chassis Liner Corporation (CLC) from continuing operations to discontinued operations as a result of the status of efforts to sell these businesses in the first and second quarters of 2005. The Company’s income statement for the three and six months ended June 30, 2004 reflects the reclassifications of the operating results to discontinued operations of Midwest Information Systems, Inc. (MIS) and SGS because these companies have been sold, and of CLC because its sale is pending. Such reclassifications had no impact on total consolidated assets, net income or shareholders’ equity.

On the Company’s consolidated statement of cash flows for the six months ended June 30, 2004 the change in the amount of checks issued in excess of cash, included in accounts payable on the Company’s consolidated balance sheet, was reclassified from change in payables and other current liabilities under cash flows from operating activities to change in checks written in excess of cash under cash flows from financing activities. This reclassification decreased cash flows from operating activities and increased cash flows from financing activities by $5,893,000 for the six months ended June 30, 2004.

Inventories

Inventories consist of the following:


	June 30,		December 31,
(in thousands)	2005		2004

Finished goods	$	43,197	$	34,081
Work in process		6,705		3,733
Raw material, fuel and supplies		45,906		34,690

	$	95,808	$	72,504

Goodwill and Other Intangible Assets

Goodwill increased $5,774,000 in the first six months of 2005 primarily due to the acquisitions of Performance Tool, Shoreline and Southeast Floating Docks.

The following table summarizes the components of the Company’s intangible assets at June 30, 2005 and December 31, 2004.


	June 30, 2005						December 31, 2004
	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	$	2,337	$	1,483	$	854	$	1,966	$	1,334	$	632
Customer relationships		10,544		364		10,180		10,045		148		9,897
Other intangible assets including contracts		2,696		1,500		1,196		2,523		1,387		1,136

Total	$	15,577	$	3,347	$	12,230	$	14,534	$	2,869	$	11,665


Non-amortized intangible assets:
Brand/trade name	$	9,319	$	—	$	9,319	$	7,935	$	—	$	7,935

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 $543,000 for the six months ended June 30, 2005 compared to $262,000 for the six months ended June 30, 2004. The estimated annual amortization expense for these intangible assets for the next five years is: $1,146,000 for 2005, $903,000 for 2006, $789,000 for 2007, $720,000 for 2008 and $597,000 for 2009.

New Accounting Standards

SFAS No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4, was issued in November 2004 to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current-period charges. This statement also requires that allocation of fixed production overheads to the costs of converting materials into finished products be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005 with earlier application permitted. The Company does not expect the application of the requirements of SFAS No. 151 to have a material effect on the Company’s consolidated net income, financial position or cash flows.

SFAS No. 123(R) (revised 2004), Share-Based Payment, issued in December 2004 is a revision of SFAS No. 123, Accounting for Stock-based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. The Company currently reports its stock-based compensation under the requirements of APB

Opinion No. 25 and furnishes related pro forma footnote information required under SFAS No. 123. Under SFAS No. 123(R), the Company will be required to record its stock-based compensation as an expense on its income statement over the period earned based on the fair value of the stock or options awarded on their grant date. The effective date for application of SFAS No. 123(R) for the Company is January 2006 with early adoption allowed. The Company will adopt SFAS No. 123(R) in January 2006. The application of SFAS No. 123(R) reporting requirements will have the effect of reducing 2006 net income by $163,000 for currently outstanding options.

FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, (FIN 47) issued in March 2005, clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. However, the obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. FIN 47 requires that the uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005. Retroactive application of interim financial information is permitted, but not required. The Company is evaluating the impact of this interpretation, but does not expect it to have a material effect on the Company’s consolidated net income, financial position or cash flows.

SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, was issued in December 2004. This Statement addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement shall be effective and applied prospectively for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 with earlier application permitted. The Company does not expect the application of the requirements of SFAS No. 153 to have a material effect on the Company’s consolidated net income, financial position or cash flows.

SFAS No. 154, Accounting for Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3, was issued in May 2005. This Statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This Statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. This Statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, with early adoption permitted. The Company does not expect the application of the requirements of SFAS No. 154 to have a material effect on the Company’s consolidated net income, financial position or cash flows.

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. Electric utility operations have been the Company’s primary business since incorporation.

Plastics consist of businesses producing polyvinyl chloride (PVC) and polyethylene (PE) 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 are located primarily in the Upper Midwest and Missouri.

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 service maintenance, diagnostic imaging, positron emission tomography and nuclear medicine imaging, portable X-ray imaging and rental of diagnostic medical imaging equipment to various medical institutions located throughout the United States.

Food ingredient processing, established as a result of the acquisition of IPH in August 2004, consists of IPH, which owns and operates potato dehydration plants in Ririe, Idaho; Center, Colorado and Souris, Prince Edward Island, Canada, producing 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 involved in residential, commercial and industrial electric contracting industries; fiber optic and electric distribution systems; waste-water, water and HVAC systems construction; transportation; energy services and natural gas marketing and 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 six Canadian provinces.

The Company’s electric operations, including wholesale power sales, are operated as a division of Otter Tail Corporation, and the Company’s energy services and natural gas marketing operations are operated as a subsidiary of Otter Tail Corporation. Substantially all of the other businesses are owned by a wholly owned subsidiary of the Company.

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 six month periods ended June 30, 2005 and 2004 and total assets by business segment as of June 30, 2005 and December 31, 2004 is presented in the following tables.

Operating Revenue


	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2005			2004			2005			2004

Electric	$	74,150		$	60,449		$	147,633		$	133,304
Plastics		36,004			32,636			68,159			59,072
Manufacturing		67,858			50,399			123,387			92,213
Health services		31,324			26,597			59,122			52,273
Food ingredient processing		8,234			—			17,489			—
Other business operations		39,707			33,906			74,604			67,421
Intersegment eliminations		(899	)		(530	)		(1,883	)		(1,243	)

Total	$	256,378		$	203,457		$	488,511		$	403,040

Income (Loss) Before Income Taxes


	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2005			2004			2005			2004

Electric	$	7,750		$	7,072		$	19,555		$	22,218
Plastics		3,950			3,827			8,357			4,899
Manufacturing		7,528			3,681			9,219			4,188
Health services		2,035			321			3,384			524
Food ingredient processing		410			—			1,609			—
Other business operations		(5,431	)		(3,399	)		(9,187	)		(8,499	)

Total	$	16,242		$	11,502		$	32,937		$	23,330

Identifiable Assets


	June 30,		December 31,
(in thousands)	2005		2004

Electric	$	636,113	$	634,433
Plastics		73,532		67,574
Manufacturing		189,311		150,800
Health services		66,556		66,506
Food ingredient processing		94,504		92,392
Other business operations		121,577		91,506
Discontinued operations		9,938		30,937

Total	$	1,191,531	$	1,134,148

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. For the three months ended June 30, 2005, 98.1% of the Company’s consolidated revenue came from sales within the United States, 1.0% came from sales in Canada and the remaining 0.9% came from sales in various foreign countries around the world. For the three months ended June 30, 2004, 97.4% of the Company’s consolidated revenue came from sales within the United States, 0.7% came from sales in Canada and the remaining 1.9% came from sales in various foreign countries around the world.

For the six months ended June 30, 2005, 98.1% of the Company’s consolidated revenue came from sales within the United States, 1.0% came from sales in Canada and the remaining 0.9% came from sales in various foreign countries around the world. For the six months ended June 30, 2004, 95.4% of the Company’s consolidated revenue came from sales within the United States, 3.5% came from sales in Canada and the remaining 1.1% came from sales in various foreign countries around the world.

Discontinued Operations

As part of an ongoing evaluation of the prospects and growth opportunities of the Company’s business operations, the Company decided to sell MIS, its telecommunications company located in Parkers Prairie, Minnesota, SGS, its structural steel fabricator located in St. George, Utah, and CLC, its manufacturer of auto and truck frame-straightening equipment and accessories located in Alexandria, Minnesota. In the second quarter of 2005, the Company completed the sales of MIS and SGS. Discontinued operations includes the operating results of MIS, SGS and CLC, and an after-tax gain on the sale of MIS of $11.9 million for the three and six month periods ended June 30, 2005, an after-tax loss on the sale of SGS of $1.8 million (an estimated loss of $1.6 million recorded

in the first quarter of 2005 plus an additional loss on disposition of $0.2 million recorded in the second quarter of 2005) and an estimated after-tax loss related to the anticipated sale of CLC of $0.2 million for the three and six month periods ended June 30, 2005 based on the expected sales price and the costs of disposition. MIS, SGS and CLC meet requirements to be reported as discontinued operations in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

The results of discontinued operations for the three and six months ended June 30, 2005 and 2004 are summarized as follows:


	Three months ended											Three months ended
	June 30, 2005											June 30, 2004
(in thousands)	MIS		SGS			CLC			Total			MIS		SGS			CLC			Total

Operating revenues	$	1,729	$	1,459		$	2,067		$	5,255		$	2,093	$	3,624		$	2,034		$	7,751
Income/(loss) before income taxes		897		(1,179	)		37			(245	)		834		(438	)		(23	)		373
Gain/(loss) on disposition — pretax		19,025		(419	)		(300	)		18,306			—		—			—			—
Income tax expense/(benefit)		7,467		(639	)		(104	)		6,724			333		(175	)		(9	)		149


	Six months ended										Six months ended
	June 30, 2005										June 30, 2004
(in thousands)	MIS		SGS			CLC			Total		MIS		SGS			CLC			Total

Operating revenues	$	3,773	$	6,329		$	3,772		$	13,874	$	4,070	$	6,579		$	4,104		$	14,753
Income/(loss) before income taxes		2,167		(1,563	)		(19	)		585		1,569		(1,089	)		(102	)		378
Gain/(loss) on disposition — pretax		19,025		(3,046	)		(300	)		15,679		—		—			—			—
Income tax expense/(benefit)		7,975		(1,843	)		(126	)		6,006		628		(435	)		(40	)		153

The results of discontinued operations for the quarters ended September 30, 2004 and December 31, 2004 are as follows:


	Quarter Ended September 30, 2004										Quarter Ended December 31, 2004
(in thousands)	MIS		SGS			CLC			Total		MIS		SGS		CLC		Total

Operating revenues	$	2,157	$	3,806		$	1,580		$	7,543	$	2,512	$	6,823	$	2,069	$	11,404
Income/(loss) before income taxes		881		(165	)		(125	)		591		1,247		322		65		1,634
Income tax expense/(benefit)		352		(65	)		(53	)		234		503		129		21		653

At June 30, 2005 and December 31, 2004 the major components of assets and liabilities of the discontinued operations were as follows:


	June 30, 2005								December 31, 2004
(in thousands)	SGS		CLC		Total		MIS		SGS		CLC		Total

Current assets	$	6,221	$	3,356	$	9,577	$	275	$	9,344	$	3,092	$	12,711
Investments and other assets		—		5		5		2,270		—		5		2,275
Goodwill—net		—		—		—		5,925		—		—		5,925
Other intangibles—net		—		43		43		—		18		74		92
Net plant		—		313		313		7,960		1,618		356		9,934

Assets of discontinued operations	$	6,221	$	3,717	$	9,938	$	16,430	$	10,980	$	3,527	$	30,937

Current liabilities	$	943	$	857	$	1,800	$	2,920	$	2,228	$	837	$	5,985
Deferred credits		—		33		33		581		271		33		885
Long-term debt		—		2		2		1,710		—		5		1,715

Liabilities of discontinued operations	$	943	$	892	$	1,835	$	5,211	$	2,499	$	875	$	8,585

The remaining assets of SGS consist of accounts receivable, accounts payable and inventory at estimated fair market values that were not settled or disposed of as of June 30, 2005.

Class B Stock Options and Class B Stock of Subsidiary

In June 2005, option holders exercised 349 Idaho Pacific Holding, Inc. (IPH) class B common stock options, resulting in the issuance of 349 IPH class B common shares. Total cash paid to IPH on exercise of the options and issuance of the class B common shares was $166,000. On issuance, the class B common shares were immediately put back to IPH and will be redeemed by IPH prior to December 31, 2005 (181 days after issuance) for $728,000; the value of the shares on the date of issuance.

Common Shares and Earnings per Share

In January 2005, 175,000 common shares were issued as a result of the underwriters exercising a portion of their over-allotment option in connection with the Company’s December 2004 public offering. The proceeds to the Company of $24.50 per share were used to pay down debt borrowed to finance the acquisition of IPH. In addition, during the first six months of 2005, the Company issued 31,541 common shares for stock options exercised and 1,210 common shares for director’s compensation.

On April 11, 2005 the Company’s Board of Directors granted 74,900 stock options to key employees and 17,700 shares of restricted stock to the directors and certain key employees under the 1999 Stock Incentive Plan (the Plan). The exercise price of the stock options is equal to the fair market value per share at the date of the grant. The options vest six months from the grant date and expire ten years after the date of the grant. As of June 30, 2005 a total of 1,530,832 vested and unvested options were outstanding and a total of 232,134 shares of restricted stock had been issued under the Plan. The Company currently accounts for the Plan under APB Opinion No. 25.

On April 11, 2005 the Company’s Board of Directors approved performance award agreements under the Plan for the Company’s executive officers. Under these agreements, the officers could be awarded up to 75,150 common shares based on the Company’s stock performance relative to the stock performances of its peer group of companies in the Edison Electric Institute Index over a three year period ending on December 31, 2007. The number of shares earned, if any, would be issued at the end of the three year performance measurement period. The participants have no voting or dividend rights under these agreements until the shares are issued at the end of the performance measurement period.

In the first six months of 2005, the Company retired 14,547 common shares for tax withholding purposes related to restricted shares that vested and also retired 17,120 common shares related to the return to the Company of stock that was held in escrow for performance contingencies that were not achieved in a health services acquisition.

Basic earnings per common share are calculated by dividing earnings available for common shares by the 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.

Comprehensive Income


	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2005			2004			2005			2004

Net income	$	22,304		$	8,032		$	32,275		$	16,291
Other comprehensive income (net-of-tax)
Minimum pension liability adjustment		(1,263	)		—			(1,263	)		—
Foreign currency translation (loss) gain		(176	)		—			(259	)		—
Unrealized (loss) on available-for-sale securities		16			(20	)		(6	)		(20	)

Total other comprehensive income		(1,423	)		(20	)		(1,528	)		(20	)

Total comprehensive income	$	20,881		$	8,012		$	30,747		$	16,271

The minimum pension liability adjustment is associated with the Company’s Executive Survivor and Supplemental Retirement Plan. The foreign currency translation adjustments are associated with the Canadian operations of IPH.

Rate and Regulatory Matters

On November 30, 2004, Otter Tail Power Company filed a Report with the Minnesota Public Utilities Commission responding to claims of allegedly improper regulatory filings brought to the attention of the Company by certain individuals. In May and June 2005, the Energy Division of the Minnesota Department of Commerce, the Residential Utilities Division of the Office of Attorney General and the claimants filed comments in response to the report. On July 15, 2005, the Company filed reply comments. Resolution of this docket is not likely to occur until the fourth quarter, 2005.

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:


	June 30,		December 31,
(in thousands)	2005		2004

Regulatory assets:
Deferred income taxes	$	15,085	$	14,526
Debt expenses and reacquisition premiums		3,205		3,424
Deferred conservation program costs		748		1,203
Plant acquisition costs		218		240
Deferred marked-to-market losses		830		331
Accrued cost-of-energy revenue		10,688		3,348
Accumulated ARO accretion/depreciation adjustment		165		114

Total regulatory assets	$	30,939	$	23,186

Regulatory liabilities:
Accumulated reserve for estimated removal costs	$	50,345	$	49,823
Deferred income taxes		6,360		6,727
Deferred marked-to-market gains		1,156		197
Gain on sale of division office building		159		162

Total regulatory liabilities	$	58,020	$	56,909

Net regulatory liability position	$	27,081	$	33,723

The regulatory assets and liabilities related to deferred income taxes are the result of the adoption of SFAS No. 109, Accounting for Income Taxes. Debt expenses 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 17.1 years. Deferred conservation program costs represent mandated conservation expenditures recoverable through retail electric rates over the next 1.5 years. Plant acquisition costs will be amortized over the next 4.9 years. Accrued cost-of-energy revenue included in accrued utility revenues will be recovered over the next nine months. All deferred marked-to-market gains and losses are related to forward purchases and sales of energy scheduled for delivery prior to May 2006. The accumulated reserve for estimated removal costs is reduced for actual removal costs incurred. 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.

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						Six months ended
	June 30,						June 30,
(in thousands)	2005			2004			2005			2004

Service cost—benefit earned during the period	$	1,034		$	900		$	2,068		$	1,800
Interest cost on projected benefit obligation		2,448			2,350			4,896			4,700
Expected return on assets		(2,996	)		(3,000	)		(5,992	)		(6,000	)
Amortization of prior-service cost		240			225			481			450

Net periodic pension cost	$	726		$	475		$	1,453		$	950

Cash Flows: The Company made $4.0 million and $2.0 million discretionary contributions to its pension plan during the six months ended June 30, 2005 and 2004 respectively.

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				Six months ended
	June 30,				June 30,
(in thousands)	2005		2004		2005		2004

Service cost—benefit earned during the period	$	92	$	205	$	184	$	410
Interest cost on projected benefit obligation		316		372		632		744
Amortization of prior-service cost		18		37		36		74
Recognized net actuarial loss		104		170		208		340

Net periodic pension cost	$	530	$	784	$	1,060	$	1,568

On January 31, 2005 the Board of Directors of the Company amended and restated the Otter Tail Corporation Executive Survivor and Supplemental Retirement Plan (the ESSRP). The amendments to the ESSRP provide for reduced future benefits effective January 1, 2005, which are expected to result in reduced expense to the Company.

Effective January 1, 2005 new participants in the ESSRP will accrue benefits under a new formula. The new formula is the same as the formula used under the Company’s qualified defined benefit pension plan but includes bonuses in the computation of covered compensation and is not subject to statutory compensation and benefit limits. Individuals who became participants in the ESSRP before January 1, 2005 will receive the greater of the old formula or the new formula until December 31, 2010. On December 31, 2010, their benefit under the old formula will be frozen. After 2010, they will receive the greater of their frozen December 31, 2010 benefit or their benefit calculated under the new formula. The amendments to the ESSRP also provide for increased service credits for certain participants and eliminate certain distribution features.

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						Six months ended
	June 30,						June 30,
(in thousands)	2005			2004			2005			2004

Service cost—benefit earned during the period	$	311		$	289		$	622		$	577
Interest cost on projected benefit obligation		666			645			1,332			1,290
Amortization of transition obligation		187			188			374			377
Amortization of prior-service cost		(77	)		(77	)		(154	)		(154	)
Amortization of net actuarial loss		156			171			312			343
Effect of Medicare Part D expected subsidy		(201	)		(189	)		(402	)		(378	)

Net periodic postretirement benefit cost	$	1,042		$	1,027		$	2,084		$	2,055

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

RESULTS OF OPERATIONS

Comparison of the Three Months Ended June 30, 2005 and 2004

Consolidated operating revenues were $256.4 million for the three months ended June 30, 2005 compared with $203.5 million for the three months ended June 30, 2004. Operating income was $20.9 million for the three months ended June 30, 2005 compared with $15.1 million for the three months ended June 30, 2004. The Company recorded diluted earnings per share from continuing operations of $0.37 for the three months ended June 30, 2005 compared to $0.29 for the three months ended June 30, 2004 and total diluted earnings per share from continuing and discontinued operations of $0.76, including $0.41 per share from a gain on the sale of Midwest Information Systems, Inc. (MIS), for the three months ended June 30, 2005 compared to $0.30 for the three months ended June 30, 2004.

Earnings increased across our electric and nonelectric businesses as compared to the same period in 2004. Electric segment earnings were up $0.9 million with better than anticipated results in wholesale power markets. The combined net earnings from continuing operations in our nonelectric segments were $5.3 million, which is up over 70% from second-quarter 2004 net earnings, reflecting improved results in the manufacturing and health services segments, along with continuing strong performance from the plastics segment.

Following is a more detailed analysis of our operating results by business segment for the three and six month periods ended June 30, 2005 and 2004, followed by our outlook for the remainder of 2005 and a discussion of changes in our financial position during the six months ended June 30, 2005.

Amounts presented in the segment tables below for the three month periods ended June 30, 2005 and 2004 for operating revenues, cost of goods sold and nonelectric segment operating expenses will not agree with amounts presented in the consolidated statements of income for those periods due to the elimination of intersegment transactions. The total intersegment eliminations include: $899,000 in operating revenues, $442,000 in cost of goods sold and $457,000 in other nonelectric expenses for the three months ended June 30, 2005; and $530,000 in operating revenues, $62,000 in cost of goods sold and $468,000 in other nonelectric expenses for the three months ended June 30, 2004.

Electric


	Three months ended
	June 30,							%
(in thousands)	2005		2004		Change			Change

Retail sales revenues	$	59,532	$	49,257	$	10,275			20.9
Wholesale revenues		9,440		5,281		4,159			78.8
Net marked-to-market gains		999		1,547		(548	)		(35.4	)
Other revenues		4,179		4,364		(185	)		(4.2	)

Total operating revenues	$	74,150	$	60,449	$	13,701			22.7
Production fuel		10,549		11,193		(644	)		(5.8	)
Purchased power – retail use		19,904		9,903		10,001			101.0
Other operation and maintenance expenses		25,334		22,202		3,132			14.1
Depreciation and amortization		6,103		6,015		88			1.5
Property taxes		2,408		2,359		49			2.1

Operating income	$	9,852	$	8,777	$	1,075			12.2

The increase in retail electric revenue is mainly due to an $8.1 million increase cost-of-energy adjustment revenues related to the recovery of increased purchase power costs in the second quarter of 2005. The remaining $2.2 million increase in retail revenues resulted from a 1.9% increase in retail megawatt-hours (mwh) sold between the periods. Increased sales reflect increases in consumption of 4.2% among commercial customers and 0.9% among residential customers, while mwh sales to industrial customers decreased 4.7%. Weather was also a factor contributing to the increase in sales as cooling-degree-days increased 223% in the second quarter of 2005 compared to the second quarter of 2004 as a result of warmer weather in June 2005.

Wholesale mwh sales from company-owned generation decreased 27.1% in the three months ended June 30, 2005, compared to the three months ended June 30, 2004 while the revenue per mwh sold increased 56.2%, resulting in an increase in revenue from sales off company-owned generation of $0.5 million between the periods. The increase in prices for company-owned generation resold is commensurate with general increases in fuel and purchased power costs across the Mid-Continent Area Power Pool (MAPP) region between the periods. Net margins on purchased power resold increased $3.6 million despite a 61.6% decrease in mwhs resold. This decrease was more than offset by an increase in the net margin per mwh of purchased power resold. The increased prices are partially due to warmer weather in the MAPP region between the quarters and partially due to a decrease in available electricity from hydro-generation in the region due to lower water levels in Upper-Missouri River reservoirs resulting from a prolonged drought in the Upper-Missouri River basin. The increase in wholesale prices also coincided with the inception of the Midwest Independent Transmission System Operator (MISO) electric markets on April 1, 2005.

The decrease in net marked-to-market gains on forward purchases and sales of electricity is related to a decline in activity in forward energy markets in the MAPP region due to uncertainty related to the implementation of the MISO electric market initiatives in April 2005. MISO electric market initiatives are designed to facilitate open access to electric transmission lines and generation sources and transparency in pricing for buyers and sellers of electricity in the geographical region under MISO control. The electric utility’s open forward contracts for the purchase and sale of electricity subject to mark-to-market accounting were lower in volume on June 30, 2005 than on June 30, 2004. The electric utility also has marked-to-market two 50 megawatt capacity agreements as of June 30 2005, one through October 2005 and one through April 2006.

The decrease in other electric operating revenues for the three months ended June 30, 2005 compared to the three months ended June 30, 2004 includes a $0.6 million decrease in transmission service revenue, load control and dispatching services related revenues and a $0.2 million decrease in revenue from steam sales, partially offset by a $0.6 million increase in revenue from contracted work performed for others in the second quarter of 2005 mainly related to transmission permitting work for MISO and the proposed Big Stone II project.

The decrease in fuel costs for the three months ended June 30, 2005 compared with the three months ended June 30, 2004 was the result of a 21.9% decrease in mwhs generated partially offset by a 20.7% increase in the cost of fuel per mwh generated between the periods. Generation used for wholesale electric sales decreased 27.1% while generation for retail sales decreased 20.6% between the quarters. The decrease in generation is mainly due to a scheduled seven-week maintenance shutdown of Big Stone Plant in the second quarter of 2005. The decrease in mwh generation at Big Stone Plant was partially offset by an increase in generation at our Hoot Lake plant where the cost of fuel per mwh of generation was 7.5% higher than at Big Stone Plant in the second quarter of 2005. Fuel costs per mwh of generation increased at all three of our coal-fired generating plants as a result of increases in coal and coal transportation costs between the periods. Approximately 90% of the fuel cost increases associated with generation to serve retail electric customers is subject to recovery through the fuel cost recovery component of retail rates.

The increase in purchased power expense for energy purchased for system use (sale to retail customers) is due to a 43.8% increase in mwhs purchased combined with a 39.7% increase in the cost per mwh purchased. Mwh purchases increased to make up for a net decrease in mwhs generated as a result of the scheduled seven-week maintenance shutdown of Big Stone Plant in the second quarter of 2005. The cost per mwh of purchased power has increased in part due to a general increase in fuel and purchased power costs across the MAPP region as a result of increases in

coal mining and transportation costs related to higher fuel prices and also for the reasons discussed above that contributed to the increase in wholesale mwh sales.

The increase in other operation and maintenance expenses for the three months ended June 30, 2005 compared with the three months ended June 30, 2004 reflects $1.3 million in increased labor expenses due to an increase in employee benefit costs, general wage and salary increases averaging approximately 3.6% and an increase in overtime pay in the second quarter of 2004. Material and operating supply expenses increased $0.9 million between the periods, most of which is attributable to maintenance costs incurred at Big Stone Plant during its scheduled seven-week maintenance shutdown in the second quarter of 2005. Costs of goods sold increased $0.5 million between the periods as a result of an increase in contracted work performed for others in the second quarter of 2005. Costs to repair damages caused by storms and other events increased $0.4 million between the quarters.

Plastics


	Three months ended
	June 30,							%
(in thousands)	2005		2004		Change			Change

Operating revenues	$	36,004	$	32,636	$	3,368			10.3
Cost of goods sold		29,664		26,491		3,173			12.0
Operating expenses		1,460		1,530		(70	)		(4.6	)
Depreciation and amortization		628		583		45			7.7

Operating income	$	4,252	$	4,032	$	220			5.5

Although pounds of polyvinyl chloride (PVC) pipe sold decreased 9.8% for the three months ended June 30, 2005 compared with the three months ended June 30, 2004, operating revenues for the plastics segment increased 10.3% between the periods mainly as result of a 21.4% increase in the price per pound of PVC pipe sold. The increase in PVC pipe prices is related to an increase in PVC resin prices. The resin cost per pound of PVC pipe shipped increased 20.7% for the three months ended June 30, 2005 compared with the three months ended June 30, 2004 and was the main contributing factor to the $3.2 million increase in cost of goods sold. The increase in depreciation and amortization expense is due to 2004 plant additions.

Manufacturing


	Three months ended
	June 30,							%
(in thousands)	2005		2004		Change			Change

Operating revenues	$	67,858	$	50,399	$	17,459			34.6
Cost of goods sold		51,519		38,417		13,102			34.1
Operating expenses		5,332		5,871		(539	)		(9.2	)
Depreciation and amortization		2,345		1,905		440			23.1

Operating income	$	8,662	$	4,206	$	4,456			105.9

Revenue increases at the manufacturing companies are due to a combination of factors including increased unit sales, increased sales of higher-priced products, higher prices related to material cost increases and 2005 acquisitions. The increase in costs of goods sold in the manufacturing segment was proportional to the increase in sales revenue resulting in a $4.4 million increase in gross profits in the manufacturing segment between the quarters.

Revenues at DMI Industries, Inc. (DMI), our manufacturer of wind towers, increased $10.2 million (110.2%) in the second quarter of 2005 compared with the second quarter of 2004 due to an increase in production and sales of wind towers mainly as a result of legislative action in the fall of 2004 extending production tax credits for investments in wind generation through 2005. The revenue increase for DMI also reflects continued improvements in productivity and plant utilization in 2005. Revenues at BTD Manufacturing, Inc. (BTD), our metal parts stamping and fabrication company, increased $4.6 million (30.1%) between the quarters as a result of a 16.9% increase in revenue per unit sold. The purchase of Performance Tool & Die, Inc. (Performance Tool) in January 2005 contributed $0.8 million toward BTD’s $4.6 million revenue variance. Revenues at ShoreMaster, our waterfront equipment manufacturer, increased $1.7 million (8.7%) in the second quarter of 2005 compared to the second quarter of 2004 as a result of increased production mainly in the area of large marina projects. Revenues at T.O. Plastics, our manufacturer of thermoformed plastic and horticultural products, increased $1.0 million (15.1%) between the quarters as a result of increased productivity and increased sales in addition to higher prices related to higher raw material costs.

DMI cost of goods sold increased $7.6 million between the quarters as a result of increased production and higher raw material costs and labor costs. Cost of goods sold at BTD increased $4.4 million as a result of higher raw material and labor costs mainly related to increased production. ShoreMaster’s increase in revenue was partially offset by a $0.8 million increase in costs of goods sold mainly related to increases in material costs. T.O. Plastics cost of goods sold increased $0.2 million between the quarters as a result of increased material costs.

Operating expenses at each of our manufacturing companies decreased in the second quarter of 2005 compared to the second quarter of 2004 mainly due to a lower level of selling, general and administrative expenses between the periods. Depreciation expense increased between the quarters as a result of 2004 equipment additions.

Health Services


	Three months ended
	June 30,							%
(in thousands)	2005		2004		Change			Change

Operating revenues	$	31,324	$	26,597	$	4,727			17.8
Cost of goods sold		22,795		20,225		2,570			12.7
Operating expenses		5,272		4,544		728			16.0
Depreciation and amortization		1,010		1,296		(286	)		(22.1	)

Operating income	$	2,247	$	532	$	1,715			322.4

The increase in health services operating revenues for the three months ended June 30, 2005 compared with the three months ended June 30, 2004 reflects a $4.1 million increase in imaging revenues combined with a $0.6 million increase in revenues from the sale and servicing of diagnostic imaging equipment. On the imaging side of the business, $2.5 million of the $4.1 million increase in revenue came from rentals and interim installations of scanning equipment along with providing technical support services for those rental and interim installations. The number of scans performed in the second quarter of 2005 compared with the second quarter of 2004 increased by 5.5%, while the fee per scan increased by 16.1%. The increase in health services revenue was partially offset by increases in cost of goods sold and operating expenses of $1.9 million to support the increases in imaging services activity. The increase in cost of goods sold is mainly related to increased equipment rental costs and increased labor costs. The increase in operating expenses is mainly due to increases payroll, contracted services and travel related expenses. The decrease in depreciation and amortization expense is the result of certain assets reaching the ends of their depreciable lives. When these assets are replaced, they are generally replaced with assets leased under operating leases.

Food Ingredient Processing


	Three months ended
(in thousands)	June 30, 2005

Operating revenues	$	8,234
Cost of goods sold		6,421
Operating expenses		536
Depreciation and amortization		821

Operating income	$	456

The food ingredient processing segment has been established as a result of the acquisition of Idaho Pacific Holdings, Inc. (IPH) in August 2004. See management’s outlook for this segment in the 2005 Outlook section that follows management’s discussion of the results of operations.

Other Business Operations


	Three months ended
	June 30,									%
(in thousands)	2005			2004			Change			Change

Operating revenues	$	39,707		$	33,906		$	5,801			17.1
Cost of goods sold		30,085			25,870			4,215			16.3
Operating expenses		13,577			9,782			3,795			38.8
Depreciation and amortization		646			730			(84	)		(11.5	)

Operating loss	$	(4,601	)	$	(2,476	)	$	(2,125	)		(85.8	)

Revenues at Midwest Construction Services, Inc. (MCS), our electrical design and construction services company, increased $6.4 million (117%) between the quarters as a result of an increase in work in progress, which was mostly offset by a $5.8 million increase in construction material and labor costs between the quarters. Revenues at Otter Tail Energy Services Co. (OTESCO), our natural gas marketing company, increased $1.6 million in the three months ended June 30, 2005 compared with the three months ended June 30, 2004. The increase in OTESCO revenues is directly related to increases in natural gas prices between the periods and was mostly offset by a $1.5 million increase in natural gas costs. Revenues at E.W. Wylie Corporation (Wylie), our flatbed trucking company, increased $0.8 million between the quarters mainly due to a 12.0% increase in miles driven by company-operated and owner-operated trucks. Wylie’s increased revenues also reflect increased fuel costs recovered through fuel surcharges between the quarters. Revenues at Foley Company, a mechanical and prime contractor on industrial projects, decreased $3.3 million in the second quarter of 2005 compared to the second quarter of 2004 due to a decrease in jobs in progress. The decrease in Foley’s revenues was mostly offset by a $3.0 million decrease in labor and subcontractor costs between the periods.

Of the $3.8 million increase in operating expenses, $2.8 million is due to increases in health and other insurance costs and other employee benefit costs that are not allocated to the other operating segments and independent auditor fees related to Sarbanes-Oxley requirements. Wylie’s increased revenue was more than offset by a $0.9 million increase in operating expenses mainly related to increases in truck leasing costs, higher fuel prices and increased fuel usage and labor costs related to the increase in miles driven between the periods. Wylie’s depreciation and amortization expenses decreased by $0.1 million between the quarters as a result of leasing rather than buying new fleet trucks in 2004.

Interest Charges and Income Taxes – Continuing Operations

The $0.5 million (12.0%) increase in interest charges in the three months ended June 30, 2005 compared with the three months ended June 30, 2004 is due to increased interest rates on short-term debt and an increase in the average level of short-term debt outstanding between the periods.

The $1.6 million (42.8%) increase in income taxes — continuing operations between the quarters is primarily the result of a $4.7 million (41.2%) increase in income from continuing operations before income taxes for the three months ended June 30, 2005 compared with the three months ended June 30, 2004. The effective tax rate for continuing operations for the three months ended June 30, 2005 was 32.1% compared to 32.5% for the three months ended June 30, 2004.

Discontinued Operations

Discontinued operations includes the operating results of MIS, our telecommunications company located in Parkers Prairie, Minnesota, SGS, our structural steel fabricator located in St. George, Utah, and CLC of Alexandria, Minnesota, our manufacturer of auto and truck frame-straightening equipment and accessories located in Alexandria, Minnesota. The sales of MIS and SGS were completed in the second quarter of 2005. The pending sale of CLC was in the process of negotiation as of June 30, 2005. Discontinued operations include net income (loss) from discontinued operations for the three month periods ended June 30, 2005 and 2004 and net after-tax gains and losses on the disposition of discontinued operations in the second quarter of 2005 as shown in the following table:


	Three months ended											Three months ended
	June 30, 2005											June 30, 2004
(in thousands)	MIS		SGS			CLC			Total			MIS		SGS			CLC			Total

Income/(loss) before income taxes	$	897	$	(1,179	)	$	37		$	(245	)	$	834	$	(438	)	$	(23	)	$	373
Gain/(loss) on disposition — pretax		19,025		(419	)		(300	)		18,306			—		—			—			—
Income tax expense/(benefit)		7,467		(639	)		(104	)		6,724			333		(175	)		(9	)		149

Net income	$	12,455	$	(959	)	$	(159	)	$	11,337		$	501	$	(263	)	$	(14	)	$	224

Comparison of the Six Months Ended June 30, 2005 and 2004

Consolidated operating revenues were $488.5 million for the six months ended June 30, 2005 compared with $403.0 million for the six months ended June 30, 2004. Operating income was $41.9 million for the six months ended June 30, 2005 compared with $31.3 million for the six months ended June 30, 2004. The Company recorded diluted earnings per share from continuing operations of $0.74 for the six months ended June 30, 2005 compared to $0.60 for the six months ended June 30, 2004 and total diluted earnings per share from continuing and discontinued operations of $1.09, including $0.41 per share from a gain on the sale of MIS and a reduction of $0.06 per share from a loss on the sale of SGS and $0.01 from a projected loss on the pending sale of CLC, for the six months ended June 30, 2005 compared to $0.61 for the six months ended June 30, 2004.

Amounts presented in the segment tables below for the six month periods ended June 30, 2005 and 2004 for operating revenues, cost of goods sold and nonelectric segment operating expenses will not agree with amounts presented in the consolidated statements of income for those periods due to the elimination of intersegment transactions. The total intersegment eliminations include: $1,883,000 in operating revenues, $953,000 in cost of goods sold and $930,000 in other nonelectric expenses for the six months ended June 30, 2005; and $1,243,000 in operating revenues, $122,000 in cost of goods sold and $1,121,000 in other nonelectric expenses for the six months ended June 30, 2004.

Electric


	Six months ended
	June 30,							%
(in thousands)	2005		2004		Change			Change

Retail sales revenues	$	122,847	$	112,385	$	10,462			9.3
Wholesale revenues		14,357		9,892		4,465			45.1
Net marked-to-market gains		1,103		3,159		(2,056	)		(65.1	)
Other revenues		9,326		7,868		1,458			18.5

Total operating revenues	$	147,633	$	133,304	$	14,329			10.7
Production fuel		25,726		25,790		(64	)		(0.2	)
Purchased power – retail use		31,442		20,825		10,617			51.0
Other operation and maintenance expenses		49,252		43,479		5,773			13.3
Depreciation and amortization		12,203		11,951		252			2.1
Property taxes		5,081		4,848		233			4.8

Operating income	$	23,929	$	26,411	$	(2,482	)		(9.4	)

The increase in retail electric revenue is mainly due to an $8.3 million increase in cost-of-energy adjustment revenues related to the recovery of increased purchase power costs in the second quarter of 2005. The remaining $2.2 million increase in retail revenues resulted from a 1.6% increase in retail mwhs sold in the first six months of 2005 compared to the first six months of 2004. Increased sales reflect increases in consumption of 2.4% among commercial customers and 1.4% among residential customers, while mwh sales to industrial customers decreased 1.6% between the periods. Weather was also a factor contributing to the increase in sales as cooling-degree-days increased 223% between the periods as a result of warmer weather in June 2005.

Wholesale mwh sales from company-owned generation decreased 21.2% in the six months ended June 30, 2005, compared to the six months ended June 30, 2004 while the revenue per mwh sold increased 35.8%, resulting in an increase in revenue from sales off company-owned generation of $0.6 million between the periods. The increase in prices for company-owned generation resold is commensurate with general increases in fuel and purchased power costs across the MAPP region between the periods. Net margins on purchased power resold increased $3.9 million despite a 59.6% decrease in mwhs resold between the periods. This decrease was more than offset by an increase in the net margin per mwh of purchased power resold. The increased prices are partially due to warmer weather in the MAPP region between the periods and partially due to a decrease in available electricity from hydro-generation in the region due to lower water levels in Upper-Missouri River reservoirs resulting from a prolonged drought in the Upper-Missouri River basin. An increase in wholesale prices also coincided with the inception of the MISO electric markets on April 1, 2005.

The decrease in net marked-to-market gains on forward purchases and sales of electricity is related to a decline in activity in forward energy markets in the MAPP region due to uncertainty related to the implementation of the MISO electric market initiatives in April 2005. The electric utility’s open forward contracts for the purchase and sale of electricity subject to mark-to-market accounting were lower in volume on June 30, 2005 than on June 30, 2004. The electric utility also has marked-to-market two 50 megawatt capacity agreements as of June 30 2005, one through October 2005 and one through April 2006.

The increase in other electric operating revenues for the six months ended June 30, 2005 compared to the six months ended June 30, 2004 includes $2.0 million in increased revenue from contracted construction services related to transmission line and substation projects done for another regional utility in the first six months of 2005. Revenue from transmission services and load control and dispatching services decreased $0.3 million and revenues from steam sales decreased $0.2 million between the periods.

The decrease in fuel costs for the six months ended June 30, 2005 compared with the six months ended June 30, 2004 was the result of a 11.1% decrease in mwhs generated partially offset by a 12.2% increase in the cost of fuel per mwh generated between the periods. Generation used for wholesale electric sales decreased 21.2% while generation for retail sales decreased 8.9% between the periods. The decrease in generation is mainly due to a scheduled seven-week maintenance shutdown of Big Stone Plant in the second quarter of 2005. The decrease in mwh generation at Big Stone Plant was partially offset by an increase in generation at our Hoot Lake plant where the cost of fuel per kwh of generation was 13.7% higher than at Big Stone Plant in the first six months of 2005. Fuel costs per mwh of generation increased at all three of our coal-fired generating plants as a result of increases in coal and coal transportation costs between the periods. Approximately 90% of the fuel cost increases associated with generation to serve retail electric customers is subject to recovery through the fuel cost recovery component of retail rates.

The increase in purchased power expense for energy purchased for system use (sale to retail customers) is due to a 16.7% increase in mwhs purchased combined with a 29.4% increase in the cost per mwh purchased. Mwh purchases were increased to make up for a net decrease in mwhs generated at company-owned power plants as a result of the scheduled seven-week maintenance shutdown of Big Stone Plant in the second quarter of 2005. The cost per mwh of purchased power has increased in part due to a general increase in fuel and purchased power costs across the MAPP region as a result of increases in coal mining and transportation costs related to higher fuel prices and also for reasons discussed above that contributed to the increase in wholesale mwh sales.

The increase in other operation and maintenance expenses for the six months ended June 30, 2005 compared with the six months ended June 30, 2004 reflects $3.1 million in increased labor expenses due to an increase in employee benefit costs, general wage and salary increases averaging approximately 3.6% and a reduction in capitalized labor of $0.4 million between the periods. Material and operating supply expenses increased $0.9 million between the periods, most of which is attributable to maintenance costs incurred at Big Stone Plant during its scheduled seven-week maintenance shutdown in the second quarter of 2005. Costs of goods sold increased $0.6 million between the periods mainly related to costs incurred on billable construction jobs in 2005. Costs to repair damages caused by storms and other events increased $0.3 million between the periods. The increase in property taxes between the periods is a result of increases in property tax rates and property values subject to taxation.

Plastics


	Six months ended
	June 30,						%
(in thousands)	2005		2004		Change		Change

Operating revenues	$	68,159	$	59,072	$	9,087		15.4
Cost of goods sold		55,081		49,803		5,278		10.6
Operating expenses		2,969		2,796		173		6.2
Depreciation and amortization		1,219		1,152		67		5.8

Operating income	$	8,890	$	5,321	$	3,569		67.1

Although pounds of PVC pipe sold decreased by 12.9% for the six months ended June 30, 2005 compared with the six months ended June 30, 2004, operating revenues for the plastics segment increased 15.4% between the periods mainly as result of a 30.7% increase in the price per pound of PVC pipe sold. The increase in PVC pipe prices is directly related to an increase in PVC resin prices. The resin cost per pound of PVC pipe shipped increased 24.6% for the six months ended June 30, 2005 compared with the six months ended June 30, 2004 and was the main contributing factor to the $5.3 million increase in cost of goods sold. The increase in operating expenses is mainly due to increases in employee benefit costs. The increase in depreciation and amortization expense is due to 2004 plant additions.

In the first six months of 2005, 94% of resin purchased was from two vendors; 46% from one and 48% from the other, with the remaining 6% provided by two other vendors. In the first six months of 2004, 100% of resin purchased was from two vendors; 50% from one and 50% from the other. We believe relationships with our key raw material vendors are good. However, the loss of a key supplier or any interruption or delay in the supply of PVC resin could have a significant impact on the plastics segment.

Manufacturing


	Six months ended
	June 30,						%
(in thousands)	2005		2004		Change		Change

Operating revenues	$	123,387	$	92,213	$	31,174		33.8
Cost of goods sold		96,878		72,572		24,306		33.5
Operating expenses		10,754		10,586		168		1.6
Depreciation and amortization		4,550		3,801		749		19.7

Operating income	$	11,205	$	5,254	$	5,951		113.3

Revenue increases at the manufacturing companies are due to a combination of factors including increased unit sales, increased sales of higher-priced products, higher prices related to material cost increases and 2005 acquisitions. The increase in costs of goods sold in the manufacturing segment was proportional to the increase in sales revenue resulting in a $6.9 million increase in gross profits in the manufacturing segment between the periods.

Revenues at DMI, our manufacturer of wind towers, increased $14.3 million (75.2%) in the six months ended June 30, 2005 compared with the six months ended June 30, 2004 due to an increase in production and sales of wind towers mainly as a result of legislative action in the fall of 2004 extending production tax credits for investments in wind generation through 2005. The revenue increase for DMI also reflects continued improvements in productivity and plant utilization in 2005. Revenues at BTD, our metal parts stamping and fabrication company, increased $11.1 million (40.6%) between the quarters as a result of a 12.2% increase in unit sales combined with a 19.7% increase in revenue per unit sold between the periods. The purchase of Performance Tool in January 2005 contributed $1.7 million toward BTD’s $11.1 million revenue increase. Revenues at ShoreMaster, our waterfront equipment manufacturer, increased $4.0 million (13.2%) in the first six months of 2005 compared to the first six months of 2004 as a result of increased production mainly in the area of large marina projects. Revenues at T.O. Plastics, our manufacturer of thermoformed plastic and horticultural products, increased $1.7 million (11.1%) between the quarters as a result of increased productivity and increased sales in addition to higher prices related to higher raw material costs.

DMI cost of goods sold increased $11.2 million between the periods as a result of increased production and higher raw material costs—especially steel—subcontractor and labor costs. Cost of goods sold at BTD increased $10.0 million as a result of higher raw material and labor costs mainly related to increased production. ShoreMaster’s increase in revenue was partially offset by a $2.9 million increase in costs of goods sold mainly related to increases in material costs. T.O. Plastics cost of goods sold increased $0.2 million between the periods as a result of increased material costs.

Operating expenses increased mainly due to increases in outside sales commission and advertising expenses between the periods. Depreciation expenses increased mainly as a result of manufacturing equipment purchases in 2004.

Health Services


	Six months ended
	June 30,							%
(in thousands)	2005		2004		Change			Change

Operating revenues	$	59,122	$	52,273	$	6,849			13.1
Cost of goods sold		43,087		39,622		3,465			8.7
Operating expenses		10,185		9,008		1,177			13.1
Depreciation and amortization		2,077		2,687		(610	)		(22.7	)

Operating income	$	3,773	$	956	$	2,817			294.7

The increase in health services operating revenues for the six months ended June 30, 2005 compared with the six months ended June 30, 2004 reflects a $7.1 million increase in imaging revenues offset by a $0.3 million decrease in revenues from the sale and servicing of diagnostic imaging equipment between the periods. On the imaging side of the business, $4.5 million of the $7.1 million increase in revenue came from rentals and interim installations of scanning equipment along with providing technical support services for those rental and interim installations. The number of scans performed in the first six months of 2005 compared with the first six months of 2004 increased by 6.7%, while the fee per scan increased by 8.6%. The increase in health services revenue was partially offset by increases in cost of goods sold and operating expenses of $4.7 million to support the increases in imaging services activity. The increase in cost of goods sold is mainly related to increased equipment rental costs and increased labor costs partially offset by decreases in materials and maintenance costs. The increase in operating expenses is mainly due to increased payroll and travel expenses and an increase in bad debt expenses between the periods. The decrease in depreciation and amortization expense is the result of certain assets reaching the ends of their depreciable lives. When these assets are replaced, they are generally replaced with assets leased under operating leases.

Food Ingredient Processing


	Six months ended
(in thousands)	June 30, 2005

Operating revenues	$	17,489
Cost of goods sold		13,106
Operating expenses		1,079
Depreciation and amortization		1,646

Operating income	$	1,658

The food ingredient processing segment has been established as a result of the acquisition of IPH in August 2004. See management’s outlook for this segment in the 2005 Outlook section that follows management’s discussion of the results of operations.

Other Business Operations


	Six months ended
	June 30,									%
(in thousands)	2005			2004			Change			Change

Operating revenues	$	74,604		$	67,421		$	7,183			10.7
Cost of goods sold		56,477			52,083			4,394			8.4
Operating expenses		24,404			20,562			3,842			18.7
Depreciation and amortization		1,243			1,445			(202	)		(14.0	)

Operating loss	$	(7,520	)	$	(6,669	)	$	(851	)		(12.8	)

Revenues at MCS, our electrical design and construction services company, increased $7.2 million (75.5%) between the periods as a result of an increase in work in progress, which was mostly offset by a $6.2 million increase in construction material and labor costs incurred between the periods. Revenues at OTESCO, our natural gas marketing company, increased $5.3 million in the six months ended June 30, 2005 compared with the six months ended June 30, 2004. The increase in OTESCO revenues is directly related to increases in natural gas prices between the periods and was entirely offset by a $5.3 million increase in natural gas costs. Revenues at Wylie, our flatbed trucking company, increased $1.9 million between the periods mainly due to a 12.2% increase in miles driven by company-operated trucks. Wylie’s increased revenues also reflect increased fuel costs recovered through fuel surcharges between the quarters. Revenues at Foley Company, a mechanical and prime contractor on industrial projects, decreased $7.3 million in the first six months of 2005 compared to the first six months of 2004 due to a decrease in jobs in progress. The decrease in Foley’s revenues was almost entirely offset by a $7.1 million decrease in material, subcontractor and labor costs between the periods.

Of the $3.8 million increase in operating expenses, $2.8 million is due to increases in health and other insurance costs and other employee benefit costs that are not allocated to the other operating segments and independent auditor fees related to Sarbanes-Oxley requirements. Wylie’s increased revenue was mostly offset by a $1.7 million increase in operating expenses mainly related to increases in truck leasing costs, higher fuel prices and increased fuel usage and labor costs related to the increase in miles driven between the periods. Wylie’s depreciation and amortization expenses decreased by $0.2 million between the periods as a result of leasing rather than buying new fleet trucks in 2004.

Interest Charges and Income Taxes – Continuing Operations

The $0.7 million (8.0%) increase in interest charges for the six months ended June 30, 2005 compared with the six months ended June 30, 2004 is due to increased interest rates on short-term debt and an increase in the average level of short-term debt outstanding between the periods.

The $3.7 million (50.3%) increase in income taxes — continuing operations between the quarters is primarily the result of a $9.6 million (41.2%) increase in income from continuing operations before income taxes for the six months ended June 30, 2005 compared with the six months ended June 30, 2004. The effective tax rate for continuing operations for the six months ended June 30, 2005 was 33.2% compared to 31.1% for the six months ended June 30, 2004. The increase in the effective tax rate is primarily due to the increase in net income before tax between the quarters.

Discontinued Operations

Discontinued operations includes the operating results of MIS, SGS and CLC The sales of MIS and SGS were completed in the second quarter of 2005. The pending sale of CLC was in the process of negotiation as of June 30, 2005. Discontinued operations include net income (loss) from discontinued operations for the six month periods

ended June 30, 2005 and 2004; and net after-tax gains and losses on the disposition of discontinued operations in the first six months of 2005 as shown in the following table:


	Six months ended										Six months ended
	June 30, 2005										June 30, 2004
(in thousands)	MIS		SGS			CLC			Total		MIS		SGS			CLC			Total

Income/(loss) before income taxes	$	2,167	$	(1,563	)	$	(19	)	$	585	$	1,569	$	(1,089	)	$	(102	)	$	378
Gain/(loss) on disposition — pretax		19,025		(3,046	)		(300	)		15,679		—		—			—			—
Income tax expense/(benefit)		7,975		(1,843	)		(126	)		6,006		628		(435	)		(40	)		153

Net income	$	13,217	$	(2,766	)	$	(193	)	$	10,258	$	941	$	(654	)	$	(62	)	$	225

2005 OUTLOOK

The statements in this section are based on our current outlook for 2005 and are subject to risks and uncertainties described under “Forward Looking Information – Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995.”

We expect 2005 earnings to be in the range of $1.50 to $1.70 of diluted earnings per share from continuing operations. Total earnings, which include expected earnings, gains and losses from discontinued operations, are expected to be in the range of $1.80 to $2.00 of diluted earnings per share.

Contributing to the earnings guidance for 2005 are the following items:

•

We expect solid performance in the electric segment in 2005 although net income is anticipated to be lower than 2004 levels. This is primarily because of uncertainty in the wholesale electric markets due to the implementation of MISO electric markets on April 1, 2005 and anticipated lower margins on retail sales. Regulated returns in 2005 for the electric segment are expected to be consistent with authorized levels.

	•		We expect the plastics segment will perform well in 2005 due to continuing strong demand in the southwestern region of the country and sustained high PVC resin prices. 2005 net earnings for this segment are expected to be similar to 2004 net earnings.

	•		The improving economy, continued enhancements in productivity and capacity utilization, and the extension of the production tax credit are expected to result in increased net income in our manufacturing segment.

	•		The health services segment is expected to grow net income in 2005 as it continues to realize earnings improvement from its imaging business.

	•		We expect our food ingredient processing business to generate net income in the range of $2.1 million to $3.8 million for the year ending December 31, 2005. The revision in the low end of the range is due to lower than expected sales volumes, high energy costs, the increasing value of the Canadian dollar relative to the U.S. dollar and excess capacity in the potato flake market.

	•		The other business operations segment is expected to show results similar to 2004. While the improving economy is having a positive impact on the transportation business and the extension of the production tax credit is expected to have a positive impact on our electrical contracting business, earnings growth in these businesses are expected to be offset by weaker performance in our other construction business, increased health and casualty insurance costs, and other employee benefit costs.

FINANCIAL POSITION

For the period 2005 through 2009, we estimate funds internally generated net of forecasted dividend payments will be sufficient to meet scheduled debt retirements, to repay currently outstanding short-term debt and to provide for our estimated consolidated capital expenditures, which currently do not include the proposed generating unit at the Big Stone Plant site. Reduced demand for electricity, reductions in wholesale sales of electricity or margins on wholesale sales, or declines in the number of products manufactured and sold by our companies could have an effect on funds internally generated. Additional equity or debt financing will be required in the period 2005 through 2009 in the event the we decide to refund or retire early any of our presently outstanding debt or cumulative preferred shares, to complete acquisitions, to fund the construction of a new generating unit at the Big Stone Plant site if the permitting process allows us to move forward with the project or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to us. If adequate funds are not available on acceptable terms, our business, results of operations, and financial condition could be adversely affected.

In January 2005, we issued 175,000 common shares as a result of the underwriters exercising a portion of their over-allotment option in connection with our December 2004 public offering. Proceeds from the January 2005 issuance of $4.3 million were used to pay down debt borrowed to finance the acquisition of IPH. The common stock was issued under a universal shelf registration statement filed with the Securities and Exchange Commission that gives us the ability to issue up to an additional $256 million of common stock, preferred stock, debt and certain other securities from time to time. During the first six months of 2005, we also issued 31,541 common shares for stock options exercised and 17,700 shares of restricted stock to directors and certain key employees under the 1999 Stock Incentive Plan.

On April 27, 2005 we renewed our line of credit with U.S. Bank National Association, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, and Bank Hapoalim B.M., and increased the amount available under the line from $70 million to $100 million. The renewed agreement expires on April 26, 2006. The terms of the renewed line of credit are essentially the same as those in place prior to the renewal. However, outstanding letters of credit issued by the Company can reduce the amount available for borrowing under the line by up to $20 million. Borrowings under the line of credit bear interest at LIBOR plus 0.6%, subject to adjustment based on the ratings of our senior unsecured debt. This line is an unsecured revolving credit facility available to support borrowings of our nonelectric operations. We anticipate that the electric utility’s cash requirements through April 2006 will be provided for by cash flows from electric utility operations. Our obligations under this line of credit are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. As of June 30, 2005, $78.0 million of the $100 million line of credit in place at that date was in use and $12.0 million was restricted from use to cover outstanding letters of credit. Proceeds from the sale of MIS received on June 30, 2005 were used to pay down the line of credit in July 2005.

Our line of credit, $90 million 6.63% senior notes, and Lombard US Equipment Finance note contain the following covenants: a debt-to-total capitalization ratio not in excess of 60% and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require that priority debt not be in excess of 20% of total capitalization. We were in compliance with all of the covenants under these financing agreements as of June 30, 2005.

Our obligations under the 6.63% senior notes are guaranteed by our 100%-owned subsidiary that owns substantially all of our nonelectric companies. Our Grant County and Mercer County pollution control refunding revenue bonds require that we grant to Ambac Assurance Corporation, under a financial guaranty insurance policy relating to the bonds, a security interest in the assets of the electric utility if the rating on our senior unsecured debt is downgraded to Baa2 or below (Moody’s) or BBB or below (Standard & Poor’s).

Our current securities ratings are:


	Moody’s
	Investors	Standard
	Service	& Poor’s

Senior unsecured debt	A2	BBB+
Preferred stock	Baa1	BBB-
Outlook	Negative	Negative

Our disclosure of these securities ratings is not a recommendation to buy, sell or hold our securities. Downgrades in these securities ratings could adversely affect our company. Further downgrades could increase borrowing costs resulting in possible reductions to net income in future periods and increase the risk of default on our debt obligations.

Cash provided by operating activities from continuing operations decreased $13.6 million for the six months ended June 30, 2005 compared to the six months ended June 30, 2004, reflecting a $7.9 million increase in net income and depreciation expense from continuing operations and a $3.2 million decrease in cash used for noncurrent liabilities and deferred credits, offset by a $20.7 million increase in changes in working capital, a $2.0 million increase in discretionary pension contributions and a $2.0 million net increase in cash used for deferred taxes and other deferred debits between the periods. In addition to the $13.6 million decrease in cash provided by continuing operations, cash provided by discontinued operations decreased by $2.3 million between the quarters resulting in a decrease in net cash provided by continuing and discontinued operations of $16.0 million.

A major use of operating cash in the first six months of 2005 related to a $20.4 million increase in inventory during the period, exclusive of inventory from business acquisitions. Inventories increased $9.0 million among the manufacturing companies, $4.9 million in the plastics segment, $3.9 million in the food ingredient processing segment, $1.3 million in the health services segment and $1.0 million in the electric segment. The increase is due to typical increases in inventories during this time of year and also due to an increase in material prices and a backlog at DMI which caused more steel to be ordered to support production of wind tower orders. The $17.6 million increase in other current assets from December 31, 2004 to June 30, 2005 is mainly due to increases in costs in excess of billings at companies using percentage-of-completion accounting with DMI showing the largest increase as wind tower jobs in progress move closer to completion.

Excluding $33.7 million in net cash received from the sales of discontinued operations, net cash used in investing activities was $36.0 million for the six months ended June 30, 2005 compared with $21.3 million for the six months ended June 30, 2004. Cash used for capital expenditures increased by $5.7 million between the periods. An increase in capital expenditures in the manufacturing segment between the periods of $2.1 million was made up of the following: increased expenditures mainly related to the purchase of production and office equipment and warehouse improvements in 2005. Capital expenditures increased by $1.8 million in the electric segment between the periods reflecting purchases of substation and load management equipment and service meters and the installation of new underground and overhead service extensions in 2005. Capital expenditures at IPH were $0.9 million in the first six months of 2005 related to the installation of additional production capacity. Capital expenditures increased $0.7 million in our other business operations segment and $0.2 million in our plastics segment between the periods. We invested $10.5 million in cash, net of cash acquired, for acquisitions in the first six months of 2005. Proceeds from the disposal of noncurrent assets increased $0.8 million between the periods.

Net cash provided by financing activities from continuing and discontinued operations increased $20.7 million in the six months ended June 30, 2005 compared with the six months ended June 30, 2004 mainly due to a $24.8 million increase in short-term borrowings and checks issued in excess of cash between the quarters. This increase was partially offset by a $2.1 million increase in common dividends paid between the periods as a result of the issuance of over 3.2 million common shares since June 30, 2004 combined with a one-cent increase in the

dividend paid per common share in the first and second quarters of 2005 compared with the first and second quarters of 2004, and a $1.6 million increase in cash used in financing activities of discontinued operations mainly related to the retirement of debt.

There has not been any material changes in our contractual obligations from those reported under the caption “Capital Requirements” on page 24 of our 2004 Annual Report to Shareholders. However, as a result of the Big Stone II plant project moving into the permitting phase, we have a commitment to spend $2 million on this project through October 2006. These funds were placed on deposit with a trustee in an interest-bearing account in June 2005. We do not have any off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Critical Accounting Policies Involving Significant Estimates

The discussion and analysis of the consolidated financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, valuation of forward energy contracts, unbilled electric revenues, unscheduled power exchanges, Midwest Independent Transmission System Operator (MISO) electric market residual load adjustments, service contract maintenance costs, percentage-of-completion and actuarially determined benefits costs. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the Board of Directors.

Goodwill Impairment

The Company currently has $1.0 million of goodwill recorded on its balance sheet related to OTESCO, its energy services subsidiary that markets natural gas to approximately 160 retail customers. An evaluation of projected cash flows from this operation in December 2004 indicated that the related goodwill was not impaired. However, actual and projected cash flows from this operation are subject to fluctuations due to low profit margins on natural gas sales combined with high volatility of natural gas prices. Reductions in profit margins or the volume of natural gas sales could result in an impairment of all or a portion of its related goodwill. The Company will continue to evaluate this reporting unit for impairment on an annual basis and as conditions warrant.

We currently have $6.7 million of goodwill recorded on our balance sheet related to the acquisition of Wylie. Highly competitive pricing in the trucking industry in recent years had resulted in decreased operating margins and lower returns on invested capital for Wylie. Wylie’s performance improved in 2004 and current projections are for operating margins to increase from current levels over the next three to five years as demand for shipping continues to increase relative to available shipping capacity and additional revenues are generated from added terminal locations and increased brokerage activity. If current trends reverse and operating margins do not increase according to our projections, the reductions in anticipated cash flows from transportation operations may indicate that the fair value of Wylie is less than its book value resulting in an impairment of goodwill and a corresponding charge against earnings. At December 31, 2004, assessment of Wylie indicated that its goodwill was not impaired. We will continue to evaluate this reporting unit for impairment on an annual basis and as conditions warrant.

A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 29 through 31 of our 2004 Annual Report to Shareholders. There were no material changes in critical accounting policies or estimates during the quarter ended June 30, 2005 with the exception of estimating residual load adjustment costs related to MISO Day 2 electric market operations.

Forward Looking Information — Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q and in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as “may”, “will”, “expect”, “anticipate”, “continue”, “estimate”, “project”, “believes” or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act.

The following factors, among others, could cause actual results for the Company to differ materially from those discussed in the forward-looking statements:

	•		We are subject to government regulations and actions that may have a negative impact on our business and results of operations.

	•		Weather conditions can adversely affect our operations and revenues.

	•		Liquidated damages due to implementation of the MISO Day 2 electric markets.

	•		Federal and state environmental regulation could cause us to incur substantial capital expenditures which could result in increased operating costs.

	•		Our plans to grow and diversify through acquisitions may not be successful and could result in poor financial performance.

	•		Competition is a factor in all of our businesses.

	•		Economic uncertainty could have a negative impact on our future revenues and earnings.

	•		Volatile financial markets could restrict our ability to access capital and could increase borrowing costs and pension plan expenses.

	•		Our food ingredient processing segment operates in a highly competitive market and is dependent on adequate sources of raw materials for processing. Should the supply of these raw materials be affected by poor growing conditions, this could negatively impact the results of operations for this segment. This segment could also be impacted by foreign currency changes between Canadian and United States currencies and prices of natural gas.

	•		Our plastics segment is highly dependent on a limited number of vendors for PVC resin. The loss of a key vendor or an interruption or delay in the supply of PVC resin could result in reduced sales or increased costs for this segment.

	•		Our health services businesses may not be able to retain or comply with the dealership arrangement and other agreements with Philips Medical.

For a further discussion of other risk factors and cautionary statements, refer to “Risk Factors and Cautionary Statements That May Affect Future Results” and “Critical Accounting Policies Involving Significant Estimates” on pages 25 through 31 of our 2004 Annual Report to Shareholders. These factors are in addition to any other cautionary statements, written or oral, which may be made or referred to in connection with any such forward-looking statement or contained in any subsequent filings by the Company with the Securities and Exchange Commission.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

At June 30, 2005 we had limited exposure to market risk associated with interest rates and commodity prices and limited exposure to market risk associated with changes in foreign currency exchange rates. Outstanding trade accounts receivable of the Canadian operations of IPH are not at risk of valuation change due to changes in foreign currency exchange rates because the Canadian company transacts all sales in U.S. dollars. However, IPH does have market risk related to changes in foreign currency exchange rates because approximately 25% of IPH sales are outside the United States and the Canadian operations of IPH pays its operating expenses in Canadian dollars.

The majority of our consolidated long-term debt has fixed interest rates. The interest rate on variable rate long-term debt is reset on a periodic basis reflecting current market conditions. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt. As of June 30, 2005, we had $23.2 million of long-term debt subject to variable interest rates. Assuming no change in our financial structure, if variable interest rates were to average one percentage point higher or lower than the average variable rate on June 30, 2005, interest expense and pretax earnings would change by approximately $232,000 on an annualized basis.

We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

The plastics companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volumes have been higher and when resin prices are falling, sales volumes and margins have been lower. Gross margins also decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

Our energy services subsidiary markets natural gas to approximately 160 retail customers. Some of these customers are served under fixed-price contracts. There is price risk associated with a limited number of these fixed-price contracts since the corresponding cost of natural gas is not immediately locked in. However, any price risk associated with these contracts is within the acceptable risk parameters established in our risk management policy. We do not consider this price risk to be material. These contracts call for the physical delivery of natural gas and are considered executory contracts for accounting purposes. Current accounting guidance requires losses on firmly committed executory contracts to be recognized when realized.

Our energy services subsidiary has entered into over-the-counter natural gas forward swap transactions that qualify as derivatives subject to mark-to-market accounting under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Although our energy services subsidiary manages its risk by balancing its position in these transactions relative to its market position in the contracts entered into for physical delivery, these swap transactions

do not qualify for the normal purchases and sales exception nor do they qualify for hedge accounting treatment under SFAS No. 133. These contracts are held for trading purposes with both realized and unrealized net gains and losses reflected in revenue on our consolidated statement of income for the three and six months ended June 30, 2005 in accordance with the guidance provided in EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.

The following table shows the effect of marking-to-market our energy services subsidiary’s forward natural gas swap transactions on our consolidated balance sheet as of June 30, 2005 and the change in our consolidated balance sheet position from December 31, 2004 to June 30, 2005:


(in thousands)	June 30, 2005

Current asset – marked-to-market gain	$	852
Current liability – marked-to-market loss		(812	)

Net fair value of marked-to-market gas contracts	$	40


	Year-to-date
(in thousands)	June 30, 2005

Fair value at beginning of year	$	134
Amount realized on contracts entered into in 2004 and settled in 2005		(62	)
Changes in fair value of contracts entered into in 2004		—

Net fair value of contracts entered into in 2004 at end of period		72
Changes in fair value of contracts entered into in 2005		(32	)

Net fair value end of period	$	40

The $40,000 in recognized but unrealized net gain on these forward natural gas swap transactions marked-to-market on June 30, 2005 is expected to be realized on settlement as scheduled over the following quarters in the amounts listed:


	3rd Quarter		4th Quarter
(in thousands)	2005		2005		Total

Net gain	$	37	$	3	$	40

We have minimal credit risk associated with the nonperformance or nonpayment by counterparties to these forward gas swap transactions as we have only one major counterparty to these transactions and this counterparty has a high investment grade credit rating.

The electric utility has market, price and credit risk associated with forward contracts for the purchase and sale of electricity. As of June 30, 2005 the electric utility had recognized, on a pretax basis, $1,130,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. Due to the nature of electricity and the physical aspects of the electricity transmission system, unanticipated events affecting the transmission grid can result in transmission constraints and the cancellation of scheduled transactions by the independent transmission system operator. In these situations, the counterparties to the cancelled transaction are generally not made whole for the difference in the contract price and the market price of the electricity at the time of cancellation. In some instances the electric utility may deliver on a sale where its offsetting purchase has been cancelled or is undeliverable, or take delivery on a purchase where its offsetting sale has been cancelled or is undeliverable. All forward energy transactions are subject to a small, and likely unquantifiable, risk of cancellation by the independent transmission system operator due to unanticipated physical constraints on the transmission system. At the time of cancellation, the electric utility could be in a gain or loss position depending on the market price of electricity relative to the contract price and the electric utility’s position in the transaction.

The market prices used to value the electric utility’s forward contracts for the purchases and sales of electricity are determined by survey of counterparties by the electric utility’s power services’ personnel responsible for contract pricing and benchmarked to regional hub prices. Of the forward energy contracts that are marked-to-market as of June 30, 2005, 50% of the forward purchases of electricity had offsetting sales in terms of volumes and delivery periods. The amount of unrealized marked-to-market gains recognized on forward purchases of electricity that were not offset by forward sales of electricity was $748,000.

We have in place an energy risk management policy with a goal to manage, through the use of defined risk management practices, price risk and credit risk associated with wholesale power purchases and sales. With the advent of the MISO Day 2 market, several changes were made to the energy risk management policy to recognize new trading opportunities created by this new market. Most of the changes were in new volumetric limits and loss limits to adequately manage the risks associated with these new opportunities. In addition, a Value at Risk (VaR) limit was also implemented to further manage market price risk. Exposure to price risk on any open positions as of June 30, 2005 was not material.

The following tables show the effect of marking-to-market forward contracts for the purchase and sale of electricity on our consolidated balance sheet as of June 30, 2005 and the change in our consolidated balance sheet position from December 31, 2004 to June 30, 2005:


(in thousands)	June 30, 2005

Current asset – marked-to-market gain	$	4,143
Regulatory asset – deferred marked-to-market loss		830

Total assets		4,973


Current liability – marked-to-market loss		(2,687	)
Regulatory liability – deferred marked-to-market gain		(1,156	)

Total liabilities		(3,843	)


Net fair value of marked-to-market energy contracts	$	1,130


	Year-to-date
(in thousands)	June 30, 2005

Fair value at beginning of year	$	301
Amount realized on contracts entered into in 2004 and settled in 2005		(322	)
Changes in fair value of contracts entered into in 2004		21

Net fair value of contracts entered into in 2004 at end of period		0
Changes in fair value of contracts entered into in 2005		1,130

Net fair value end of period	$	1,130

The $1,130,000 in recognized but unrealized net gains on the forward energy purchases and sales marked-to-market on June 30, 2005 is expected to be realized on physical settlement as scheduled over the following quarter in the amount listed:


	3rd Quarter		4th Quarter		1st Quarter		2nd Quarter
(in thousands)	2005		2005		2006		2006		Total

Net gain	$	383	$	52	$	557	$	138	$	1,130

We have credit risk associated with the nonperformance or nonpayment by counterparties to our forward energy purchases and sales agreements. We have established guidelines and limits to manage credit risk associated with wholesale power purchases and sales. Specific limits are determined by a counterparty’s financial strength. Our credit risk with our largest counterparty on delivered and marked-to-market forward contracts as of June 30, 2005 was $1.6 million. As of June 30, 2005 we had a net credit risk exposure of $4.1 million from eleven counterparties with investment grade credit ratings.

The $4.1 million credit risk exposure includes net amounts due to the electric utility on receivables/payables from completed transactions billed and unbilled plus marked-to-market gains/losses on forward contracts for the purchase and sale of electricity scheduled for delivery after June 30, 2005. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch).

Item 4. Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2005, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2005.

On April 1, 2005, the MISO Day 2 market became effective which impacted the Company’s regulated electric generation and purchased power. In connection with the implementation of MISO Day 2, we have implemented new processes and modified existing process to facilitate participation in, and resultant settlements within the MISO market. Apart from this change, there have not been any other changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

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

The Company does not have a publicly announced stock repurchase program. The following table shows previously issued common shares that were surrendered to the Company during the quarter ended June 30, 2005, by employees to pay taxes in connection with the vesting of restricted stock granted to such employees under the Company’s 1999 Stock Incentive Plan:


	Total number of		Average price
Period	shares purchased		paid per share

April 2005		14,295	$	25.10
May 2005		—		—
June 2005		—		—

Total		14,295

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

The Annual Meeting of Shareholders of the Company was held on April 11, 2005, for the purpose of electing three nominees to the Board of Directors with terms expiring in 2008 and to ratify the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2005. All nominees for directors as listed in the proxy statement were elected. The names of each other director whose term of office continued after the meeting are as follows: Karen M. Bohn, Thomas M. Brown, Arvid R. Liebe, John C. MacFarlane, Gary J. Spies, and Robert N. Spolum. The voting results are as follows:


	Shares		Shares Voted		Broker
Election of Directors	Voted For		Withheld Authority		Non-Votes
Dennis R. Emmen		22,524,766		1,274,497		-0-
Kenneth L. Nelson		23,167,503		631,760		-0-
Nathan I. Partain		23,307,042		492,221		-0-

Ratification of

Independent Registered

Voted

Broker

Public Accounting Firm

Voted For

Against

Abstain

Non-Votes

Deloitte & Touche LLP

23,214,836

347,494

236,933

-0-

Item 6. Exhibits

	10.1		Big Stone II Power Plant Participation Agreement dated as of June 30, 2005 by and among Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., Otter Tail Corporation dba Otter Tail Power Company, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners. *

	10.2		Big Stone II Power Plant Operation & Maintenance Services Agreement dated as of June 30, 2005 by and among Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., Otter Tail Corporation dba Otter Tail Power Company, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners, and Otter Tail Corporation dba Otter Tail Power Company, as Operator. *

	10.3		Big Stone I and Big Stone II 2005 Joint Facilities Agreement dated as of June 30, 2005 by and among Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation dba NorthWestern Energy, Otter Tail Corporation dba Otter Tail Power Company, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners. *

	10.4		Form of 2005 Performance Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 15, 2005) **

	10.5		Executive Annual Incentive Plan (Effective April 1, 2005) (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed April 15, 2005) **

	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.

	32.1		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Confidential information has been omitted from this Exhibit and filed separately with the Commission pursuant to a confidential treatment request under Rule 24b-2.

**		Management contract or compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K

EXHIBIT INDEX


Exhibit Number		Description
10.1		Big Stone II Power Plant Participation Agreement dated as of June 30, 2005 by and among Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., Otter Tail Corporation dba Otter Tail Power Company, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners. *

10.2		Big Stone II Power Plant Operation & Maintenance Services Agreement dated as of June 30, 2005 by and among Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., Otter Tail Corporation dba Otter Tail Power Company, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners, and Otter Tail Corporation dba Otter Tail Power Company, as Operator. *

10.3		Big Stone I and Big Stone II 2005 Joint Facilities Agreement dated as of June 30, 2005 by and among Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation dba NorthWestern Energy, Otter Tail Corporation dba Otter Tail Power Company, Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency, as Owners. *

10.4		Form of 2005 Performance Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 15, 2005) **

10.5		Executive Annual Incentive Plan (Effective April 1, 2005) (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed April 15, 2005) **

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.

32.1		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Confidential information has been omitted from this Exhibit and filed separately with the Commission pursuant to a confidential treatment request under Rule 24b-2.

**		Management contract or compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K


	Page No.
Part I. Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets – June 30, 2005 and December 31, 2004 (not audited)		2 & 3

Consolidated Statements of Income — Three and Six Months Ended June 30, 2005 and 2004 (not audited)		4

Consolidated Statements of Cash Flows — Six Months Ended June 30, 2005 and 2004 (not audited)		5

Notes to Consolidated Financial Statements (not audited)		6-18

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19-35

Item 3. Quantitative and Qualitative Disclosures about Market Risk		35-38

Item 4. Controls and Procedures		38

Part II. Other Information

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		39

Item 4. Submission of Matters to a Vote of Security Holders		39

Item 6. Exhibits		40

Signatures		41
Big Stone II Power Plant Participation Agreement
Big Stone II Power Plant Operation & Maintenance Services Agreement
Big Stone I and Big Stone II 2005 Joint Facilities Agreement
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



	By:	/s/ Kevin G. Moug
		Kevin G. Moug
		Chief Financial Officer and Treasurer (Chief Financial Officer/Authorized Officer)