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

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

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota		27-0383995
(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

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

July 31, 2009 — 35,611,789 Common Shares ($5 par value)

 

 

OTTER TAIL CORPORATION

INDEX

		Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets — June 30, 2009 and December 31, 2008 (not audited)			2 & 3
Consolidated Statements of Income — Three and Six Months Ended June 30, 2009 and 2008 (not audited)			4
Consolidated Statements of Cash Flows — Six Months Ended June 30, 2009 and 2008 (not audited)			5
Notes to Consolidated Financial Statements (not audited)			6-30
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			31-49
Item 3. Quantitative and Qualitative Disclosures About Market Risk			50-52
Item 4. Controls and Procedures			52
Part II. Other Information
Item 1. Legal Proceedings			53
Item 1A. Risk Factors			53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			53
Item 4. Submission of Matters to a Vote of Securities Holders			54
Item 6. Exhibits			54-55
Signatures			55
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Otter Tail Corporation

(not audited)

		June 30,				December 31,
		2009				2008
		(Thousands of dollars)
Current Assets
Cash and Cash Equivalents		$	9,056			$	7,565
Accounts Receivable:
Trade—Net			107,239				136,609
Other			9,757				13,587
Inventories			92,140				101,955
Deferred Income Taxes			8,402				8,386
Accrued Utility and Cost-of-Energy Revenues			11,952				24,030
Costs and Estimated Earnings in Excess of Billings			50,605				65,606
Income Taxes Receivable			11,955				26,754
Other			20,225				8,519
Total Current Assets			321,331				393,011
Investments			8,634				7,542
Other Assets			88,249				22,615
Goodwill			106,778				106,778
Other Intangibles—Net			34,637				35,441
Deferred Debits
Unamortized Debt Expense and Reacquisition Premiums			9,598				7,247
Regulatory Assets and Other Deferred Debits			81,336				82,384
Total Deferred Debits			90,934				89,631
Plant
Electric Plant in Service			1,210,035				1,205,647
Nonelectric Operations			343,358				321,032
Total Plant			1,553,393				1,526,679
Less Accumulated Depreciation and Amortization			575,448				548,070
Plant—Net of Accumulated Depreciation and Amortization			977,945				978,609
Construction Work in Progress			82,230				58,960
Net Plant			1,060,175				1,037,569
Total		$	1,710,738			$	1,692,587

See accompanying notes to consolidated financial statements

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

		June 30,				December 31,
		2009				2008
		(Thousands of dollars)
Current Liabilities
Short-Term Debt		$	119,914			$	134,914
Current Maturities of Long-Term Debt			1,242				3,747
Accounts Payable			85,927				113,422
Accrued Salaries and Wages			19,437				29,688
Accrued Taxes			8,155				10,939
Other Accrued Liabilities			13,240				12,034
Total Current Liabilities			247,915				304,744
Pensions Benefit Liability			82,882				80,912
Other Postretirement Benefits Liability			33,464				32,621
Other Noncurrent Liabilities			20,095				19,391
Commitments (note 9)
Deferred Credits
Deferred Income Taxes			132,923				123,086
Deferred Tax Credits			33,212				34,288
Regulatory Liabilities			65,801				64,684
Other			427				397
Total Deferred Credits			232,363				222,455
Capitalization
Long-Term Debt, Net of Current Maturities			411,835				339,726
Class B Stock Options of Subsidiary			1,220				1,220
Cumulative Preferred Shares Authorized 1,500,000 Shares Without Par Value; Outstanding 2009 and 2008 — 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 2009 — 35,558,465 and 2008 — 35,384,620			177,792				176,923
Premium on Common Shares			243,933				241,731
Retained Earnings			246,025				260,364
Accumulated Other Comprehensive Loss			(2,286	)			(3,000	)
Total Common Equity			665,464				676,018
Total Capitalization			1,094,019				1,032,464
Total		$	1,710,738			$	1,692,587

See accompanying notes to consolidated financial statements

Otter Tail Corporation

(not audited)

		Three months ended								Six months ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands, except share								(In thousands, except share
		and per share amounts)								and per share amounts)
Operating Revenues
Electric		$	70,610			$	68,577			$	159,089			$	166,083
Nonelectric			176,247				255,023				365,007				457,754
Total Operating Revenues			246,857				323,600				524,096				623,837
Operating Expenses
Production Fuel — Electric			11,754				14,808				30,413				34,712
Purchased Power — Electric System Use			11,877				10,156				29,250				29,142
Electric Operation and Maintenance Expenses			28,959				27,757				55,889				54,500
Cost of Goods Sold — Nonelectric (depreciation included below)			135,319				204,235				288,280				369,458
Other Nonelectric Expenses			32,410				36,242				63,044				70,989
Product Recall and Testing Costs			—				—				1,766				—
Plant Closure Costs			—				1,412				—				1,412
Depreciation and Amortization			18,103				16,124				35,920				31,037
Property Taxes — Electric			2,255				2,563				4,745				5,187
Total Operating Expenses			240,677				313,297				509,307				596,437
Operating Income			6,180				10,303				14,789				27,400
Other Income			1,351				626				2,018				1,588
Interest Charges			6,652				7,043				12,922				13,754
Income Before Income Taxes			879				3,886				3,885				15,234
Income Taxes			(1,852	)			369				(3,234	)			3,487
Net Income			2,731				3,517				7,119				11,747
Preferred Dividend Requirements			184				184				368				368
Earnings Available for Common Shares		$	2,547			$	3,333			$	6,751			$	11,379
Earnings Per Common Share:
Basic		$	0.07			$	0.11			$	0.19			$	0.38
Diluted		$	0.07			$	0.11			$	0.19			$	0.38
Average Number of Common Shares Outstanding:
Basic			35,388,754				29,993,484				35,356,745				29,905,782
Diluted			35,643,707				30,300,207				35,610,545				30,198,967
Dividends Per Common Share		$	0.2975			$	0.2975			$	0.5950			$	0.5950

See accompanying notes to consolidated financial statements

Otter Tail Corporation

(not audited)

		Six Months Ended
		June 30,
		2009				2008
		(Thousands of dollars)
Cash Flows from Operating Activities
Net Income		$	7,119			$	11,747
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization			35,920				31,037
Deferred Tax Credits			(1,075	)			(782	)
Deferred Income Taxes			9,614				5,959
Change in Deferred Debits and Other Assets			(538	)			(2,627	)
Change in Noncurrent Liabilities and Deferred Credits			3,826				752
Allowance for Equity (Other) Funds Used During Construction			(1,003	)			(801	)
Change in Derivatives Net of Regulatory Deferral			(661	)			(655	)
Stock Compensation Expense			1,754				1,908
Other—Net			139				316
Cash Provided by (Used for) Current Assets and Current Liabilities:
Change in Receivables			33,264				(1,904	)
Change in Inventories			10,130				(10,082	)
Change in Other Current Assets			18,688				(17,520	)
Change in Payables and Other Current Liabilities			(41,161	)			16,244
Change in Interest and Income Taxes Payable/Receivable			14,289				1,348
Net Cash Provided by Operating Activities			90,305				34,940
Cash Flows from Investing Activities
Capital Expenditures			(57,930	)			(117,785	)
Proceeds from Disposal of Noncurrent Assets			4,551				3,517
Acquisitions—Net of Cash Acquired			—				(41,674	)
Net (Increase) Decrease in Other Investments and Long-Term Assets			(66,671	)			(376	)
Net Cash Used in Investing Activities			(120,050	)			(156,318	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash			—				3,636
Net Short-Term Borrowings			(15,000	)			91,600
Proceeds from Issuance of Common Stock			1,901				5,176
Common Stock Issuance Expenses			(17	)			—
Payments for Retirement of Common Stock			(229	)			(91	)
Proceeds from Issuance of Long-Term Debt			75,004				1,137
Short-Term and Long-Term Debt Issuance Expenses			(3,175	)			(19	)
Payments for Retirement of Long-Term Debt			(5,438	)			(1,829	)
Dividends Paid			(21,457	)			(18,212	)
Net Cash Provided by Financing Activities			31,589				81,398
Effect of Foreign Exchange Rate Fluctuations on Cash			(353	)			156
Net Change in Cash and Cash Equivalents			1,491				(39,824	)
Cash and Cash Equivalents at Beginning of Period			7,565				39,824
Cash and Cash Equivalents at End of Period		$	9,056			$	—

See accompanying notes to consolidated financial statements

OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(not audited)

On July 1, 2009, Otter Tail Corporation completed a holding company reorganization whereby Otter Tail Power Company, which had previously been operated as a division of Otter Tail Corporation, became a wholly owned subsidiary of the new parent holding company named Otter Tail Corporation (formerly known as Otter Tail Holding Company). See Note 19 — Subsequent Events. The new parent holding company (now known as Otter Tail Corporation) was incorporated in June 2009 under the laws of the State of Minnesota in connection with the holding company reorganization. References in this report to Otter Tail Corporation and the Company refer, for periods prior to July 1, 2009, to the corporation that was the registrant prior to the reorganization, and, for periods after the reorganization, to the new parent holding company, in each case including its consolidated subsidiaries, unless otherwise indicated or the context otherwise requires.

In the opinion of management, 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, 2008, 2007 and 2006 included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008. Because of seasonal and other factors, the earnings for the three-month and six-month periods ended June 30, 2009 should not be taken as an indication of earnings for all or any part of the balance of the year.

The following notes are numbered to correspond to numbers of the notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

1. Summary of Significant Accounting Policies

Revenue Recognition

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

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

Some of the operating businesses enter into fixed-price construction contracts. Revenues under these contracts are recognized on a percentage-of-completion basis. The Company’s consolidated revenues recorded under the percentage-of-completion method were 25.7% for the three months ended June 30, 2009 compared with 33.6% for the three months ended June 30, 2008 and 27.6% for the six months ended June 30, 2009 compared with 31.0% for the six months ended June 30, 2008. The method used to determine the progress of completion is based on the ratio of labor costs incurred to total estimated labor costs at the Company’s wind tower manufacturer, square footage completed to total bid square footage for certain floating dock projects and costs incurred to total estimated costs on all other construction projects. If a loss is indicated at any point in time during a contract, a projected loss for the entire contract is estimated and recognized.

The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:

		June 30,				December 31,
(in thousands)		2009				2008
Costs Incurred on Uncompleted Contracts		$	374,103			$	377,237
Less Billings to Date			(380,992	)			(366,931	)
Plus Estimated Earnings Recognized			53,686				47,355
		$	46,797			$	57,661

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)		2009				2008
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts		$	50,605			$	65,606
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts			(3,808	)			(7,945	)
		$	46,797			$	57,661

Costs and Estimated Earnings in Excess of Billings at DMI Industries, Inc. (DMI) were $43,894,000 as of June 30, 2009 and $59,300,000 as of December 31, 2008. This amount is related to costs incurred on wind towers in the process of completion on major contracts under which the customer is not billed until towers are completed and ready for shipment.

Retainage

Accounts Receivable include amounts billed by the Company’s subsidiaries under contracts that have been retained by customers pending project completion of $8,356,000 on June 30, 2009 and $10,311,000 on December 31, 2008.

Sales of Receivables

DMI has a $40 million receivables purchase agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement expires in March 2011. Accounts receivable totaling $64.8 million have been sold in 2009. Discounts and commissions and fees of $92,000 for the three months ended June 30, 2009 and $267,000 for the six months ended June 30, 2009 were charged to operating expenses in the consolidated statements of income. In compliance with SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, sales of accounts receivable are reflected as a reduction of accounts receivable in the consolidated balance sheets and the proceeds are included in the cash flows from operating activities in the consolidated statements of cash flows.

Marketing and Sales Incentive Costs

ShoreMaster, Inc. (ShoreMaster), the Company’s waterfront equipment manufacturer, provides dealer floor plan financing assistance for certain dealer purchases of ShoreMaster products for certain set time periods based on the timing and size of a dealer’s order. ShoreMaster recognizes the estimated cost of projected interest payments related to each financed sale as a liability and a reduction of revenue at the time of sale, based on historical experience of the average length of time floor plan debt is outstanding, in accordance with Emerging Issues Task Force Issue No. 01-9, Accounting for Consideration Given by a Vendor to a Customer (Including a Reseller of a Vendor’s Products). The liability is reduced when interest is paid. To the extent current experience differs from previous estimates the accrued liability for financing assistance costs is adjusted accordingly. Financing assistance costs charged to revenue were $88,000 for the three months ended June 30, 2009 and $233,000 for the six months ended June 30, 2009 compared with $240,000 for both the three and six months ended June 30, 2008.

Supplemental Disclosures of Cash Flow Information

		Six Months Ended
		June 30,
(in thousands)		2009				2008
Increases (Decreases) in Accounts Payable and Other Liabilities Related to Capital Expenditures		$	330			$	(21,419	)

Fair Value Measurements

Effective January 1, 2008, the Company adopted SFAS No. 157, Fair Value Measurements, for recurring fair value measurements. SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the SFAS No. 157 hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.

The following table presents, for each of these hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2009:

(in thousands)		Level 1				Level 2				Level 3				Total
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market, Mutual Funds and Cash		$	782			$	—			$	—			$	782
Cash Surrender Value of Life Insurance Policies							8,598								8,598
Cash Surrender Value of Keyman Life Insurance Policies — Net of Policy Loans							10,941								10,941
Forward Energy Contracts							3,595								3,595
Forward Foreign Currency Exchange Contracts			120												120
Investments of Captive Insurance Company:
Corporate Debt Securities			4,112												4,112
U.S. Government Debt Securities			1,930												1,930
Total Assets		$	6,944			$	23,134			$	—			$	30,078
Liabilities:
Forward Energy Contracts		$	—			$	3,727			$	—			$	3,727
Forward Foreign Currency Exchange Contracts			41												41
Asset Retirement Obligations											3,438				3,438
Total Liabilities		$	41			$	3,727			$	3,438			$	7,206
Net Assets (Liabilities)		$	6,903			$	19,407			$	(3,438	)		$	22,872

Inventories

Inventories consist of the following:

		June 30,				December 31,
(in thousands)		2009				2008
Finished Goods		$	39,946			$	38,943
Work in Process			6,674				10,205
Raw Material, Fuel and Supplies			45,520				52,807
Total Inventories		$	92,140			$	101,955

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at June 30, 2009 and December 31, 2008:

		Gross Carrying				Accumulated				Net Carrying				Amortization
June 30, 2009 (in thousands)		Amount				Amortization				Amount				Periods
Amortized Intangible Assets:
Covenants Not to Compete		$	2,190			$	1,938			$	252			3 - 5 years
Customer Relationships			26,884				3,059				23,825			15 - 25 years
Other Intangible Assets Including Contracts			2,359				1,670				689			5 - 30 years
Total		$	31,433			$	6,667			$	24,766
Nonamortized Intangible Assets:
Brand/Trade Name		$	9,871			$	—			$	9,871
December 31, 2008 (in thousands)
Amortized Intangible Assets:
Covenants Not to Compete		$	2,250			$	1,889			$	361			3 - 5 years
Customer Relationships			26,854				2,429				24,425			15 - 25 years
Other Intangible Assets Including Contracts			2,710				1,921				789			5 - 30 years
Total		$	31,814			$	6,239			$	25,575
Nonamortized Intangible Assets:
Brand/Trade Name		$	9,866			$	—			$	9,866

The amortization expense for these intangible assets was $835,000 for the six months ended June 30, 2009 compared to $563,000 for the six months ended June 30, 2008. The estimated annual amortization expense for these intangible assets for the next five years is $1,639,000 for 2009, $1,461,000 for 2010, $1,332,000 for 2011, $1,312,000 for 2012 and $1,308,000 for 2013.

Comprehensive Income

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2009				2008				2009				2008
Net Income		$	2,731			$	3,517			$	7,119			$	11,747
Other Comprehensive Gain (Loss) (net-of-tax):
Foreign Currency Translation Gain (Loss)			1,008				77				584				(375	)
Amortization of Unrecognized Losses and Costs Related to Postretirement Benefit Programs			89				37				104				80
Unrealized Gain (Loss) on Available-for-Sale Securities			81				(94	)			26				(35	)
Total Other Comprehensive Gain (Loss)			1,178				20				714				(330	)
Total Comprehensive Income		$	3,909			$	3,537			$	7,833			$	11,417

New Accounting Standards

SFAS No. 141 (revised 2007), Business Combinations (SFAS No. 141(R)), was issued by the Financial Accounting Standards Board (FASB) in December 2007. SFAS No. 141(R) replaces SFAS No. 141, Business Combinations, and will apply prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree). In addition to replacing the term “purchase method of accounting” with “acquisition method of accounting,” SFAS No. 141(R) requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions. This guidance will replace SFAS No. 141’s cost-allocation process, which requires the cost of an acquisition to be allocated to the individual assets acquired and liabilities assumed based on their estimated fair values. SFAS No. 141’s guidance results in not recognizing some assets and liabilities at the acquisition date, and it also results in measuring some assets and liabilities at amounts other than their fair values at the acquisition date. For example, SFAS No. 141 requires the acquirer to include the costs incurred to effect an acquisition (acquisition-related costs) in the cost of the

acquisition that is allocated to the assets acquired and the liabilities assumed. SFAS No. 141(R) requires those costs to be expensed as incurred. In addition, under SFAS No. 141, restructuring costs that the acquirer expects but is not obligated to incur are recognized as if they were a liability assumed at the acquisition date. SFAS No. 141(R) requires the acquirer to recognize those costs separately from the business combination. The Company adopted SFAS No. 141(R) on January 1, 2009. The adoption did not have a material impact on its consolidated financial statements.

SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133, was issued by the FASB in March 2008. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities to improve the transparency of financial reporting. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company adopted SFAS No. 161 on January 1, 2009. Adoption of SFAS No. 161 resulted in additional footnote disclosures related to the Company’s use of derivative instruments, the location and fair value of derivatives reported on the Company’s consolidated balance sheets, the location and amounts of derivative instrument gains and losses reported on the Company’s consolidated statements of income, and information on credit risk exposure related to derivative instruments.

FASB Staff Position (FSP) FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets, was issued by the FASB in December 2008. FSP FAS 132(R)-1 amends SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to expand an employer’s required disclosures about plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, information regarding fair value measurements, and significant concentrations of credit risk. FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009. The Company does not expect the adoption of FSP FAS 132(R)-1 to have a material impact on its consolidated financial statements.

FASB Staff Position (FSP) FAS 107-1 and Accounting Principles Board (APB) 28-1), Interim Disclosures about Fair Value of Financial Instruments, was issued by the FASB in April 2009. FSP FAS 107-1 and APB 28-1, amends SFAS No. 107, Disclosures About Fair Value of Financial Instruments, and APB Opinion No. 28, Interim Financial Reporting, to require disclosures regarding the fair value of financial instruments in interim financial statements. FSP FAS 107-1 and APB 28-1 was effective for interim periods ending after June 15, 2009. The Company implemented FSP FAS 107-1 and APB 28-1 on April 1, 2009. The implementation did not have a material impact on the Company’s consolidated financial statements. FSP FAS 107-1 and APB 28-1 required disclosures have been included in the Company’s notes to consolidated financial statements, where applicable.

SFAS No. 165, Subsequent Events, was issued by the FASB in May 2009. SFAS No. 165 establishes general standards of accounting and disclosure for events that occur after the balance sheet date but before financial statements are issued. The accounting guidance contained in SFAS No. 165 is consistent with the auditing literature widely used for accounting and disclosure of subsequent events, however, SFAS No. 165 requires an entity to disclose the date through which subsequent events have been evaluated. SFAS No. 165 is effective for interim and annual periods ending after June 15, 2009. The Company implemented SFAS No. 165 on April 1, 2009. The implementation did not have a material impact on the Company’s consolidated financial statements.

SFAS No. 167, Amendments to FASB Interpretation No. 46(R), was issued by the FASB in June 2009. SFAS No. 167 amends the consolidation guidance applicable to variable interest entities. The amendments will significantly affect various elements of consolidation guidance under FASB Interpretation No. 46(R), including guidance for determining whether an entity is a variable interest entity and whether an enterprise is the primary beneficiary of a variable interest entity. SFAS No. 167 is effective for fiscal years beginning after Nov. 15, 2009. The Company does not expect the implementation of SFAS No. 167 to have a significant impact on its consolidated financial statements.

SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162, was issued by the FASB in June 2009. SFAS No. 168 confirms that the FASB Accounting Standards Codification (Codification) is the single source of authoritative GAAP, other than guidance put forth by the Securities and Exchange Commission. All other accounting literature not included in the Codification will be considered non-authoritative. SFAS No. 168 is effective for interim and annual periods ending after Sept. 15, 2009. The Company expects the implementation of SFAS No. 168 to have no impact on its consolidated financial statements. However, all references to accounting standards in future filings will be to applicable standards in the Codification or to applicable code sections within the Codification.

2. 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 (the electric utility). In addition, the electric utility is an active wholesale participant in the Midwest Independent Transmission System Operator (MISO) markets. The electric utility operations have been the Company’s primary business since 1907.

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

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

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

Food Ingredient Processing consists of Idaho Pacific Holdings, Inc. (IPH), which owns and operates potato dehydration plants in Ririe, Idaho; Center, Colorado; and Souris, Prince Edward Island, Canada. IPH produces dehydrated potato products that are sold in the United States, Canada and other countries.

Other Business Operations consists of businesses in residential, commercial and industrial electric contracting industries, fiber optic and electric distribution systems, wastewater and HVAC systems construction, transportation and energy services. These businesses operate primarily in the Central United States, except for the transportation company which operates in 48 states and four Canadian provinces.

Our electric operations, including wholesale power sales, are operated by our wholly owned subsidiary, Otter Tail Power Company, and our energy services operation is operated by a separate wholly owned subsidiary of Otter Tail Corporation. Substantially all of our other businesses are owned by our wholly owned subsidiary Varistar Corporation.

Corporate includes items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

No single external customer accounted for 10% or more of the Company’s revenues in the six months ended June 30, 2009. Substantially all of the Company’s long-lived assets are within the United States except for a food ingredient processing dehydration plant in Souris, Prince Edward Island, Canada and a wind tower manufacturing plant in Fort Erie, Ontario, Canada.

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
United States of America			97.3	%			97.2	%			97.9	%			96.6	%
Canada			1.3	%			1.5	%			1.0	%			1.4	%
All Other Countries (none greater than 1%)			1.4	%			1.3	%			1.1	%			2.0	%

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 for the business segments for three and six month periods ended June 30, 2009 and 2008 and total assets by business segment as of June 30, 2009 and December 31, 2008 are presented in the following tables:

Operating Revenue

		Three Months Ended								Six Months Ended
		June 30,								June 30,
(in thousands)		2009				2008				2009				2008
Electric		$	70,663			$	68,666			$	159,204			$	166,256
Plastics			22,183				40,645				35,713				62,995
Manufacturing			76,843				120,342				172,862				217,937
Health Services			28,192				30,740				56,359				60,005
Food Ingredient Processing			20,581				15,913				40,667				31,811
Other Business Operations			29,597				48,080				61,492				86,190
Corporate Revenues and Intersegment Eliminations			(1,202	)			(786	)			(2,201	)			(1,357	)
Total		$	246,857			$	323,600			$	524,096			$	623,837

Interest Expense

		Three months ended								Six months ended
		June 30,								June 30,
(in thousands)		2009				2008				2009				2008
Electric		$	4,266			$	3,133			$	8,277			$	6,114
Plastics			199				327				399				468
Manufacturing			1,439				2,231				2,718				4,377
Health Services			100				176				196				355
Food Ingredient Processing			10				31				20				41
Other Business Operations			112				295				232				602
Corporate and Intersegment Eliminations			526				850				1,080				1,797
Total		$	6,652			$	7,043			$	12,922			$	13,754

Income Taxes

		Three months ended								Six months ended
		June 30,								June 30,
(in thousands)		2009				2008				2009				2008
Electric		$	(832	)		$	(266	)		$	939			$	6,154
Plastics			198				429				(1,449	)			854
Manufacturing			(208	)			618				(1,012	)			15
Health Services			(63	)			(11	)			(76	)			(426	)
Food Ingredient Processing			1,613				614				2,338				1,214
Other Business Operations			(944	)			543				(1,150	)			(617	)
Corporate			(1,616	)			(1,558	)			(2,824	)			(3,707	)
Total		$	(1,852	)		$	369			$	(3,234	)		$	3,487

Earnings Available for Common Shares

		Three months ended								Six months ended
		June 30,								June 30,
(in thousands)		2009				2008				2009				2008
Electric		$	4,211			$	3,092			$	12,553			$	15,658
Plastics			291				652				(2,167	)			1,272
Manufacturing			(167	)			1,396				(1,257	)			780
Health Services			(153	)			(88	)			(226	)			(779	)
Food Ingredient Processing			2,325				685				3,772				1,808
Other Business Operations			(1,456	)			794				(1,781	)			(971	)
Corporate			(2,504	)			(3,198	)			(4,143	)			(6,389	)
Total		$	2,547			$	3,333			$	6,751			$	11,379

Total Assets

		June 30,				December 31,
(in thousands)		2009				2008
Electric		$	1,059,063			$	992,159
Plastics			74,239				78,054
Manufacturing			313,719				356,697
Health Services			59,843				61,086
Food Ingredient Processing			87,426				88,813
Other Business Operations			62,785				71,359
Corporate			53,663				44,419
Total		$	1,710,738			$	1,692,587

3. Rate and Regulatory Matters

Minnesota

General Rate Case — In an order issued by the Minnesota Public Utilities Commission (MPUC) on August 1, 2008 the electric utility was granted an increase in Minnesota retail electric rates of $3.8 million or approximately 2.9%, which went into effect in February 2009. The MPUC approved a rate of return on equity of 10.43% on a capital structure with 50.0% equity. An interim rate increase of 5.4% was in effect from November 30, 2007 through January 31, 2009. Amounts refundable totaling $3.9 million had been recorded as a liability on the Company’s consolidated balance sheet as of December 31, 2008. An additional $0.5 million refund liability was accrued in January 2009. The electric utility refunded Minnesota customers the difference between interim rates and final rates, with interest, in March 2009. The electric utility deferred recognition of $1.5 million in rate case-related filing and administrative costs in June 2008 that are subject to amortization and recovery over a three year period beginning in February 2009.

Capacity Expansion 2020 (CapX 2020) Mega Certificate of Need (MegaCON) —On August 16, 2007 the eleven CapX 2020 utilities asked the MPUC to determine the need for three 345-kilovolt (kv) transmission lines. Evidentiary hearings for the Certificate of Need for the three CapX 2020 345-kv transmission line projects began in July 2008 and continued into August 2008. On April 16, 2009 the MPUC approved by a 5-0 vote the MegaCON for the three 345-kv Group 1 CapX 2020 line projects (Fargo-St. Cloud, Brookings-Southeast Twin Cities, and Twin Cities-LaCrosse). The MPUC then voted 3-2 to impose conditions pertaining to reserving line capacity for renewable energy sources on the Brookings line project. The MPUC did take up reconsideration of the original order regarding the conditions. Upon deliberation, the MPUC slightly modified the conditions on the Brookings line. As part of the MegaCON approval, the MPUC accepted a CapX 2020 request to build the 345-kv lines for double-circuit capability to have two 345-kv transmission circuits on each structure. The current plan is to string only one circuit. Route permit applications were filed for the Brookings project in late December 2008 and for the Monticello-to-St. Cloud portion of the Fargo project in March 2009. Portions of the lines would also require approvals by federal officials and by regulators in North Dakota, South Dakota and Wisconsin. After regulatory need is established and routing decisions are completed (expected in 2010 and 2011), construction will begin. The lines would be expected to be

completed over a two to four year period. Great River Energy and Xcel Energy are leading these projects, and Otter Tail Power Company and eight other utilities are involved in permitting, building and financing. Otter Tail Power Company is directly involved in two of these three projects.

Otter Tail Power Company serves as the lead utility in a fourth Group 1 project, the Bemidji-Grand Rapids 230-kv line which has an expected in-service date of 2012-2013. The electric utility filed a Certificate of Need (CON) for this fourth project on March 17, 2008. The Department of Commerce Office of Energy Security (MNOES) staff completed briefing papers regarding the Bemidji-Grand Rapids route permit application. The MNOES staff recommended to the MPUC: (1) the route permit application be found to be complete, (2) the need determination not be sent to a contested case but be handled informally by MPUC review, and (3) the Certificate of Need and route permit proceedings be combined as requested. The MPUC met on June 26, 2008 to act on the MNOES staff recommendation. The MPUC agreed the Certificate of Need and route permit applications were complete. The MNOES subsequently recommended a determination that need for the line has been established. The Environmental Report for the CON was issued in April 2009. CON hearings were conducted on May 20 and May 21, 2009 and a summary of comments was issued on June 8, 2009. The CON was placed on the MPUC agenda for July 9, 2009. The MNOES and the National Forest Service continue to work on the Environmental Impact Statement (EIS) for the project. The MNOES expects to issue a draft EIS by September 1, 2009. The MNOES further expects to have the hearings for the Bemidji-Grand Rapids route in November 2009. The MPUC is expected to determine if there is a need for this line and, if appropriate, issue the route permit in summer 2010.

Renewable Energy Standards, Conservation, Renewable Resource and Transmission Riders —In February 2007, the Minnesota legislature passed a renewable energy standard requiring the electric utility to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 12% by 2012; 17% by 2016; 20% by 2020 and 25% by 2025. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. The electric utility has acquired renewable resources and expects to acquire additional renewable resources in order to maintain compliance with the Minnesota renewable energy standard. By the end of 2010, the electric utility expects to have sufficient renewable energy resources available to comply with the required 2012 level of the Minnesota renewable energy standard. The electric utility’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

Under the Next Generation Energy Act of 2007 passed by the Minnesota legislature in May 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover investments and costs incurred to satisfy the requirements of the renewable energy standards. The MPUC is now authorized to approve a rate schedule rider to enable utilities to recover the costs of qualifying renewable energy projects that supply renewable energy to Minnesota customers. Cost recovery for qualifying renewable energy projects can now be authorized outside of a rate case proceeding, provided that such renewable projects have received previous MPUC approval. Renewable resource costs eligible for recovery may include return on investment, depreciation, operation and maintenance costs, taxes, renewable energy delivery costs and other related expenses.

In an order issued on August 15, 2008, the MPUC approved the electric utility’s proposal to implement a Renewable Resource Cost Recovery Rider for its Minnesota jurisdictional portion of investment in renewable energy facilities. The rider enables the electric utility to recover from its Minnesota retail customers its investments in owned renewable energy facilities and provides for a return on those investments. The Renewable Resource Adjustment (RRA) of 0.19 cents per kilowatt-hour (kwh) was included on Minnesota customers’ electric service statements beginning in September 2008. The first renewable energy project for which the electric utility is receiving cost recovery is its 40.5 megawatt ownership share of the Langdon Wind Energy Center, which became fully operational in January 2008.

The electric utility’s 2009 RRA filing includes a request for recovery of the electric utility’s investment costs and expenses related to its 32 wind turbines at the Ashtabula Wind Energy Center that became commercially operational in November 2008. The MPUC acted on the electric utility’s petition for a 2009 RRA in July 2009 approving an RRA of 0.415 cents per kwh for the recovery of $6.6 million through March 31, 2010—$4.0 million from August through December 2009 and $2.6 million from January through March 2010—and for accrued renewable resource recovery revenues not recovered through billings by March 31, 2010, recovery was granted over a 48-month period beginning in April 2010. The electric utility has recognized a regulatory asset of $4.8 million for revenues that are eligible for recovery through the rider but have not been billed to Minnesota customers as of June 30, 2009.

In addition to the Renewable Resource Cost Recovery Rider, the Minnesota Public Utilities Act provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new electric transmission facilities. The MPUC may approve a tariff rider to recover the Minnesota jurisdictional costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need proceeding or certified by the MPUC as a Minnesota priority transmission project or investment and expenditures made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers. Such transmission cost recovery riders would allow a return on investments at the level approved in a utility’s last general rate case. Additionally, following approval of the tariff, the MPUC may approve annual rate adjustments filed pursuant to the tariff. The electric utility filed a proposed rider with the MPUC to recover its share of costs of eligible transmission infrastructure upgrade projects on July 28, 2009.

North Dakota

General Rate Case —On November 3, 2008 the electric utility filed a general rate case in North Dakota requesting an overall revenue increase of approximately $6.1 million, or 5.1%, and an interim rate increase of approximately 4.1%, or $4.8 million annualized, that went into effect on January 2, 2009. The North Dakota Public Service Commission’s (NDPSC) order authorizing an interim rate increase requires the electric utility to refund North Dakota customers the difference between final and interim rates, with interest, if final rates approved by the NDPSC are lower than interim rates. NDPSC advocacy staff and intervenors’ testimony was received in April 2009. A tentative settlement of all issues in the case, joined by all parties and NDPSC advocacy staff, was filed with the NDPSC in June 2009. The NDPSC scheduled a September 28, 2009 hearing for the purpose of considering the settlement. Interim rates will remain in effect for all North Dakota customers until the NDPSC makes its final determination. In June 2009, based on terms agreed to in the tentative settlement, the electric utility established a refund reserve of $0.5 million for revenues collected under interim rates.

Renewable Resource Cost Recovery Rider —On May 21, 2008 the NDPSC approved the electric utility’s request for a Renewable Resource Cost Recovery Rider to enable the electric utility to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. The Renewable Resource Cost Recovery Rider Adjustment of 0.193 cents per kwh was included on North Dakota customers’ electric service statements beginning in June 2008, which reflects cost recovery for the electric utility’s 40.5 megawatt ownership share of the Langdon Wind Energy Center, which became fully operational in January 2008. The electric utility may also recover through this rider costs associated with other new renewable energy projects as they are completed. The electric utility has included investment costs and expenses related to its 32 wind turbines at the Ashtabula Wind Energy Center that became commercially operational in November 2008 in its 2009 annual request to the NDPSC to increase the amount of the Renewable Resource Cost Recovery Rider Adjustment. A Renewable Resource Cost Recovery Rider Adjustment rate of 0.51 cents per kwh was approved by the NDPSC on January 14, 2009 and went into effect beginning with billing statements sent on February 1, 2009.

In a proceeding being processed in combination with the electric utility’s General Rate Case, the NDPSC is reviewing whether to move the costs of the projects currently being recovered through the rider into base rate cost recovery and whether to make changes to the rider. As described above, NDPSC advocacy staff and intervenors’ testimony were received in April 2009, and a settlement of all issues, including all issues relative to Renewable Resource Cost Recovery Rider, will be considered by the NDPSC at a September 28, 2009 hearing. The proposed settlement reflects some changes in the timing of cost recovery and a reduction in the RRA. The electric utility will apply for a Renewable Resource Cost Recovery Rider Adjustment to be effective January 1, 2010, to include cost recovery for its Luverne Wind Project.

The electric utility had not been deferring recognition of its renewable resource costs eligible for recovery under the North Dakota Renewable Resource Cost Recovery Rider but had been charging those costs to operating expense since January 2008. After approval of the rider in May 2008, the electric utility accrued revenues related to its investment in renewable energy and for renewable energy costs incurred since January 2008 that are eligible for recovery through the North Dakota Renewable Resource Cost Recovery Rider. The Company’s June 30, 2009 consolidated balance sheet includes a regulatory asset of $1.2 million for revenues that are eligible for recovery through the North Dakota Renewable Resource Cost Recovery Rider but have not been billed to North Dakota customers as of June 30, 2009. Terms of the proposed settlement provide for the recovery of accrued but unbilled North Dakota resource recovery rider revenues over a period of 48 months beginning in January 2010.

South Dakota

General Rate Case —On October 31, 2008 the electric utility filed a general rate case in South Dakota requesting an overall revenue increase of approximately $3.8 million, or 15.3%, which includes recovery of renewable resource investments and expenses in base rates. The electric utility increased rates by approximately 11.7% on a temporary basis beginning with electricity consumed on and after May 1, 2009, as allowed by South Dakota statutes. In an order issued by the South Dakota Public Utilities Commission on June 30, 2009 the electric utility was granted an increase in South Dakota retail electric rates of $2.9 million or approximately 11.7%. The electric utility implemented final, approved rates in July 2009.

Federal

Revenue Sufficiency Guarantee (RSG) Charges —Since 2006, the electric utility has been a party to litigation before the Federal Energy Regulatory Commission (FERC) regarding the application of RSG charges to market participants who withdraw energy from the market or engage in financial-only, virtual sales of energy into the market or both. These litigated proceedings occurred in several electric rate and complaint dockets before the FERC and several of the FERC’s orders are on review before the United States Court of Appeals for the district of Columbia Circuit (D.C. Circuit).

On November 10, 2008 the FERC issued an order on the paper hearing finding the current RSG rate unjust and unreasonable and accepting an interim rate that applied RSG charges to all virtual sales until such time as MISO makes a subsequent filing of the new RSG rate. In response to RSG Compliance Order III, MISO made another compliance filing on December 8, 2008 in which it proposed to re-resettle the RSG charges and cost allocations back to market start to correct its previous resettlement completed in January 2008 that was based on the FERC’s interpretation of the RSG rate and billing determinants affirmed in RSG III. In addition to correcting the RSG rate denominator to limit it to only virtual sales associated with actual physical energy withdrawals, MISO proposed additional corrections designed to reduce the denominator. Both changes would increase the RSG rate that the electric utility must pay. Also, on November 11, 2008 the FERC issued an order on rehearing of a November 28, 2007 order on complaint. Again, where the revenue from RSG charges collected is not sufficient to make RSG payments to suppliers, MISO recovers the shortage through an uplift charge from all load.

The electric utility requested rehearing of both November 2008 orders (in conjunction with the FERC’s RSG Compliance Order III). The electric utility’s principal concern in these proceedings was to ensure that the FERC did not impose refunds prior to the August 10, 2007 refund effective date. The FERC did not impose such refunds but did offer an interpretation in support of its decision in RSG Compliance Order III (in ER04-691 docket) that would subject the electric utility to further RSG refunds and resettlements prior to August 10, 2007. Several market participants filed an Emergency Motion and Emergency Request for Stay of the FERC’s November 10, 2008 order.

On February 23, 2009 MISO filed its Redesign Proposal for allocation of RSG costs in compliance with the November 10, 2008 order. MISO anticipates an effective date at or about the third quarter of 2009. The electric utility submitted a limited protest to ask that the FERC reject all portions of MISO’s Compliance Filing that do not comply with its explicit directives in the November 10, 2008 order (in particular the RSG rate denominator change). Also on February 23, 2009 the MISO Independent Market Monitor submitted a Findings and Recommendations report to the FERC arguing that the current implementation of the RSG rate is adversely affecting the MISO markets. Shortly thereafter, DC Energy and several other parties filed a Motion to Lodge in the RSG Complaint dockets in response to the February 27, 2009 decision of the D.C. Circuit in City of Anaheim, California v. FERC. In City of Anaheim, the Court held that the FERC cannot order retroactive rate increases under section 206 of the Federal Power Act (FPA). In their Motion to Lodge, the parties noted City of Anaheim should resolve the outcome of the “refund” issue pending before the FERC on rehearing in the RSG proceeding.

On April 28, 2009, a group of eight financial market participants filed a Writ of Mandamus with the D.C. Circuit. The group asked the court to require the FERC to act on the pending requests for rehearing, order MISO to stop issuing RSG invoices for previous periods, correct all past invoices, refund with interest amounts paid by the companies, and restore trading privileges for some of the companies. The Court acted on April 29, 2009, requiring the FERC to file a response to the complaint by May 7, 2009.

On May 6, 2009 the FERC issued an order granting rehearing on certain aspects of its November 10, 2008 order. The order requires MISO to cease ongoing refunds and resettlements, as well as modify the effective date of the Interim Rate for RSG to November 10, 2008.

On June 12, 2009 the FERC issued an order on rehearing of the November 10, 2008 order. The order on rehearing, at a minimum, relieved MISO from having to resettle RSG payments resulting from any difference between the megawatt-hours associated with virtual supply in the denominator of the RSG rate and the billing determinants associated with virtual supply transactions (VSO mismatch). This relief applies to the period April 25, 2006 through November 4, 2007. Since the electric utility would have had a payment obligation associated with the virtual supply and other mismatches, the June order eliminates that payment obligation. However, the June order, like many of the other orders in this docket, is subject to appellate review and potential reversal. Beginning November 5, 2007, MISO is obligated to resettle to correct the VSO mismatch, which may impose a payment obligation on the electric utility. Whether other mismatches must be resettled will not be determined until the FERC issues orders addressing the December 2008 compliance filings. The Company does not know when these litigation proceedings will conclude.

Big Stone II Project

On June 30, 2005 the electric utility and a coalition of six other electric providers entered into several agreements for the development of a second electric generating unit, named Big Stone II, at the site of the existing Big Stone Plant near Milbank, South Dakota. The three primary agreements were the Participation Agreement, the Operation and Maintenance Agreement and the Joint Facilities Agreement, which expired on January 1, 2009 pursuant to a provision in the agreement. Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency were parties to all three agreements. In September 2007, Great River Energy and Southern Minnesota Municipal Power Agency withdrew from the project. The five remaining project participants decided to downsize the proposed plant’s nominal generating capacity from 630 megawatts to between 500 and 580 megawatts. New procedural schedules were established in the various project-related proceedings, which take into consideration the optimal plant configuration decided on by the remaining participants. NorthWestern Corporation, one of the co-owners of the existing Big Stone Plant, was an additional party to the Joint Facilities Agreement.

On January 15, 2009 the MPUC approved, by a vote of 5-0, a motion to grant the Certificate of Need and Route Permit for the Minnesota portion of the Big Stone II transmission line. The motion involved numerous elements, including the following:

	•		That there is reasonable assurance that Big Stone II would be more cost-effective than renewable energy beyond the statutory levels of renewable energy based on accepted estimates of construction costs and carbon dioxide;
	•		That the 345 kv transmission project is necessary based on identified regional and state transmission needs; and
	•		That the project presents risks requiring additional measures to protect the applicants’ ratepayers.

Therefore, the MPUC determined to grant the Certificate of Need subject to a number of additional conditions pending issuance of a final order, including but not limited to: (1) fulfilling various requirements relating to renewable energy goals, energy efficiency, community-based energy development projects and emissions reduction; (2) that the generation plant be built as a “carbon capture retrofit ready” facility; (3) that the applicants report to the MPUC on the feasibility of building the plant using ultra-supercritical technology; and (4) that the applicants achieve specific limits on construction cost at $3000/kilowatt (kW) and carbon dioxide costs at $26/ton.

On March 17, 2009 the MPUC issued its written order reflecting the decision. While construction and carbon dioxide cost caps were not formal conditions of the certificate of need issuance, the MPUC’s order notified the electric utility that the MPUC’s present intention is to shield ratepayers from construction costs exceeding the $2,600 to $3,000/kW range and carbon regulation cost exceeding $26/ton adjusted for the passage of time, including inflation.

The applicants and intervenors subsequently filed petitions for reconsideration of the MPUC order. On April 30, 2009 the MPUC denied the petitions. The intervenors filed an appeal of the Certificate of Need with the Minnesota Court of Appeals in early June 2009. The intervenors, applicants and the MPUC filed briefs in July and early August 2009.

The Certificate of Need and Route Permit are required by state law and would allow the Big Stone II utilities to construct and upgrade 112 miles of electric transmission lines in western Minnesota for delivery of power from the Big Stone site and from numerous other planned generation projects, most of which are wind energy.

The electric utility’s integrated resource plan (IRP) includes generation from Big Stone II beginning in 2013 to accommodate load growth and to replace expiring purchased power contracts and older coal-fired base-load generation units scheduled for retirement. On June 5, 2008 the MPUC deferred approval of the electric utility’s 2006-2020 IRP, originally filed in 2005. The addition of 160 megawatts of wind generation in the IRP was approved early in 2007 and, on January 15, 2009, the MPUC approved the electric utility’s 2006-2020 IRP in its entirety. On June 2, 2009 the MPUC issued an order denying reconsideration. This 2006-2020 IRP includes new renewable wind generation and significant demand-side management including conservation, new baseload including the proposed Big Stone II power plant, natural gas-fired peaking plants and wholesale energy purchases.

On August 27, 2008 the NDPSC determined the electric utility’s participation in Big Stone II was prudent in a range of 121.8 to 130 megawatts. The NDPSC decision has been appealed to Burleigh County District Court by interveners in the matter.

On November 20, 2008 the South Dakota Board of Minerals and Environment (Board) unanimously approved the Big Stone II participating utilities’ application for a Prevention of Significant Deterioration (PSD) permit for Big Stone II and a proposed Title V Operating Permit for the Big Stone site. A PSD permit is a pre-construction permit designed to protect air quality. Joint petitioners Sierra Club and Clean Water Action appealed the administrative decision on the PSD permit to the Circuit Court of Hughes County. In July 2009, the parties entered into a stipulation dismissing the appeal with prejudice. The issuance of the Title V permit is subject to review by the U.S. Environmental Protection Agency (EPA). On January 22, 2009, the EPA filed a formal objection to the proposed Title V permit. The State of South Dakota revised and submitted a proposed permit in response to the EPA’s objection. In a hearing before the Board held on April 20 and 21, 2009 in Pierre, South Dakota, the Board again directed issuance of the Title V permit if the EPA did not object within its review period. The EPA did not file any comments or objections and the South Dakota Department of Environment and Natural Resources issued the permit on June 9, 2009. On August 3, 2009 the Sierra Club and Clean Water Action petitioned the EPA to object to the Title V permit.

The Big Stone II federal EIS process led by the Western Area Power Administration (WAPA) continues to move forward. WAPA and its third party subcontractor completed the Final EIS, which included comments on the Draft EIS and the Supplemental Draft EIS, and responses to those comments. Notice of Availability of the EIS was published in the Federal Register on June 26, 2009. WAPA can issue a final Record of Decision (ROD) at the conclusion of a 30-day waiting period following publication of the NOA, which ended on July 27, 2009. Financial close, which requires the participants to provide binding financial commitments to support their share of costs, is to occur 90 days after the EIS ROD. No one can predict the exact outcome of any of these proceedings.

The delays in approval of the Big Stone II transmission Certificate of Need in Minnesota and issuance of required permits may delay the availability of Big Stone II as a generation resource. Also, the electric utility had experienced more rapid load growth than was expected since originally filing the IRP in 2005. The electric utility is assessing ways in which to address this potential near-term generation shortfall and has received approval from the MPUC to immediately acquire up to 110 megawatts of peaking capacity.

As of June 30, 2009 the electric utility has capitalized $12.8 million in costs related to the planned construction of Big Stone II. If the project is abandoned for permitting or other reasons, a portion of these capitalized costs and others incurred in future periods may be subject to expense and may not be recoverable.

4. 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)		2009				2008
Regulatory Assets:
Unrecognized Prior Service Costs and Actuarial Losses on Pension Benefits		$	63,868			$	64,490
Deferred Income Taxes			6,392				7,094
Minnesota Renewable Resource Rider Accrued Revenues			4,846				3,045
Debt Reacquisition Premiums			3,191				3,357
Accumulated ARO Accretion/Depreciation Adjustment			1,596				1,437
Minnesota General Rate Case Recoverable Expenses			1,472				1,457
North Dakota Renewable Resource Rider Accrued Revenues			1,165				2,009
Accrued Cost-of-Energy Revenue			736				8,982
MISO Schedule 16 and 17 Deferred Administrative Costs — ND			686				823
Deferred Marked-to-Market Losses			629				1,162
MISO Schedule 16 and 17 Deferred Administrative Costs — MN			389				526
Deferred Holding Company Formation Costs			180				—
Plant Acquisition Costs			41				63
Deferred Conservation Improvement Program Costs			(95	)			280
Total Regulatory Assets		$	85,096			$	94,725
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs		$	59,654			$	58,768
Deferred Income Taxes			4,602				4,943
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Gains on Other Postretirement Benefits			1,082				834
Deferred Marked-to-Market Gains			326				—
Gain on Sale of Division Office Building			137				139
Total Regulatory Liabilities		$	65,801			$	64,684
Net Regulatory Asset Position		$	19,295			$	30,041

The regulatory asset related to prior service costs and actuarial losses on pension benefits and the regulatory liability related to the unrecognized transition obligation, prior service costs and actuarial gains on other postretirement benefits represents benefit costs and actuarial gains subject to recovery or return through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial gains were required to be recognized as components of Accumulated Other Comprehensive Income in equity under SFAS No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, but were determined to be eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with SFAS No. 109, Accounting for Income Taxes.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying 2008 and 2009 renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of June 30, 2009. Minnesota Renewable Resource Rider Accrued Revenues are expected to be recovered over 57 months, from July 2009 through March 2014.

Debt Reacquisition Premiums included in Unamortized Debt Expense are being recovered from electric utility customers over the remaining original lives of the reacquired debt issues, the longest of which is 23.3 years.

The Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

Minnesota General Rate Case Recoverable Expenses will be recovered over the next 31 months.

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying 2008 and 2009 renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of June 30, 2009. North Dakota Renewable Resource Rider Accrued Revenues are expected to be recovered over 54 months, from July 2009 through January 2014.

Accrued Cost-of-Energy Revenue included in Accrued Utility and Cost-of-Energy Revenues will be recovered over the next 14 months.

MISO Schedule 16 and 17 Deferred Administrative Costs — ND will be recovered over the next 30 months.

All Deferred Marked-to-Market Gains and Losses recorded as of June 30, 2009 are related to forward purchases of energy scheduled for delivery through April 2013.

MISO Schedule 16 and 17 Deferred Administrative Costs — MN will be recovered over the next 17 months.

Deferred Holding Company Formation Costs will be amortized over the next 5 years.

Plant Acquisition Costs will be amortized over the next 11 months.

Deferred Conservation Program Costs represent mandated conservation expenditures and incentives recoverable through retail electric rates over the next 12 months.

The Accumulated Reserve for Estimated Removal Costs is reduced as actual removal costs are incurred.

The remaining regulatory liabilities 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.

5. Forward Contracts Classified as Derivatives

Electricity Contracts

All of the electric utility’s wholesale purchases and sales of energy under forward contracts that do not meet the definition of capacity contracts are considered derivatives subject to mark-to-market accounting. The electric utility’s objective in entering into forward contracts for the purchase and sale of energy is to optimize the use of its generating and transmission facilities and leverage its knowledge of wholesale energy markets in the region to maximize financial returns for the benefit of both its customers and shareholders. The electric utility’s intent in entering into certain of these contracts is to settle them through the physical delivery of energy when physically possible and economically feasible. The electric utility also enters into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales.

As of June 30, 2009 the electric utility had recognized, on a pretax basis, $171,000 in net unrealized gains on open forward contracts for the purchase and sale of electricity. 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 or brokers used by the electric utility’s power services’ personnel responsible for contract pricing, as well as prices gathered from daily settlement prices published by the Intercontinental Exchange. For certain contracts, prices at illiquid trading points are based on a basis spread between that

trading point and more liquid trading hub prices. Prices are benchmarked to forward price curves and indices acquired from a third party price forecasting service. The fair value measurements of these forward energy contracts fall into level 2 of the fair value hierarchy set forth in SFAS No. 157.

The following tables show the effect of marking to market forward contracts for the purchase and sale of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of June 30, 2009 and December 31, 2008, and the change in the Company’s consolidated balance sheet position from December 31, 2008 to June 30, 2009:

(in thousands)		June 30, 2009				December 31, 2008
In Other Current Assets — Marked-to-Market Gain		$	3,595			$	405
In Regulatory Assets and Other Deferred Debits — Deferred Marked-to-Market Loss			629				1,162
In Other Accrued Current Liabilities - Marked-to-Market Loss			(3,727	)			(1,690	)
In Regulatory Liabilities — Deferred Marked-to-Market Gain			(326	)			—
Net Fair Value of Marked-to-Market Energy Contracts		$	171			$	(123	)

		Year-to-Date
(in thousands)		June 30, 2009
Fair Value at Beginning of Year		$	(123	)
Less: Amount Realized on Contracts Entered into in 2008 and Settled in 2009			123
Changes in Fair Value of Contracts Entered into in 2008			—
Net Fair Value of Contracts Entered into in 2008 at End of Period			—
Changes in Fair Value of Contracts Entered into in 2009			171
Net Fair Value End of Period		$	171

Realized and unrealized net gains (losses) on forward energy contracts of $140,000 for the three months ended June 30, 2009, $1,174,000 for the six months ended June 30, 2009, ($31,000) for the three months ended June 30, 2008 and $2,219,000 for the six months ended June 30, 2008 are included in electric operating revenues on the Company’s consolidated statements of income.

The electric utility has credit risk associated with the nonperformance or nonpayment by counterparties to its forward energy purchases and sales agreements. The electric utility has 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. The credit risk with the largest counterparty on delivered and marked-to-market forward contracts as of June 30, 2009 was $2,156,000. As of June 30, 2009 the net credit risk exposure was $5,965,000 from ten counterparties with investment grade credit ratings and two counterparties that have not been rated by an external credit rating agency but have been evaluated internally and assigned an internal credit rating equivalent to investment grade. The electric utility had no exposure at June 30, 2009 to counterparties with credit ratings below investment grade. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). The $5,965,000 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, 2009. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

The mark-to-market losses of certain of the Company’s derivative energy contracts included in the $3,727,000 derivative liability on June 30, 2009 are covered by deposited funds. The aggregate fair value of these derivative liabilities on June 30, 2009 was $1,472,000. Certain other of the Company’s derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on the Company’s debt. If the Company’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request immediate and ongoing full overnight collateralization on contracts in net liability positions. The Company had no forward energy derivative contracts with credit-risk-related contingent features in a liability position on June 30, 2009.

Fuel Contracts

In order to limit its exposure to fluctuations in future prices of natural gas and fuel oil, IPH entered into contracts with its fuel suppliers in August 2008 and January 2009 for firm purchases of natural gas and fuel oil to cover portions of its anticipated natural gas needs in Ririe, Idaho and Center, Colorado from September 2008 through August 2009 and its fuel oil needs in Souris, Prince Edward Island, Canada from January 2009 through August 2009 at fixed prices. These contracts qualify for the normal purchase exception to mark-to-market accounting under SFAS No. 133, as amended by SFAS No. 138.

Foreign Currency Exchange Forward Windows

The Canadian operations of IPH records its sales and carries its receivables in U.S. dollars but pays its expenses for goods and services consumed in Canada in Canadian dollars. The payment of its bills in Canada requires the periodic exchange of U.S. currency for Canadian currency. In order to lock in acceptable exchange rates and hedge its exposure to future fluctuations in foreign currency exchange rates between the U.S. dollar and the Canadian dollar, IPH’s Canadian subsidiary entered into forward contracts for the exchange of U.S. dollars into Canadian dollars in 2008. Each monthly contract was for the exchange of $400,000 U.S. dollars for the amount of Canadian dollars stated in each contract. The following table lists the contracts outstanding as of June 30, 2009:

(in thousands)		Settlement Periods		USD				CAD
Contracts entered into in July 2008		July 2009		$	400			$	417
Contracts entered into in October 2008		July 2009 — October 2009			1,600				1,999
Contracts outstanding on June 30, 2009		July 2009 — October 2009		$	2,000			$	2,416

The following tables show the effect of marking to market IPH’s foreign currency exchange forward windows and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of June 30, 2009 and December 31, 2008, and the change in the Company’s consolidated balance sheet position from December 31, 2008 to June 30, 2009:

(in thousands)		June 30, 2009				December 31, 2008
Fair Value of IPH Foreign Currency Exchange Forward Windows included in:
Other Current Assets		$	120			$	—
Other Accrued Current Liabilities			(42	)			(289	)
Net Fair Value of Foreign Currency Exchange Forward Windows		$	78			$	(289	)

		Year-to-Date
(in thousands)		June 30, 2009
Fair Value at Beginning of Year		$	(289	)
Less: Amount Realized on Contracts Entered into in 2008 and Settled in 2009			277
Changes in Fair Value of Contracts Entered into in 2008			90
Net Fair Value of Contracts Entered into in 2008 at End of Period			78
Changes in Fair Value of Contracts Entered into in 2009			—
Net Fair Value End of Period		$	78

These contracts are derivatives subject to mark-to-market accounting. IPH does not enter into these contracts for speculative purposes or with the intent of early settlement, but for the purpose of locking in acceptable exchange rates and hedging its exposure to future fluctuations in exchange rates with the intent of settling these contracts during their stated settlement periods and using the proceeds to pay its Canadian liabilities when they come due. These contracts do not qualify for hedge accounting treatment because the timing of their settlements did not and will not coincide with the payment of specific bills or existing contractual obligations. The foreign currency exchange forward contracts outstanding as of June 30, 2009 were valued and marked to market on June 30, 2009 based on quoted exchange values on June 30, 2009. Realized and unrealized net gains on IPH’s foreign currency exchange forward windows of $234,000 for the three months ended June 30, 2009 and $90,000 for the six months ended June 30, 2009 are included in other income on the Company’s consolidated statements of income.

The fair value measurements of the above foreign currency exchange forward windows fall into level 1 of the fair value hierarchy set forth in SFAS No. 157.

6. Common Shares and Earnings Per Share

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2008 through June 30, 2009:

Common Shares Outstanding, December 31, 2008			35,384,620
Issuances:
Dividend Reinvestment Plan — Dividend Purchases			59,538
Executive Officer Stock Performance Awards			29,350
Restricted Stock Issued to Nonemployee Directors			28,800
Restricted Stock Issued to Employees			27,600
Dividend Reinvestment Plan — Direct Purchases			26,181
Employee Stock Purchase Plan — Dividend Reinvestment			5,859
Vesting of Restricted Stock Units			5,350
Stock Options Exercised			1,350
Retirements:
Shares Withheld for Individual Income Tax Requirements			(10,183	)
Common Shares Outstanding, June 30, 2009			35,558,465

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

Excluded from the calculation of diluted earnings per share are the following outstanding stock options which had exercise prices greater than the average market price for the three-month and six-month periods ended June 30, 2009 and 2008:

Three Months Ended June 30,		Options Outstanding		Range of Exercise Prices
2009		419,460		$24.93 — $31.34
2008		—		NA

Six Months Ended June 30,		Options Outstanding		Range of Exercise Prices
2009		419,460		$24.93 — $31.34
2008		—		NA

7. Share-Based Payments

The Company has five share-based payment programs.

On April 20, 2009 the Company’s Board of Directors granted 29,515 restricted stock units to key employees under the 1999 Stock Incentive Plan, as amended (Incentive Plan), payable in common shares on April 8, 2013, the date the units vest. The grant date fair value of each restricted stock unit was $18.86 per share determined under a Monte Carlo valuation method based on the market value of the Company’s common stock on April 20, 2009.

On April 20, 2009 the Company’s Board of Directors granted 28,800 shares of restricted stock to the Company’s nonemployee directors and 27,600 shares of restricted stock to the Company’s executive officers under the Incentive Plan. The restricted shares vest 25% per year on April 8 of each year in the period 2010 through 2013 and are eligible for full dividend and voting rights. The grant date fair value of each share of restricted stock was $22.15 per share, the average market price on the date of grant.

On April 20, 2009 the Company’s Board of Directors granted performance share awards to the Company’s executive officers under the Incentive Plan. Under these awards, the Company’s executive officers could earn up to an aggregate of 181,200 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance period of January 1, 2009 through December 31, 2011. The aggregate target share award is 90,600 shares. Actual payment may range from zero to 200% of the target amount. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance period. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under SFAS No. 123(R), and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.

As of June 30, 2009 the remaining unrecognized compensation expense related to stock-based compensation was approximately $7.9 million (before income taxes) which will be amortized over a weighted-average period of 2.4 years.

Amounts of compensation expense recognized under the Company’s five stock-based payment programs for the three-month and six-month periods ended June 30, 2009 and 2008 are presented in the table below:

		Three months ended								Six months ended
		June 30,								June 30,
(in thousands)		2009				2008				2009				2008
Employee Stock Purchase Plan (15% discount)		$	72			$	65			$	162			$	135
Restricted Stock Granted to Directors			143				132				254				240
Restricted Stock Granted to Employees			111				121				202				239
Restricted Stock Units Granted to Employees			148				144				269				238
Stock Performance Awards Granted to Executive Officers			787				784				1,222				1,124
Totals		$	1,261			$	1,246			$	2,109			$	1,976

9. Commitments and Contingencies

Electric Utility Coal Contract

In March 2009, the electric utility entered into an agreement for the purchase of coal to cover a portion of its current coal requirements in 2009 and 2010 with a minimum purchase commitment totaling approximately $9,500,000. The Fuel Clause Adjustment mechanism in retail electric rates lessens the risk of loss from market price changes because it provides for recovery of most fuel costs.

Dealer Floor Plan Financing

Under ShoreMaster’s floor plan financing agreement with GE Commercial Distribution Finance Corporation (CDF), ShoreMaster is required to repurchase new and unused inventory repossessed from ShoreMaster’s dealers by CDF to satisfy dealer obligations to CDF. ShoreMaster has agreed to unconditionally guarantee to CDF all current and future liabilities which any dealer owes to CDF under this agreement. Any amounts due under this guaranty will be payable despite impairment or unenforceability of CDF’s security interest with respect to inventory that may prevent CDF from repossessing the inventory. The aggregate total of amounts owed by dealers to CDF under this agreement was $3.9 million on June 30, 2009. ShoreMaster has incurred no losses under this agreement. The Company believes current available cash and cash generated from operations provide sufficient funding in the event there is a requirement to perform under this agreement. CDF exercised its right under this agreement to terminate the agreement effective February 28, 2009. The termination of the agreement has no affect on ShoreMaster’s obligations to CDF for any products financed, advances made or approvals granted by CDF under the agreement prior to the effective termination date. Additionally, ShoreMaster is liable for any expenses incurred by CDF after the effective termination date in connection with the collection of any amounts or other charges as set forth in the agreement.

Sierra Club Complaint

On June 10, 2008 the Sierra Club filed a complaint in the U.S. District Court for the District of South Dakota (Northern Division) against the Company and two other co-owners of Big Stone Generating Station (Big Stone). The complaint alleged certain violations of the Prevention of Significant Deterioration and New Source Performance Standards (NSPS) provisions of the Clean Air Act and certain violations of the South Dakota State Implementation Plan (South Dakota SIP). The action further

alleged the defendants modified and operated Big Stone without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. The Sierra Club alleged the defendants’ actions have contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. The Sierra Club sought both declaratory and injunctive relief to bring the defendants into compliance with the Clean Air Act and the South Dakota SIP and to require the defendants to remedy the alleged violations. The Sierra Club also seeks unspecified civil penalties, including a beneficial mitigation project. The Company believes these claims are without merit and that Big Stone was and is being operated in compliance with the Clean Air Act and the South Dakota SIP.

The defendants filed a motion to dismiss the Sierra Club complaint on August 12, 2008. On March 31, 2009 and April 6, 2009, the U.S. District Court for the District of South Dakota (Northern Division) issued a Memorandum and Order and Amended Memorandum and Order, respectively, granting the defendants’ motion to dismiss the Sierra Club complaint. On April 17, 2009 the Sierra Club filed a motion for reconsideration of the Amended Memorandum Opinion and Order. The Sierra Club motion was opposed by the defendants. The Sierra Club motion for reconsideration was denied on July 22, 2009. On July 31, 2009 the Sierra Club filed a notice of appeal to the 8th U.S. Circuit Court of Appeals. The ultimate outcome of this matter cannot be determined at this time.

Product Recall

Aviva Sports, Inc. (Aviva), a subsidiary of ShoreMaster, markets a variety of consumer products to catalog companies and internet based retailers. Some of these products are regulated by the U.S. Consumer Product Safety Commission (CPSC). On February 3, 2009 Aviva received a report of consumer contacts from a catalog customer related to one of Aviva’s trampoline products. Aviva has not received any personal injury claims or lawsuits related to this product. Aviva submitted notification of the complaints to the CPSC and voluntarily agreed to undertake a recall of approximately 12,000 of the trampoline products. ShoreMaster recorded a liability and operating expense of $1.4 million related to the recall in the first quarter of 2009. The expense includes a projected 50% customer response rate on the recall request, fees to the third party recall administrator, costs to destroy inventory and all legal and administration fees. The customer response rate was 43.5% as of the end of July 2009.

The Company is a party to litigation arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of June 30, 2009 will not be material.

10. Short-Term and Long-Term Borrowings

Term Loan Agreement

On May 22, 2009, Otter Tail Corporation, d/b/a Otter Tail Power Company (now known as Otter Tail Power Company) entered into a Term Loan Agreement (the Loan Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, KeyBank National Association, as syndication agent, Union Bank, N.A., as documentation agent, and the banks named therein. The Loan Agreement provides for a $75 million term loan to Otter Tail Power Company due May 20, 2011, which was fully drawn on May 22, 2009.

Borrowings under the Loan Agreement bear interest at a rate equal to the base rate in effect from time to time. The base rate is a fluctuating rate per annum equal to (i) the highest of (A) JPMorgan Chase Bank, N.A.’s prime rate, (B) the Federal funds effective rate plus 0.5% per annum, and (C) a daily LIBOR rate plus 1.0% per annum, plus (ii) a margin of 1.5% to 3.0% determined on the basis of Otter Tail Power Company’s senior unsecured credit ratings, as provided in the Loan Agreement. At Otter Tail Power Company’s option, the interest rate on outstanding borrowings may be converted to a LIBOR rate that would fluctuate based on the rate at which deposits of U.S. dollars in the London interbank market are quoted, plus a margin of 2.5% to 4.0% determined on the basis of Otter Tail Power Company’s senior unsecured credit ratings, as provided in the Loan Agreement. Otter Tail Power Company is using the proceeds borrowed under the Loan Agreement to support its working capital needs and other capital requirements, including construction of the Luverne Wind Farm in North Dakota. The interest rate on borrowings under the Loan Agreement was 3.81% at June 30, 2009.

The Loan Agreement contains a number of restrictions on the business of Otter Tail Power Company, including restrictions on its ability to merge, sell assets, make certain investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The Loan Agreement also contains certain financial covenants. Specifically, Otter Tail Power Company must not permit the ratio of its “Interest-bearing Debt” to “Total Capitalization” (each as defined in the Loan Agreement) to be greater than 0.60 to 1.00, or permit its “Interest and Dividend Coverage Ratio” (as defined in the Loan Agreement) for any period of four consecutive fiscal quarters to be less than 1.50 to 1.00. The Loan Agreement also contains affirmative covenants and events of default. The Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in Otter Tail Power Company’s credit ratings. The obligations of Otter Tail Power Company under the Term Loan Agreement are unsecured. Since completion of the Company’s holding company formation on July 1, 2009, the Loan Agreement is an obligation of Otter Tail Power Company. See Note 19 - Subsequent Events.

Debt Retirement

In June 2009, the Company paid $3,493,000 to retire early its Lombard US Equipment Finance Note due October 2, 2010. No penalty was paid for early retirement of the note.

Amendments to Note Purchase Agreements

In connection with Otter Tail Corporation’s holding company reorganization on July 1, 2009, amendments to the following note purchase agreements were entered into in order to obtain the consent of the related noteholders to the reorganization.

Fourth Amendment to 2001 Note Purchase Agreement

On June 30, 2009 Otter Tail Corporation (now known as Otter Tail Power Company) (Old Otter Tail) entered into a Fourth Amendment dated as of June 30, 2009 to Note Purchase Agreement dated as of December 1, 2001 (the Fourth Amendment) with the holders of the 2001 Notes referred to below, amending the Note Purchase Agreement dated as of December 1, 2001 among Old Otter Tail and each of the purchasers named on Schedule A attached thereto, as amended (the 2001 Note Purchase Agreement). The 2001 Note Purchase Agreement relates to the issuance and sale by Old Otter Tail, in a private placement transaction, of its $90,000,000 6.63% Senior Notes due December 1, 2011 (the 2001 Notes). The Fourth Amendment sets forth the terms and conditions of the 2001 Noteholders’ consent to the holding company reorganization and amends certain provisions of the 2001 Note Purchase Agreement, both in connection with the holding company reorganization and for the purpose of achieving greater consistency among Old Otter Tail’s note purchase agreements. These amendments include changes to negative covenants in the 2001 Note Purchase Agreement regarding limitations on liens and contingent liabilities, and to events of default. As provided in the Fourth Amendment, the 2001 Note Purchase Agreement and the 2001 Notes remained obligations of Old Otter Tail, under the name Otter Tail Power Company, following the effectiveness of the holding company reorganization. In addition, the guaranties issued by certain subsidiaries of Old Otter Tail under the 2001 Note Purchase Agreement and the 2001 Notes were released on the effectiveness of the holding company reorganization.

Third Amendment to 2007 Note Purchase Agreement

On June 26, 2009 Old Otter Tail entered into a Third Amendment dated as of June 26, 2009 to Note Purchase Agreement dated as of August 20, 2007 (the Third Amendment) with the holders of the 2007 Notes referred to below, amending the Note Purchase Agreement dated as of August 20, 2007 among Old Otter Tail and each of the purchasers party thereto, as amended (the 2007 Note Purchase Agreement). The 2007 Note Purchase Agreement relates to the issuance and sale by Old Otter Tail of $155 million aggregate principal amount of Old Otter Tail’s Senior Unsecured Notes in four series, in the designations and aggregate principal amounts set forth in the 2007 Note Purchase Agreement (the 2007 Notes). The Third Amendment sets forth the terms and conditions of the 2007 Noteholders’ consent to the holding company reorganization and also amends certain provisions of the 2007 Note Purchase Agreement, both in connection with the holding company reorganization and for the purpose of achieving greater consistency among Old Otter Tail’s note purchase agreements. These amendments include changes to negative covenants in the 2007 Note Purchase Agreement regarding limitations on liens and subsidiary guarantees. As provided in the Third Amendment, the 2007 Note Purchase Agreement and the 2007 Notes remained obligations of Old Otter Tail, under the name Otter Tail Power Company, following the effectiveness of the holding company reorganization.

Amendment No. 2 to Cascade Note Purchase Agreement

On June 30, 2009 Old Otter Tail entered into an Amendment No. 2 dated as of June 30, 2009 to Note Purchase Agreement dated as of February 23, 2007 (Amendment No. 2) with Cascade Investment, L.L.C. (Cascade), amending the Note Purchase Agreement dated as of February 23, 2007 between Old Otter Tail and Cascade, as amended (the Cascade Note Purchase

Agreement). The Cascade Note Purchase Agreement relates to the issuance and sale by Old Otter Tail to Cascade, in a private placement transaction, of Old Otter Tail’s $50,000,000 5.778% Senior Note due November 30, 2017 (the Cascade Note). Amendment No. 2 sets forth the terms and conditions of Cascade’s consent to the assignment by Old Otter Tail of its rights and obligations in, to and under the Cascade Note Purchase Agreement and the Cascade Note to Otter Tail Holding Company, the new parent holding company of Old Otter Tail that is now known as Otter Tail Corporation (the Company), effective immediately prior to the effectiveness of the holding company reorganization. Amendment No. 2 also provides for Cascade’s consent to the holding company reorganization, and amends certain provisions of the Cascade Note Purchase Agreement, both in connection with the holding company reorganization and for the purpose of achieving greater consistency among the Company’s note purchase agreements. These amendments include changes to negative covenants in the Cascade Note Purchase Agreement regarding limitations on liens, contingent liabilities and to events of default. In addition, Amendment No. 2 provides for an additional financial covenant applicable to the Company as of the effectiveness of the holding company reorganization. Specifically, the Company may not permit the aggregate principal amount of all debt of Otter Tail Power Company and its subsidiaries to exceed 60% of Otter Tail Consolidated Total Capitalization (as defined in the Cascade Note Purchase Agreement, as amended by Amendment No. 2), determined as of the end of each fiscal quarter of the Company. In addition, the interest rate applicable to the Cascade Note was increased to 8.89% per annum which is reflective of the Company’s new senior unsecured debt ratings. The obligations of the Company under the Cascade Note Purchase Agreement and the Cascade Notes continue to be guaranteed by Varistar Corporation and certain of its subsidiaries. As provided in Amendment No. 2, the Cascade Note Purchase Agreement and the Cascade Notes became obligations of the Company immediately prior to the effectiveness of the holding company reorganization.

Financial Covenants

Following the Company’s holding company reorganization on July 1, 2009 the Company’s borrowing agreements are subject to certain financial covenants. Specifically:

	•		Under the credit agreement relating to the $200 million credit facility of the Company (as assignee of Varistar Corporation), the Company may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), as provided in the credit agreement.
	•		Under the Cascade Note Purchase Agreement, the Company may not permit its Consolidated Debt to exceed 60% of Consolidated Total Capitalization or its Interest Charges Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), permit the Debt of Otter Tail Power Company to exceed 60% of Otter Power Consolidated Total Capitalization, or permit the Priority Debt of Varistar and its subsidiaries to exceed 20% of Varistar Consolidated Total Capitalization, as provided in the Cascade Note Purchase Agreement.
	•		Under the Loan Agreement and the credit agreement relating to Otter Tail Power Company’s $170 million credit facility, Otter Tail Power Company may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, as provided in the Loan Agreement.
	•		Under the 2001 Note Purchase Agreement, the 2007 Note Purchase Agreement and the financial guaranty insurance policy with Ambac Assurance Corporation relating to certain pollution control refunding bonds, Otter Tail Power Company may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio (or, in the case of the 2001 Note Purchase Agreement, its Interest Charges Coverage Ratio) to be less than 1.50 to 1.00, in each case as provided in the related borrowing or insurance agreement. In addition, under the 2001 Note Purchase Agreement and the 2007 Note Purchase Agreement, Otter Tail Power Company may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement.

11. Class B Stock Options of Subsidiary

As of June 30, 2009 there were 912 options for the purchase of IPH Class B common shares outstanding with a combined exercise price of $683,000, of which 732 options were “in-the-money” with a combined exercise price of $307,000.

12. 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)		2009				2008				2009				2008
Service Cost—Benefit Earned During the Period		$	1,133			$	1,275			$	2,266			$	2,550
Interest Cost on Projected Benefit Obligation			2,975				2,800				5,950				5,600
Expected Return on Assets			(3,448	)			(3,550	)			(6,896	)			(7,100	)
Amortization of Prior-Service Cost			181				175				362				350
Amortization of Net Actuarial Loss			5				125				10				250
Net Periodic Pension Cost		$	846			$	825			$	1,692			$	1,650

The Company did not make a contribution to its pension plan in the six months ended June 30, 2009 and is not currently required to make a contribution in 2009.

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)		2009				2008				2009				2008
Service Cost—Benefit Earned During the Period		$	188			$	173			$	376			$	346
Interest Cost on Projected Benefit Obligation			424				384				848				768
Amortization of Prior-Service Cost			18				16				36				32
Amortization of Net Actuarial Loss			96				120				192				240
Net Periodic Pension Cost		$	726			$	693			$	1,452			$	1,386

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)		2009				2008				2009				2008
Service Cost—Benefit Earned During the Period		$	301			$	300			$	602			$	600
Interest Cost on Projected Benefit Obligation			753				725				1,506				1,450
Amortization of Transition Obligation			187				187				374				374
Amortization of Prior-Service Cost			53				50				106				100
Amortization of Net Actuarial Loss			1				125				2				250
Effect of Medicare Part D Expected Subsidy			(297	)			(400	)			(594	)			(800	)
Net Periodic Postretirement Benefit Cost		$	998			$	987			$	1,996			$	1,974

15. Income Taxes

The Company’s effective income tax rate for the three months ended June 30, 2009 was lower than the effective tax rate for the three months ended June 30, 2008. The reduction from the federal statutory rate mainly reflects the benefit of production tax credits (PTCs) and North Dakota wind energy credits related to the electric utility’s wind projects of approximately $1.8 million in the second quarter of 2009 and $0.9 million in the second quarter of 2008.

The Company’s effective income tax rate for the six months ended June 30, 2009 was lower than the effective tax rate for the six months ended June 30, 2008. The reduction from the federal statutory rate mainly reflects the benefit of PTCs and North Dakota wind energy credits related to the electric utility’s wind projects of approximately $3.9 million in the first six months of 2009 and $1.5 million in the first six months of 2008.

The Company recognizes PTCs as wind energy is generated and sold based on a per kilowatt-hour rate prescribed in applicable federal statutes, which may differ significantly from amounts computed, on a quarterly basis, using an overall effective income tax rate anticipated for the full year. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years. The Company utilizes this method of recognizing PTCs for specific reasons, including that PTCs are an integral part of the financial viability of most wind projects and a fundamental component of such wind projects’ results of operations.

19. Subsequent Events

On July 1, 2009 Otter Tail Corporation completed a holding company reorganization in accordance with Section 302A.626 of the Minnesota Business Corporation Act (the MBCA) whereby Otter Tail Power Company (also referred to as Old Otter Tail), which had previously been operated as a division of Otter Tail Corporation, became a wholly owned subsidiary of the new parent holding company named Otter Tail Corporation (formerly known as Otter Tail Holding Company).

The new holding company structure was effected as of 12:00 a.m. Central Time on July 1, 2009 pursuant to a Plan of Merger dated as of June 30, 2009 (the Plan of Merger), by and among Old Otter Tail, Otter Tail Holding Company (now known as Otter Tail Corporation), a Minnesota corporation and, prior to the reorganization a direct subsidiary of Old Otter Tail, and Otter Tail Merger Sub Inc., a Minnesota corporation and indirect subsidiary of Old Otter Tail and direct subsidiary of Otter Tail Holding Company (Merger Sub). The Plan of Merger provided for the merger (the Merger) of Old Otter Tail with Merger Sub, with Old Otter Tail as the surviving corporation. Pursuant to Section 302A.626 (subd. 2) of the MBCA shareholder approval was not required for the Merger. As a result of the Merger, Old Otter Tail is now a wholly owned subsidiary of the Company with the name Otter Tail Power Company. Immediately following the completion of the Merger, the Company changed its name from Otter Tail Holding Company to Otter Tail Corporation.

In the Merger, each issued and outstanding common share of Old Otter Tail was converted into one common share of the Company, par value $5 per share, and each issued and outstanding cumulative preferred share of Old Otter Tail was converted into one cumulative preferred share of the Company having the same designations, rights, powers and preferences. In connection with the Merger, each person that held rights to purchase, or other rights to or interests in, common shares of Old Otter Tail under any stock option, stock purchase or compensation plan or arrangement of Old Otter Tail immediately prior to the Merger holds a corresponding number of rights to purchase, and other rights to or interests in, common shares of the Company, par value $5 per share, immediately following the Merger.

The conversion of the common shares in the Merger occurred without an exchange of certificates. Accordingly, certificates formerly representing outstanding common shares of Old Otter Tail are deemed to represent the same number of common shares of the Company.

Pursuant to Section 302A.626 (subd. 7) of the MBCA, the provisions of the Restated Articles of Incorporation and Restated Bylaws of the Company are consistent with those of Old Otter Tail prior to the Merger. The authorized common shares and cumulative preferred shares of the Company, the designations, rights, powers and preferences of such shares and the qualifications, limitations and restrictions thereof are also consistent with those of Old Otter Tail’s common shares and cumulative preferred shares immediately prior to the Merger. The directors and executive officers of the Company are the same individuals who were directors and executive officers, respectively, of Old Otter Tail immediately prior to the Merger.

Immediately prior to the Merger, Old Otter Tail transferred to the Company by means of assignment the capital stock of its direct subsidiaries and all of its other assets not specific to the operation of the electric utility business. As a result, the Company is a holding company with two primary subsidiaries, Otter Tail Power Company (the electric utility) and Varistar Corporation (a holding company for the nonelectric utility businesses).

The following table provides a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of July 1, 2009.

		Otter Tail												Otter Tail
		Power								Otter Tail				Corporation
(in thousands)		Company				Varistar				Corporation				Consolidated
Lines of Credit		$	19,914							$	100,000			$	119,914
Term Loan, Variable 3.81% at July 1, 2009, due May 20, 2011		$	75,000											$	75,000
Senior Unsecured Notes 6.63%, due December 1, 2011			90,000												90,000
Pollution Control Refunding Revenue Bonds, Variable, 3.50% at July 1, 2009, due December 1, 2012			10,400												10,400
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017			33,000												33,000
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017			5,165												5,165
Senior Unsecured Note 8.89%, due November 30, 2017										$	50,000				50,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022			30,000												30,000
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022			20,580												20,580
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027			42,000												42,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037			50,000												50,000
Obligations of Varistar Corporation — Various up to 8.25% at July 1, 2009						$	7,289								7,289
Total		$	356,145			$	7,289			$	50,000			$	413,434
Less:
Current Maturities			—				1,242				—				1,242
Unamortized Debt Discount			—				357				—				357
Total Long-Term Debt		$	356,145			$	5,690			$	50,000			$	411,835
Total Short-Term and Long-Term Debt (with current maturities)		$	376,059			$	6,932			$	150,000			$	532,991

The Company has evaluated events occurring through August 6, 2009 and determined there are no other events that have occurred subsequent to June 30, 2009 that would affect the Company’s financial statements as of, and for the periods ending, June 30, 2009, or require additional disclosure in this report on Form 10-Q.

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

RESULTS OF OPERATIONS

Following is an analysis of our operating results by business segment for the three and six months ended June 30, 2009 and 2008, followed by our outlook for the remainder of 2009 and a discussion of changes in our consolidated financial position during the six months ended June 30, 2009.

Comparison of the Three Months Ended June 30, 2009 and 2008

Consolidated operating revenues were $246.9 million for the three months ended June 30, 2009 compared with $323.6 million for the three months ended June 30, 2008. Operating income was $6.2 million for the three months ended June 30, 2009 compared with $10.3 million for the three months ended June 30, 2008. The Company recorded diluted earnings per share of $0.07 for the three months ended June 30, 2009 compared with $0.11 for the three months ended June 30, 2008.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the three month periods ended June 30, 2009 and 2008 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

		Three Months Ended				Three Months Ended
(in thousands)		June 30, 2009				June 30, 2008
Operating Revenues:
Electric		$	53			$	89
Nonelectric			1,149				697
Cost of Goods Sold			1,186				599
Other Nonelectric Expenses			16				187

Electric

		Three Months Ended
		June 30,												%
(in thousands)		2009				2008				Change				Change
Retail Sales Revenues		$	61,273			$	57,389			$	3,884				6.8
Wholesale Revenues			3,272				6,221				(2,949	)			(47.4	)
Net Marked-to-Market Gain (Loss)			140				(31	)			171				—
Other Revenues			5,978				5,087				891				17.5
Total Operating Revenues		$	70,663			$	68,666			$	1,997				2.9
Production Fuel			11,754				14,808				(3,054	)			(20.6	)
Purchased Power — System Use			11,877				10,156				1,721				16.9
Other Operation and Maintenance Expenses			28,959				27,757				1,202				4.3
Depreciation and Amortization			8,998				7,806				1,192				15.3
Property Taxes			2,255				2,563				(308	)			(12.0	)
Operating Income		$	6,820			$	5,576			$	1,244				22.3