Large accelerated filer X                                                                                     Accelerated filer __

 

Non-accelerated filer __                                                                                     Smaller reporting company  __

(Do not check if a smaller reporting company)

PART I. FINANCIAL INFORMATION
Item 1.  F inancial S tatements
Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
(in thousands)		September 30, 2011				December 31, 2010
ASSETS
Current Assets
Cash and Cash Equivalents		$	6,604			$	--
Accounts Receivable:
Trade—Net			152,761				124,353
Other			16,249				19,399
Inventories			91,114				79,270
Deferred Income Taxes			11,987				11,068
Accrued Utility and Cost-of-Energy Revenues			13,446				16,323
Costs and Estimated Earnings in Excess of Billings			54,309				67,352
Income Taxes Receivable			1,530				4,146
Other			23,627				20,224
Assets of Discontinued Operations			77				93,783
Total Current Assets			371,704				435,918
Investments			11,564				9,708
Other Assets			27,109				27,356
Goodwill			69,742				69,742
Other Intangibles—Net			15,712				16,280
Deferred Debits
Unamortized Debt Expense			6,763				6,444
Regulatory Assets			111,454				127,766
Total Deferred Debits			118,217				134,210
Plant
Electric Plant in Service			1,343,080				1,332,974
Nonelectric Operations			368,739				340,167
Construction Work in Progress			67,174				42,031
Total Gross Plant			1,778,993				1,715,172
Less Accumulated Depreciation and Amortization			681,057				637,831
Net Plant			1,097,936				1,077,341
Total Assets		$	1,711,984			$	1,770,555
See accompanying notes to consolidated financial statements.

 

 

2

---

 

 

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
(in thousands, except share data)		September 30, 2011				December 31, 2010
LIABILITIES AND EQUITY
Current Liabilities
Short-Term Debt		$	39,075			$	79,490
Current Maturities of Long-Term Debt			3,286				604
Accounts Payable			113,966				113,761
Accrued Salaries and Wages			21,682				20,252
Accrued Taxes			10,034				11,957
Derivative Liabilities			16,390				17,991
Other Accrued Liabilities			11,368				9,546
Liabilities of Discontinued Operations			77				23,176
Total Current Liabilities			215,878				276,777
Pensions Benefit Liability			76,237				73,538
Other Postretirement Benefits Liability			43,666				42,372
Other Noncurrent Liabilities			19,813				21,043
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes			178,308				162,208
Deferred Tax Credits			33,573				44,945
Regulatory Liabilities			69,113				66,416
Other			497				556
Total Deferred Credits			281,491				274,125
Capitalization
Long-Term Debt, Net of Current Maturities			433,454				434,812
Class B Stock Options of Subsidiary			--				525
Cumulative Preferred Shares Authorized 1,500,000 Shares Without Par Value;  Outstanding 2011 and 2010 – 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, 2011—36,062,023 Shares; 2010—36,002,739 Shares			180,310				180,014
Premium on Common Shares			252,219				251,919
Retained Earnings			196,295				198,443
Accumulated Other Comprehensive (Loss) Income			(2,879	)			1,487
Total Common Equity			625,945				631,863
Total Capitalization			1,074,899				1,082,700
Total Liabilities and Equity		$	1,711,984			$	1,770,555
See accompanying notes to consolidated financial statements.

 

 

3

---

 

Otter Tail Corporation
Consolidated Statements of Income
(not audited)
		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands, except share and per-share amounts)		2011				2010				2011				2010
Operating Revenues
Electric		$	85,117			$	89,272			$	254,618			$	258,130
Nonelectric			230,641				170,474				659,473				495,879
Total Operating Revenues			315,758				259,746				914,091				754,009
Operating Expenses
Production Fuel - Electric			19,080				18,210				55,737				55,611
Purchased Power - Electric System Use			7,488				10,254				27,759				32,730
Electric Operation and Maintenance Expenses			27,323				27,098				84,718				84,817
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)			184,964				138,403				534,503				392,899
Other Nonelectric Expenses			37,163				32,298				97,470				93,527
Asset Impairment Charge			--				--				--				19,740
Depreciation and Amortization			19,937				19,175				58,748				56,404
Property Taxes - Electric			2,601				2,271				7,427				7,222
Total Operating Expenses			298,556				247,709				866,362				742,950
Operating Income			17,202				12,037				47,729				11,059
Other Income			489				704				2,317				1,269
Interest Charges			8,708				9,287				27,346				27,707
Income (Loss) Before Income Taxes – Continuing Operations			8,983				3,454				22,700				(15,379	)
Income Tax Expense (Benefit) – Continuing Operations			2,109				(607	)			4,194				(6,625	)
Net Income (Loss) from Continuing Operations			6,874				4,061				18,506				(8,754	)
Discontinued Operations
Income (Loss) from Discontinued Operations net of income tax (benefit)
expense of $(34), $1,225, $(398), and $3,081 for the respective periods			(52	)			2,040				(412	)			5,354
Gain (Loss) on Disposition of Discontinued Operations net of income tax
(benefit) expense of $(302), $0, $3,213, and $0 for the respective periods			(454	)			--				12,798				--
Net Income (Loss) from Discontinued Operations			(506	)			2,040				12,386				5,354
Total Net Income (Loss)			6,368				6,101				30,892				(3,400	)
Preferred Dividend Requirement and Other Adjustments			184				187				874				650
Earnings Available for Common Shares		$	6,184			$	5,914			$	30,018			$	(4,050	)
Average Number of Common Shares Outstanding—Basic			35,933,003				35,806,453				35,911,993				35,775,418
Average Number of Common Shares Outstanding—Diluted			36,171,555				36,076,421				36,150,545				35,775,418
Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)		$	0.18			$	0.11			$	0.50			$	(0.26	)
Discontinued Operations (net of other adjustments)			(0.01	)			0.06				0.34				0.15
		$	0.17			$	0.17			$	0.84			$	(0.11	)
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)		$	0.18			$	0.11			$	0.50			$	(0.26	)
Discontinued Operations (net of other adjustments)			(0.01	)			0.05				0.33				0.15
		$	0.17			$	0.16			$	0.83			$	(0.11	)
Dividends Declared Per Common Share		$	0.2975			$	0.2975			$	0.8925			$	0.8925
See accompanying notes to consolidated financial statements.

 

 

4

---

 

 

Otter Tail Corporation
Consolidated Statements of Cash Flows
(not audited)
		Nine Months Ended September 30,
(in thousands)		2011				2010
Cash Flows from Operating Activities
Net Income (Loss)		$	30,892			$	(3,400	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations			(12,798	)			--
Net Loss (Income) from Discontinued Operations			412				(5,354	)
Depreciation and Amortization			58,748				56,404
Asset Impairment Charge			--				19,740
Deferred Tax Credits			(1,834	)			(2,037	)
Deferred Income Taxes			10,144				17,373
Change in Deferred Debits and Other Assets			11,844				(1,298	)
Discretionary Contribution to Pension Fund			--				(20,000	)
Change in Noncurrent Liabilities and Deferred Credits			1,742				5,534
Allowance for Equity (Other) Funds Used During Construction			(576	)			(8	)
Change in Derivatives Net of Regulatory Deferral			(177	)			202
Stock Compensation Expense – Equity Awards			1,760				1,973
Other—Net			(301	)			(444	)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables			(25,251	)			(47,442	)
Change in Inventories			(11,845	)			87
Change in Other Current Assets			11,038				4,586
Change in Payables and Other Current Liabilities			3,463				1,103
Change in Interest Payable and Income Taxes Receivable/Payable			764				29,886
Net Cash Provided by Continuing Operations			78,025				56,905
Net Cash Provided by Discontinued Operations			2,347				3,970
Net Cash Provided by Operating Activities			80,372				60,875
Cash Flows from Investing Activities
Capital Expenditures			(71,337	)			(61,382	)
Proceeds from Disposal of Noncurrent Assets			3,055				2,709
Net Decrease (Increase) in Other Investments			234				(1,669	)
Net Cash Used in Investing Activities - Continuing Operations			(68,048	)			(60,342	)
Net Proceeds from Sale of Discontinued Operations			84,330				--
Net Cash Used in Investing Activities - Discontinued Operations			(6,065	)			(1,485	)
Net Cash Provided by (Used in) Investing Activities			10,217				(61,827	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash			(10,031	)			4,528
Net Short-Term Borrowings			(40,415	)			86,388
Proceeds from Issuance of Common Stock			--				549
Proceeds from Issuance of Class B Stock of Subsidiary			--				158
Common Stock Issuance Expenses			--				(142	)
Payments for Retirement of Common Stock			(152	)			(401	)
Payments for Retirement of Class B Stock of Subsidiary			--				(1,017	)
Proceeds from Issuance of Long-Term Debt			2,007				95
Short-Term and Long-Term Debt Issuance Expenses			(1,577	)			(1,699	)
Payments for Retirement of Long-Term Debt			(683	)			(59,166	)
Dividends Paid and Other Distributions			(33,011	)			(32,824	)
Net Cash Used in Financing Activities - Continuing Operations			(83,862	)			(3,531	)
Net Cash Provided by Financing Activities - Discontinued Operations			201				256
Net Cash Used in Financing Activities			(83,661	)			(3,275	)
Cash and Cash Equivalents at Beginning of Period – Discontinued Operations			--				(609	)
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations			(324	)			(205	)
Net Change in Cash and Cash Equivalents			6,604				(5,041	)
Cash and Cash Equivalents at Beginning of Period			--				5,041
Cash and Cash Equivalents at End of Period		$	6,604			$	--
See accompanying notes to consolidated financial statements.

 

 

5

---

 

 

OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the condensed consolidated financial statements for the periods presented. The condensed 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, 2010, 2009 and 2008 included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Because of seasonal and other factors, the earnings for the three month and nine month periods ended September 30, 2011 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, 2010.

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 Otter Tail Power Company’s (OTP) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board Accounting Standards Codification (ASC). 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 in the Company’s Wind Energy, Manufacturing and Construction segments enter into fixed-price construction contracts. Revenues under these contracts are recognized on a percentage-of-completion basis. The method used to determine the progress of completion is based on the ratio of labor hours incurred to total estimated labor hours at the Company’s wind tower manufacturer and costs incurred to total estimated costs on all other construction projects. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Percentage-of-Completion Revenues			34.9	%			26.3	%			33.5	%			26.5	%

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

		September 30,				December 31,
(in thousands)		2011				2010
Costs Incurred on Uncompleted Contracts		$	525,259			$	460,125
Less Billings to Date			(507,751	)			(430,471	)
Plus Estimated Earnings Recognized			26,756				31,231
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts		$	44,264			$	60,885

 

 

6

---

 

 

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

		September 30,				December 31,
(in thousands)		2011				2010
Costs and Estimated Earnings in Excess of Billings		$	54,309			$	67,352
Billings in Excess of Costs and Estimated Earnings			(10,045	)			(6,467	)
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts		$	44,264			$	60,885

Included in Costs and Estimated Earnings in Excess of Billings are the following amounts at DMI Industries, Inc. (DMI), the Company’s wind tower manufacturer:

		September 30,				December 31,
(in thousands)		2011				2010
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI		$	38,843			$	58,990

These amounts are 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.

Warranty Reserves

The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain Company products carry one to fifteen year warranties. Although the Company engages in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures.

 

(in thousands)
Warranty Reserve Balance, December 31, 2010		$	2,676
Provision for Warranties Used During the Year			845
Less Settlements Made During the Year			991
Increase in Warranty Estimates for Prior Years			145
Warranty Reserve Balance, September 30, 2011		$	2,675

 

Expenses associated with remediation activities in the Wind Energy segment could be substantial. The potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. If the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated results of operations and financial condition.

Retainage

Accounts Receivable include the following amounts, billed under contracts by the Company’s subsidiaries, that have been retained by customers pending project completion:

 

		September 30,				December 31,
(in thousands)		2011				2010
Accounts Receivable Retained by Customers		$	12,447			$	11,848

 

 

7

---

 

 

Sales of Receivables

DMI is a party to a $40 million receivables sales agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. The agreement is subject to renewal in March 2012. The current discount rate is 3-month LIBOR plus 4%. In compliance with guidance under ASC 860-20, Sales of Financial Assets, 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. Following are the amounts of accounts receivable sold and discounts, fees and commissions paid under DMI’s receivables sales agreement with General Electric Capital Corporation:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Accounts Receivable Sold		$	20,662			$	14,800			$	48,802			$	44,100
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable			153				45				406				152

Fair Value Measurements

The Company follows ASC 820, Fair Value Measurements and Disclosures, for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and 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 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.

 

 

8

---

 

 

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 September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)		Level 1				Level 2			Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash		$	513			$	--
Forward Gasoline Purchase Contracts			24
Forward Energy Contracts							3,929
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts							13,560
Investments of Captive Insurance Company:
Corporate Debt Securities			9,172
Proceeds from Sale of Idaho Pacific Holdings, Inc. (IPH) Held in Escrow Account			3,000
Total Assets		$	12,709			$	17,489
Liabilities:
Forward Energy Contracts		$	--			$	16,390
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts							125
Total Liabilities		$	--			$	16,515

December 31, 2010 (in thousands)		Level 1				Level 2			Level 3
Assets:
Investments for Nonqualified Retirement Savings Retirement Plan:
Money Market and Mutual Funds and Cash		$	800			$	--
Forward Gasoline Purchase Contracts			58
Forward Energy Contracts							6,875
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts							12,054
Investments of Captive Insurance Company:
Corporate Debt Securities			8,467
Total Assets		$	9,325			$	18,929
Liabilities:
Forward Energy Contracts		$	--			$	17,991
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts							175
Total Liabilities		$	--			$	18,166

Reclassifications and Changes to Presentation

The Company’s consolidated balance sheet as of December 31, 2010, and consolidated income statement and consolidated statement of cash flows for the three and nine months ended September 30, 2010 reflect the reclassifications of the assets and liabilities, operating results and cash flows of IPH and E.W. Wylie’s (Wylie) heavy haul and specialized shipment and transportation of wind turbine components business to discontinued operations as a result of second quarter 2011 sale of IPH and the Company's decision to exit the heavy haul and specialized shipment and transportation of wind turbine components business. The Company sold IPH on May 6, 2011. The reclassifications had no impact on the Company’s total assets, consolidated net income or cash flows for the three and nine months ended September 30, 2010.

In 2011 management reported Minnesota Conservation Improvement Program (MNCIP) incentives in Operating Revenues – Electric rather than Other Income as they had been classified prior to 2011. The Company has corrected this classification resulting in the following increases in Operating Revenues and Operating Income and decreases in Other Income:

		Three Months Ended				Nine Months Ended
(in thousands)		September 30, 2010				September 30, 2010
MNCIP Incentives reclassified from Other Income to Operating Revenue		$	550			$	2,151

The correction had no impact on the Company’s net income, total assets, or operating cash flows for the three and nine months ended September 30, 2010.

 

 

9

---

 

 

Inventories

Inventories consist of the following:

		September 30,				December 31,
(in thousands)		2011				2010
Finished Goods		$	26,218			$	29,113
Work in Process			14,248				7,171
Raw Material, Fuel and Supplies			50,648				42,986
Total Inventories		$	91,114			$	79,270

Goodwill

The following table summarizes changes to goodwill by business segment during 2011:

 

(in thousands)		Gross Balance December 31, 2010				Accumulated Impairments				Balance (net of impairments) December 31, 2010				Adjustments to Goodwill in 2011				Balance (net of impairments) September 30, 2011
Electric		$	240			$	(240	)		$	--			$	--			$	--
Wind Energy			6,959				--				6,959				--				6,959
Manufacturing			24,445				(12,259	)			12,186				--				12,186
Construction			7,630				--				7,630				--				7,630
Plastics			19,302				--				19,302				--				19,302
Health Services			23,665				--				23,665				--				23,665
Total		$	82,241			$	(12,499	)		$	69,742			$	--			$	69,742

Other Intangible Assets

The following table summarizes the components of the Company’s intangible assets at September 30, 2011 and December 31, 2010:

 

September 30, 2011 (in thousands)		Gross Carrying Amount				Accumulated Amortization				Net Carrying Amount			Amortization Periods
Amortized Intangible Assets:
Customer Relationships		$	16,811			$	3,024			$	13,787		15 – 25 years
Covenants Not to Compete			1,704				1,697				7		3 – 5 years
Other Intangible Assets Including Contracts			1,030				902				128		5 – 30 years
Total		$	19,545			$	5,623			$	13,922
Nonamortized Intangible Assets:
Brand/Trade Name		$	1,790			$	--			$	1,790
December 31, 2010   (in thousands)
Amortized Intangible Assets:
Customer Relationships		$	16,811			$	2,388			$	14,423		15 – 25 years
Covenants Not to Compete			1,704				1,676				28		3 – 5 years
Other Intangible Assets Including Contracts			930				891				39		5 – 30 years
Total		$	19,445			$	4,955			$	14,490
Nonamortized Intangible Assets:
Brand/Trade Name		$	1,790			$	--			$	1,790

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Amortization Expense – Intangible Assets		$	220			$	238			$	668			$	784

(in thousands)		2011				2012				2013				2014				2015
Estimated Amortization Expense – Intangible Assets		$	887			$	911			$	947			$	947			$	931

 

 

10

---

 

 

Comprehensive Income

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Net Income (Loss)		$	6,368			$	6,101			$	30,892			$	(3,400	)
Other Comprehensive Income (Loss) (net-of-tax):
Foreign Currency Translation Gains and (Reversal of   Previously Recorded Foreign Currency Translation Gains)			--				484				(3,977	)			295
Amortization of Unrecognized Losses and Costs   Related to Postretirement Benefit Programs			47				105				(395	)			314
Unrealized Gain (Loss) on Available-for-Sale Securities			(2	)			54				6				86
Total Other Comprehensive Income (Loss)			45				643				(4,366	)			695
Total Comprehensive Income (Loss)		$	6,413			$	6,744			$	26,526			$	(2,705	)

Supplemental Disclosures of Cash Flow Information

		Nine Months Ended
		September 30,
(in thousands)		2011				2010
Increases in Accounts Payable Related to Capital Expenditures		$	1,790			$	63

2.  Segment Information

The Company's businesses have been classified into six segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision makers. These businesses reach customers in all 50 states and international markets. The six segments are: Electric, Wind Energy, Manufacturing, Construction, Plastics and Health Services.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is an active wholesale participant in the Midwest Independent Transmission System Operator (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. Additionally, the electric segment includes Otter Tail Energy Services Company (OTESCO), which provides technical and engineering services, wind farm site development and energy efficient lighting primarily in North Dakota and Minnesota.

Wind Energy consists of two businesses: a steel fabrication company primarily involved in the production of wind towers sold in the United States and Canada, with manufacturing facilities in North Dakota, Oklahoma and Ontario, Canada, and a trucking company headquartered in West Fargo, North Dakota, specializing in flatbed services and operating in 49 states and six Canadian provinces. Prior to the realignment of the Company’s business segments, the wind tower production company was included in Manufacturing and the trucking company was included in Other Business Operations.

Manufacturing consists of businesses in the following manufacturing activities: 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 and Missouri and sell products primarily in the United States.

Construction consists of businesses involved in residential, commercial and industrial electric contracting and construction of fiber optic and electric distribution systems, water, wastewater and HVAC systems primarily in the central United States. Construction operations were included in Other Business Operations prior to the realignment of the Company’s business segments.

 

 

11

---

 

 

Plastics consists of businesses producing polyvinyl chloride (PVC) pipe in the upper Midwest and Southwest regions of 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 equipment and technical staff to various medical institutions located throughout the United States.

 

Food Ingredient Processing is no longer a reportable segment as a result of the sale of IPH on May 6, 2011. The results of operations, financial position and cash flows of IPH are reported as discontinued operations in the Company’s consolidated financial statements.

OTP and OTESCO are wholly owned subsidiaries of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar).

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.

 

The Company had no single external customer that accounted for 10% or more of the Company’s consolidated revenues in 2010. One customer of DMI has accounted for 11.2% of the Company’s consolidated revenues in the first nine months of 2011. Substantially all of the Company’s long-lived assets are within the United States except for 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								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
United States of America			98.2	%			98.9	%			98.2	%			98.2	%
Canada			1.3	%			0.9	%			1.5	%			1.6	%
All Other Countries			0.5	%			0.2	%			0.3	%			0.2	%

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 nine month periods ended September 30, 2011 and 2010 and total assets by business segment as of September 30, 2011 and December 31, 2010 are presented in the following tables:

Operating Revenue

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Electric		$	85,172			$	89,315			$	254,799			$	258,294
Wind Energy			65,007				40,389				187,534				134,764
Manufacturing			55,815				43,342				170,486				130,880
Construction			53,247				36,885				139,895				84,808
Plastics			36,231				26,736				99,082				76,562
Health Services			21,853				24,300				67,331				73,116
Corporate Revenues and Intersegment Eliminations			(1,567	)			(1,221	)			(5,036	)			(4,415	)
Total		$	315,758			$	259,746			$	914,091			$	754,009

 

 

12

---

 

 

Interest Charges

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Electric		$	4,796			$	5,172			$	14,874			$	15,791
Wind Energy			1,925				1,641				5,806				4,511
Manufacturing			1,323				1,298				3,984				3,839
Construction			251				190				698				463
Plastics			411				403				1,176				1,194
Health Services			451				377				1,295				902
Corporate and Intersegment Eliminations			(449	)			206				(487	)			1,007
Total		$	8,708			$	9,287			$	27,346			$	27,707

 

Income Tax Expense (Benefit) – Continuing Operations

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Electric		$	3,364			$	4,257			$	5,972			$	8,562
Wind Energy			(863	)			(3,529	)			(4,676	)			(5,053	)
Manufacturing			591				(349	)			3,650				(4,800	)
Construction			(115	)			435				(195	)			(872	)
Plastics			1,295				238				3,198				873
Health Services			115				311				863				(66	)
Corporate			(2,278	)			(1,970	)			(4,618	)			(5,269	)
Total		$	2,109			$	(607	)		$	4,194			$	(6,625	)

Earnings Available for Common Shares

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Electric		$	10,900			$	12,265			$	29,428			$	24,188
Wind Energy			(3,497	)			(7,120	)			(16,443	)			(9,755	)
Manufacturing			1,083				(383	)			6,071				(16,234	)
Construction			(179	)			645				(320	)			(1,337	)
Plastics			1,970				367				4,908				1,380
Health Services			125				421				1,155				(235	)
Corporate			(3,712	)			(2,319	)			(6,845	)			(7,313	)
Discontinued Operations			(506	)			2,038				12,064				5,256
Total		$	6,184			$	5,914			$	30,018			$	(4,050	)

Total Assets

		September 30,				December 31,
(in thousands)		2011				2010
Electric		$	1,101,146			$	1,106,261
Wind Energy			169,138				172,753
Manufacturing			152,693				144,272
Construction			74,639				60,978
Plastics			84,463				73,508
Health Services			72,566				75,898
Corporate			57,262				43,102
Discontinued Operations			77				93,783
Total		$	1,711,984			$	1,770,555

 

 

13

---

 

 

3.  Rate and Regulatory Matters

Minnesota

2010 General Rate Case Filing —OTP filed a general rate case on April 2, 2010 requesting an 8.01% base rate increase as well as a 3.8% interim rate increase.   On May 27, 2010, the Minnesota Public Utilities Commission (MPUC) issued an order accepting the filing, suspending rates, and approving the interim rate increase, as requested, to be effective with customer usage on and after June 1, 2010. The MPUC held a hearing to decide on the issues in the rate case on March 25, 2011 and issued a written order on April 25, 2011. The MPUC authorized a revenue increase of approximately $5.0 million, or 3.76% in base rate revenues, excluding the effect of moving recovery of wind investments to base rates. The MPUC’s written order included: (1) recovery of Big Stone II costs over five years (see discussion below), (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of MNCIP costs from rider recovery to base rate recovery, (4) transfer of the investment in two transmission lines from rider recovery to base rate recovery, and (5) changing the mechanism for providing customers with a credit for margins earned on asset-based wholesale sales of electricity from a credit to base rates to a credit to the Minnesota fuel clause adjustment (FCA). Final rates went into effect October 1, 2011. The overall increase to customers will be approximately 1.6% compared to the authorized interim rate increase of 3.8%,   which resulted in an interim rate refund of approximately $3.9 million. As of September 30, 2011, OTP had recognized a $3.9 million refund liability for revenue billed under interim rates from June 1, 2010 through September 30, 2011. On October 31, 2011 OTP issued the interim rate refund, including interest, to Minnesota customers. Pursuant to the order, OTP’s allowed rate of return on rate base will increase from 8.33% to 8.61% and its allowed rate of return on equity will increase from 10.43% to 10.74%. OTP's rates of return will be based on a capital structure of 48.28% long term debt and 51.72% common equity.

OTP has a regulatory asset of $3.5 million for revenues that are eligible for recovery through the Minnesota Renewable Resource Adjustment (MNRRA) rider that have not been billed to Minnesota customers as of September 30, 2011. The recovery of MNRRA costs was moved to base rates as of October 1, 2011 under the MPUC’s April 25, 2011 general rate case order with the exception of the remaining balance of this regulatory asset.

In its April 25, 2011 general rate case order, the MPUC approved the transfer of transmission costs currently being recovered through OTP’s Minnesota Transmission Cost Recovery (TCR) rider to recovery in base rates. Final rates went into effect on October 1, 2011. The Company will continue to utilize the rider cost recovery mechanism until the remaining balance of the current transmission projects has been collected as well as to recover costs associated with approved regional projects. OTP filed a request for an update to its Minnesota TCR rider on October 5, 2010. Comments and reply comments have been filed but the MPUC has not yet scheduled a hearing on the request.

 

Conservation Improvement Program —OTP has a regulatory asset of $7.2 million for allowable costs and financial incentives that are eligible for recovery through the MNCIP rider that have not been billed to Minnesota customers as of  September 30, 2011. OTP has recognized $3.7 million in financial incentives relating to 2010. A final decision regarding the 2010 MNCIP financial incentive is expected in December 2011. OTP currently has $1.3 million of income recognized relating to the 2011 MNCIP financial incentive. 

North Dakota

Transmission Cost Recovery Rider —North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. OTP requested recovery of such costs in its general rate case filed in November 2008 and was granted recovery of such costs by the North Dakota Public Service Commission (NDPSC) in its November 25, 2009 order. OTP filed a request for an initial North Dakota TCR rider with the NDPSC on April 29, 2011. The request is under review by the NDPSC.

 

 

14

---

 

 

South Dakota

2010 General Rate Case Filing —On August 20, 2010 OTP filed a general rate case with the South Dakota Public Utilities Commission (SDPUC) requesting an overall revenue increase of approximately $2.8 million, or just under 10.0%, which includes, among other things, recovery of investments and expenses related to renewable resources. On September 28, 2010 the SDPUC suspended OTP’s proposed rates for a period of 180 days to allow time to review OTP’s proposal. On January 19, 2011 OTP submitted a proposal to use current rate design to implement an interim rate in South Dakota to be effective on and after February 17, 2011. On January 26, 2011 OTP submitted an amended proposal to use a lower interim rate increase than originally proposed. At its February 1, 2011 meeting, the SDPUC approved OTP’s request to implement interim rates using current rate design and the lower interim increase to be effective on and after February 17, 2011. On April 21, 2011, the SDPUC issued its written order approving an overall final revenue increase of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50 percent for the interim rates and final rates. Final rates were effective with bills rendered on and after June 1, 2011.

Transmission Cost Recovery Rider —South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. OTP submitted a request for an initial South Dakota TCR rider to the SDPUC on November 5, 2010. The South Dakota TCR has been assigned to an SDPUC outside consultant and likely will not be on an SDPUC agenda until later this year.

 

Capacity Expansion 2020 (CapX2020)

CapX2020 is a joint initiative of 11 investor-owned, cooperative, and municipal utilities in Minnesota and the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service. The CapX2020 companies identified four major transmission projects for the region: (1) the Fargo–Monticello 345 kiloVolt (kV) Project (the Fargo Project), (2) the Brookings–Southeast Twin Cities 345 kV Project (the Brookings Project), (3) the Bemidji – Grand Rapids Project (the Bemidji Project), and (4) the Twin Cities–LaCrosse 345 kV Project. OTP is an investor in the Fargo Project, the Brookings Project and the Bemidji Project.

On April 16, 2009 the MPUC approved Certificates of Need (CONs) for the three 345 kV Group 1 CapX2020 line projects: the Fargo Project, the Brookings Project and the Twin Cities–LaCrosse 345 kV Project.

The Fargo Project —The route permit application for the Monticello to St. Cloud portion of the Fargo Project was filed in April 2009. The MPUC approved the route permit application and issued a written order on July 12, 2010. Required permits from the Minnesota Department of Transportation, Minnesota Department of Natural Resources and the U.S. Army Corps of Engineers were received in 2010. A Transmission Capacity Exchange Agreement, allocating transmission capacity rights to owners across the Monticello to St. Cloud portion of the Fargo Project, was accepted by the Federal Energy Regulatory Commission (FERC) in the third quarter of 2010. The Monticello to St. Cloud portion of the Fargo Project is scheduled for completion in December 2011.

The Minnesota route permit application for the St. Cloud to Fargo portion of the Fargo Project was filed on October 1, 2009. Minnesota State Environmental Impact Statement (EIS) scoping meetings were held in September 2010 and public hearings were held in November 2010. The MPUC approved the route permit on June 24, 2011. The agreements for Phase 2, which consists of the line section between St. Cloud and Alexandria, Minnesota were signed by all of the participants on August 3, 2011. Easement acquisition discussions with landowners are underway. Construction is expected to begin in November 2011.

On October 8, 2010, OTP submitted its application for a Certificate of Public Convenience and Necessity (CPCN) from the NDPSC for the North Dakota portion of the Fargo Project. The NDPSC approved the CPCN in January 2011. The application for the North Dakota Certificate of Corridor Compatibility (CCC) was filed on December 30, 2010 and was revised in March 2011. The June 23, 2011 hearing for the North Dakota CCC application was postponed. A combined North Dakota CCC and route permit application was submitted to the NDPSC on October 3, 2011.

 

 

15

---

 

 

The Brookings Project —The Minnesota route permit application for the Brookings Project was filed in the fourth quarter of 2008. The MPUC approved the final line segment route permit for the Brookings Project on February 3, 2011.

 

An application for a South Dakota facility route permit was filed with the SDPUC on November 22, 2010. The SDPUC conducted a public hearing in January 2011 and the South Dakota route permit was approved in June 2011. The MISO board of directors granted conditional approval of the Multi-Value Project (MVP) cost allocation designation under the MISO Tariff for the Brookings Project. Once the MISO board finalizes its analysis of all of the MVP projects in its study portfolio, the MISO board will be in a position to remove the condition, which is anticipated to occur in December 2011. Easement acquisition discussions with landowners are underway.

The Bemidji Project —OTP serves as the lead utility for the Bemidji Project, which has an expected in-service date in late 2012. The MPUC approved the CON for this project on July 9, 2009. A route permit application was filed with the MPUC in the second quarter of 2008 and approved on October 28, 2010.  The joint state and federal EIS was published by federal agencies on September 7, 2010, and the project’s Transmission Capacity Exchange Agreement was accepted and approved by the FERC in the third quarter of 2010. On March 25, 2011, the Leech Lake Band of Ojibwe (LLBO) submitted a petition to the MPUC, requesting the revocation or suspension of the project’s route permit. The request is based on the LLBO’s allegation that it has jurisdiction to require the project to obtain its permission to cross through the historical boundaries of the Leech Lake Reservation. The owners of the Bemidji Project, including OTP, filed reply comments in opposition to the LLBO’s request. On April 25, 2011, the Bemidji Project owners filed a declaratory judgment in the U.S. District Court for Minnesota against the LLBO seeking that no consent from the LLBO is required for the project to run through the LLBO reservation boundaries since the project is located exclusively on non LLBO lands. On June 22, 2011, Federal District Judge Frank issued a preliminary injunction which ordered the LLBO to cease and desist from pursuing its claims of jurisdiction over the project in tribal court or the MPUC or from taking any other actions to interfere with the routing or construction of the project. The parties had engaged in court supervised mediation; however, no agreement was reached. The preliminary injunction remains in place prohibiting the LLBO from interfering with project construction.

CapX2020 Request for Advance Determination of Prudence —On October 5, 2009 OTP filed an application for an advance determination of prudence with the NDPSC for its proposed participation in three of the four Group 1 projects: the Fargo Project, the Brookings Project and the Bemidji Project. An administrative law judge conducted an evidentiary hearing on the application in May 2010. On October 6, 2010 the NDPSC adopted an order approving a settlement between OTP and intervener NDPSC advocacy staff, and issued an advance determination of prudence to OTP for participation in the three Group 1 projects. The order is subject to a number of terms and conditions in addition to the settlement agreement, including the provision of additional information on the eventual resolution of cost allocation issues relevant to the Brookings Project and its associated impact on North Dakota. On April 29, 2011, OTP filed its compliance filing with the NDPSC, seeking a determination of continued prudence for OTP’s investment in the Brookings Project. The NDPSC hearing occurred on July 25, 2011. On August 23, 2011, an executed settlement agreement on continued prudence was filed and the hearing for consideration of the settlement agreement on continued prudence was held on October 26, 2011.  A final decision is expected later this year.

 

16

---

 

 

Big Stone Air Quality Control System

The South Dakota Department of Environment and Natural Resources (DENR) determined that the Big Stone Plant is subject to Best Available Retrofit Technology (BART) requirements of the Clean Air Act (CAA), based on air dispersion modeling indicating that Big Stone’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan. Under the U.S. Environmental Protection Agency’s (EPA) regional haze regulations, South Dakota developed and submitted its implementation plan and associated implementation rules to the EPA on January 21, 2011. The DENR and EPA have agreed on non-substantive rule revisions, which were adopted by the Board of Minerals and Environment and became effective on September 19, 2011. South Dakota developed and submitted its revised implementation plan and associated implementation rules to EPA on September 19, 2011. Under the South Dakota implementation plan, and its implementing rules, the Big Stone Plant must install and operate a new BART compliant air quality control system to reduce emissions as expeditiously as practicable, but no later than five years after the EPA’s approval of South Dakota’s implementation plan. Although studies and evaluations are continuing, the current project cost is estimated to be approximately $490 million (OTP’s share would be $264 million). On January 14, 2011 OTP filed a petition asking the MPUC for advance determination of prudence (ADP) for the design, construction and operation of the BART compliant air quality control system at Big Stone Plant attributable to serving OTP’s Minnesota customers. On June 1, 2011, the MPUC referred the matter to the Office of Administrative Hearings for contested case proceedings before an administrative law judge (ALJ). Evidentiary hearings took place on September 14 and 15, 2011 with an ALJ report and recommendation expected by November 9, 2011. A decision by the MPUC is expected in December. OTP filed an application for an ADP with the NDPSC on May 20, 2011 with a decision expected by December 20, 2011. North Dakota has hired a consulting firm to evaluate the ADP request. Evidentiary hearings are scheduled for November 29 and 30, 2011. Big Stone Plant is currently operating within all presently applicable federal and state air quality and emission standards.

 

Big Stone II Project

On June 30, 2005 OTP 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. On September 11, 2009 OTP announced its withdrawal—both as a participating utility and as the project’s lead developer—from Big Stone II, due to a number of factors. On November 2, 2009, the remaining Big Stone II participants announced the cancellation of the Big Stone II project.

OTP requested recovery of the Minnesota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in Minnesota on April 2, 2010. In a written order issued on April 25, 2011, the MPUC authorized recovery of the Minnesota portion of Big Stone II generation development costs from Minnesota ratepayers over a 60-month recovery period which began on October 1, 2011. The amount of Big Stone II generation costs incurred by OTP that were deemed recoverable from Minnesota ratepayers was $3,199,000 (which excludes $3,246,000 of project transmission-related costs). Because the MPUC denied OTP an investment return on these deferred costs over the 60-month recovery period, the recoverable amount has been discounted to its present value of $2,758,000, in accordance with ASC 980, Regulated Operations , accounting requirements.

On December 30, 2010 OTP filed a request for an extension of the Minnesota Route Permit for the Big Stone transmission facilities. The request asks to extend the deadline for filing a CON for these transmission facilities until March 17, 2013. The April 25, 2011 MPUC order instructed OTP to transfer the $3,246,000 Minnesota share of Big Stone II transmission costs to Construction Work in Progress (CWIP) and to create a tracker account through which any over or under recoveries could be accumulated for refund or recovery determination in future rate cases as a regulatory liability or asset. If determined eligible for recovery under the FERC-approved MISO regional transmission tariff, the Minnesota portion of Big Stone II transmission costs and accumulated Allowance for Funds Used During Construction (AFUDC) will receive rate base treatment and recovery through the FERC-approved MISO regional transmission rates. Any amounts over or under collected through MISO rates will be reflected in the tracker account.

OTP requested recovery of the South Dakota portion of its Big Stone II development costs over a five-year period as part of its general rate case filed in South Dakota on August 20, 2010. In the first quarter of 2011, the SDPUC approved recovery of the South Dakota portion of Big Stone II generation development costs totaling approximately $1.0 million from South Dakota ratepayers over a ten-year period beginning in February 2011 with the implementation of interim rates. OTP will be allowed to earn a return on the amount subject to recovery over the ten-year recovery period. Therefore, the South Dakota settlement amount is not discounted. OTP transferred the South Dakota portion of the remaining Big Stone II transmission costs to CWIP, with such costs subject to AFUDC and recovery in future FERC-approved MISO rates or retail rates.

 

17

---

 

 

4.  Regulatory Assets and Liabilities

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC 980, Regulated Operations . This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. The following table indicates the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheet:

		September 30,				December 31,			Remaining Recovery/
(in thousands)		2011				2010			Refund Period
Regulatory Assets – Current:
Accrued Cost-of-Energy Revenue		$	2,552			$	2,387		23 months
Regulatory Assets – Long Term:
Unrecognized Transition Obligation, Prior Service Costs and Actuarial
Losses on Pensions and Other Postretirement Benefits		$	70,265			$	74,156		see notes
Deferred Marked-to-Market Losses			13,560				12,054		47 months
Deferred Conservation Improvement Program Costs & Accrued Incentives			7,158				6,655		21 months
Minnesota Renewable Resource Rider Accrued Revenues			3,452				6,834		30 months
Big Stone II Unrecovered Project Costs – Minnesota			2,758				6,445		60 months
Debt Reacquisition Premiums			2,582				3,107		252 months
Accumulated ARO Accretion/Depreciation Adjustment			2,545				2,218		asset lives
Big Stone II Unrecovered Project Costs – North Dakota			2,508				3,460		22 months
Deferred Income Taxes			2,025				5,785		asset lives
North Dakota Renewable Resource Rider Accrued Revenues			1,379				2,415		27 months
General Rate Case Recoverable Expenses			1,189				1,773		28 months
Big Stone II Unrecovered Project Costs – South Dakota			936				1,419		112 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND			436				717		14 months
South Dakota – Asset-Based Margin Sharing Shortfall			257				501		5 months
Minnesota Transmission Rider Accrued Revenues			252				34		15 months
Deferred Holding Company Formation Costs			152				193		33 months
Total Regulatory Assets – Long Term		$	111,454			$	127,766
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		$	64,031			$	61,740		asset lives
Deferred Income Taxes			3,691				4,289		asset lives
Minnesota Transmission Rider Accrued Refund			1,081				--		see notes
Deferred Marked-to-Market Gains			125				175		35 months
Deferred Gain on Sale of Utility Property – Minnesota Portion			124				128		267 months
South Dakota – Nonasset-Based Margin Sharing Excess			61				84		15 months
Total Regulatory Liabilities		$	69,113			$	66,416
Net Regulatory Asset Position		$	44,893			$	63,737

 

The regulatory asset related to the unrecognized transition obligation, prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

All Deferred Marked-to-Market Gains and Losses recorded as of September 30, 2011 are related to forward purchases of energy scheduled for delivery through August 2015.

 

 

18

---

 

 

Deferred Conservation Program Costs & Accrued Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying 2008 through 2011 renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers as of September 30, 2011.

Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 252 months.

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

Big Stone II Unrecovered Project Costs – North Dakota are the North Dakota share of costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

 

The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC 740, Income Taxes .

North Dakota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of September 30, 2011.

General Rate Case Recoverable Expenses relate to expenses incurred during the rate case proceedings that are eligible for recovery.

Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

South Dakota – Asset-Based Margin Sharing Shortfall represents differences in OTP’s South Dakota share of actual profit margins on wholesale sales of electricity from company-owned generating units and estimated profit margins from those sales that were used in determining current South Dakota retail electric rates. Net asset-based margin sharing accumulated shortfalls will be subject to recovery or refund through future retail rate adjustments in South Dakota.

 

Minnesota Transmission Rider Accrued Revenues are expected to be recovered from Minnesota retail electric customers over 12 months beginning in January 2012.

The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

No schedule has been set for the return of the September 30, 2011 Minnesota Transmission Rider Accrued Refund balance.

South Dakota – Nonasset-Based Margin Sharing Excess represents 25% of OTP’s South Dakota share of actual profit margins on nonasset-based wholesale sales of electricity. The excess margins accumulated annually will be subject to refund through future retail rate adjustments in South Dakota in the following year.

If for any reason, OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its 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 guidance under ASC 980 ceases.

 

19

---

 

 

5.  Forward Contracts Classified as Derivatives

Electricity Contracts

All of OTP’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. OTP’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. OTP’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. OTP 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.

The market prices used to value OTP’s forward contracts for the purchases and sales of electricity and electricity generating capacity are determined by survey of counterparties or brokers used by OTP’s power services’ personnel responsible for contract pricing, as well as prices gathered from daily settlement prices published by the Intercontinental Exchange and CME Globex. For certain contracts, prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The fair value measurements of these forward energy contracts fall into level 2 of the fair value hierarchy set forth in ASC 820.

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 September 30, 2011 and December 31, 2010, and the change in the Company’s consolidated balance sheet position from December 31, 2010 to September 30, 2011:

(in thousands)		September 30, 2011				December 31, 2010
Other Current Assets – Marked-to-Market Gain		$	3,929			$	6,875
Regulatory Assets – Deferred Marked-to-Market Loss			13,560				12,054
Total Assets			17,489				18,929
Derivative Liabilities – Marked-to-Market Loss			(16,390	)			(17,991	)
Regulatory Liabilities – Deferred Marked-to-Market Gain			(125	)			(175	)
Total Liabilities			(16,515	)			(18,166	)
Net Fair Value of Marked-to-Market Energy Contracts		$	974			$	763

(in thousands)		Year-to-Date September 30, 2011
Fair Value at Beginning of Year		$	763
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011			(225	)
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011			(28	)
Changes in Fair Value of Contracts Entered into in 2009 in 2011			(14	)
Changes in Fair Value of Contracts Entered into in 2010 in 2011			(72	)
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period			424
Changes in Fair Value of Contracts Entered into in 2011			550
Net Fair Value End of Period		$	974

 

The September 30, 2011 balance of recognized but unrealized net mark-to-market gains on the forward energy and capacity purchases and sales is expected to be realized on settlement as scheduled over the following periods in the amounts listed:

(in thousands)		4th Quarter 2011				2012				Total
Net Gain		$	354			$	620			$	974

 

 

20

---

 

 

The following realized and unrealized net gains on forward energy contracts are included in electric operating revenues on the Company’s consolidated statements of income:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Net Gains on Forward Electric Energy Contracts		$	456			$	144			$	587			$	1,945

OTP has credit risk associated with the nonperformance or nonpayment by counterparties to its forward energy and capacity purchases and sales agreements. We have established guidelines and limits to manage credit risk associated with wholesale power and capacity purchases and sales. Specific limits are determined by a counterparty’s financial strength.

The following table provides information on OTP’s credit risk exposure on delivered and marked-to-market forward contracts as of September 30, 2011 and December 31, 2010:

		September 30, 2011								December 31, 2010
(in thousands)		Exposure				Counterparties				Exposure				Counterparties
Net Credit Risk on Forward Energy Contracts		$	792				5			$	1,129				4
Net Credit Risk to Single Largest Counterparty		$	372							$	585

OTP had no exposure at September 30, 2011 or December 31, 2010 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 credit risk exposures include net amounts due to OTP 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 subsequent to the reporting date. Individual counterparty exposures are offset according to legally enforceable netting arrangements.

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of September 30, 2011 and December 31, 2010:

Current Liability – Marked-to-Market Loss   (in thousands)		September 30, 2011				December 31, 2010
Loss Contracts Covered by Deposited Funds		$	2,551			$	427
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1			13,803				10,904
Loss Contracts with No Ratings Triggers or Deposit Requirements			36				6,660
Total Current Liability – Marked-to-Market Loss		$	16,390			$	17,991
1    Certain OTP derivative energy contracts contain provisions that require an
investment grade credit rating from each of the major credit rating agencies on
OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the
counterparties to these forward energy contracts could request the immediate
deposit of cash to cover contracts in net liability positions.
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade		$	13,803			$	10,904
Offsetting Gains with Counterparties under Master Netting Agreements			(3,411	)			(6,219	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered		$	10,392			$	4,685

 

 

21

---

 

 

6.  Common Shares and Earnings Per Share

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2010 through September 30, 2011:

 

Common Shares Outstanding, December 31, 2010			36,002,739
Issuances:
Restricted Stock Issued to Employees			24,600
Restricted Stock Issued to Nonemployee Directors			24,000
Vesting of Restricted Stock Units			17,325
Retirements:
Shares Withheld for Individual Income Tax Requirements			(6,641	)
Common Shares Outstanding, September 30, 2011			36,062,023

Earnings Per Share

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 prices:

Three Months Ended September 30,	Options Outstanding	Range of Exercise Prices
2011	170,960	$24.93 – $31.34
2010	383,460	$24.93 – $31.34

Nine Months Ended September 30,	Options Outstanding	Range of Exercise Prices
2011	170,960	$24.93 – $31.34
2010	383,460	$24.93 – $31.34

 

 

22

---

 

 

7.  Share-Based Payments

The Company has five share-based payment programs.

Stock Incentive Awards

On April 11, 2011 the Company’s Board of Directors granted the following stock incentive awards to the Company’s non-employee directors, executive officers and key employees under the 1999 Stock Incentive Plan, as amended:

Award		Shares/Units Granted		Grant-Date Fair Value per Share			Vesting
Restricted Stock Granted to Nonemployee Directors		24,000		$	22.51		25% per year through April 8, 2015
Restricted Stock Granted to Executive Officers		24,600		$	22.51		25% per year through April 8, 2015
SStock Performance Awards Granted to Executive Officers		48,600		$	23.61		December 31, 2013
Restricted Stock Units Granted to Employees		19,800		$	18.03		100% on April 8, 2015

 

The restricted shares granted to the Company’s nonemployee directors and executive officers (which includes OTP’s president) are eligible for full dividend and voting rights. The grant date fair value of each share of restricted stock was the average of the high and low market price per share on the date of grant.

Under the performance share awards, the Company’s executive officers could earn up to an aggregate of 97,200 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 measurement period of January 1, 2011 through December 31, 2013. The aggregate target share award is 48,600 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 grant date fair value of the target amount of common shares projected to be awarded was determined under a Monte Carlo simulation valuation method. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under ASC 718-10-25-18, 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.

The grant date fair value of each restricted stock unit was based on the market value of one share of the Company’s common stock on the grant date, discounted for the value of the dividend exclusion over the four-year vesting period.

As of September 30, 2011 the remaining unrecognized compensation expense related to stock-based compensation was approximately $2.8 million (before income taxes) which will be amortized over a weighted-average period of 2.6 years.

Compensation expense recognized under the Company’s stock-based payment programs:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(in thousands)		2011				2010				2011				2010
Employee Stock Purchase Plan (15% discount)		$	51			$	64			$	185			$	205
Restricted Stock Granted to Directors			185				148				571				446
Restricted Stock Granted to Employees			511				239				759				519
Stock Performance Awards Granted to Executive Officers			1,766				722				1,766				879
Restricted Stock Units Granted to Employees			92				(20	)			244				137
Totals		$	2,605			$	1,153			$	3,525			$	2,186

 

 

23

---

 

 

9.  Commitments and Contingencies

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

In the first quarter of 2011, OTP entered into additional energy purchase agreements increasing its commitments for capacity and energy requirements. Amounts of commitments for OTP’s capacity and energy requirements under agreements extending through 2032 were as follows:

Capacity and Energy Requirements (thousands)		September 30, 2011				December 31, 2010				Increase
2011		$	21,268			$	20,134			$	1,134
2012			25,025				21,637				3,388
2013			21,868				16,492				5,376
2014			24,701				15,388				9,313
2015			18,915				12,307				6,608
Beyond 2015			78,879				78,879				--
Total		$	190,656			$	164,837			$	25,819

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. In the first half of 2011, OTP extended its contract for the purchase of coal for Hoot Lake Plant resulting in an increase in minimum purchase commitments. OTP’s current coal purchase agreements under contracts expire in 2012 and 2016. OTP is now committed to the minimum purchase, dating from January 1, 2011, or to make payments in lieu thereof in the following amounts:

Coal and Freight Purchase Commitments (thousands)		September 30, 2011				December 31, 2010				Increase
2011		$	52,819			$	47,122			$	5,697
2012			48,444				34,958				13,486
2013			9,855				9,855				--
2014			9,854				9,854				--
2015			9,854				9,854				--
Beyond 2015			4,106				4,106				--
Total		$	134,932			$	115,749			$	19,183

The FCA mechanism lessens the risk of loss from market price changes because it provides for recovery of most fuel costs.

Other

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 September 30, 2011 will not be material.

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood that a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to product warranty, environmental remediation, litigation matters, possible liquidated damages and the resolution of matters related to open tax years. Should any of these items result in a liability being incurred, the range of loss could be as high as $9.0 million. Additionally, we may become subject to significant claims of which we are unaware, or the claims of which we are aware may result in our incurring a significantly greater liability than we anticipate.

 

 

24

---

 

 

10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of September 30, 2011 and December 31, 2010:

(in thousands)		Line Limit				In Use on September 30, 2011				Restricted due to Outstanding Letters of Credit				Available on September 30, 2011				Available on December 31, 2010
Otter Tail Corporation Credit Agreement		$	200,000			$	20,000			$	1,374			$	178,626			$	144,350
OTP Credit Agreement			170,000				19,010				1,050				149,940				144,436
Total		$	370,000			$	39,010			$	2,424			$	328,566			$	288,786

On March 3, 2011 OTP entered into an Amended and Restated Credit Agreement (the OTP Credit Agreement) with the Banks named therein. The OTP Credit Agreement provides for a $170 million line of credit that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. The OTP Credit Agreement is an unsecured revolving credit facility that OTP can draw on to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under the line of credit currently bear interest at LIBOR plus 1.5%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. Under the OTP Credit Agreement OTP is required to pay the Banks’ commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement expires on March 3, 2016.

 

The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default. The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings.   The OTP Credit Agreement amends and restates the $170 million Credit Agreement dated as of July 30, 2008 among OTP (formerly known as Otter Tail Corporation, dba Otter Tail Power Company), the Banks named therein, as amended by a First Amendment to Credit Agreement dated as of April 21, 2009 and a Second Amendment to Credit Agreement dated as of June 22, 2009.

The OTP Credit Agreement also contains certain financial covenants. Specifically, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization (as defined in the OTP Credit Agreement) to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio (as defined in the OTP Credit Agreement) to be less than 1.50 to 1.00.

On March 18, 2011 Otter Tail Corporation borrowed $1.5 million under a Partnership in Assisting Community Expansion loan to finance capital investments at Northern Pipe Products, Inc. (NPP), the Company’s PVC pipe manufacturing subsidiary located in Fargo, North Dakota. The ten-year unsecured note bears interest at 2.54% with monthly principal and interest payments through March 2021. On April 6, 2011 Otter Tail Corporation borrowed $0.5 million under a North Dakota Development Fund loan to finance additional capital investments at NPP. The seven-year unsecured note bears interest at 3.95% with monthly principal and interest payments through April 1, 2018.

On July 29, 2011, OTP entered into a Note Purchase Agreement with the purchasers named therein, pursuant to which OTP has agreed to issue to the purchasers in a private placement transaction $140 million aggregate principal amount of OTP’s 4.63% Senior Unsecured Notes due December 1, 2021 (the 2021 Notes).  The 2021 Notes are expected to be issued on December 1, 2011, subject to the satisfaction of certain customary conditions to closing.  OTP intends to use a portion of the proceeds of the 2021 Notes to retire $90 million aggregate principal amount of OTP’s 6.63% Senior Notes due December 1, 2011 and $10.4 million aggregate principal amount of its pollution control refunding revenue bonds due December 1, 2012.  The remaining proceeds of the 2021 Notes will be used to repay short-term debt of OTP, to pay fees and expenses related to the issuance of the 2021 Notes and for other general corporate purposes.

 

 

25

---

 

 

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2011 and December 31, 2010:

September 30, 2011 (in thousands)		OTP				Varistar				Otter Tail Corporation				Otter Tail Corporation Consolidated
Short-Term Debt		$	19,010		$	65				$	20,000			$	39,075
Long-Term Debt:
Senior Unsecured Notes 6.63%, due December 1, 2011		$	90,000											$	90,000
Pollution Control Refunding Revenue Bonds,   Variable, 1.50% at September 30, 2011, due December 1, 2012			10,400												10,400
9.000% Notes, due December 15, 2016										$	100,000				100,000
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			5,090												5,090
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			20,105												20,105
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
Other Obligations - Various up to 13.31% at September 30, 2011						$	4,220				1,929				6,149
Total		$	280,595			$	4,220			$	151,929			$	436,744
Less: Current Maturities			--				3,124				162				3,286
Unamortized Debt Discount			--				--				4				4
Total Long-Term Debt		$	280,595			$	1,096			$	151,763			$	433,454
Total Short-Term and Long-Term Debt (with current maturities)		$	299,605			$	4,285			$	171,925			$	475,815

December 31, 2010 (in thousands)		OTP				Varistar				Otter Tail Corporation				Otter Tail Corporation Consolidated
Short-Term Debt		$	25,314		$	--				$	54,176			$	79,490
Long-Term Debt:
Senior Unsecured Notes 6.63%, due December 1, 2011		$	90,000											$	90,000
Pollution Control Refunding Revenue Bonds,   Variable, 2.50% at December 31, 2010, due December 1, 2012			10,400												10,400
9.000% Notes, due December 15, 2016										$	100,000				100,000
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			5,100												5,100
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			20,215												20,215
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
Other Obligations - Various up to 13.31% at December 31, 2010						$	4,706								4,706
Total		$	280,715			$	4,706			$	150,000			$	435,421
Less: Current Maturities			--				604				--				604
Unamortized Debt Discount			--				--				5				5
Total Long-Term Debt		$	280,715			$	4,102			$	149,995			$	434,812
Total Short-Term and Long-Term Debt (with current maturities)		$	306,029			$	4,706			$	204,171			$	514,906

 

26

---

 

 

11. Class B Stock Options of Subsidiary

In conjunction with the sale of IPH on May 6, 2011, all 363 outstanding IPH Class B common share options were cancelled by mutual agreement between the issuer and the holders of the options and a liability to the holders of the options was established based on the fair value of the options on May 6, 2011. The liability was assumed by the new owner of IPH. The options were adjusted to their fair value based on the fair value of an underlying share of Class B Common Stock of $2,973.90 per share on May 6, 2011. The book value of IPH Class B common share options prior to their cancellation on May 6, 2011 was based on an IPH Class B common share value of $2,085.88 per share. The $322,000 difference between the fair value and book value of the options was charged to retained earnings and earnings available for common shares were reduced by $322,000 in the second quarter of 2011.

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 September 30,								Nine Months Ended September 30,
(in thousands)		2011				2010				2011				2010
Service Cost—Benefit Earned During the Period		$	961			$	997			$	3,311			$	3,491
Interest Cost on Projected Benefit Obligation			3,150				2,990				9,500				9,050
Expected Return on Assets			(3,530	)			(3,483	)			(10,605	)			(10,283	)
Amortization of Prior-Service Cost			125				172				325				512
Amortization of Net Actuarial Loss			663				511				1,963				1,501
Net Periodic Pension Cost		$	1,369			$	1,187			$	4,494			$	4,271

The Company did not make a contribution to its pension plan in the nine months ended September 30, 2011 and is not currently required to make a contribution in 2011.

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 September 30,								Nine Months Ended September 30,
(in thousands)		2011				2010				2011				2010
Service Cost—Benefit Earned During the Period		$	20			$	165			$	61			$	495
Interest Cost on Projected Benefit Obligation			407				417				1,223				1,253
Amortization of Prior-Service Cost			18				19				55				55
Amortization of Net Actuarial Loss			62				120				184				358
Net Periodic Pension Cost		$	507			$	721			$	1,523			$	2,161

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

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)		2011				2010				2011				2010
Service Cost—Benefit Earned During the Period		$	425			$	375			$	1,275			$	1,225
Interest Cost on Projected Benefit Obligation			850				855				2,550				2,405
Amortization of Transition Obligation			187				187				561				561
Amortization of Prior-Service Cost			50				58				150				158
Amortization of Net Actuarial Loss			213				248				639				624
Effect of Medicare Part D Expected Subsidy			(525	)			(558	)			(1,575	)			(1,558	)
Net Periodic Postretirement Benefit Cost		$	1,200			$	1,165			$	3,600			$	3,415

 

 

27

---

 

13. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and Short-Term Investments —The carrying amount approximates fair value because of the short-term maturity of those instruments.

Long-Term Debt —The fair value of the Company's long-term debt is estimated based on the current rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value.

		September 30, 2011								December 31, 2010
(in thousands)		Carrying Amount				Fair Value				Carrying Amount				Fair Value
Cash and Short-Term Investments		$	6,604			$	6,604			$	--			$	--
Long-Term Debt			(433,454	)			(479,567	)			(434,812	)			(474,307	)

15. Income Tax Expense (Benefit) – Continuing Operations

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)		2011				2010				2011				2010
Income (Loss) Before Income Taxes – Continuing Operations		$	8,983			$	3,454			$	22,700			$	(15,379	)
Income Tax Expense (Benefit) – Continuing Operations			2,109				(607	)			4,194				(6,625	)
Effective Income Tax Rate – Continuing Operations			23.5	%			(17.6	)%			18.5	%			43.1	%

The increase in Income Tax Expense (Benefit) - Continuing Operations for the three months ended September 30, 2011 compared with the three months ended September 30, 2010 is mainly due to the increase in income before income taxes between the quarters, but also due to DMI deferring recognition of tax benefits in the third quarter of 2011 on the operating losses of its Canadian wind tower manufacturing company until those operations become profitable. DMI’s deferred tax benefits totaled $0.5 million in the third quarter of 2011. The Company’s effective income tax rates for the three months ended September 30, 2011 and 2010 were decreased as a result of recording $1.4 million and $1.6 million, respectively, in federal production tax credits (PTCs) earned on kilowatt-hours (kwhs) generated from tax credit qualified wind turbines owned by OTP.

The increase in Income Tax Expense (Benefit) - Continuing Operations for the nine months ended September 30, 2011 compared with the nine months ended September 30, 2010 is mainly due to the increase in income before income taxes between the periods.  Also, only $2.8 million of ShoreMaster’s $12.2 million second quarter 2010 goodwill impairment loss was deductible for income taxes and DMI is deferring recognition of tax benefits in the first nine months of 2011 on the operating losses of its Canadian wind tower manufacturing company until those operations become profitable. DMI’s 2011 deferred tax benefits totaled $2.4 million through September 30, 2011. The Company’s effective income tax rates for the nine months ended September 30, 2011 and 2010 were decreased as a result of recording $5.3 million and $4.7 million, respectively, in federal PTCs earned on kwhs generated from tax credit qualified wind turbines owned by OTP.

 

 

28

---

 

 

17. Discontinued Operations

On May 6, 2011, the Company completed the sale of IPH to affiliates of Novacap Industries III, L.P. for approximately $87.0 million in cash. The proceeds from the sale, net of $3.0 million deposited in an escrow account, were used to pay down borrowings under the Otter Tail Corporation Credit Agreement. In the second quarter of 2011, Wylie decided to exit its heavy haul/specialized shipment and transportation of wind turbine components business, determining that the risks associated with continuing to provide these services outweighed any potential profits to be derived from these operations. The financial position, results of operations, and cash flows of IPH and Wylie’s specialized shipment and transportation of wind turbine components business are reported as discontinued operations in the Company’s consolidated financial statements as of September 30, 2011 and December 31, 2010, and for the three and nine month periods ended September 30, 2011 and 2010. Following are summary presentations of the results of discontinued operations for the three and nine month periods ended September 30, 2011 and 2010 and of the major components of assets and liabilities of discontinued operations as of September 30, 2011 and December 31, 2010:

		Three Months Ended
		September 30, 2011												September 30, 2010
(in thousands)		IPH				Wylie-Wind				Total				IPH				Wylie-Wind				Total
Operating Revenues		$	--			$	--			$	--			$	19,478			$	2,046			$	21,524
Income (Loss) Before Income Taxes		$	--			$	(86	)		$	(86	)		$	3,183			$	82			$	3,265
Gain (Loss) on Disposition - Pretax			(756	)			--				(756	)			--				--				--
Income Tax Expense (Benefit)			(302	)			(34	)			(336	)			1,192				33				1,225
Net Income (Loss)		$	(454	)		$	(52	)		$	(506	)		$	1,991			$	49			$	2,040

		Nine Months Ended
		September 30, 2011												September 30, 2010
(in thousands)		IPH				Wylie-Wind				Total				IPH				Wylie-Wind				Total
Operating Revenues		$	28,125			$	5,448			$	33,573			$	56,648			$	4,700			$	61,348
Income (Loss) Before Income Taxes		$	3,840			$	(4,650	)		$	(810	)		$	8,306			$	129			$	8,435
Gain on Disposition - Pretax			16,011				--				16,011				--				--				--
Income Tax Expense (Benefit)			4,675				(1,860	)			2,815				3,029				52				3,081
Net Income (Loss)		$	15,176			$	(2,790	)		$	12,386			$	5,277			$	77			$	5,354

		September 30, 2011								December 31, 2010
(in thousands)		Wylie-Wind				Total				IPH				Wylie-Wind				Total
Current Assets		$	2			$	2			$	24,836			$	2,461			$	27,297
Goodwill			--				--				24,324				--				24,324
Other Intangibles - Net			--				--				10,852				--				10,852
Net Plant			75				75				30,672				638				31,310
Assets of Discontinued Operations		$	77			$	77			$	90,684			$	3,099			$	93,783
Current Liabilities		$	77			$	77			$	6,839			$	4,150			$	10,989
Deferred Income Taxes			--				--				11,553				--				11,553
Long-Term Debt			--				--				634				--				634
Liabilities of Discontinued Operations		$	77			$	77			$	19,026			$	4,150			$	23,176

 

29

---

 

 

Because IPH was a material subsidiary, the Company is providing the following pro forma summary presentations of its consolidated income statements for the years ended December 31, 2010 and 2009, reflecting the classification of IPH’s results as discontinued operations:

 

Otter Tail Corporation Summary Consolidated Income Statements For the Years Ended December 31,
		2010												2009
(in thousands, except per share amounts)		As Previously Reported				IPH 1				With IPH classified as Discontinued Operations				As Previously Reported				IPH 1				With IPH classified as Discontinued Operations
Operating Revenues		$	1,119,084			$	77,202			$	1,041,882			$	1,039,512			$	78,632			$	960,880
Operating Expenses:
Cost of Goods Sold			600,956				56,619				544,337				565,192				58,718				506,474
Other Operating Expenses			402,919				3,729				399,190				355,322				3,330				351,992
Depreciation Expense			80,696				4,703				75,993				73,608				4,333				69,275
Total Operating Expenses			1,084,571				65,051				1,019,520				994,122				66,381				927,741
Operating Income			34,513				12,151				22,362				45,390				12,251				33,139
Other Income (Deductions)			5,126				(408	)			5,534				4,550				(404	)			4,954
Interest Charges			37,032				29				37,003				28,514				30				28,484
Income Tax Expense (Benefit)			3,951				3,716				235				(4,605	)			4,410				(9,015	)
Net Income - Continuing Operations			(1,344	)			7,998				(9,342	)			26,031				7,407				18,624
Net Income – Discontinued Operations											7,998												7,407
Net Income (Loss)			(1,344	)			7,998				(1,344	)			26,031				7,407				26,031
Preferred Dividend Requirements			833				--				833				736				--				736
Earnings Available for Common Shares		$	(2,177	)		$	7,998			$	(2,177	)		$	25,295			$	7,407			$	25,295
Basic Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)		$	(0.06	)		$	0.22			$	(0.28	)		$	0.71			$	0.21			$	0.50
Discontinued Operations											0.22												0.21
										$	(0.06	)										$	0.71
Diluted Earnings Per Common Share:
Continuing Operations (net of preferred dividend requirement)		$	(0.06	)		$	0.22			$	(0.28	)		$	0.71			$	0.21			$	0.50
Discontinued Operations											0.22												0.21
										$	(0.06	)										$	0.71
1 Includes reinstatement of intercompany eliminations related to intercompany transactions with IPH.

 

 

30

---