a6813580.htm
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 10-Q

(Mark One)
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended
June 30, 2011

OR

[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from
 
to
   

 Commission file number
           0-53713

OTTER TAIL CORPORATION
(Exact name of registrant as specified in its charter)

              Minnesota
27-0383995
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)

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

866-410-8780
(Registrant's telephone number, including area code)
 
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.      YES  X      NO     

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer X
Accelerated filer __
 
Non-accelerated filer __
(Do not check if a smaller reporting company)
Smaller reporting company  __

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).  YES__    NO X 
 
Indicate the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date:

July 31, 2011 – 36,061,873 Common Shares ($5 par value)
 
 
 

 
 
OTTER TAIL CORPORATION

INDEX

Page No.
   
 
     
 
2 & 3
     
 
4
     
 
5
     
 
6-28
     
29-49
     
49-51
     
51
     
 
     
52
     
52-53
     
54
     
54
     
54
 
 
1

 
 
PART I. FINANCIAL INFORMATION
 
   
Item 1. Financial Statements
 
   
Otter Tail Corporation
 
Consolidated Balance Sheets
 
(not audited)
 
   
(in thousands)
 
June 30,
2011
   
December 31,
2010
 
       
ASSETS
           
             
Current Assets
           
  Cash and Cash Equivalents
  $ --     $ --  
  Accounts Receivable:
               
    Trade—Net
    148,252       124,353  
    Other
    14,554       19,399  
  Inventories
    86,235       79,270  
  Deferred Income Taxes
    12,096       11,068  
  Accrued Utility and Cost-of-Energy Revenues
    11,818       16,323  
  Costs and Estimated Earnings in Excess of Billings
    71,688       67,352  
  Income Taxes Receivable
    --       4,146  
  Other
    21,017       20,224  
  Assets of Discontinued Operations
    2,537       93,783  
    Total Current Assets
    368,197       435,918  
                 
Investments
    12,872       9,708  
Other Assets
    28,581       27,356  
Goodwill
    69,742       69,742  
Other Intangibles—Net
    15,932       16,280  
                 
Deferred Debits
               
  Unamortized Debt Expense
    6,267       6,444  
  Regulatory Assets
    114,514       127,766  
    Total Deferred Debits
    120,781       134,210  
                 
Plant
               
  Electric Plant in Service
    1,336,640       1,332,974  
  Nonelectric Operations
    365,642       340,167  
  Construction Work in Progress
    56,330       42,031  
    Total Gross Plant
    1,758,612       1,715,172  
  Less Accumulated Depreciation and Amortization
    666,570       637,831  
    Net Plant
    1,092,042       1,077,341  
                 
      Total Assets
  $ 1,708,147     $ 1,770,555  
See accompanying notes to consolidated financial statements.
               
 
 
2

 
 
   
Otter Tail Corporation
 
Consolidated Balance Sheets
 
(not audited)
 
   
(in thousands, except share data)
 
June 30,
2011
   
December 31,
2010
 
             
LIABILITIES AND EQUITY
           
             
Current Liabilities
           
  Short-Term Debt
  $ 30,362     $ 79,490  
  Current Maturities of Long-Term Debt
    3,340       604  
  Accounts Payable
    121,020       113,761  
  Accrued Salaries and Wages
    20,247       20,252  
  Accrued Federal and State Income Taxes
    504       --  
  Other Accrued Taxes
    8,392       11,957  
  Derivative Liabilities
    18,683       17,991  
  Other Accrued Liabilities
    8,464       9,546  
  Liabilities of Discontinued Operations
    2,537       23,176  
    Total Current Liabilities
    213,549       276,777  
                 
Pensions Benefit Liability
    75,470       73,538  
Other Postretirement Benefits Liability
    43,187       42,372  
Other Noncurrent Liabilities
    20,526       21,043  
                 
Commitments (note 9)
               
                 
Deferred Credits
               
  Deferred Income Taxes
    173,561       162,208  
  Deferred Tax Credits
    34,125       44,945  
  Regulatory Liabilities
    68,275       66,416  
  Other
    488       556  
    Total Deferred Credits
    276,449       274,125  
                 
Capitalization
               
  Long-Term Debt, Net of Current Maturities
    433,715       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—36,061,173 Shares; 2010—36,002,739 Shares
    180,306       180,014  
  Premium on Common Shares
    251,530       251,919  
  Retained Earnings
    200,839       198,443  
  Accumulated Other Comprehensive (Loss) Income
    (2,924 )     1,487  
    Total Common Equity
    629,751       631,863  
                 
      Total Capitalization
    1,078,966       1,082,700  
                 
        Total Liabilities and Equity
  $ 1,708,147     $ 1,770,555  
See accompanying notes to consolidated financial statements.
   
 
 
3

 
 
Otter Tail Corporation
 
Consolidated Statements of Income
 
(not audited)
 
   
   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
(in thousands, except share and per-share amounts)
 
2011
   
2010
   
2011
   
2010
 
                         
Operating Revenues
                       
  Electric
  $ 77,977     $ 77,476     $ 169,502     $ 168,857  
  Nonelectric
    238,998       173,838       428,831       325,406  
    Total Operating Revenues
    316,975       251,314       598,333       494,263  
                                 
Operating Expenses
                               
  Production Fuel - Electric
    17,080       16,492       36,657       37,401  
  Purchased Power - Electric System Use
    7,894       10,420       20,271       22,476  
  Electric Operation and Maintenance Expenses
    28,687       29,253       57,395       57,719  
  Cost of Goods Sold - Nonelectric (excludes depreciation; included below)
    193,830       137,012       349,539       254,496  
  Other Nonelectric Expenses
    32,765       32,463       60,307       61,229  
  Asset Impairment Charge
    --       19,740       --       19,740  
  Depreciation and Amortization
    19,725       18,655       38,811       37,229  
  Property Taxes - Electric
    2,417       2,477       4,826       4,951  
    Total Operating Expenses
    302,398       266,512       567,806       495,241  
                                 
Operating Income (Loss)
    14,577       (15,198 )     30,527       (978 )
                                 
Other Income
    1,107       552       1,828       565  
Interest Charges
    9,149       9,398       18,638       18,420  
Income (Loss) Before Income Taxes – Continuing Operations
    6,535       (24,044 )     13,717       (18,833 )
Income Tax Expense (Benefit) – Continuing Operations
    537       (7,769 )     2,085       (6,018 )
Net Income (Loss) from Continuing Operations
    5,998       (16,275 )     11,632       (12,815 )
Discontinued Operations
                               
  Income (Loss) from Discontinued Operations net of income tax expense
                               
    (benefit) of $(342), $1,227, $(364), and $1,856 for the respective periods
    (422 )     2,057       (360 )     3,314  
  Gain on Disposition of Discontinued Operations net of income taxes
                               
    of $3,515 for the three and six months ended June 30, 2011
    13,252       --       13,252       --  
Net Income from Discontinued Operations
    12,830       2,057       12,892       3,314  
Total Net Income (Loss)
    18,828       (14,218 )     24,524       (9,501 )
Preferred Dividend Requirement and Other Adjustments
    506       279       690       463  
Earnings Available for Common Shares
  $ 18,322     $ (14,497 )   $ 23,834     $ (9,964 )
                                 
Average Number of Common Shares Outstanding—Basic
    35,926,124       35,799,231       35,901,489       35,759,901  
Average Number of Common Shares Outstanding—Diluted
    36,163,805       35,799,231       36,139,170       35,759,901  
                                 
Basic Earnings Per Common Share:
                               
  Continuing Operations (net of preferred dividend requirement)
  $ 0.16     $ (0.46 )   $ 0.31     $ (0.37 )
  Discontinued Operations (net of other adjustments)
    0.35       0.06       0.35       0.09  
    $ 0.51     $ (0.40 )   $ 0.66     $ (0.28 )
                                 
Diluted Earnings Per Common Share:
                               
  Continuing Operations (net of preferred dividend requirement)
  $ 0.16     $ (0.46 )   $ 0.31     $ (0.37 )
  Discontinued Operations (net of other adjustments)
    0.35       0.06       0.35       0.09  
    $ 0.51     $ (0.40 )   $ 0.66     $ (0.28 )
                                 
Dividends Per Common Share
  $ 0.2975     $ 0.2975     $ 0.5950     $ 0.5950  
See accompanying notes to consolidated financial statements.
                               
 
 
4

 
 
Otter Tail Corporation
 
Consolidated Statements of Cash Flows
 
(not audited)
 
   
Six Months Ended
June 30,
 
(in thousands)
 
2011
   
2010
 
Cash Flows from Operating Activities
           
  Net Income (Loss)
  $ 24,524     $ (9,501 )
  Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
               
    Net Gain from Sale of Discontinued Operations
    (13,252 )     --  
    Net Loss (Income) from Discontinued Operations
    360       (3,314 )
    Depreciation and Amortization
    38,811       37,229  
    Asset Impairment Charge
    --       19,740  
    Deferred Tax Credits
    (1,281 )     (1,358 )
    Deferred Income Taxes
    5,611       7,547  
    Change in Deferred Debits and Other Assets
    7,648       (858 )
    Change in Noncurrent Liabilities and Deferred Credits
    1,230       4,471  
    Allowance for Equity (Other) Funds Used During Construction
    (292 )     --  
    Change in Derivatives Net of Regulatory Deferral
    45       (409 )
    Stock Compensation Expense – Equity Awards
    921       1,320  
    Other—Net
    (243 )     (389 )
  Cash (Used for) Provided by Current Assets and Current Liabilities:
               
    Change in Receivables
    (18,936 )     (20,998 )
    Change in Inventories
    (6,966 )     (4,083 )
    Change in Other Current Assets
    (2,594 )     (15,874 )
    Change in Payables and Other Current Liabilities
    4,727       (276 )
    Change in Interest Payable and Income Taxes Receivable/Payable
    377       36,594  
      Net Cash Provided by Continuing Operations
    40,690       49,841  
      Net Cash Provided by (Used in) Discontinued Operations
    47       (422 )
        Net Cash Provided by Operating Activities
    40,737       49,419  
Cash Flows from Investing Activities
               
  Capital Expenditures
    (48,111 )     (38,605 )
  Proceeds from Disposal of Noncurrent Assets
    2,229       1,999  
  Net Decrease (Increase) in Other Investments
    837       (808 )
      Net Cash Used in Investing Activities - Continuing Operations
    (45,045 )     (37,414 )
      Net Proceeds from Sale of Discontinued Operations
    84,363       --  
      Net Cash Used in Investing Activities - Discontinued Operations
    (6,065 )     (960 )
    Net Cash Provided by (Used in) Investing Activities
    33,253       (38,374 )
Cash Flows from Financing Activities
               
  Change in Checks Written in Excess of Cash
    (5,937 )     4,987  
  Net Short-Term Borrowings
    (49,128 )     60,002  
  Proceeds from Issuance of Common Stock
    --       549  
  Proceeds from Issuance of Class B Stock of Subsidiary
    --       153  
  Common Stock Issuance Expenses
    --       (142 )
  Payments for Retirement of Common Stock
    (152 )     (401 )
  Payments for Retirement of Class B Stock of Subsidiary
    --       (994 )
  Proceeds from Issuance of Long-Term Debt
    2,007       95  
  Short-Term and Long-Term Debt Issuance Expenses
    (688 )     (1,598 )
  Payments for Retirement of Long-Term Debt
    (368 )     (58,693 )
  Dividends Paid and Other Distributions
    (21,952 )     (21,812 )
      Net Cash Used in Financing Activities - Continuing Operations
    (76,218 )     (17,854 )
      Net Cash Provided by Financing Activities - Discontinued Operations
    2,552       2,241  
    Net Cash Used in Financing Activities
    (73,666 )     (15,613 )
Cash and Cash Equivalents at Beginning of Period – Discontinued Operations
    --       (609 )
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations
    (324 )     136  
Net Change in Cash and Cash Equivalents
    --       (5,041 )
Cash and Cash Equivalents at Beginning of Period
    --       5,041  
Cash and Cash Equivalents at End of Period
  $ --     $ --  
See accompanying notes to consolidated financial statements.
               
 
 
5

 
 
OTTER TAIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes as of and for the years ended December 31, 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 six month periods ended June 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 Accounting Standards Codification (ASC) 815-10-45-9. 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
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2011
   
2010
   
2011
   
2010
 
Percentage-of-Completion Revenues
    33.9     27.6     32.8     26.7

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

   
June 30,
   
December 31,
 
(in thousands)
 
2011
   
2010
 
Costs Incurred on Uncompleted Contracts
  $ 464,849     $ 460,125  
Less Billings to Date
    (418,120     (430,471 )   
Plus Estimated Earnings Recognized
    22,085       31,231  
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts
  $ 68,814     $ 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:

 
 
June 30,
   
December 31,
 
(in thousands)
 
2011
   
2010
 
Costs and Estimated Earnings in Excess of Billings
  $ 71,688     $ 67,352  
Billings in Excess of Costs and Estimated Earnings
    (2,874     (6,467
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts
  $ 68,814     $ 60,885  

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

 
 
June 30,
   
December 31,
 
(in thousands)
 
2011
   
2010
 
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI
  $ 60,410     $ 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. The warranty reserve balance was $2,956,000 as of June 30, 2011. 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.
 
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:

 
 
June 30,
   
December 31,
 
(in thousands)
 
2011
   
2010
 
Accounts Receivable Retained by Customers
  $ 10,643     $ 11,848  
 
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
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
Accounts Receivable Sold
  $ 9,092     $ 18,500     $ 28,140     $ 29,300  
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable
    135       75       253       107  
 
 
 
7

 
 
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 and requires enhanced disclosures about assets and liabilities measured at fair value. ASC 820-10-35 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.

The following table presents, for each of these hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2011 and December 31, 2010:

June 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
  $ 804     $ --    
Forward Gasoline Purchase Contracts
    131            
Forward Energy Contracts
            4,832    
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts
            14,646    
Investments of Captive Insurance Company:
                 
Corporate Debt Securities
    8,885            
  Total Assets
  $ 9,820     $ 19,478    
Liabilities:
                 
Forward Energy Contracts
  $ --     $ 18,683    
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts
            149    
  Total Liabilities
  $ --     $ 18,832    

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    
 
 
8

 

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 six months ended June 30, 2010 reflect the reclassifications of the assets and liabilities, operating results and cash flows of Idaho Pacific Holdings, Inc. (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 decisions to sell IPH and to exit the heavy haul and specialized shipment and transportation of wind turbine components business. The Company reached an agreement to sell 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 six months ended June 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
   
Six Months Ended
 
(in thousands)
 
June 30, 2010
   
June 30, 2010
 
MNCIP Incentives reclassified from Other Income to Operating Revenue
  $ 1,239     $ 1,601  

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

Inventories
Inventories consist of the following:

   
June 30,
   
December 31,
 
(in thousands)
 
2011
   
2010
 
Finished Goods
  $ 30,519     $ 29,113  
Work in Process
    11,428       7,171  
Raw Material, Fuel and Supplies
    44,288       42,986  
Total Inventories
  $ 86,235     $ 79,270  

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

 
(in thousands)
 
Balance
December 31,
2010
   
Impairments
   
Balance (net of
impairments)
December 31,
2010
   
Adjustments
to Goodwill
in 2011
   
Balance (net of
impairments)
June 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  
 
 
9

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

June 30, 2011 (in thousands)
 
Gross Carrying
Amount
   
Accumulated
Amortization
   
Net Carrying
Amount
 
Amortization
Periods
Amortized Intangible Assets:
                   
  Customer Relationships
  $ 16,811     $ 2,812     $ 13,999  
15 – 25 years
  Covenants Not to Compete
    1,704       1,694       10  
3 – 5 years
  Other Intangible Assets Including Contracts
    1,030       897       133  
5 – 30 years
    Total
  $ 19,545     $ 5,403     $ 14,142    
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
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
Amortization Expense – Intangible Assets
  $ 224     $ 263     $ 448     $ 546  

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

Comprehensive Income

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
Net Income (Loss)
  $ 18,828     $ (14,218   $ 24,524     $ (9,501
Other Comprehensive (Loss) Income (net-of-tax):
                               
Reversal of Previously Recorded Foreign Currency Translation Gains
    (4,422     (676     (3,977     (188
Amortization of Unrecognized Losses and Costs
  Related to Postretirement Benefit Programs
    428       104       (442     209  
Unrealized Gain (Loss) on Available-for-Sale Securities
    18       (8     8       31  
      Total Other Comprehensive (Loss) Income
    (3,976     (580     (4,411     52  
Total Comprehensive Income (Loss)
  $ 14,852     $ (14,798 )   $ 20,113     $ (9,449 )

Supplemental Disclosures of Cash Flow Information

   
Six Months Ended
 
   
June 30,
 
(in thousands)
 
2011
   
2010
 
Increases in Accounts Payable Related to Capital Expenditures
  $ 237     $ 745  
 
 
10

 
 
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.

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 11.7% of the Company’s consolidated revenues in the first six 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.
 
 
11

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

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2011
   
2010
   
2011
   
2010
 
  United States of America
    97.8     98.6     98.2     97.9
  Canada
    2.0     1.2     1.7     2.0
  All Other Countries
    0.2     0.2     0.1     0.1

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for three and six month periods ended June 30, 2011 and 2010 and total assets by business segment as of June 30, 2011 and December 31, 2010 are presented in the following tables:

Operating Revenue

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
  Electric
  $ 78,031     $ 77,527     $ 169,627     $ 168,979  
  Wind Energy
    66,253       45,714       122,527       94,375  
  Manufacturing
    58,358       49,507       114,671       87,538  
  Construction
    49,133       30,149       86,648       47,923  
  Plastics
    44,373       26,739       62,851       49,826  
  Health Services
    22,983       23,645       45,478       48,816  
  Corporate Revenues and Intersegment Eliminations
    (2,156     (1,967     (3,469     (3,194
    Total
  $ 316,975     $ 251,314     $ 598,333     $ 494,263  

Interest Charges

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
  Electric
  $ 4,990     $ 5,349     $ 10,078     $ 10,619  
  Wind Energy
    2,013       1,549       3,881       2,870  
  Manufacturing
    1,355       1,294       2,661       2,541  
  Construction
    227       155       447       273  
  Plastics
    402       428       765       791  
  Health Services
    445       280       844       525  
  Corporate and Intersegment Eliminations
    (283     343       (38     801  
    Total
  $ 9,149     $ 9,398     $ 18,638     $ 18,420  

Income Tax Expense (Benefit) - Continuing Operations

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
  Electric
  $ 7     $ (529   $ 2,608     $ 4,305  
  Wind Energy
    (2,148     (1,615     (3,813     (1,524
  Manufacturing
    1,529       (3,833     3,059       (4,451
  Construction
    130       (306     (80     (1,307
  Plastics
    2,144       141       1,903       635  
  Health Services
    339       55       748       (377
  Corporate
    (1,464     (1,682     (2,340     (3,299
    Total
  $ 537     $ (7,769   $ 2,085     $ (6,018
 
 
12

 
 
Earnings Available for Common Shares

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
  Electric
  $ 7,386     $ 4,432     $ 18,528     $ 11,923  
  Wind Energy
    (6,535     (2,815     (12,946     (2,635
  Manufacturing
    2,721       (15,116     4,988       (15,851
  Construction
    184       (493     (141     (1,982
  Plastics
    3,312       232       2,938       1,013  
  Health Services
    458       35       1,030       (656
  Corporate
    (1,712     (2,733     (3,133     (4,994
  Discontinued Operations
    12,508       1,961       12,570       3,218  
    Total
  $ 18,322     $ (14,497 )     $ 23,834     $ (9,964

Total Assets

   
June 30,
   
December 31,
 
(in thousands)
 
2011
   
2010
 
  Electric
  $ 1,092,111     $ 1,106,261  
  Wind Energy
    181,884       172,753  
  Manufacturing
    157,199       144,272  
  Construction
    65,351       60,978  
  Plastics
    94,035       73,508  
  Health Services
    73,650       75,898  
  Corporate
    41,380       43,102  
  Discontinued Operations
    2,537       93,783  
    Total
  $ 1,708,147     $ 1,770,555  

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 with a 3.8% interim rate increase request. On May 27, 2010, the Minnesota Public Utilities Commission (MPUC) issued an order accepting the filing, suspending rates, and approving an interim rate increase of 3.8% 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). When these changes to recovery mechanisms are taken into account, the overall increase to customers will be approximately 1.6% compared to the authorized interim rate increase of 3.8%, which will result in an interim rate refund of approximately $3.9 million. OTP accrued a $2.3 million refund liability in the first quarter of 2011 and an additional $1.2 million in the second quarter of 2011 for revenue billed under interim rates from June 1, 2010 through June 30, 2011. OTP expects the refund to be distributed to Minnesota customers during the fourth quarter of 2011. 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. On May 16, 2011, OTP requested that the MPUC reconsider its decisions on test year pension costs, the impact of accumulated pension contributions, a sales adjustment, and clarification of the expenses related to pension and other benefits. The MPUC denied all of OTP’s petitions for reconsideration and clarification on June 23, 2011. Final rates are anticipated to become effective October 1, 2011.
 
 
13

 
 
OTP has a regulatory asset of $4.1 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 June 30, 2011. Except for the balance of this regulatory asset and any amount necessary to true-up amounts undercollected while the current MNRRA rider rate has been in effect, the recovery of MNRRA costs will be moved to base rates in October 2011 under the MPUC’s April 25, 2011 general rate case order.

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. The transmission investments for two projects currently in the TCR will continue to be recovered through OTP’s Minnesota TCR rider until final rates go into effect in October 2011. 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.

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.

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 also 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 a revenue increase of approximately $643,000 with an overall rate of return on rate base of 8.50%. Final rates went into effect on 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 request is expected to be on the SDPUC agenda in fall 2011.

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.
 
 
14

 
 
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. Construction is expected to begin in the fall of 2011 on the line section between St. Cloud and Alexandria, Minnesota.

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. It is expected that a route permit application will be filed with the NDPSC in the third quarter of 2011. Due to the postponement of the CCC hearing, the NDPSC will conduct a joint process going forward pertaining to the CCC and North Dakota route permit applications.
 
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.

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 have engaged in mediated settlement discussions with the federal magistrate judge. The LLBO’s motion to dismiss the declaratory judgment action is currently scheduled to be heard on September 16, 2011.

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 and the NDPSC scheduled a working session for August 5, 2011 to discuss the matter.
 
 
15

 
 
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. Under the South Dakota Implementation Plan, and its implementing rules that became effective in December 2010, 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). On June 17, 2011, the ALJ entered a scheduling order that calls for evidentiary hearings from August 17-19, 2011, with an ALJ report and recommendation by September 30, 2011. Because of the Minnesota government shutdown in July 2011, these dates have changed to a hearing date of September 14-16, 2011 with an ALJ report by November 4, 2011. OTP filed an application for an ADP with the NDPSC on May 20, 2011 with a decision expected by December 20, 2011. The 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 expected to begin in October 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 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.
 
 
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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:

   
 
   
 
   
(in thousands)
 
June 30,
2011
   
December 31,
2010
 
Remaining
Recovery/
Refund Period
Regulatory Assets - Current:
             
Accrued Cost-of-Energy Revenue
  $ 525     $ 2,387  
14 months
Regulatory Assets – Long Term:
                 
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
  $ 71,264     $ 74,156  
see notes
Deferred Marked-to-Market Losses
    14,646       12,054  
50 months
Deferred Conservation Improvement Program Costs & Accrued Incentives
    7,569       6,655  
24 months
Minnesota Renewable Resource Rider Accrued Revenues
    4,057       6,834  
33 months
Big Stone II Unrecovered Project Costs – North Dakota
    2,768       3,460  
25 months
Big Stone II Unrecovered Project Costs – Minnesota
    2,758       6,445  
63 months
Debt Reacquisition Premiums
    2,664       3,107  
255 months
Accumulated ARO Accretion/Depreciation Adjustment
    2,434       2,218  
asset lives
Deferred Income Taxes
    1,644       5,785  
asset lives
General Rate Case Recoverable Expenses
    1,373       1,773  
31 months
North Dakota Renewable Resource Rider Accrued Revenues
    1,053       2,415  
30 months
Big Stone II Unrecovered Project Costs – South Dakota
    962       1,419  
115 months
MISO Schedule 16 and 17 Deferred Administrative Costs - ND
    530       717  
17 months
South Dakota – Asset-Based Margin Sharing Shortfall
    375       501  
8 months
Minnesota Transmission Rider Accrued Revenues
    252       34  
18 months
Deferred Holding Company Formation Costs
    165       193  
36 months
Total Regulatory Assets – Long Term
  $ 114,514     $ 127,766    
Regulatory Liabilities:
                 
Accumulated Reserve for Estimated Removal Costs – Net of Salvage
  $ 63,242     $ 61,740  
asset lives
Deferred Income Taxes
    4,007       4,289  
asset lives
Minnesota Transmission Rider Accrued Refund
    677       --  
see notes
Deferred Marked-to-Market Gains
    149       175  
38 months
Deferred Gain on Sale of Utility Property – Minnesota Portion
    125       128  
270 months
South Dakota – Nonasset-Based Margin Sharing Excess
    75       84  
18 months
Total Regulatory Liabilities
  $ 68,275     $ 66,416    
Net Regulatory Asset Position
  $ 46,764     $ 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 June 30, 2011 are related to forward purchases of energy scheduled for delivery through August 2015.
 
 
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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 June 30, 2011.

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.
 
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 255 months.

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

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 June 30, 2011.

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 June 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.
 
 
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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 820-10-35.

The following tables show the effect of marking to market forward contracts for the purchase and sale of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of June 30, 2011 and December 31, 2010, and the change in the Company’s consolidated balance sheet position from December 31, 2010 to June 30, 2011:

 (in thousands)
 
June 30,
2011
   
December 31,
2010
 
Current Asset – Marked-to-Market Gain
  $ 4,832     $ 6,875  
Regulatory Asset – Deferred Marked-to-Market Loss
    14,646       12,054  
  Total Assets
    19,478       18,929  
Current Liability – Marked-to-Market Loss
    (18,683 )     (17,991 )
Regulatory Liability – Deferred Marked-to-Market Gain
    (149 )     (175 )
  Total Liabilities
    (18,832 )     (18,166 )
Net Fair Value of Marked-to-Market Energy Contracts
  $ 646     $ 763  

 (in thousands)
 
Year-to-Date
June 30, 2011
 
Fair Value at Beginning of Year
  $ 763  
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011
    (145
      Amounts Realized on Contracts Entered into in 2010 and Settled in 2011
    (6
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
    526  
Changes in Fair Value of Contracts Entered into in 2011
    120  
Net Fair Value End of Period
  $ 646  

The June 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)
 
3rd Quarter 2011
   
4th Quarter 2011
   
2012
   
Total
 
Net Gain
  $ 32     $ 145     $ 469     $ 646  
 
 
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The following realized and unrealized net (losses)/gains on forward energy contracts are included in electric operating revenues on the Company’s consolidated statements of income:

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
Net Gains (Losses) on Forward Electric Energy Contracts
  $ 139     $ (24 )   $ 131     $ 1,801  

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 June 30, 2011 and December 31, 2010:

   
June 30, 2011
   
December 31, 2010
 
(in thousands)
 
Exposure
   
Counterparties
   
Exposure
   
Counterparties
 
Net Credit Risk on Forward Energy Contracts
  $ 1,732       4     $ 1,129       4  
Net Credit Risk to Single Largest Counterparty
  $ 970             $ 585          

OTP had no exposure at June 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 a marked-to-market loss positions as of June 30, 2011 and December 31, 2010:

Current Liability – Marked-to-Market Loss  (in thousands)
 
June 30,
2011
   
December 31,
2010
 
Loss Contracts Covered by Deposited Funds
  $ --     $ 427  
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1
    4,112       10,904  
Loss Contracts with No Ratings Triggers or Deposit Requirements
    14,571       6,660  
Total Current Liability – Marked-to-Market Loss
  $ 18,683     $ 17,991  
1Certain 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
  $ 4,112     $ 10,904  
Offsetting Gains with Counterparties under Master Netting Agreements
    (4,112 )     (6,219 )
Net Deposit Requirements on Contracts with Credit Risk Related Features
  $ --     $ 4,685  
Covered by Deposited Funds
    --       --  
Reporting Date Deposit Requirement if Credit Risk Feature Triggered
  $ --     $ 4,685  
 
 
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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 June 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
    16,475  
Retirements:
       
  Shares Withheld for Individual Income Tax Requirements
    (6,641 )
Common Shares Outstanding, June 30, 2011
    36,061,173  

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 June 30,
Options Outstanding
Range of Exercise Prices
2011
172,460
$24.93 – $31.34
2010
388,960
$24.93 – $31.34

Six Months Ended June 30,
Options Outstanding
Range of Exercise Prices
2011
172,460
$24.93 – $31.34
2010
388,960
$24.93 – $31.34

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
Stock 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.
 
 
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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 June 30, 2011 the remaining unrecognized compensation expense related to stock-based compensation was approximately $3.2 million (before income taxes) which will be amortized over a weighted-average period of 2.8 years.

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

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
(in thousands)
 
2011
   
2010
   
2011
   
2010
 
Employee Stock Purchase Plan (15% discount)
  $ 72     $ 72     $ 134     $ 141  
Restricted Stock Granted to Directors
    195       158       387       298  
Restricted Stock Granted to Employees
    133       162       248       280  
Stock Performance Awards Granted to Executive Officers
    --       (65 )     --       157  
Restricted Stock Units Granted to Employees
    70       97       153       157  
  Totals
  $ 470     $ 424     $ 922     $ 1,033  
 
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: