UNITED STATES 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
   September 30, 2014

OR

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

 Commission file number
 0-53713

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 o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.:
 
Large accelerated filer x Accelerated filer o
   
Non-accelerated filer o Smaller reporting company o
(Do not check if a 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 o No x
 
Indicate the number of shares outstanding of each of the issuer’s classes of Common Stock, as of the latest practicable date:

October 31, 2014 – 36,806,160 Common Shares ($5 par value)
 
 
 

 

 
OTTER TAIL CORPORATION
 
INDEX
 
 
Page No.
   
 
   
 
     
 
2 & 3
     
 
4
     
 
5
     
 
6
     
 
7-36
     
37-56
     
57
     
57
     
 
     
58
     
58
     
58
     
59
 
1
 

 

 
 
   
 
   
Otter Tail Corporation
 
 
(not audited)
 
   
(in thousands)
 
September 30,
2014
   
December 31,
2013
 
       
ASSETS
           
             
Current Assets
           
Cash and Cash Equivalents
  $ --     $ 1,150  
Accounts Receivable:
               
Trade—Net
    105,119       83,572  
Other
    13,687       9,790  
Inventories
    78,939       72,681  
Deferred Income Taxes
    47,228       35,452  
Unbilled Revenues
    15,804       18,157  
Costs and Estimated Earnings in Excess of Billings
    6,271       4,063  
Regulatory Assets
    19,947       17,940  
Other
    10,779       7,747  
Assets of Discontinued Operations
    10       38  
Total Current Assets
    297,784       250,590  
                 
Investments
    8,706       9,362  
Other Assets
    29,856       28,834  
Goodwill
    38,808       38,971  
Other Intangibles—Net
    12,595       13,328  
                 
Deferred Debits
               
Unamortized Debt Expense
    4,147       4,188  
Regulatory Assets
    73,725       83,730  
Total Deferred Debits
    77,872       87,918  
                 
Plant
               
Electric Plant in Service
    1,521,948       1,460,884  
Nonelectric Operations
    197,767       194,872  
Construction Work in Progress
    234,342       187,461  
Total Gross Plant
    1,954,057       1,843,217  
Less Accumulated Depreciation and Amortization
    705,393       676,201  
Net Plant
    1,248,664       1,167,016  
                 
 Total Assets
  $ 1,714,285     $ 1,596,019  
 
See accompanying condensed notes to consolidated financial statements.
 
2
 

 

 
Otter Tail Corporation
 
Consolidated Balance Sheets
 
(not audited)
 
   
(in thousands, except share data)
 
September 30,
2014
   
December 31,
2013
 
             
LIABILITIES AND EQUITY
           
             
Current Liabilities
           
Short-Term Debt
  $ 39,000     $ 51,195  
Current Maturities of Long-Term Debt
    198       188  
Accounts Payable
    107,307       113,457  
Accrued Salaries and Wages
    21,679       19,903  
Billings In Excess Of Costs and Estimated Earnings
    2,508       13,707  
Accrued Taxes
    10,998       12,491  
Derivative Liabilities
    6,520       11,782  
Other Accrued Liabilities
    8,286       6,532  
Liabilities of Discontinued Operations
    3,300       3,637  
Total Current Liabilities
    199,796       232,892  
                 
Pensions Benefit Liability
    50,799       69,743  
Other Postretirement Benefits Liability
    46,083       45,221  
Other Noncurrent Liabilities
    21,890       25,209  
                 
Commitments and Contingencies (note 9)
               
                 
Deferred Credits
               
Deferred Income Taxes
    229,148       195,603  
Deferred Tax Credits
    26,927       28,288  
Regulatory Liabilities
    76,942       73,926  
Other
    918       718  
Total Deferred Credits
    333,935       298,535  
                 
Capitalization
               
Long-Term Debt, Net of Current Maturities
    498,540       389,589  
                 
Cumulative Preferred Shares– Authorized 1,500,000 Shares Without Par Value;
Outstanding - None
    --       --  
                 
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, 2014—36,797,438 Shares; 2013—36,271,696 Shares
    183,987       181,358  
Premium on Common Shares
    267,346       255,759  
Retained Earnings
    113,569       99,441  
Accumulated Other Comprehensive Loss
    (1,660 )     (1,728 )
Total Common Equity
    563,242       534,830  
                 
Total Capitalization
    1,061,782       924,419  
                 
Total Liabilities and Equity
  $ 1,714,285     $ 1,596,019  
 
See accompanying condensed notes to consolidated financial statements.
 
3
 

 

 
Otter Tail Corporation
 
 
(not audited)
 
   
   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
(in thousands, except share and per-share amounts)
 
2014
   
2013
   
2014
   
2013
 
                         
Operating Revenues
                       
Electric
  $ 89,376     $ 86,275     $ 301,328     $ 270,089  
Product Sales
    107,149       95,984       304,527       281,102  
Construction Services
    45,846       47,509       111,599       108,920  
Total Operating Revenues
    242,371       229,768       717,454       660,111  
Operating Expenses
                               
Production Fuel - Electric
    15,121       18,785       49,754       52,341  
Purchased Power - Electric System Use
    10,710       8,691       48,971       36,575  
Electric Operation and Maintenance Expenses
    33,346       30,626       107,742       98,878  
Cost of Products Sold (depreciation included below)
    85,384       74,477       239,501       214,601  
Cost of Construction Revenues Earned (depreciation included below)
    37,767       40,998       94,010       96,873  
Other Nonelectric Expenses
    13,421       12,857       42,086       38,811  
Depreciation and Amortization
    15,122       15,039       44,871       44,794  
Property Taxes - Electric
    3,178       3,163       9,536       9,088  
Total Operating Expenses
    214,049       204,636       636,471       591,961  
Operating Income
    28,322       25,132       80,983       68,150  
Interest Charges
    7,687       6,574       21,909       20,431  
Other Income
    494       1,401       3,175       2,958  
Income Before Income Taxes—Continuing Operations
    21,129       19,959       62,249       50,677  
Income Tax Expense—Continuing Operations
    5,476       5,133       15,250       13,113  
Net Income from Continuing Operations
    15,653       14,826       46,999       37,564  
Discontinued Operations
                               
Income - net of Income Tax Expense (Benefit) of
$116, $39, $166 and ($35) for the respective periods
    172       312       249       428  
Gain on Disposition - net of Income Tax Expense of
$6 for the nine months ended September 30, 2013
    --       --       --       210  
Net Income from Discontinued Operations
    172       312       249       638  
Net Income
    15,825       15,138       47,248       38,202  
Preferred Dividend Requirements and Other Adjustments
    --       --       --       513  
Earnings Available for Common Shares
  $ 15,825     $ 15,138     $ 47,248     $ 37,689  
                                 
Average Number of Common Shares Outstanding—Basic
    36,596,396       36,179,507       36,415,500       36,141,664  
Average Number of Common Shares Outstanding—Diluted
    36,838,990       36,381,900       36,658,257       36,344,063  
                                 
Basic Earnings Per Common Share:
                               
Continuing Operations (net of preferred dividend requirement and other adjustments)
  $ 0.43     $ 0.41     $ 1.29     $ 1.02  
Discontinued Operations
    --       0.01       0.01       0.02  
    $ 0.43     $ 0.42     $ 1.30     $ 1.04  
Diluted Earnings Per Common Share:
                               
Continuing Operations (net of preferred dividend requirement and other adjustments)
  $ 0.43     $ 0.41     $ 1.28     $ 1.02  
Discontinued Operations
    --       0.01       0.01       0.02  
    $ 0.43     $ 0.42     $ 1.29     $ 1.04  
Dividends Declared Per Common Share
  $ 0.3025     $ 0.2975     $ 0.9075     $ 0.8925  
 
See accompanying condensed notes to consolidated financial statements.
 
4
 

 

 
Otter Tail Corporation
 
Consolidated Statements of Comprehensive Income
 
(not audited)
 
   
   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
(in thousands)
 
2014
   
2013
   
2014
   
2013
 
Net Income
  $ 15,825     $ 15,138     $ 47,248     $ 38,202  
Other Comprehensive Income:
                               
Unrealized Gain on Available-for-Sale Securities:
                               
Reversal of Previously Recognized Gains Realized on Sale of
Investments and Included in Other Income During Period
    --       --       (17 )     (25 )
(Losses) Gains Arising During Period
    (37 )     19       (18 )     (66 )
Income Tax Benefit (Expense)
    13       (7 )     12       32  
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax
    (24 )     12       (23 )     (59 )
Pension and Postretirement Benefit Plans:
                               
Amortization of Unrecognized Postretirement Benefit Losses
and Costs (note 12)
    50       145       151       436  
Income Tax (Expense)
    (20 )     (58 )     (60 )     (175 )
Pension and Postretirement Benefit Plans – net-of-tax
    30       87       91       261  
Total Other Comprehensive Income
    6       99       68       202  
Total Comprehensive Income
  $ 15,831     $ 15,237     $ 47,316     $ 38,404  
 
See accompanying condensed notes to consolidated financial statements.
 
5
 

 

 
Otter Tail Corporation
 
 
(not audited)
 
   
   
Nine Months Ended
September 30,
 
(in thousands)
 
2014
   
2013
 
Cash Flows from Operating Activities
           
Net Income
  $ 47,248     $ 38,202  
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
               
Net Gain from Sale of Discontinued Operations
    --       (210 )
Net Income from Discontinued Operations
    (249 )     (428 )
Depreciation and Amortization
    44,871       44,794  
Deferred Tax Credits
    (1,361 )     (1,422 )
Deferred Income Taxes
    20,824       15,215  
Change in Deferred Debits and Other Assets
    4,299       9,817  
Discretionary Contribution to Pension Plan
    (20,000 )     (10,000 )
Change in Noncurrent Liabilities and Deferred Credits
    (1,336 )     7,318  
Allowance for Equity/Other Funds Used During Construction
    (1,180 )     (1,462 )
Change in Derivatives Net of Regulatory Deferral
    214       120  
Stock Compensation Expense—Equity Awards
    1,126       1,116  
Other—Net
    (1,303 )     813  
Cash (Used for) Provided by Current Assets and Current Liabilities:
               
Change in Receivables
    (23,651 )     (9,775 )
Change in Inventories
    (6,298 )     (3,323 )
Change in Other Current Assets
    (1,769 )     (252 )
Change in Payables and Other Current Liabilities
    (15,094 )     4,170  
Change in Interest and Income Taxes Receivable/Payable
    1,028       1,156  
Net Cash Provided by Continuing Operations
    47,369       95,849  
Net Cash Used in Discontinued Operations
    (341 )     (2,499 )
Net Cash Provided by Operating Activities
    47,028       93,350  
Cash Flows from Investing Activities
               
Capital Expenditures
    (125,164 )     (109,690 )
Net Proceeds from Disposal of Noncurrent Assets
    3,262       2,615  
Net Increase in Other Investments
    (2,148 )     (680 )
Net Cash Used in Investing Activities - Continuing Operations
    (124,050 )     (107,755 )
Net Proceeds from Sale of Discontinued Operations
    --       12,842  
Net Cash Provided by Investing Activities - Discontinued Operations
    284       505  
Net Cash Used in Investing Activities
    (123,766 )     (94,408 )
Cash Flows from Financing Activities
               
Net Short-Term (Repayments) Borrowings
    (12,195 )     40,335  
Proceeds from Issuance of Common Stock
    13,331       1,496  
Common Stock Issuance Expenses
    (412 )     --  
Payments for Retirement of Capital Stock
    (459 )     (15,723 )
Proceeds from Issuance of Long-Term Debt
    150,000       40,900  
Short-Term and Long-Term Debt Issuance Expenses
    (516 )     (126 )
Payments for Retirement of Long-Term Debt
    (41,039 )     (25,266 )
Dividends Paid and Other Distributions
    (33,119 )     (33,027 )
Net Cash Provided by Financing Activities - Continuing Operations
    75,591       8,589  
Net Cash Used in Financing Activities - Discontinued Operations
    --       --  
Net Cash Provided by Financing Activities
    75,591       8,589  
Net Change in Cash and Cash Equivalents - Discontinued Operations
    (3 )     (776 )
Net Change in Cash and Cash Equivalents
    (1,150 )     6,755  
Cash and Cash Equivalents at Beginning of Period
    1,150       52,362  
Cash and Cash Equivalents at End of Period
  $ --     $ 59,117  
 
See accompanying condensed notes to consolidated financial statements.
 
6
 

 

 
OTTER TAIL CORPORATION
 
CONDENSED 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 condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013. Because of seasonal and other factors, the earnings for the three and nine month periods ended September 30, 2014 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, 2013.
 
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 (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 (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging. 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.
 
The companies in the Construction segment 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 costs incurred to total estimated costs on construction projects. Following are the percentages of the Company’s consolidated revenues recorded under the percentage-of-completion method:
 
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2014
   
2013
   
2014
   
2013
 
Percentage-of-Completion Revenues
  16.0%     20.6%     13.3%     16.4%  
 
The following table summarizes costs incurred and billings and estimated earnings recognized on uncompleted contracts:
 
   
September 30,
   
December 31,
 
(in thousands)
 
2014
   
2013
 
Costs Incurred on Uncompleted Contracts
  $ 418,588     $ 361,487  
Less Billings to Date
    (429,830 )     (377,608 )
Plus Estimated Earnings Recognized
    15,005       6,477  
Net Costs in Excess of Billings plus Estimated Earnings on Uncompleted Contracts
  $ 3,763     $ (9,644 )
 
The following amounts are included in the Company’s consolidated balance sheets:
 
   
September 30,
   
December 31,
 
(in thousands)
 
2014
   
2013
 
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts
  $ 6,271     $ 4,063  
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts
    (2,508 )     (13,707 )
Net Costs in Excess of Billings plus Estimated Earnings on Uncompleted Contracts
  $ 3,763     $ (9,644 )
 
7
 

 

 
The Company has a standard quarterly Estimate at Completion process in which management reviews the progress and performance of the Company’s contracts accounted for under percentage-of-completion accounting. As part of this process, management reviews include, but are not limited to, any outstanding key contract matters, progress towards completion and the related program schedule, identified risks and opportunities, and the related changes in estimates of revenues and costs. The risks and opportunities include management’s judgment about the ability and cost to achieve the schedule, technical requirements and other contract requirements. Management must make assumptions regarding labor productivity and availability, the complexity of the work to be performed, the availability of materials, the length of time to complete the contract, and performance by subcontractors, among other variables. Based on this analysis, any adjustments to net sales, costs of sales, and the related impact to operating income are recorded as necessary in the period they become known. These adjustments may result from positive program performance and an increase in operating profit during the performance of individual contracts if management determines it will be successful in mitigating risks surrounding the technical, schedule, and cost aspects of those contracts or realizing related opportunities. Likewise, these adjustments may result in a decrease in operating profit if management determines it will not be successful in mitigating these risks or realizing related opportunities. Changes in estimates of net sales, costs of sales, and the related impact to operating income are recognized using a cumulative catch-up, which recognizes, in the current period, the cumulative effect of the changes on current and prior periods based on a contract’s percent complete. A significant change in one or more of these estimates could affect the profitability of one or more of the Company’s contracts. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized.
 
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. The warranty reserve balance as of December 31, 2013 and September 30, 2014 relates entirely to products produced by the Company’s former wind tower and waterfront equipment manufacturing companies and is included in liabilities of discontinued operations. See note 17 to consolidated financial statements.
 
Retainage
Accounts Receivable include the following amounts, billed under contracts by the Company’s construction subsidiaries, that have been retained by customers pending project completion:
 
   
September 30,
   
December 31,
 
(in thousands)
 
2014
   
2013
 
Accounts Receivable Retained by Customers
  $ 7,854     $ 7,125  
 
Fair Value Measurements
The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), 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 (NYMEX).
 
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 tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013:
 
September 30, 2014 (in thousands)
 
Level 1
   
Level 2
   
Level 3
 
Assets:
                 
Current Assets – Other:
                 
Forward Energy Contracts
  $ --     $ --     $ 2,016  
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan
    120                  
Investments:
                       
Corporate Debt Securities – Held by Captive Insurance Company
            7,128          
U.S. Government Debt Securities – Held by Captive Insurance Company
            1,254          
Other Assets:
                       
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan
    582                  
Total Assets
  $ 702     $ 8,382     $ 2,016  
Liabilities:
                       
Derivative Liabilities - Forward Gasoline Purchase Contracts
  $ --     $ 37     $ --  
Derivative Liabilities - Forward Energy Contracts
                    6,483  
Total Liabilities
  $ --     $ 37     $ 6,483  
 
December 31, 2013 (in thousands)
 
Level 1
   
Level 2
   
Level 3
 
Assets:
                 
Current Assets – Other:
                 
Forward Energy Contracts
  $ --     $ --     $ 338  
Forward Gasoline Purchase Contracts
            62          
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan
    110                  
Investments:
                       
Corporate Debt Securities – Held by Captive Insurance Company
            7,671          
U.S. Government Debt Securities – Held by Captive Insurance Company
            1,271          
Other Assets:
                       
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan
    866                  
Total Assets
  $ 976     $ 9,004     $ 338  
Liabilities:
                       
Derivative Liabilities - Forward Energy Contracts
  $ --     $ 103     $ 11,679  
Total Liabilities
  $ --     $ 103     $ 11,679  
 
The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:
 
Forward Energy Contracts – Prices used for the fair valuation of these forward purchases and sales of electricity, which have illiquid trading points, are indexed to a price at an active market.
 
Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.
 
Corporate and U.S. Government Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.
 
Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of September 30, 2014 and December 31, 2013, are based on prices indexed to observable prices at an active trading hub. 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 September 30, 2014 Level 3 forward electric basis spreads ranged from $1.58 to $7.25 per megawatt-hour under the active trading hub price. The weighted average price was $38.67 per megawatt-hour.
 
9
 

 

 
In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of September 30, 2014 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three and nine month periods ended September 30, 2014 and 2013.
 
The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the nine-month periods ended September 30, 2014 and 2013:
 
   
Nine Months Ended
 
   
September 30,
 
 (in thousands)
 
2014
   
2013
 
Forward Energy Contracts - Fair Values Beginning of Period
  $ (11,341 )   $ (17,782 )
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods
    1,252       5,066  
Changes in Fair Value of Contracts Entered into in Prior Periods
    5,622       325  
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period
    (4,467 )     (12,391 )
Net Change in Value of Open Contracts Entered into in Current Period
    --       --  
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period
  $ (4,467 )   $ (12,391 )
 
Inventories
Inventories consist of the following:
 
   
September 30,
   
December 31,
 
(in thousands)
 
2014
   
2013
 
Finished Goods
  $ 22,177     $ 20,649  
Work in Process
    12,193       9,942  
Raw Material, Fuel and Supplies
    44,569       42,090  
Total Inventories
  $ 78,939     $ 72,681  
 
Goodwill and Other Intangible Assets
 
In the first quarter of 2014, Aevenia, Inc. (Aevenia) recorded a $289,000 gain on the sale of its data communication installation and services business which, over the years of its existence, did not provide a materially significant impact to Aevenia’s operating results. In connection with this sale, Aevenia disposed of $163,000 in goodwill associated with the purchase of this business in May 2004.
 
The following table summarizes changes to goodwill by business segment during 2014:
 
 
(in thousands)
 
Gross Balance
December 31,
2013
   
Accumulated Impairments
   
Balance (net of impairments)
December 31,
2013
   
Adjustments
to Goodwill
in 2014
   
Balance (net of impairments)
September 30,
2014
 
Manufacturing
  $ 12,186     $ --     $ 12,186     $ --     $ 12,186  
Plastics
    19,302       --       19,302       --       19,302  
Construction
    7,483       --       7,483       163       7,320  
Total
  $ 38,971     $ --     $ 38,971     $ 163     $ 38,808  
 
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Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. The following table summarizes the components of the Company’s intangible assets at September 30, 2014 and December 31, 2013:
 
September 30, 2014 (in thousands)
 
Gross Carrying Amount
   
Accumulated Amortization
   
Net Carrying
Amount
 
Remaining
Amortization
Periods
Amortizable Intangible Assets:
                   
 Customer Relationships
  $ 16,811     $ 5,572     $ 11,239  
63-163 months
 Other Intangible Assets
    639       383       256  
24 months
 Total
  $ 17,450     $ 5,955     $ 11,495    
Indefinite-Lived Intangible Assets:
                         
 Trade Name
  $ 1,100       --     $ 1,100    
                           
December 31, 2013 (in thousands)
                         
Amortizable Intangible Assets:
                         
 Customer Relationships
  $ 16,811     $ 4,935     $ 11,876  
72-172 months
 Other Intangible Assets Including Contracts
    825       473       352  
33 months
 Total
  $ 17,636     $ 5,408     $ 12,228    
Indefinite-Lived Intangible Assets:
                         
 Trade Name
  $ 1,100       --     $ 1,100    
 
The amortization expense for these intangible assets was:
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
(in thousands)
 
2014
   
2013
   
2014
   
2013
 
Amortization Expense – Intangible Assets
  $ 245     $ 245     $ 733     $ 733  
 
The estimated annual amortization expense for these intangible assets for the next five years is:
 
(in thousands)
 
2014
   
2015
   
2016
   
2017
   
2018
 
Estimated Amortization Expense – Intangible Assets
  $ 977     $ 977     $ 945     $ 849     $ 849  
 
Supplemental Disclosures of Cash Flow Information
 
   
As of September 30,
 
(in thousands)
 
2014
   
2013
 
Noncash Investing Activities:
           
Accounts Payable Outstanding Related to Capital Additions1
  $ 21,512     $ 25,133  
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2
  $ 5,058     $ 5,172  
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled.
2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received.
 
 
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Coyote Station Lignite Supply Agreement – Variable Interest Entity
In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and CCMC is not required to be consolidated in the Company’s consolidated financial statements.
 
Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through September 30, 2014 is $16.2 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of September 30, 2014 could be as high as $16.2 million.
 
Revisions to Presentation
Beginning with the Company’s 2013 Annual Report on Form 10-K, the Company is reporting revenues and costs related to the sale of products by its manufacturing and plastic pipe companies separately from the revenues and costs of its construction companies on the face of its consolidated statements of income. Its nonelectric revenues and cost of goods sold for the three and nine month periods ended September 30, 2013 have been revised in a similar manner to be consistent with, and comparable to, the presentation of revenues and costs for the three and nine month periods ended September 30, 2014. The change in presentation of 2013 nonelectric revenues and cost of goods sold had no effect on the Company’s reported consolidated revenues, costs, operating income or net income for the three and nine month periods ended September 30, 2013.
 
New Accounting Standards
 
Accounting Standards Update (ASU) 2013-11
In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740) (ASC 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, which requires an entity with unrecognized tax benefits to present the unrecognized tax benefits as a reduction to a deferred tax asset related to a net operating loss carryforward, a similar tax loss, or a tax credit carryforward when such net operating loss carryforward, similar tax loss, or tax credit carryforward is available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position. The ASU 2013-11 amendments to ASC 740 are effective for fiscal years beginning after December 15, 2013. The Company adopted the reporting requirements in ASU 2013-11 in the first quarter of 2014 on a prospective basis and transferred $4.3 million of unrecognized tax benefits from other long-term liabilities to long-term deferred income taxes.
 
ASU 2014-09
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
 
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ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options.
 
2. Segment Information
 
The Company’s businesses have been classified into four 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 sell products and provide services to customers primarily in the United States. The four segments are: Electric, Manufacturing, Plastics and Construction.
 
(FLOW CHART)
 
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 Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.
 
Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping and fabrication, and production of material and handling trays, horticultural containers and produce packaging. These businesses have manufacturing facilities in Illinois and Minnesota and sell products primarily in the United States.
 
Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.
 
Construction consists of businesses involved in commercial and industrial electric contracting and construction of fiber optic, electric distribution, water, wastewater and HVAC systems primarily in the central United States.
 
OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.
 
No single customer accounted for over 10% of the Company’s consolidated revenues in 2013. All of the Company’s long-lived assets are within the United States.
 
13
 

 

 
The following table presents the percent of consolidated sales revenue by country:
 
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2014
   
2013
   
2014
   
2013
 
United States of America
    95.9 %     97.7 %     96.5 %     97.7 %
Mexico
    3.0 %     1.5 %     2.5 %     1.3 %
Canada
    1.0 %     0.7 %     0.9 %     0.9 %
All Other Countries (none greater than 0.05%)
    0.1 %     0.1 %     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 the three and nine months ended September 30, 2014 and 2013 and total assets by business segment as of September 30, 2014 and December 31, 2013 are presented in the following tables:
 
Operating Revenue
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
(in thousands)
 
2014
   
2013
   
2014
   
2013
 
Electric
  $ 89,410     $ 86,283     $ 301,409     $ 270,155  
Manufacturing
    55,536       49,323       164,341       152,282  
Plastics
    51,613       46,659       140,186       128,820  
Construction
    45,846       47,509       111,599       108,928  
Intersegment Eliminations
    (34 )     (6 )     (81 )     (74 )
Total
  $ 242,371     $ 229,768     $ 717,454     $ 660,111  
 
Interest Charges
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
(in thousands)
 
2014
   
2013
   
2014
   
2013
 
Electric
  $ 6,071     $ 3,960     $ 17,209     $ 13,032  
Manufacturing
    812       816       2,433       2,447  
Plastics
    276       249       797       753  
Construction
    220       128       489       345  
Corporate and Intersegment Eliminations
    308       1,421       981       3,854  
Total
  $ 7,687     $ 6,574     $ 21,909     $ 20,431  
 
Income Taxes
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
(in thousands)
 
2014
   
2013
   
2014
   
2013
 
Electric
  $ 1,714     $ 2,565     $ 6,472     $ 5,830  
Manufacturing
    1,164       1,124       4,171       4,715  
Plastics
    1,888       2,278       6,135       7,508  
Construction
    1,137       1,193       1,966       490  
Corporate
    (427 )     (2,027 )     (3,494 )     (5,430 )
Total
  $ 5,476     $ 5,133     $ 15,250     $ 13,113  
 
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Earnings (Loss) Available for Common Shares
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
(in thousands)
 
2014
   
2013
   
2014
   
2013
 
Electric
  $ 8,612     $ 8,787     $ 30,507     $ 24,301  
Manufacturing
    2,899       2,970       8,095       8,333  
Plastics
    3,092       3,403       9,985       11,215  
Construction
    2,205       1,784       3,438       716  
Corporate
    (1,155 )     (2,118 )     (5,026 )     (7,514 )
Discontinued Operations
    172       312       249       638  
Total
  $ 15,825     $ 15,138     $ 47,248     $ 37,689  
 
Identifiable Assets
 
   
September 30,
   
December 31,
 
(in thousands)
 
2014
   
2013
 
Electric
  $ 1,380,563     $ 1,290,416  
Manufacturing
    127,534       119,302  
Plastics
    90,217       76,853  
Construction
    60,704       49,440  
Corporate
    55,257       59,970  
Discontinued Operations
    10       38  
Total
  $ 1,714,285     $ 1,596,019  
 
3. Rate and Regulatory Matters
 
Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC), impacting OTP’s revenues in 2014 and 2013.
 
Major Capital Expenditure Projects
 
Multi-Value Transmission ProjectsOn December 16, 2010, FERC approved the cost allocation for a new classification of projects in the MISO region called Multi-Value Projects (MVP). MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. Effective January 1, 2012, the FERC authorized OTP to recover 100% of prudently incurred Construction Work in Progress (CWIP) and Abandoned Plant recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South – Brookings MVP and the Big Stone South – Ellendale MVP. Abandoned Plant recovery provides a basis for OTP to request recovery of prudently incurred costs in the event a project is cancelled for reasons beyond OTP’s control. The following projects have been approved by MISO as MVPs under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff).
 
The Big Stone South – Brookings Project—This is a planned 345 kiloVolt (kV) transmission line that will extend approximately 70 miles between a proposed substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Xcel Energy jointly developed this project. MISO approved this project as an MVP under the MISO Tariff in December 2011. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. The SDPUC approved the certification for the northern portion of the route on April 9, 2013. The SDPUC granted OTP and Xcel Energy approval of a route permit for the southern portion of the Big Stone South - Brookings line on February 18, 2014. On August 1, 2014 OTP and Xcel Energy entered into agreements to construct the project. This line is expected to be in service in 2017.
 
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The Big Stone South – Ellendale Project—This is a proposed 345 kV transmission line that will extend 160 to 170 miles between a proposed substation near Big Stone City, South Dakota and a proposed substation near Ellendale, North Dakota. OTP is jointly developing this project with Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (MDU). MISO approved this project as an MVP under the MISO Tariff in December 2011. OTP and MDU jointly filed an NICF with the SDPUC in March of 2012. On August 25, 2013 the NDPSC granted Certificates of Public Convenience and Necessity to OTP and MDU for ten miles of the proposed line to be built in North Dakota. On July 10, 2014 the NDPSC approved a Certificate of Corridor Compatibility and a route permit for the North Dakota section of the proposed line. On August 22, 2014 the SDPUC issued an order approving the route permit for the South Dakota section of the proposed line.
 
Capacity Expansion 2020 (CapX2020) Transmission Line Projects—CapX2020 is a joint initiative of eleven 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 kV Project (the Fargo Project), (2) the Brookings–Southeast Twin Cities 345 kV Project (the Brookings Project), (3) the Bemidji–Grand Rapids 230 kV 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. Recovery of OTP’s CapX2020 transmission investments is through the MISO Tariff (the Brookings Project as an MVP) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.
 
The Fargo Project—The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011. The St. Cloud to Alexandria portion of the Fargo Project was placed into service on April 23, 2014. Construction is underway for the remaining portion of the project, which is expected to be in service in 2015.
 
The Brookings Project—The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff in December 2011. The first phase of the 250 mile Brookings Project was energized in March 2014. Additional segments of the line were energized in April 2014. The entire project is expected to be in service in 2015.
 
The Bemidji Project—The Bemidji-Grand Rapids transmission line was fully energized and put into service on September 17, 2012.
 
Big Stone Plant Air Quality Control System (AQCS)—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 Plant’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan.
 
OTP is currently in the process of constructing the BART-compliant AQCS at Big Stone Plant for a current projected cost of approximately $384 million (OTP’s 53.9% share would be $207 million) with an expected commercial operation date of October 2015. OTP’s share of AQCS construction expenditures incurred through September 30, 2014 is $143 million.
 
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. On November 2, 2009, the remaining Big Stone II participants announced the cancellation of the Big Stone II project. OTP requested jurisdictional recovery in Minnesota, North Dakota and South Dakota of amounts it had invested in the Big Stone II Project at the time of its withdrawal, discussed below under the respective jurisdictional sections of this note.
 
Minnesota
 
2010 General Rate CaseOTP’s most recent general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. The MPUC’s written order included: (1) recovery of Big Stone II costs over five years, (2) moving recovery of wind farm assets from rider recovery to base rate recovery, (3) transfer of a portion of Minnesota Conservation Improvement Program (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.
 
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Renewable Energy Standards, Conservation, Renewable Resource Riders—Minnesota has a renewable energy standard which requires OTP to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 17% by 2016; 20% by 2020 and 25% by 2025. In addition, a standard established by the 2013 legislature requires 1.5% of total electric sales to be supplied by solar energy by the year 2020. OTP is currently evaluating potential options for meeting that standard. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. OTP has acquired renewable resources and expects to acquire additional renewable resources in order to maintain compliance with Minnesota renewable energy standards. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.
 
Under the Next Generation Energy Act of 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover investments and costs incurred to satisfy the requirements of the renewable energy standard. The MPUC is authorized to approve a rate schedule rider to enable utilities to recover the costs of qualifying renewable energy projects that supply renewable energy to Minnesota customers. Cost recovery for qualifying renewable energy projects can be authorized outside of a rate case proceeding, provided that such renewable projects have received previous MPUC approval. Renewable resource costs eligible for recovery may include return on investment, depreciation, operation and maintenance costs, taxes, renewable energy delivery costs and other related expenses.
 
The costs for three major wind farms previously approved by the MPUC for recovery through OTP’s Minnesota Renewable Resource Adjustment (MNRRA) were 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 the MNRRA regulatory asset. The MNRRA rate continued to collect the remaining regulatory asset balance through April 30, 2013, when the balance was near zero. On April 4, 2013 the MPUC authorized that any remaining unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case. Effective May 1, 2013 the resource adjustment on OTP’s Minnesota customers’ bills no longer includes MNRRA costs.
 
Minnesota Conservation Improvement Programs (MNCIP)—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state’s energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota. The Next Generation Energy Act of 2007 transitioned from a conservation spending goal to a conservation energy savings goal in 2010.
 
The Minnesota Department of Commerce (MNDOC) may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC.
 
In December 2012, the MPUC ordered a change in the MNCIP cost recovery methodology used by OTP from a percentage of a customer’s bill to an amount per kilowatt-hour (kwh) consumed. On January 1, 2013 OTP’s MNCIP surcharge decreased from 3.8% of the customer’s bill to $0.00142 per kwh, which equates to approximately 1.9% of a customer’s bill. On October 10, 2013 the MPUC approved OTP’s 2012 financial incentive request for $2.7 million as well as its request for an updated surcharge rate to be implemented on November 1, 2013. OTP recognized $3.9 million in MNCIP financial incentives in 2013 related to the results of its conservation improvement programs in Minnesota in 2013. On April 1, 2014 OTP submitted its annual 2013 financial incentive filing request for $4.0 million along with a request for an updated surcharge rate. On September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case.
 
OTP had a regulatory asset of $7.2 million for allowable costs and financial incentives eligible for recovery through the MNCIP rider that had not been billed to Minnesota customers as of September 30, 2014. OTP recognized revenue for Minnesota conservation costs and incentives earned totaling $1.3 million in the three month period ended September 30, 2014, compared with $1.5 million in the three month period ended September 30, 2013, and $4.3 million in the nine month period ended September 30, 2014, compared with $4.8 million in the nine month period ended September 30, 2013.
 
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Transmission Cost Recovery (TCR) RiderIn addition to the MNRRA rider, the Minnesota Public Utilities Act (the Act) provides a similar mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility’s retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The Act also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. OTP’s initial request for approval of a TCR rider was granted by the MPUC on January 7, 2010, and became effective February 1, 2010.
 
MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers. On March 26, 2012 the MPUC approved an update to OTP’s Minnesota TCR rider along with an all-in method for MISO regional cost allocations in which OTP’s retail customers would be responsible for the entire investment OTP made in transmission facilities that qualify for regional cost allocation under the MISO Tariff, with an offsetting credit for revenues received from other MISO utilities under the MISO Tariff for projects included in the TCR. OTP’s updated Minnesota TCR rider went into effect April 1, 2012.
 
On May 24, 2012 OTP filed a petition with the MPUC to seek a determination of eligibility for the inclusion of twelve additional transmission related projects in subsequent Minnesota TCR rider filings. On February 20, 2013 the MPUC approved three of the additional projects as eligible for recovery through the TCR rider. OTP filed its annual update to the TCR rider on February 7, 2013 to include the three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but disallowed recovery of capitalized internal costs, costs in excess of CON estimates and a carrying charge in the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP will be allowed to seek recovery of these costs in a future rate case. In response to the MPUC approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. OTP filed its 2014 annual update on May 1, 2014. The MNDOC issued comments on the 2014 update on August 22, 2014.
 
OTP had a regulatory asset of $2.7 million for amounts eligible for recovery through the Minnesota TCR rider that had not been billed to Minnesota customers as of September 30, 2014. OTP recognized revenue for amounts eligible for recovery through the Minnesota TCR rider of $1.1 million in the three month period ended September 30, 2014, compared with $0.5 million in the three month period ended September 30, 2013, and $5.2 million in the nine month period ended September 30, 2014, compared with $2.7 million in the nine month period ended September 30, 2013.
 
Environmental Cost Recovery (ECR) Rider—In a written order issued on January 23, 2012 the MPUC granted OTP’s petition for Advance Determination of Prudence (ADP) for costs associated with the design, construction and operation of the BART-compliant AQCS at Big Stone Plant attributable to serving OTP’s Minnesota customers. On May 24, 2013 legislation was enacted in Minnesota which allowed OTP to file an emission-reduction rider for recovery of the revenue requirements of the AQCS. The legislation authorizes the rider to allow a current return on investment (including CWIP) at the level approved in OTP’s most recent general rate case, unless a different return is determined by the MPUC to be in the public interest. On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance at the level approved in OTP’s most recent general rate case. The rate charged to customers will be updated in an annual filing with the MPUC until the costs are rolled into base rates at an undetermined future date. OTP filed its 2014 annual update on July 31, 2014. The MNDOC filed its comments recommending approval on October 17, 2014. The 2014 annual update is pending approval from the MPUC.
 
OTP had a regulatory asset of $0.5 million for amounts eligible for recovery through the Minnesota ECR rider that had not been billed to Minnesota customers as of September 30, 2014. OTP recognized revenue for amounts eligible for recovery through the Minnesota ECR rider in the three and nine month periods ended September 30, 2014 of $1.7 million and $5.2 million, respectively.
 
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Big Stone II Cost Recovery—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 as part of the rates established in that proceeding was $3.2 million. Because OTP will not earn a return on these deferred costs over the 60-month recovery period, the recoverable amount of $3.2 million was discounted to its present value of $2.8 million using OTP’s incremental borrowing rate, in accordance with ASC Topic 980, Regulated Operations (ASC 980), accounting requirements. Transmission-related project costs of $3.2 million remained in CWIP as active project costs.
 
Approximately $0.4 million of the total Minnesota jurisdictional share of Big Stone II transmission costs were transferred to the Big Stone South - Brookings MVP in the first quarter of 2013. The remaining transmission costs, along with accumulated Allowance for Funds Used During Construction (AFUDC), were transferred from CWIP to the Big Stone II Unrecovered Project Costs – Minnesota regulatory asset account in May 2013, based on recovery granted in the April 25, 2011 order. Because OTP will not earn a return on these deferred costs over their anticipated recovery period, the recoverable amount of approximately $3.5 million was discounted to its present value using OTP’s incremental borrowing rate. In May 2013, OTP recorded a charge of $0.7 million related to the discount in accordance with ASC 980 accounting requirements. In June 2014, OTP recorded an additional discount of $0.3 million to reflect changes in the end date of the anticipated recovery period from September 2020 to December 2022.
 
North Dakota
 
General Rates—OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009.
 
Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed. On March 21, 2012 the NDPSC approved an update to OTP’s NDRRA effective April 1, 2012. The updated NDRRA recovered $9.9 million over the period April 1, 2012 through March 31, 2013. On December 28, 2012 OTP submitted its annual update to the NDRRA with a proposed effective date of April 1, 2013. The update resulted in a rate reduction, so the NDPSC did not issue an order suspending the rate change. Consequently, pursuant to statute, OTP was allowed to implement updated rates effective April 1, 2013. On July 10, 2013, the NDPSC approved the updated rates implemented on April 1, 2013. The NDPSC approved OTP’s most recent annual update to the NDRRA on March 12, 2014 with an effective date of April 1, 2014. The update approved on March 12, 2014 resulted in a 13.5% reduction in the NDRRA rate.
 
OTP had a net regulatory liability of $0.7 million as of September 30, 2014 for amounts billed to North Dakota customers that were subject to refund through the NDRRA rider. OTP recognized revenue for amounts eligible for recovery through the NDRRA rider of $2.2 million in the three month period ended September 30, 2014, compared with $2.4 million in the three month period ended September 30, 2013, and $5.7 million in the nine month period ended September 30, 2014, compared with $6.9 million in the nine month period ended September 30, 2013.
 
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. On August 30, 2013 OTP filed its annual update to its North Dakota TCR rider rate, which was approved on December 30, 2013 and became effective January 1, 2014. On August 29, 2014 OTP filed its annual update to the North Dakota TCR rider rate with a proposed implementation date of January 1, 2015. Within this TCR filing, as required by the order for the North Dakota Big Stone II rider, OTP included the over-collection of North Dakota Big Stone II abandoned plant costs of $0.1 million.
 
OTP had a regulatory asset of $0.7 million for amounts eligible for recovery through the North Dakota TCR rider that had not been billed to North Dakota customers as of September 30, 2014. OTP recognized revenue for amounts eligible for recovery through the North Dakota TCR rider of $1.3 million in the three month period ended September 30, 2014, compared with $0.7 million in the three month period ended September 30, 2013, and $4.5 million in the nine month period ended September 30, 2014, compared with $2.4 million in the nine month period ended September 30, 2013.
 
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Environmental Cost Recovery RiderOn May 9, 2012 the NDPSC approved OTP’s application for an ADP related to the Big Stone Plant AQCS. On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. On March 31, 2014 OTP filed its annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. On July 10, 2014 the NDPSC approved OTP’s 2014 ECR rider annual update request with an August 1, 2014 implementation date.
 
OTP had a regulatory asset of $1.7 million as of September 30, 2014 for amounts eligible for recovery through the North Dakota ECR rider that had not been billed to North Dakota customers as of September 30, 2014. OTP recognized revenue for amounts eligible for recovery through the North Dakota ECR rider of $1.5 million in the three month period ended September 30, 2014, compared with ($0.4) million in the three month period ended September 30, 2013, and $4.4 million in the nine month period ended September 30, 2014, compared with $0.0 million in the nine month period ended September 30, 2013.
 
Big Stone II Cost Recovery—In an order issued June 25, 2010, the NDPSC authorized recovery of Big Stone II development costs from North Dakota ratepayers, pursuant to a final settlement agreement filed June 23, 2010, between the NDPSC advocacy staff, OTP and the North Dakota Large Industrial Energy Group, Interveners. The terms of the settlement agreement indicate that OTP’s discontinuation of participation in the project was prudent and OTP should be authorized to recover the portion of costs it incurred related to the Big Stone II generation project. The total amount of Big Stone II generation costs incurred by OTP (which excluded $2.6 million of project transmission-related costs) was determined to be $10.1 million, of which $4.1 million represents North Dakota’s jurisdictional share.
 
OTP included in its total recovery amount a carrying charge of approximately $0.3 million on the North Dakota share of Big Stone II generation costs for the period from September 1, 2009 through the date the recovery of costs began based on OTP’s average 2009 AFUDC rate of 7.65%. Because OTP would not earn a return on these deferred costs over the 36-month recovery period, the recoverable amount of $4.3 million was discounted to its then present value of $3.9 million using OTP’s incremental borrowing rate, in accordance with ASC 980 accounting requirements. The North Dakota portion of Big Stone II generation costs was recovered over a 36-month period which began on August 1, 2010.
 
The North Dakota jurisdictional share of Big Stone II costs incurred by OTP related to transmission was $1.1 million. Approximately $0.3 million of the total North Dakota jurisdictional share of Big Stone II transmission costs were transferred to the Big Stone South - Brookings MVP during the first quarter of 2013. On July 30, 2013 the NDPSC approved OTP’s request to continue the Big Stone II cost recovery rates for an additional eight months through March 31, 2014 to recover the remaining North Dakota share of Big Stone II transmission-related costs plus accrued AFUDC totaling $1.0 million. As of April 1, 2014 North Dakota customer’s bills no longer include a charge for North Dakota share of Big Stone II costs. OTP had a regulatory liability of $0.1 million as of September 30, 2014 for amounts billed to North Dakota customers that will be subject to refund through the North Dakota TCR rider. The North Dakota TCR rider annual update, requesting an increase in the North Dakota TCR rider rate, was filed on August 29, 2014.
 
South Dakota
 
2010 General Rate Case—On April 21, 2011 the SDPUC issued a 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% for the interim rates and final rates for OTP in South Dakota. 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 was approved by the SDPUC and implemented on December 1, 2011. The SDPUC approved an annual update to OTP’s South Dakota TCR on April 23, 2013 with an effective date of May 1, 2013. The SDPUC approved OTP’s most recent annual update to its South Dakota TCR on February 18, 2014 with an effective date of March 1, 2014.
 
OTP had a regulatory asset of $0.1 million for amounts eligible for recovery through the South Dakota TCR rider that had not been billed to South Dakota customers as of September 30, 2014. OTP recognized revenue for amounts eligible for recovery through the South Dakota TCR rider of $0.3 million in the three month period ended September 30, 2014, compared with $0.2 million in the three month period ended September 30, 2013, and $1.0 million in the nine month period ended September 30, 2014, compared with $0.6 million in the nine month period ended September 30, 2013.
 
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Environmental Cost Recovery Rider—On March 30, 2012 OTP requested approval from the SDPUC for an ECR rider to recover costs associated with the Big Stone Plant AQCS. On April 17, 2013 OTP filed a request to either suspend or withdraw this filing. The SDPUC approved withdrawing this filing on April 23, 2013. Instead of receiving rider recovery on the portion of AQCS construction costs assignable to OTP’s South Dakota customers, OTP will accrue AFUDC on these costs until, under a future rate filing, recovery of and a return on the accumulated costs, including AFUDC, may be granted in South Dakota. On August 29, 2014 OTP filed a new request with the SDPUC for an ECR rider to recover costs associated with new environmental measures including costs to comply with mercury and air toxics standards.
 
Big Stone II Cost Recovery—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 is 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. On July 31, 2012 the SDPUC approved the transfer of the Big Stone II transmission route permits to OTP.
 
A portion of the Big Stone II transmission costs were transferred out of CWIP in February 2013 to be included within the Big Stone South - Brookings MVP. On March 28, 2013, OTP filed a petition with the SDPUC requesting deferred accounting for the remaining unrecovered Big Stone II Transmission costs until OTP’s next South Dakota general rate case. The petition was approved by the SDPUC on April 23, 2013 and in May 2013 OTP transferred the remaining South Dakota jurisdictional portion of unrecovered Big Stone II transmission costs plus accumulated AFUDC totaling $0.2 million from CWIP to the Big Stone II Unrecovered Project Costs – South Dakota regulatory asset accounts, which had a combined balance of $0.9 million on September 30, 2014.
 
Federal
 
Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.
 
Effective January 1, 2010 the FERC authorized OTP’s implementation of a forward looking formula transmission rate under the MISO Tariff. OTP was also authorized by the FERC to recover in its formula rate: (1) 100% of prudently incurred CWIP in rate base and (2) 100% of prudently incurred costs of transmission facilities that are cancelled or abandoned for reasons beyond OTP’s control (Abandoned Plant Recovery), as determined by the FERC subsequent to abandonment, specifically for three regional transmission CapX2020 projects in which OTP is invested.
 
On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint at the FERC seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the current 12.38% return on equity used in MISO’s transmission rates to a proposed 9.15%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. On October 16, 2014 the FERC issued an order finding that the current MISO return on equity may be unjust and unreasonable and setting the issue for hearing, subject to the outcome of settlement discussion. The parties’ first settlement conference is currently scheduled for November 13, 2014.
 
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United States Environmental Protection Agency (EPA) Cross-State Air Pollution Rule (CSAPR)
On April 29, 2014 the U.S. Supreme Court issued its opinion in litigation concerning the EPA’s CSAPR, reversing the August 21, 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated CSAPR. CSAPR was remanded to the D.C. Circuit for further proceedings where, on July 26, 2014, the United States moved to lift the previously–entered stay. The EPA’s motion asked the D.C. Circuit to implement CSAPR’s Phase 1 emission budgets beginning January 1, 2015, for the annual sulfur dioxide (SO2) and nitrogen oxide programs. The D.C. Circuit granted the EPA’s motion on October 23, 2014, but did not make clear in its order whether that grant included the extension of the deadline requested by the EPA. The EPA has not yet opined on how it interprets the order lifting the stay or whether it believes additional EPA action is necessary to extend the compliance deadline.
 
The CSAPR rule is expected to apply to OTP’s Solway gas peaking plant and the Hoot Lake coal-fired plant in Minnesota. The primary anticipated impact of the rule for Hoot Lake Plant is to acquire SO2 allowances to continue operating at historical levels. Based on Hoot Lake’s historical generation and EPA’s predicted allowance costs at the time of the 2012 rule, CSAPR would have resulted in annual SO2 allowance purchase costs of approximately $1.0 million. At this time, the specific cost impact of purchasing allowances is unknown, the market has not yet been well established and, since the time CSAPR was vacated in 2012, there has been a substantial reduction in SO2 emissions in OTP’s CSAPR region. Minnesota is considered a Group 2 state for SO2 compliance along with Alabama, Georgia, Kansas, Nebraska, South Carolina and Texas. Any SO2 allowances that need to be obtained for Hoot Lake Plant will need to be from an entity in a Group 2 state.
 
EPA Proposed Carbon Dioxide (CO2) Emissions Standards and Guidelines
On January 8, 2014, the EPA published proposed standards of performance for CO2 emissions from new fossil fuel-fired power plants, based on implementation of partial carbon capture and storage for coal-fired units and natural gas combined cycle technology for gas-fired units. On June 18, 2014 the EPA published proposed CO2 emission guidelines for existing fossil fuel-fired power plants, based on a combination of heat-rate improvements, re-dispatch of electricity to lower-emitting natural gas units or non-emitting renewable energy and nuclear units, and demand-side energy efficiency measures. At the same time, the EPA published separate CO2 emission standards for reconstructed and modified fossil fuel-fired power plants essentially requiring that such plants install modern technology, when modifying or reconstructing, to reduce their emissions. The EPA plans to issue final rules for each of these proposals by July 2015. For existing sources, states would then be required to develop and submit plans, either individually or with other states, spelling out how they will achieve the individualized, reduced CO2 emission rates that the EPA has identified. Those state plans are due by July 2016. The EPA is proposing to allow, upon reasonable request, one-year extensions for states proposing individual plans and two-year extensions for states proposing to submit multi-state plans.
 
OTP is participating with other stakeholders in efforts to shape the final performance standards for new, modified and reconstructed, and existing power plants both at the federal level and, where applicable, at the state level. On September 16, 2014 the EPA announced a 45-day extension for comments to be submitted regarding its proposed 111(d) rule, which seeks to regulate CO2 emissions for existing coal-based power plants. The extension moved the deadline for comments from October 16, 2014 to December 1, 2014. OTP intends to submit comments on the proposed 111(d) rule by that deadline. It is not possible to determine, at this time, the potential impact to OTP of these future regulations on new, modified or reconstructed, or existing sources.
 
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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. 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. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:
         
   
September 30, 2014
 
Remaining
Recovery/
Refund Period
(in thousands)
 
Current
   
Long-Term
   
Total
 
Regulatory Assets:
                   
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1
  $ 3,941     $ 52,089     $ 56,030  
see note
Conservation Improvement Program Costs and Incentives2
    5,867       1,448       7,315  
21 months
Deferred Marked-to-Market Losses1
    3,193       3,290       6,483  
51 months
Accumulated ARO Accretion/Depreciation Adjustment1
    --       5,053       5,053  
asset lives
Big Stone II Unrecovered Project Costs – Minnesota1
    584       3,326       3,910  
99 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1
    2,336       1,133       3,469  
24 months
Minnesota Transmission Rider Accrued Revenues2
    588       2,142       2,730  
24 months
Deferred Income Taxes1
    --       2,430       2,430  
asset lives
Debt Reacquisition Premiums1
    354       1,978       2,332  
216 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2
    1,701       --       1,701  
12 months
Big Stone II Unrecovered Project Costs – South Dakota2
    100       768       868  
104 months
North Dakota Transmission Rider Accrued Revenues2
    748       --       748  
12 months
Minnesota Environmental Cost Recovery Rider Accrued Revenues2
    468       --       468  
12 months
Minnesota Renewable Resource Rider Accrued Revenues2
    --       68       68  
see note
South Dakota Transmission Rider Accrued Revenues2
    67       --       67  
12 months
Total Regulatory Assets
  $ 19,947     $ 73,725     $ 93,672    
Regulatory Liabilities:
                         
Accumulated Reserve for Estimated Removal Costs – Net of Salvage
  $ --     $ 73,173     $ 73,173  
asset lives
Deferred Marked-to-Market Gains
    1,114       902       2,016  
47 months
Deferred Income Taxes
    --       1,686       1,686  
asset lives
North Dakota Renewable Resource Rider Accrued Refund
    314       419       733  
18 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota
    --       660       660  
see note
Refundable Fuel Clause Adjustment Revenues
    412       --       412  
12 months
Big Stone II Over Recovered Project Costs – North Dakota
    144       --       144  
12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion
    6       102       108  
231 months
South Dakota – Nonasset-Based Margin Sharing Excess
    16       --       16  
12 months
Total Regulatory Liabilities
  $ 2,006     $ 76,942     $ 78,948    
Net Regulatory Asset (Liability) Position
  $ 17,941     $ (3,217 )   $ 14,724    
1Costs subject to recovery without a rate of return.
2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
 
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December 31, 2013
 
Remaining
Recovery/
Refund Period
(in thousands)
 
Current
   
Long-Term
   
Total
 
Regulatory Assets:
                   
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1
  $ 4,095     $ 55,012     $ 59,107  
see note
Deferred Marked-to-Market Losses1
    3,008       8,674       11,682  
60 months
Conservation Improvement Program Costs and Incentives2
    4,945       3,959       8,904  
18 months
Accumulated ARO Accretion/Depreciation Adjustment1
    --       4,646       4,646  
asset lives
Big Stone II Unrecovered Project Costs – Minnesota1
    558       3,967       4,525  
81 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1
    1,351       1,753       3,104  
24 months
Debt Reacquisition Premiums1
    351       2,241       2,592  
225 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2
    2,331       --       2,331  
12 months
Deferred Income Taxes1
    --       1,805       1,805  
asset lives
Big Stone II Unrecovered Project Costs – South Dakota2
    101       843       944  
113 months
North Dakota Renewable Resource Rider Accrued Revenues2
    --       762       762  
15 months
Recoverable Fuel and Purchased Power Costs1
    760       --       760  
12 months
Big Stone II Unrecovered Project Costs – North Dakota1
    375       --       375  
3 months
Minnesota Renewable Resource Rider Accrued Revenues2
    --       68       68  
see note
South Dakota Transmission Rider Accrued Revenues2
    32       --       32  
12 months
Deferred Holding Company Formation Costs1
    27       --       27  
6 months
General Rate Case Recoverable Expenses – South Dakota1
    6       --       6  
1 month
Total Regulatory Assets
  $ 17,940     $ 83,730     $ 101,670    
Regulatory Liabilities:
                         
Accumulated Reserve for Estimated Removal Costs – Net of Salvage
  $ --     $ 71,454     $ 71,454  
asset lives
Deferred Income Taxes
    --       1,960       1,960  
asset lives
Minnesota Transmission Rider Accrued Refund
    670       --       670  
12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota
    --       289       289  
see note
North Dakota Renewable Resource Rider Accrued Refund
    261       --       261  
12 months
North Dakota Transmission Rider Accrued Refund
    215       --       215  
12 months
Deferred Marked-to-Market Gains
    6       117       123  
56 months
Deferred Gain on Sale of Utility Property – Minnesota Portion
    5       106       111  
240 months
South Dakota – Nonasset-Based Margin Sharing Excess
    38       --       38  
12 months
Total Regulatory Liabilities
  $ 1,195     $ 73,926     $ 75,121    
Net Regulatory Asset Position
  $ 16,745     $ 9,804     $ 26,549    
1Costs subject to recovery without a rate of return.
2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
 
The regulatory asset related to 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 Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.
 
Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.
 
All Deferred Marked-to-Market Gains and Losses recorded as of September 30, 2014 are related to forward purchases of energy scheduled for delivery through December 2018.
 
The Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.
 
Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.
 
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MISO Schedule 26/26A Transmission Cost Recovery Rider True-up relates to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-up also includes the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.
 
Minnesota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of September 30, 2014.
 
The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740.
 
Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 216 months.
 
North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the North Dakota share of amounts invested in the construction of the Big Stone Plant AQCS project, net of amounts billed under the rider.
 
Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.
 
North Dakota Transmission Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of September 30, 2014.
 
Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the Minnesota share of amounts invested in the construction of the Big Stone Plant AQCS project, net of amounts billed under the rider.
 
Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the MNRRA rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.
 
South Dakota Transmission Rider Accrued Revenues relate to revenues earned for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that have not been billed to South Dakota customers as of September 30, 2014.
 
The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.
 
The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of September 30, 2014.
 
Revenue for Rate Case Expenses Subject to Refund – Minnesota relate to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund.
 
Big Stone II Over Recovered Project Costs – North Dakota represent amounts collected from North Dakota customers in excess of the North Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project. The September 30, 2014 liability will be refunded to North Dakota customers through an adjustment to revenue requirements under the North Dakota TCR rider.
 
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 energ