[X]
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
|
For the quarterly period ended
|
June 30, 2011
|
[ ]
|
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)
|
Large accelerated filer X
|
Accelerated filer __
|
Non-accelerated filer __
(Do not check if a smaller reporting company)
|
Smaller reporting company __
|
Page No.
|
||
2 & 3
|
||
4
|
||
5
|
||
6-28
|
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29-49
|
||
49-51
|
||
51
|
||
52
|
||
52-53
|
||
54
|
||
54
|
||
54
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PART I. FINANCIAL INFORMATION
|
||||||||
Item 1. Financial Statements
|
||||||||
Otter Tail Corporation
|
||||||||
Consolidated Balance Sheets
|
||||||||
(not audited)
|
||||||||
(in thousands)
|
June 30,
2011
|
December 31,
2010
|
||||||
ASSETS
|
||||||||
Current Assets
|
||||||||
Cash and Cash Equivalents
|
$ | -- | $ | -- | ||||
Accounts Receivable:
|
||||||||
Trade—Net
|
148,252 | 124,353 | ||||||
Other
|
14,554 | 19,399 | ||||||
Inventories
|
86,235 | 79,270 | ||||||
Deferred Income Taxes
|
12,096 | 11,068 | ||||||
Accrued Utility and Cost-of-Energy Revenues
|
11,818 | 16,323 | ||||||
Costs and Estimated Earnings in Excess of Billings
|
71,688 | 67,352 | ||||||
Income Taxes Receivable
|
-- | 4,146 | ||||||
Other
|
21,017 | 20,224 | ||||||
Assets of Discontinued Operations
|
2,537 | 93,783 | ||||||
Total Current Assets
|
368,197 | 435,918 | ||||||
Investments
|
12,872 | 9,708 | ||||||
Other Assets
|
28,581 | 27,356 | ||||||
Goodwill
|
69,742 | 69,742 | ||||||
Other Intangibles—Net
|
15,932 | 16,280 | ||||||
Deferred Debits
|
||||||||
Unamortized Debt Expense
|
6,267 | 6,444 | ||||||
Regulatory Assets
|
114,514 | 127,766 | ||||||
Total Deferred Debits
|
120,781 | 134,210 | ||||||
Plant
|
||||||||
Electric Plant in Service
|
1,336,640 | 1,332,974 | ||||||
Nonelectric Operations
|
365,642 | 340,167 | ||||||
Construction Work in Progress
|
56,330 | 42,031 | ||||||
Total Gross Plant
|
1,758,612 | 1,715,172 | ||||||
Less Accumulated Depreciation and Amortization
|
666,570 | 637,831 | ||||||
Net Plant
|
1,092,042 | 1,077,341 | ||||||
Total Assets
|
$ | 1,708,147 | $ | 1,770,555 |
See accompanying notes to consolidated financial statements.
|
Otter Tail Corporation
|
||||||||
Consolidated Balance Sheets
|
||||||||
(not audited)
|
||||||||
(in thousands, except share data)
|
June 30,
2011
|
December 31,
2010
|
||||||
LIABILITIES AND EQUITY
|
||||||||
Current Liabilities
|
||||||||
Short-Term Debt
|
$ | 30,362 | $ | 79,490 | ||||
Current Maturities of Long-Term Debt
|
3,340 | 604 | ||||||
Accounts Payable
|
121,020 | 113,761 | ||||||
Accrued Salaries and Wages
|
20,247 | 20,252 | ||||||
Accrued Federal and State Income Taxes
|
504 | -- | ||||||
Other Accrued Taxes
|
8,392 | 11,957 | ||||||
Derivative Liabilities
|
18,683 | 17,991 | ||||||
Other Accrued Liabilities
|
8,464 | 9,546 | ||||||
Liabilities of Discontinued Operations
|
2,537 | 23,176 | ||||||
Total Current Liabilities
|
213,549 | 276,777 | ||||||
Pensions Benefit Liability
|
75,470 | 73,538 | ||||||
Other Postretirement Benefits Liability
|
43,187 | 42,372 | ||||||
Other Noncurrent Liabilities
|
20,526 | 21,043 | ||||||
Commitments (note 9)
|
||||||||
Deferred Credits
|
||||||||
Deferred Income Taxes
|
173,561 | 162,208 | ||||||
Deferred Tax Credits
|
34,125 | 44,945 | ||||||
Regulatory Liabilities
|
68,275 | 66,416 | ||||||
Other
|
488 | 556 | ||||||
Total Deferred Credits
|
276,449 | 274,125 | ||||||
Capitalization
|
||||||||
Long-Term Debt, Net of Current Maturities
|
433,715 | 434,812 | ||||||
Class B Stock Options of Subsidiary
|
-- | 525 | ||||||
Cumulative Preferred Shares
Authorized 1,500,000 Shares Without Par Value;
Outstanding 2011 and 2010 – 155,000 Shares
|
15,500 | 15,500 | ||||||
|
||||||||
Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value;
Outstanding - None
|
-- | -- | ||||||
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares;
|
||||||||
Outstanding, 2011—36,061,173 Shares; 2010—36,002,739 Shares
|
180,306 | 180,014 | ||||||
Premium on Common Shares
|
251,530 | 251,919 | ||||||
Retained Earnings
|
200,839 | 198,443 | ||||||
Accumulated Other Comprehensive (Loss) Income
|
(2,924 | ) | 1,487 | |||||
Total Common Equity
|
629,751 | 631,863 | ||||||
Total Capitalization
|
1,078,966 | 1,082,700 | ||||||
Total Liabilities and Equity
|
$ | 1,708,147 | $ | 1,770,555 |
See accompanying notes to consolidated financial statements.
|
Otter Tail Corporation
|
||||||||||||||||
Consolidated Statements of Income
|
||||||||||||||||
(not audited)
|
||||||||||||||||
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
(in thousands, except share and per-share amounts)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Operating Revenues
|
||||||||||||||||
Electric
|
$ | 77,977 | $ | 77,476 | $ | 169,502 | $ | 168,857 | ||||||||
Nonelectric
|
238,998 | 173,838 | 428,831 | 325,406 | ||||||||||||
Total Operating Revenues
|
316,975 | 251,314 | 598,333 | 494,263 | ||||||||||||
Operating Expenses
|
||||||||||||||||
Production Fuel - Electric
|
17,080 | 16,492 | 36,657 | 37,401 | ||||||||||||
Purchased Power - Electric System Use
|
7,894 | 10,420 | 20,271 | 22,476 | ||||||||||||
Electric Operation and Maintenance Expenses
|
28,687 | 29,253 | 57,395 | 57,719 | ||||||||||||
Cost of Goods Sold - Nonelectric (excludes depreciation; included below)
|
193,830 | 137,012 | 349,539 | 254,496 | ||||||||||||
Other Nonelectric Expenses
|
32,765 | 32,463 | 60,307 | 61,229 | ||||||||||||
Asset Impairment Charge
|
-- | 19,740 | -- | 19,740 | ||||||||||||
Depreciation and Amortization
|
19,725 | 18,655 | 38,811 | 37,229 | ||||||||||||
Property Taxes - Electric
|
2,417 | 2,477 | 4,826 | 4,951 | ||||||||||||
Total Operating Expenses
|
302,398 | 266,512 | 567,806 | 495,241 | ||||||||||||
Operating Income (Loss)
|
14,577 | (15,198 | ) | 30,527 | (978 | ) | ||||||||||
Other Income
|
1,107 | 552 | 1,828 | 565 | ||||||||||||
Interest Charges
|
9,149 | 9,398 | 18,638 | 18,420 | ||||||||||||
Income (Loss) Before Income Taxes – Continuing Operations
|
6,535 | (24,044 | ) | 13,717 | (18,833 | ) | ||||||||||
Income Tax Expense (Benefit) – Continuing Operations
|
537 | (7,769 | ) | 2,085 | (6,018 | ) | ||||||||||
Net Income (Loss) from Continuing Operations
|
5,998 | (16,275 | ) | 11,632 | (12,815 | ) | ||||||||||
Discontinued Operations
|
||||||||||||||||
Income (Loss) from Discontinued Operations net of income tax expense
|
||||||||||||||||
(benefit) of $(342), $1,227, $(364), and $1,856 for the respective periods
|
(422 | ) | 2,057 | (360 | ) | 3,314 | ||||||||||
Gain on Disposition of Discontinued Operations net of income taxes
|
||||||||||||||||
of $3,515 for the three and six months ended June 30, 2011
|
13,252 | -- | 13,252 | -- | ||||||||||||
Net Income from Discontinued Operations
|
12,830 | 2,057 | 12,892 | 3,314 | ||||||||||||
Total Net Income (Loss)
|
18,828 | (14,218 | ) | 24,524 | (9,501 | ) | ||||||||||
Preferred Dividend Requirement and Other Adjustments
|
506 | 279 | 690 | 463 | ||||||||||||
Earnings Available for Common Shares
|
$ | 18,322 | $ | (14,497 | ) | $ | 23,834 | $ | (9,964 | ) | ||||||
Average Number of Common Shares Outstanding—Basic
|
35,926,124 | 35,799,231 | 35,901,489 | 35,759,901 | ||||||||||||
Average Number of Common Shares Outstanding—Diluted
|
36,163,805 | 35,799,231 | 36,139,170 | 35,759,901 | ||||||||||||
Basic Earnings Per Common Share:
|
||||||||||||||||
Continuing Operations (net of preferred dividend requirement)
|
$ | 0.16 | $ | (0.46 | ) | $ | 0.31 | $ | (0.37 | ) | ||||||
Discontinued Operations (net of other adjustments)
|
0.35 | 0.06 | 0.35 | 0.09 | ||||||||||||
$ | 0.51 | $ | (0.40 | ) | $ | 0.66 | $ | (0.28 | ) | |||||||
Diluted Earnings Per Common Share:
|
||||||||||||||||
Continuing Operations (net of preferred dividend requirement)
|
$ | 0.16 | $ | (0.46 | ) | $ | 0.31 | $ | (0.37 | ) | ||||||
Discontinued Operations (net of other adjustments)
|
0.35 | 0.06 | 0.35 | 0.09 | ||||||||||||
$ | 0.51 | $ | (0.40 | ) | $ | 0.66 | $ | (0.28 | ) | |||||||
Dividends Per Common Share
|
$ | 0.2975 | $ | 0.2975 | $ | 0.5950 | $ | 0.5950 |
See accompanying notes to consolidated financial statements.
|
Otter Tail Corporation
|
||||||||
Consolidated Statements of Cash Flows
|
||||||||
(not audited)
|
||||||||
Six Months Ended
June 30,
|
||||||||
(in thousands)
|
2011
|
2010
|
||||||
Cash Flows from Operating Activities
|
||||||||
Net Income (Loss)
|
$ | 24,524 | $ | (9,501 | ) | |||
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
|
||||||||
Net Gain from Sale of Discontinued Operations
|
(13,252 | ) | -- | |||||
Net Loss (Income) from Discontinued Operations
|
360 | (3,314 | ) | |||||
Depreciation and Amortization
|
38,811 | 37,229 | ||||||
Asset Impairment Charge
|
-- | 19,740 | ||||||
Deferred Tax Credits
|
(1,281 | ) | (1,358 | ) | ||||
Deferred Income Taxes
|
5,611 | 7,547 | ||||||
Change in Deferred Debits and Other Assets
|
7,648 | (858 | ) | |||||
Change in Noncurrent Liabilities and Deferred Credits
|
1,230 | 4,471 | ||||||
Allowance for Equity (Other) Funds Used During Construction
|
(292 | ) | -- | |||||
Change in Derivatives Net of Regulatory Deferral
|
45 | (409 | ) | |||||
Stock Compensation Expense – Equity Awards
|
921 | 1,320 | ||||||
Other—Net
|
(243 | ) | (389 | ) | ||||
Cash (Used for) Provided by Current Assets and Current Liabilities:
|
||||||||
Change in Receivables
|
(18,936 | ) | (20,998 | ) | ||||
Change in Inventories
|
(6,966 | ) | (4,083 | ) | ||||
Change in Other Current Assets
|
(2,594 | ) | (15,874 | ) | ||||
Change in Payables and Other Current Liabilities
|
4,727 | (276 | ) | |||||
Change in Interest Payable and Income Taxes Receivable/Payable
|
377 | 36,594 | ||||||
Net Cash Provided by Continuing Operations
|
40,690 | 49,841 | ||||||
Net Cash Provided by (Used in) Discontinued Operations
|
47 | (422 | ) | |||||
Net Cash Provided by Operating Activities
|
40,737 | 49,419 | ||||||
Cash Flows from Investing Activities
|
||||||||
Capital Expenditures
|
(48,111 | ) | (38,605 | ) | ||||
Proceeds from Disposal of Noncurrent Assets
|
2,229 | 1,999 | ||||||
Net Decrease (Increase) in Other Investments
|
837 | (808 | ) | |||||
Net Cash Used in Investing Activities - Continuing Operations
|
(45,045 | ) | (37,414 | ) | ||||
Net Proceeds from Sale of Discontinued Operations
|
84,363 | -- | ||||||
Net Cash Used in Investing Activities - Discontinued Operations
|
(6,065 | ) | (960 | ) | ||||
Net Cash Provided by (Used in) Investing Activities
|
33,253 | (38,374 | ) | |||||
Cash Flows from Financing Activities
|
||||||||
Change in Checks Written in Excess of Cash
|
(5,937 | ) | 4,987 | |||||
Net Short-Term Borrowings
|
(49,128 | ) | 60,002 | |||||
Proceeds from Issuance of Common Stock
|
-- | 549 | ||||||
Proceeds from Issuance of Class B Stock of Subsidiary
|
-- | 153 | ||||||
Common Stock Issuance Expenses
|
-- | (142 | ) | |||||
Payments for Retirement of Common Stock
|
(152 | ) | (401 | ) | ||||
Payments for Retirement of Class B Stock of Subsidiary
|
-- | (994 | ) | |||||
Proceeds from Issuance of Long-Term Debt
|
2,007 | 95 | ||||||
Short-Term and Long-Term Debt Issuance Expenses
|
(688 | ) | (1,598 | ) | ||||
Payments for Retirement of Long-Term Debt
|
(368 | ) | (58,693 | ) | ||||
Dividends Paid and Other Distributions
|
(21,952 | ) | (21,812 | ) | ||||
Net Cash Used in Financing Activities - Continuing Operations
|
(76,218 | ) | (17,854 | ) | ||||
Net Cash Provided by Financing Activities - Discontinued Operations
|
2,552 | 2,241 | ||||||
Net Cash Used in Financing Activities
|
(73,666 | ) | (15,613 | ) | ||||
Cash and Cash Equivalents at Beginning of Period – Discontinued Operations
|
-- | (609 | ) | |||||
Effect of Foreign Exchange Rate Fluctuations on Cash – Discontinued Operations
|
(324 | ) | 136 | |||||
Net Change in Cash and Cash Equivalents
|
-- | (5,041 | ) | |||||
Cash and Cash Equivalents at Beginning of Period
|
-- | 5,041 | ||||||
Cash and Cash Equivalents at End of Period
|
$ | -- | $ | -- | ||||
See accompanying notes to consolidated financial statements.
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Percentage-of-Completion Revenues
|
33.9 | % | 27.6 | % | 32.8 | % | 26.7 | % |
June 30,
|
December 31,
|
|||||||
(in thousands)
|
2011
|
2010
|
||||||
Costs Incurred on Uncompleted Contracts
|
$ | 464,849 | $ | 460,125 | ||||
Less Billings to Date
|
(418,120 | ) | (430,471 | ) | ||||
Plus Estimated Earnings Recognized
|
22,085 | 31,231 | ||||||
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts
|
$ | 68,814 | $ | 60,885 |
|
June 30,
|
December 31,
|
||||||
(in thousands)
|
2011
|
2010
|
||||||
Costs and Estimated Earnings in Excess of Billings
|
$ | 71,688 | $ | 67,352 | ||||
Billings in Excess of Costs and Estimated Earnings
|
(2,874 | ) | (6,467 | ) | ||||
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts
|
$ | 68,814 | $ | 60,885 |
|
June 30,
|
December 31,
|
||||||
(in thousands)
|
2011
|
2010
|
||||||
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts - DMI
|
$ | 60,410 | $ | 58,990 |
|
June 30,
|
December 31,
|
||||||
(in thousands)
|
2011
|
2010
|
||||||
Accounts Receivable Retained by Customers
|
$ | 10,643 | $ | 11,848 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Accounts Receivable Sold
|
$ | 9,092 | $ | 18,500 | $ | 28,140 | $ | 29,300 | ||||||||
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable
|
135 | 75 | 253 | 107 |
June 30, 2011 (in thousands)
|
Level 1
|
Level 2
|
Level 3
|
||||||
Assets:
|
|||||||||
Investments for Nonqualified Retirement Savings Retirement Plan:
|
|||||||||
Money Market and Mutual Funds and Cash
|
$ | 804 | $ | -- | |||||
Forward Gasoline Purchase Contracts
|
131 | ||||||||
Forward Energy Contracts
|
4,832 | ||||||||
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts
|
14,646 | ||||||||
Investments of Captive Insurance Company:
|
|||||||||
Corporate Debt Securities
|
8,885 | ||||||||
Total Assets
|
$ | 9,820 | $ | 19,478 | |||||
Liabilities:
|
|||||||||
Forward Energy Contracts
|
$ | -- | $ | 18,683 | |||||
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts
|
149 | ||||||||
Total Liabilities
|
$ | -- | $ | 18,832 |
December 31, 2010 (in thousands)
|
Level 1
|
Level 2
|
Level 3
|
||||||
Assets:
|
|||||||||
Investments for Nonqualified Retirement Savings Retirement Plan:
|
|||||||||
Money Market and Mutual Funds and Cash
|
$ | 800 | $ | -- | |||||
Forward Gasoline Purchase Contracts
|
58 | ||||||||
Forward Energy Contracts
|
6,875 | ||||||||
Regulatory Asset – Deferred Mark-to-Market Losses on Forward Energy Contracts
|
12,054 | ||||||||
Investments of Captive Insurance Company:
|
|||||||||
Corporate Debt Securities
|
8,467 | ||||||||
Total Assets
|
$ | 9,325 | $ | 18,929 | |||||
Liabilities:
|
|||||||||
Forward Energy Contracts
|
$ | -- | $ | 17,991 | |||||
Regulatory Liability – Deferred Mark-to-Market Gains on Forward Energy Contracts
|
175 | ||||||||
Total Liabilities
|
$ | -- | $ | 18,166 |
Three Months Ended
|
Six Months Ended
|
|||||||
(in thousands)
|
June 30, 2010
|
June 30, 2010
|
||||||
MNCIP Incentives reclassified from Other Income to Operating Revenue
|
$ | 1,239 | $ | 1,601 |
June 30,
|
December 31,
|
|||||||
(in thousands)
|
2011
|
2010
|
||||||
Finished Goods
|
$ | 30,519 | $ | 29,113 | ||||
Work in Process
|
11,428 | 7,171 | ||||||
Raw Material, Fuel and Supplies
|
44,288 | 42,986 | ||||||
Total Inventories
|
$ | 86,235 | $ | 79,270 |
(in thousands)
|
Balance
December 31,
2010
|
Impairments
|
Balance (net of
impairments)
December 31,
2010
|
Adjustments
to Goodwill
in 2011
|
Balance (net of
impairments)
June 30,
2011
|
|||||||||||||||
Electric
|
$ | 240 | $ | (240 | ) | $ | -- | $ | -- | $ | -- | |||||||||
Wind Energy
|
6,959 | -- | 6,959 | -- | 6,959 | |||||||||||||||
Manufacturing
|
24,445 | (12,259 | ) | 12,186 | -- | 12,186 | ||||||||||||||
Construction
|
7,630 | -- | 7,630 | -- | 7,630 | |||||||||||||||
Plastics
|
19,302 | -- | 19,302 | -- | 19,302 | |||||||||||||||
Health Services
|
23,665 | -- | 23,665 | -- | 23,665 | |||||||||||||||
Total
|
$ | 82,241 | $ | (12,499 | ) | $ | 69,742 | $ | -- | $ | 69,742 |
June 30, 2011 (in thousands)
|
Gross Carrying
Amount
|
Accumulated
Amortization
|
Net Carrying
Amount
|
Amortization
Periods
|
|||||||||
Amortized Intangible Assets:
|
|||||||||||||
Customer Relationships
|
$ | 16,811 | $ | 2,812 | $ | 13,999 |
15 – 25 years
|
||||||
Covenants Not to Compete
|
1,704 | 1,694 | 10 |
3 – 5 years
|
|||||||||
Other Intangible Assets Including Contracts
|
1,030 | 897 | 133 |
5 – 30 years
|
|||||||||
Total
|
$ | 19,545 | $ | 5,403 | $ | 14,142 | |||||||
Nonamortized Intangible Assets:
|
|||||||||||||
Brand/Trade Name
|
$ | 1,790 | $ | -- | $ | 1,790 | |||||||
December 31, 2010 (in thousands)
|
|||||||||||||
Amortized Intangible Assets:
|
|||||||||||||
Customer Relationships
|
$ | 16,811 | $ | 2,388 | $ | 14,423 |
15 – 25 years
|
||||||
Covenants Not to Compete
|
1,704 | 1,676 | 28 |
3 – 5 years
|
|||||||||
Other Intangible Assets Including Contracts
|
930 | 891 | 39 |
5 – 30 years
|
|||||||||
Total
|
$ | 19,445 | $ | 4,955 | $ | 14,490 | |||||||
Nonamortized Intangible Assets:
|
|||||||||||||
Brand/Trade Name
|
$ | 1,790 | $ | -- | $ | 1,790 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Amortization Expense – Intangible Assets
|
$ | 224 | $ | 263 | $ | 448 | $ | 546 |
(in thousands)
|
2011
|
2012
|
2013
|
2014
|
2015
|
|||||||||||||||
Estimated Amortization Expense – Intangible Assets
|
$ | 887 | $ | 911 | $ | 947 | $ | 947 | $ | 931 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Net Income (Loss)
|
$ | 18,828 | $ | (14,218 | ) | $ | 24,524 | $ | (9,501 | ) | ||||||
Other Comprehensive (Loss) Income (net-of-tax):
|
||||||||||||||||
Reversal of Previously Recorded Foreign Currency Translation Gains
|
(4,422 | ) | (676 | ) | (3,977 | ) | (188 | ) | ||||||||
Amortization of Unrecognized Losses and Costs
Related to Postretirement Benefit Programs
|
428 | 104 | (442 | ) | 209 | |||||||||||
Unrealized Gain (Loss) on Available-for-Sale Securities
|
18 | (8 | ) | 8 | 31 | |||||||||||
Total Other Comprehensive (Loss) Income
|
(3,976 | ) | (580 | ) | (4,411 | ) | 52 | |||||||||
Total Comprehensive Income (Loss)
|
$ | 14,852 | $ | (14,798 | ) | $ | 20,113 | $ | (9,449 | ) |
Six Months Ended
|
||||||||
June 30,
|
||||||||
(in thousands)
|
2011
|
2010
|
||||||
Increases in Accounts Payable Related to Capital Expenditures
|
$ | 237 | $ | 745 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
United States of America
|
97.8 | % | 98.6 | % | 98.2 | % | 97.9 | % | ||||||||
Canada
|
2.0 | % | 1.2 | % | 1.7 | % | 2.0 | % | ||||||||
All Other Countries
|
0.2 | % | 0.2 | % | 0.1 | % | 0.1 | % |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Electric
|
$ | 78,031 | $ | 77,527 | $ | 169,627 | $ | 168,979 | ||||||||
Wind Energy
|
66,253 | 45,714 | 122,527 | 94,375 | ||||||||||||
Manufacturing
|
58,358 | 49,507 | 114,671 | 87,538 | ||||||||||||
Construction
|
49,133 | 30,149 | 86,648 | 47,923 | ||||||||||||
Plastics
|
44,373 | 26,739 | 62,851 | 49,826 | ||||||||||||
Health Services
|
22,983 | 23,645 | 45,478 | 48,816 | ||||||||||||
Corporate Revenues and Intersegment Eliminations
|
(2,156 | ) | (1,967 | ) | (3,469 | ) | (3,194 | ) | ||||||||
Total
|
$ | 316,975 | $ | 251,314 | $ | 598,333 | $ | 494,263 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Electric
|
$ | 4,990 | $ | 5,349 | $ | 10,078 | $ | 10,619 | ||||||||
Wind Energy
|
2,013 | 1,549 | 3,881 | 2,870 | ||||||||||||
Manufacturing
|
1,355 | 1,294 | 2,661 | 2,541 | ||||||||||||
Construction
|
227 | 155 | 447 | 273 | ||||||||||||
Plastics
|
402 | 428 | 765 | 791 | ||||||||||||
Health Services
|
445 | 280 | 844 | 525 | ||||||||||||
Corporate and Intersegment Eliminations
|
(283 | ) | 343 | (38 | ) | 801 | ||||||||||
Total
|
$ | 9,149 | $ | 9,398 | $ | 18,638 | $ | 18,420 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Electric
|
$ | 7 | $ | (529 | ) | $ | 2,608 | $ | 4,305 | |||||||
Wind Energy
|
(2,148 | ) | (1,615 | ) | (3,813 | ) | (1,524 | ) | ||||||||
Manufacturing
|
1,529 | (3,833 | ) | 3,059 | (4,451 | ) | ||||||||||
Construction
|
130 | (306 | ) | (80 | ) | (1,307 | ) | |||||||||
Plastics
|
2,144 | 141 | 1,903 | 635 | ||||||||||||
Health Services
|
339 | 55 | 748 | (377 | ) | |||||||||||
Corporate
|
(1,464 | ) | (1,682 | ) | (2,340 | ) | (3,299 | ) | ||||||||
Total
|
$ | 537 | $ | (7,769 | ) | $ | 2,085 | $ | (6,018 | ) |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Electric
|
$ | 7,386 | $ | 4,432 | $ | 18,528 | $ | 11,923 | ||||||||
Wind Energy
|
(6,535 | ) | (2,815 | ) | (12,946 | ) | (2,635 | ) | ||||||||
Manufacturing
|
2,721 | (15,116 | ) | 4,988 | (15,851 | ) | ||||||||||
Construction
|
184 | (493 | ) | (141 | ) | (1,982 | ) | |||||||||
Plastics
|
3,312 | 232 | 2,938 | 1,013 | ||||||||||||
Health Services
|
458 | 35 | 1,030 | (656 | ) | |||||||||||
Corporate
|
(1,712 | ) | (2,733 | ) | (3,133 | ) | (4,994 | ) | ||||||||
Discontinued Operations
|
12,508 | 1,961 | 12,570 | 3,218 | ||||||||||||
Total
|
$ | 18,322 | $ | (14,497 | ) | $ | 23,834 | $ | (9,964 | ) |
June 30,
|
December 31,
|
|||||||
(in thousands)
|
2011
|
2010
|
||||||
Electric
|
$ | 1,092,111 | $ | 1,106,261 | ||||
Wind Energy
|
181,884 | 172,753 | ||||||
Manufacturing
|
157,199 | 144,272 | ||||||
Construction
|
65,351 | 60,978 | ||||||
Plastics
|
94,035 | 73,508 | ||||||
Health Services
|
73,650 | 75,898 | ||||||
Corporate
|
41,380 | 43,102 | ||||||
Discontinued Operations
|
2,537 | 93,783 | ||||||
Total
|
$ | 1,708,147 | $ | 1,770,555 |
|
|
||||||||
(in thousands)
|
June 30,
2011 |
December 31,
2010 |
Remaining
Recovery/
Refund Period
|
||||||
Regulatory Assets - Current:
|
|||||||||
Accrued Cost-of-Energy Revenue
|
$ | 525 | $ | 2,387 |
14 months
|
||||
Regulatory Assets – Long Term:
|
|||||||||
Unrecognized Transition Obligation, Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
|
$ | 71,264 | $ | 74,156 |
see notes
|
||||
Deferred Marked-to-Market Losses
|
14,646 | 12,054 |
50 months
|
||||||
Deferred Conservation Improvement Program Costs & Accrued Incentives
|
7,569 | 6,655 |
24 months
|
||||||
Minnesota Renewable Resource Rider Accrued Revenues
|
4,057 | 6,834 |
33 months
|
||||||
Big Stone II Unrecovered Project Costs – North Dakota
|
2,768 | 3,460 |
25 months
|
||||||
Big Stone II Unrecovered Project Costs – Minnesota
|
2,758 | 6,445 |
63 months
|
||||||
Debt Reacquisition Premiums
|
2,664 | 3,107 |
255 months
|
||||||
Accumulated ARO Accretion/Depreciation Adjustment
|
2,434 | 2,218 |
asset lives
|
||||||
Deferred Income Taxes
|
1,644 | 5,785 |
asset lives
|
||||||
General Rate Case Recoverable Expenses
|
1,373 | 1,773 |
31 months
|
||||||
North Dakota Renewable Resource Rider Accrued Revenues
|
1,053 | 2,415 |
30 months
|
||||||
Big Stone II Unrecovered Project Costs – South Dakota
|
962 | 1,419 |
115 months
|
||||||
MISO Schedule 16 and 17 Deferred Administrative Costs - ND
|
530 | 717 |
17 months
|
||||||
South Dakota – Asset-Based Margin Sharing Shortfall
|
375 | 501 |
8 months
|
||||||
Minnesota Transmission Rider Accrued Revenues
|
252 | 34 |
18 months
|
||||||
Deferred Holding Company Formation Costs
|
165 | 193 |
36 months
|
||||||
Total Regulatory Assets – Long Term
|
$ | 114,514 | $ | 127,766 | |||||
Regulatory Liabilities:
|
|||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage
|
$ | 63,242 | $ | 61,740 |
asset lives
|
||||
Deferred Income Taxes
|
4,007 | 4,289 |
asset lives
|
||||||
Minnesota Transmission Rider Accrued Refund
|
677 | -- |
see notes
|
||||||
Deferred Marked-to-Market Gains
|
149 | 175 |
38 months
|
||||||
Deferred Gain on Sale of Utility Property – Minnesota Portion
|
125 | 128 |
270 months
|
||||||
South Dakota – Nonasset-Based Margin Sharing Excess
|
75 | 84 |
18 months
|
||||||
Total Regulatory Liabilities
|
$ | 68,275 | $ | 66,416 | |||||
Net Regulatory Asset Position
|
$ | 46,764 | $ | 63,737 |
(in thousands)
|
June 30,
2011
|
December 31,
2010
|
||||||
Current Asset – Marked-to-Market Gain
|
$ | 4,832 | $ | 6,875 | ||||
Regulatory Asset – Deferred Marked-to-Market Loss
|
14,646 | 12,054 | ||||||
Total Assets
|
19,478 | 18,929 | ||||||
Current Liability – Marked-to-Market Loss
|
(18,683 | ) | (17,991 | ) | ||||
Regulatory Liability – Deferred Marked-to-Market Gain
|
(149 | ) | (175 | ) | ||||
Total Liabilities
|
(18,832 | ) | (18,166 | ) | ||||
Net Fair Value of Marked-to-Market Energy Contracts
|
$ | 646 | $ | 763 |
(in thousands)
|
Year-to-Date
June 30, 2011
|
|||
Fair Value at Beginning of Year
|
$ | 763 | ||
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011
|
(145 | ) | ||
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011
|
(6 | ) | ||
Changes in Fair Value of Contracts Entered into in 2009 in 2011
|
(14 | ) | ||
Changes in Fair Value of Contracts Entered into in 2010 in 2011
|
(72 | ) | ||
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period
|
526 | |||
Changes in Fair Value of Contracts Entered into in 2011
|
120 | |||
Net Fair Value End of Period
|
$ | 646 |
(in thousands)
|
3rd Quarter 2011
|
4th Quarter 2011
|
2012
|
Total
|
||||||||||||
Net Gain
|
$ | 32 | $ | 145 | $ | 469 | $ | 646 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Net Gains (Losses) on Forward Electric Energy Contracts
|
$ | 139 | $ | (24 | ) | $ | 131 | $ | 1,801 |
June 30, 2011
|
December 31, 2010
|
|||||||||||||||
(in thousands)
|
Exposure
|
Counterparties
|
Exposure
|
Counterparties
|
||||||||||||
Net Credit Risk on Forward Energy Contracts
|
$ | 1,732 | 4 | $ | 1,129 | 4 | ||||||||||
Net Credit Risk to Single Largest Counterparty
|
$ | 970 | $ | 585 |
Current Liability – Marked-to-Market Loss (in thousands)
|
June 30,
2011
|
December 31,
2010
|
||||||
Loss Contracts Covered by Deposited Funds
|
$ | -- | $ | 427 | ||||
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1
|
4,112 | 10,904 | ||||||
Loss Contracts with No Ratings Triggers or Deposit Requirements
|
14,571 | 6,660 | ||||||
Total Current Liability – Marked-to-Market Loss
|
$ | 18,683 | $ | 17,991 | ||||
1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
|
||||||||
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade
|
$ | 4,112 | $ | 10,904 | ||||
Offsetting Gains with Counterparties under Master Netting Agreements
|
(4,112 | ) | (6,219 | ) | ||||
Net Deposit Requirements on Contracts with Credit Risk Related Features
|
$ | -- | $ | 4,685 | ||||
Covered by Deposited Funds
|
-- | -- | ||||||
Reporting Date Deposit Requirement if Credit Risk Feature Triggered
|
$ | -- | $ | 4,685 |
Common Shares Outstanding, December 31, 2010
|
36,002,739 | |||
Issuances:
|
||||
Restricted Stock Issued to Employees
|
24,600 | |||
Restricted Stock Issued to Nonemployee Directors
|
24,000 | |||
Vesting of Restricted Stock Units
|
16,475 | |||
Retirements:
|
||||
Shares Withheld for Individual Income Tax Requirements
|
(6,641 | ) | ||
Common Shares Outstanding, June 30, 2011
|
36,061,173 |
Three Months Ended June 30,
|
Options Outstanding
|
Range of Exercise Prices
|
2011
|
172,460
|
$24.93 – $31.34
|
2010
|
388,960
|
$24.93 – $31.34
|
Six Months Ended June 30,
|
Options Outstanding
|
Range of Exercise Prices
|
2011
|
172,460
|
$24.93 – $31.34
|
2010
|
388,960
|
$24.93 – $31.34
|
Award
|
Shares/Units
Granted
|
Grant-Date
Fair Value
per Share
|
Vesting
|
||||||
Restricted Stock Granted to Nonemployee Directors
|
24,000 | $ | 22.51 |
25% per year through April 8, 2015
|
|||||
Restricted Stock Granted to Executive Officers
|
24,600 | $ | 22.51 |
25% per year through April 8, 2015
|
|||||
Stock Performance Awards Granted to Executive Officers
|
48,600 | $ | 23.61 |
December 31, 2013
|
|||||
Restricted Stock Units Granted to Employees
|
19,800 | $ | 18.03 |
100% on April 8, 2015
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Employee Stock Purchase Plan (15% discount)
|
$ | 72 | $ | 72 | $ | 134 | $ | 141 | ||||||||
Restricted Stock Granted to Directors
|
195 | 158 | 387 | 298 | ||||||||||||
Restricted Stock Granted to Employees
|
133 | 162 | 248 | 280 | ||||||||||||
Stock Performance Awards Granted to Executive Officers
|
-- | (65 | ) | -- | 157 | |||||||||||
Restricted Stock Units Granted to Employees
|
70 | 97 | 153 | 157 | ||||||||||||
Totals
|
$ | 470 | $ | 424 | $ | 922 | $ | 1,033 |
Capacity and Energy Requirements (thousands)
|
June 30, 2011
|
December 31, 2010
|
Increase
|
|||||||||
2011
|
$ | 21,268 | $ | 20,134 | $ | 1,134 | ||||||
2012
|
25,025 | 21,637 | 3,388 | |||||||||
2013
|
21,868 | 16,492 | 5,376 | |||||||||
2014
|
24,701 | 15,388 | 9,313 | |||||||||
2015
|
18,915 | 12,307 | 6,608 | |||||||||
Beyond 2015
|
78,879 | 78,879 | -- | |||||||||
Total
|
$ | 190,656 | $ | 164,837 | $ | 25,819 |
Coal and Freight Purchase Commitments (thousands)
|
June 30, 2011
|
December 31, 2010
|
Increase
|
|||||||||
2011
|
$ | 52,819 | $ | 47,122 | $ | 5,697 | ||||||
2012
|
48,692 | 34,958 | 13,734 | |||||||||
2013
|
9,855 | 9,855 | -- | |||||||||
2014
|
9,854 | 9,854 | -- | |||||||||
2015
|
9,854 | 9,854 | -- | |||||||||
Beyond 2015
|
4,106 | 4,106 | -- | |||||||||
Total
|
$ | 135,180 | $ | 115,749 | $ | 19,431 |
(in thousands)
|
Line Limit
|
In Use on
June 30, 2011
|
Restricted due to
Outstanding
Letters of Credit
|
Available on
June 30, 2011
|
Available on
December 31,
2010
|
|||||||||||||||
Otter Tail Corporation Credit Agreement
|
$ | 200,000 | $ | 16,661 | 1 | $ | 1,674 | $ | 181,665 | $ | 144,350 | |||||||||
OTP Credit Agreement
|
170,000 | 16,052 | 1,050 | 152,898 | 144,436 | |||||||||||||||
Total
|
$ | 370,000 | $ | 32,713 | 1 | $ | 2,724 | $ | 334,563 | $ | 288,786 | |||||||||
1In use amount includes $2,351,000 assigned to the heavy haul and specialized shipment and transportation of wind turbine components business of Wylie and reflected in Liabilities of Discontinued Operations on the Company’s June 30, 2011 consolidated balance sheet.
|
(in thousands)
|
OTP
|
Varistar
|
Otter Tail
Corporation
|
Otter Tail
Corporation
Consolidated
|
||||||||||||
Short-Term Debt – Credit Lines
|
$ | 16,052 | $ | 16,661 | $ | 32,713 | ||||||||||
Long-Term Debt:
|
||||||||||||||||
Senior Unsecured Notes 6.63%, due December 1, 2011
|
$ | 90,000 | $ | 90,000 | ||||||||||||
Pollution Control Refunding Revenue Bonds,
Variable, 2.10% at June 30, 2011, due December 1, 2012
|
10,400 | 10,400 | ||||||||||||||
9.000% Notes, due December 15, 2016
|
$ | 100,000 | 100,000 | |||||||||||||
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
|
33,000 | 33,000 | ||||||||||||||
Grant County, South Dakota Pollution Control
Refunding Revenue Bonds 4.65%, due September 1, 2017
|
5,090 | 5,090 | ||||||||||||||
Senior Unsecured Note 8.89%, due November 30, 2017
|
50,000 | 50,000 | ||||||||||||||
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
|
30,000 | 30,000 | ||||||||||||||
Mercer County, North Dakota Pollution Control
Refunding Revenue Bonds 4.85%, due September 1, 2022
|
20,215 | 20,215 | ||||||||||||||
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
|
42,000 | 42,000 | ||||||||||||||
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
|
50,000 | 50,000 | ||||||||||||||
Other Obligations - Various up to 13.31% at June 30, 2011
|
$ | 4,387 | 1,968 | 6,355 | ||||||||||||
Total
|
$ | 280,705 | $ | 4,387 | $ | 151,968 | $ | 437,060 | ||||||||
Less:
|
||||||||||||||||
Current Maturities
|
-- | 3,181 | 159 | 3,340 | ||||||||||||
Unamortized Debt Discount
|
-- | -- | 5 | 5 | ||||||||||||
Total Long-Term Debt
|
$ | 280,705 | $ | 1,206 | $ | 151,804 | $ | 433,715 | ||||||||
Total Short-Term and Long-Term Debt (with current maturities)
|
$ | 296,757 | $ | 4,387 | $ | 168,624 | $ | 469,768 |
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service Cost—Benefit Earned During the Period
|
$ | 1,175 | $ | 1,247 | $ | 2,350 | $ | 2,494 | ||||||||
Interest Cost on Projected Benefit Obligation
|
3,175 | 3,030 | 6,350 | 6,060 | ||||||||||||
Expected Return on Assets
|
(3,538 | ) | (3,400 | ) | (7,075 | ) | (6,800 | ) | ||||||||
Amortization of Prior-Service Cost
|
100 | 170 | 200 | 340 | ||||||||||||
Amortization of Net Actuarial Loss
|
650 | 495 | 1,300 | 990 | ||||||||||||
Net Periodic Pension Cost
|
$ | 1,562 | $ | 1,542 | $ | 3,125 | $ | 3,084 |
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service Cost—Benefit Earned During the Period
|
$ | 21 | $ | 165 | $ | 41 | $ | 330 | ||||||||
Interest Cost on Projected Benefit Obligation
|
408 | 418 | 816 | 836 | ||||||||||||
Amortization of Prior-Service Cost
|
18 | 18 | 37 | 36 | ||||||||||||
Amortization of Net Actuarial Loss
|
61 | 119 | 122 | 238 | ||||||||||||
Net Periodic Pension Cost
|
$ | 508 | $ | 720 | $ | 1,016 | $ | 1,440 |
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service Cost—Benefit Earned During the Period
|
$ | 425 | $ | 425 | $ | 850 | $ | 850 | ||||||||
Interest Cost on Projected Benefit Obligation
|
850 | 775 | 1,700 | 1,550 | ||||||||||||
Amortization of Transition Obligation
|
187 | 187 | 374 | 374 | ||||||||||||
Amortization of Prior-Service Cost
|
50 | 50 | 100 | 100 | ||||||||||||
Amortization of Net Actuarial Loss
|
213 | 188 | 426 | 376 | ||||||||||||
Effect of Medicare Part D Expected Subsidy
|
(525 | ) | (500 | ) | (1,050 | ) | (1,000 | ) | ||||||||
Net Periodic Postretirement Benefit Cost
|
$ | 1,200 | $ | 1,125 | $ | 2,400 | $ | 2,250 |
June 30, 2011
|
December 31, 2010
|
|||||||||||||||
(in thousands)
|
Carrying
Amount
|
Fair Value
|
Carrying
Amount
|
Fair Value
|
||||||||||||
Cash and Short-Term Investments
|
$ | -- | $ | -- | $ | -- | $ | -- | ||||||||
Long-Term Debt
|
(433,715 | ) | (466,010 | ) | (434,812 | ) | (474,307 | ) |
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||||||||||
(in thousands)
|
2011
|
2010
|
Variance
|
2011
|
2010
|
Variance
|
||||||||||||||||||
Income (Loss) Before Income Taxes – Continuing Operations
|
$ | 6,535 | $ | (24,044 | ) | $ | 30,579 | $ | 13,717 | $ | (18,833 | ) | $ | 32,550 | ||||||||||
Income Tax Expense (Benefit) - Continuing Operations
|
537 | (7,769 | ) | 8,306 | 2,085 | (6,018 | ) | 8,103 | ||||||||||||||||
Effective Income Tax Rate – Continuing Operations
|
8.2 | % | 32.3 | % | 15.2 | % | 32.0 | % |
Three Months Ended
|
||||||||||||||||||||||||
June 30, 2011
|
June 30, 2010
|
|||||||||||||||||||||||
(in thousands)
|
IPH
|
Wylie-Wind
|
Total
|
IPH
|
Wylie-Wind
|
Total
|
||||||||||||||||||
Operating Revenues
|
$ | 7,480 | $ | 125 | $ | 7,605 | $ | 18,255 | $ | 1,917 | $ | 20,172 | ||||||||||||
Income (Loss) Before Income Taxes
|
$ | 966 | $ | (1,730 | ) | $ | (764 | ) | $ | 2,992 | $ | 292 | $ | 3,284 | ||||||||||
Gain on Disposition - Pretax
|
16,767 | -- | 16,767 | -- | -- | -- | ||||||||||||||||||
Income Tax Expense (Benefit)
|
3,865 | (692 | ) | 3,173 | 1,110 | 117 | 1,227 | |||||||||||||||||
Net Income
|
$ | 13,868 | $ | (1,038 | ) | $ | 12,830 | $ | 1,882 | $ | 175 | $ | 2,057 |
Six Months Ended
|
||||||||||||||||||||||||
June 30, 2011
|
June 30, 2010
|
|||||||||||||||||||||||
(in thousands)
|
IPH
|
Wylie-Wind
|
Total
|
IPH
|
Wylie-Wind
|
Total
|
||||||||||||||||||
Operating Revenues
|
$ | 28,125 | $ | 5,448 | $ | 33,573 | $ | 37,170 | $ | 2,654 | $ | 39,824 | ||||||||||||
Income (Loss) Before Income Taxes
|
$ | 3,840 | $ | (4,564 | ) | $ | (724 | ) | $ | 5,123 | $ | 47 | $ | 5,170 | ||||||||||
Gain on Disposition - Pretax
|
16,767 | -- | 16,767 | -- | -- | -- | ||||||||||||||||||
Income Tax Expense (Benefit)
|
4,977 | (1,826 | ) | 3,151 | 1,837 | 19 | 1,856 | |||||||||||||||||
Net Income
|
$ | 15,630 | $ | (2,738 | ) | $ | 12,892 | $ | 3,286 | $ | 28 | $ | 3,314 |
June 30, 2011
|
December 31, 2010
|
|||||||||||||||||||
(in thousands)
|
Wylie-Wind
|
Total
|
IPH
|
Wylie-Wind
|
Total
|
|||||||||||||||
Current Assets
|
$ | 2,462 | $ | 2,462 | $ | 24,836 | $ | 2,461 | $ | 27,297 | ||||||||||
Goodwill
|
-- | -- | 24,324 | -- | 24,324 | |||||||||||||||
Other Intangibles - Net
|
-- | -- | 10,852 | -- | 10,852 | |||||||||||||||
Net Plant
|
75 | 75 | 30,672 | 638 | 31,310 | |||||||||||||||
Assets of Discontinued Operations
|
$ | 2,537 | $ | 2,537 | $ | 90,684 | $ | 3,099 | $ | 93,783 | ||||||||||
Short-Term Debt
|
$ | 2,351 | $ | 2,351 | $ | -- | $ | -- | $ | -- | ||||||||||
Other Current Liabilities
|
186 | 186 | 6,839 | 4,150 | 10,989 | |||||||||||||||
Deferred Income Taxes
|
-- | -- | 11,553 | -- | 11,553 | |||||||||||||||
Long-Term Debt
|
-- | -- | 634 | -- | 634 | |||||||||||||||
Liabilities of Discontinued Operations
|
$ | 2,537 | $ | 2,537 | $ | 19,026 | $ | 4,150 | $ | 23,176 |
Otter Tail Corporation
Summary Consolidated Income Statements
For the Years Ended December 31,
|
||||||||||||||||||||||||
2010
|
2009
|
|||||||||||||||||||||||
(in thousands, except per share amounts)
|
As Previously Reported
|
IPH1
|
With IPH classified as Discontinued Operations
|
As Previously Reported
|
IPH1
|
With IPH classified as Discontinued Operations
|
||||||||||||||||||
Operating Revenues
|
$ | 1,119,084 | $ | 77,202 | $ | 1,041,882 | $ | 1,039,512 | $ | 78,632 | $ | 960,880 | ||||||||||||
Operating Expenses:
|
||||||||||||||||||||||||
Cost of Goods Sold
|
600,956 | 56,619 | 544,337 | 565,192 | 58,718 | 506,474 | ||||||||||||||||||
Other Operating Expenses
|
402,919 | 3,729 | 399,190 | 355,322 | 3,330 | 351,992 | ||||||||||||||||||
Depreciation Expense
|
80,696 | 4,703 | 75,993 | 73,608 | 4,333 | 69,275 | ||||||||||||||||||
Total Operating Expenses
|
1,084,571 | 65,051 | 1,019,520 | 994,122 | 66,381 | 927,741 | ||||||||||||||||||
Operating Income
|
34,513 | 12,151 | 22,362 | 45,390 | 12,251 | 33,139 | ||||||||||||||||||
Other Income (Deductions)
|
5,126 | (408 | ) | 5,534 | 4,550 | (404 | ) | 4,954 | ||||||||||||||||
Interest Charges
|
37,032 | 29 | 37,003 | 28,514 | 30 | 28,484 | ||||||||||||||||||
Income Tax Expense (Benefit)
|
3,951 | 3,716 | 235 | (4,605 | ) | 4,410 | (9,015 | ) | ||||||||||||||||
Net Income - Continuing Operations
|
(1,344 | ) | 7,998 | (9,342 | ) | 26,031 | 7,407 | 18,624 | ||||||||||||||||
Net Income – Discontinued Operations
|
7,998 | 7,407 | ||||||||||||||||||||||
Net Income
|
(1,344 | ) | 7,998 | (1,344 | ) | 26,031 | 7,407 | 26,031 | ||||||||||||||||
Preferred Dividend Requirements
|
833 | -- | 833 | 736 | -- | 736 | ||||||||||||||||||
Earnings Available for Common Shares
|
$ | (2,177 | ) | $ | 7,998 | $ | (2,177 | ) | $ | 25,295 | $ | 7,407 | $ | 25,295 | ||||||||||
Basic Earnings Per Common Share:
|
||||||||||||||||||||||||
Continuing Operations (net of preferred dividend requirement)
|
$ | (0.06 | ) | $ | 0.22 | $ | (0.28 | ) | $ | 0.71 | $ | 0.21 | $ | 0.50 | ||||||||||
Discontinued Operations
|
0.22 | 0.21 | ||||||||||||||||||||||
$ | (0.06 | ) | $ | 0.71 | ||||||||||||||||||||
Diluted Earnings Per Common Share:
|
||||||||||||||||||||||||
Continuing Operations (net of preferred dividend requirement)
|
$ | (0.06 | ) | $ | 0.22 | $ | (0.28 | ) | $ | 0.71 | $ | 0.21 | $ | 0.50 | ||||||||||
Discontinued Operations
|
0.22 | 0.21 | ||||||||||||||||||||||
$ | (0.06 | ) | $ | 0.71 | ||||||||||||||||||||
1Includes reinstatement of intercompany eliminations related to intercompany transactions with IPH.
|
Intersegment Eliminations (in thousands)
|
June 30, 2011
|
June 30, 2010
|
||||||
Operating Revenues:
|
||||||||
Electric
|
$ | 54 | $ | 51 | ||||
Nonelectric
|
2,102 | 1,916 | ||||||
Cost of Goods Sold
|
2,105 | 1,644 | ||||||
Other Nonelectric Expenses
|
51 | 323 |
Three Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Retail Sales Revenues
|
$ | 67,702 | $ | 67,791 | $ | (89 | ) | (0.1 | ) | |||||||
Wholesale Revenues – Company Generation
|
3,563 | 5,201 | (1,638 | ) | (31.5 | ) | ||||||||||
Net Revenue – Energy Trading Activity
|
750 | 519 | 231 | 44.5 | ||||||||||||
Other Revenues
|
6,016 | 4,016 | 2,000 | 49.8 | ||||||||||||
Total Operating Revenues
|
$ | 78,031 | $ | 77,527 | $ | 504 | 0.7 | |||||||||
Production Fuel
|
17,080 | 16,492 | 588 | 3.6 | ||||||||||||
Purchased Power – System Use
|
7,894 | 10,420 | (2,526 | ) | (24.2 | ) | ||||||||||
Other Operation and Maintenance Expenses
|
28,687 | 29,253 | (566 | ) | (1.9 | ) | ||||||||||
Depreciation and Amortization
|
10,020 | 10,038 | (18 | ) | (0.2 | ) | ||||||||||
Property Taxes
|
2,417 | 2,477 | (60 | ) | (2.4 | ) | ||||||||||
Operating Income
|
$ | 11,933 | $ | 8,847 | $ | 3,086 | 34.9 |
Three Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Wind Tower Revenues
|
$ | 55,022 | $ | 35,676 | $ | 19,346 | 54.2 | |||||||||
Transportation Revenues
|
11,231 | 10,038 | 1,193 | 11.9 | ||||||||||||
Total Operating Revenues
|
$ | 66,253 | $ | 45,714 | 20,539 | 44.9 | ||||||||||
Cost of Goods Sold
|
55,937 | 33,230 | 22,707 | 68.3 | ||||||||||||
Operating Expenses
|
14,070 | 12,426 | 1,644 | 13.2 | ||||||||||||
Depreciation and Amortization
|
2,939 | 2,759 | 180 | 6.5 | ||||||||||||
Operating Loss
|
$ | (6,693 | ) | $ | (2,701 | ) | $ | (3,992 | ) | (147.8 | ) |
●
|
Revenues at DMI Industries, Inc., (DMI), our manufacturer of wind towers, increased as a result of a 43.4% increase in tower production.
|
●
|
Revenues at Wylie, our flatbed trucking company, increased as a result of an 8.1% increase in miles driven by company-owned trucks combined with an increase in fuel surcharge revenues related to a 35.8% increase in the average cost per gallon of fuel consumed.
|
● | Cost of goods sold at DMI increased $22.7 million, reflecting $19.0 million in increased costs related to the increase in towers produced, a $1.5 million increase in outsourced quality control costs to satisfy expanded customer requirements, productivity losses of $1.3 million due to rework and underutilization of plant capacity, and $0.8 million from the absorption of higher steel costs when a supplier did not fulfill its delivery requirements. |
●
|
Operating expenses at DMI were unchanged between the quarters.
|
●
|
Operating expenses at Wylie increased $1.6 million as a result of increases in labor and fuel costs related to the increase in miles driven by company-owned trucks combined with higher fuel prices.
|
Three Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Revenues
|
$ | 58,358 | $ | 49,507 | $ | 8,851 | 17.9 | |||||||||
Cost of Goods Sold
|
43,252 | 36,086 | 7,166 | 19.9 | ||||||||||||
Operating Expenses
|
6,273 | 8,082 | (1,809 | ) | (22.4 | ) | ||||||||||
Asset Impairment Charge
|
-- | 19,740 | (19,740 | ) | -- | |||||||||||
Depreciation and Amortization
|
3,231 | 3,263 | (32 | ) | (1.0 | ) | ||||||||||
Operating Income (Loss)
|
$ | 5,602 | $ | (17,664 | ) | $ | 23,266 | 131.7 |
●
|
Revenues at BTD Manufacturing, Inc. (BTD), our metal parts stamping and fabrication company, increased $9.3 million as a result of higher sales volume due to improved customer demand.
|
●
|
Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased by $0.6 million due to decreases in sales volumes of all product lines except horticultural products.
|
●
|
Revenues at ShoreMaster, Inc. (ShoreMaster), our waterfront equipment business, increased $0.2 million mainly as a result of higher sales of residential products.
|
●
|
Cost of goods sold at BTD increased $7.7 million mainly as a result of increased sales volume.
|
●
|
Cost of goods sold at T.O. Plastics decreased $0.5 million as a result of the decrease in sales volume.
|
●
|
Cost of goods sold at ShoreMaster was unchanged between the quarters.
|
●
|
Operating expenses at BTD increased $0.5 million mainly due to increased salary and benefit costs related to workforce expansion.
|
●
|
Operating expenses at T.O. Plastics did not change between the quarters.
|
●
|
Operating expenses at ShoreMaster decreased $2.4 million, reflecting a $2.2 million increase to its allowance for doubtful accounts in its residential and commercial businesses in the second quarter of 2010.
|
Three Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Revenues
|
$ | 49,133 | $ | 30,149 | $ | 18,984 | 63.0 | |||||||||
Cost of Goods Sold
|
45,108 | 27,360 | 17,748 | 64.9 | ||||||||||||
Operating Expenses
|
3,015 | 3,027 | (12 | ) | (0.4 | ) | ||||||||||
Depreciation and Amortization
|
495 | 431 | 64 | 14.8 | ||||||||||||
Operating Income (Loss)
|
$ | 515 | $ | (669 | ) | $ | 1,184 | 177.0 |
●
|
Revenues at Foley Company, a mechanical and prime contractor on industrial projects, increased $19.8 million due to an increase in the magnitude and volume of jobs in progress.
|
●
|
Revenues at Aevenia, Inc. (Aevenia), our electrical design and construction services company, decreased $0.8 million between the quarters.
|
●
|
Cost of goods sold at Foley Company increased $18.4 million, mainly in the areas of material and subcontractor costs related to the increase in Foley’s work volume between the quarters.
|
●
|
Cost of goods sold at Aevenia decreased $0.7 million between the quarters, commensurate with their decrease in revenues.
|
Three Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Revenues
|
$ | 44,373 | $ | 26,739 | $ | 17,634 | 65.9 | |||||||||
Cost of Goods Sold
|
36,220 | 23,942 | 12,278 | 51.3 | ||||||||||||
Operating Expenses
|
1,436 | 1,225 | 211 | 17.2 | ||||||||||||
Depreciation and Amortization
|
864 | 778 | 86 | 11.1 | ||||||||||||
Operating Income
|
$ | 5,853 | $ | 794 | $ | 5,059 | 637.2 |
Three Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Revenues
|
$ | 22,983 | $ | 23,645 | $ | (662 | ) | (2.8 | ) | |||||||
Cost of Goods Sold
|
15,418 | 18,038 | (2,620 | ) | (14.5 | ) | ||||||||||
Operating Expenses
|
4,598 | 4,146 | 452 | 10.9 | ||||||||||||
Depreciation and Amortization
|
2,034 | 1,252 | 782 | 62.5 | ||||||||||||
Operating Income
|
$ | 933 | $ | 209 | $ | 724 | 346.4 |
Three Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Expenses
|
$ | 3,424 | $ | 3,880 | $ | (456 | ) | (11.8 | ) | |||||||
Depreciation and Amortization
|
142 | 134 | 8 | 6.0 |
Three Months Ended
June 30,
|
||||||||||||
(in thousands)
|
2011
|
2010
|
Variance
|
|||||||||
Income (Loss) Before Income Taxes – Continuing Operations
|
$ | 6,535 | $ | (24,044 | ) | $ | 30,579 | |||||
Income Tax Expense (Benefit) - Continuing Operations
|
537 | (7,769 | ) | 8,306 | ||||||||
Effective Income Tax Rate – Continuing Operations
|
8.2 | % | 32.3 | % |
Three Months Ended
|
||||||||||||||||||||||||
June 30, 2011
|
June 30, 2010
|
|||||||||||||||||||||||
(in thousands)
|
IPH
|
Wylie-Wind
|
Total
|
IPH
|
Wylie-Wind
|
Total
|
||||||||||||||||||
Operating Revenues
|
$ | 7,480 | $ | 125 | $ | 7,605 | $ | 18,255 | $ | 1,917 | $ | 20,172 | ||||||||||||
Income (Loss) Before Income Taxes
|
$ | 966 | $ | (1,730 | ) | $ | (764 | ) | $ | 2,992 | $ | 292 | $ | 3,284 | ||||||||||
Gain on Disposition - Pretax
|
16,767 | -- | 16,767 | -- | -- | -- | ||||||||||||||||||
Income Tax Expense (Benefit)
|
3,865 | (692 | ) | 3,173 | 1,110 | 117 | 1,227 | |||||||||||||||||
Net Income
|
$ | 13,868 | $ | (1,038 | ) | $ | 12,830 | $ | 1,882 | $ | 175 | $ | 2,057 |
Intersegment Eliminations (in thousands)
|
June 30, 2011
|
June 30, 2010
|
||||||
Operating Revenues:
|
||||||||
Electric
|
$ | 125 | $ | 122 | ||||
Nonelectric
|
3,344 | 3,072 | ||||||
Cost of Goods Sold
|
3,160 | 2,725 | ||||||
Other Nonelectric Expenses
|
309 | 469 |
Six Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Retail Sales Revenues
|
$ | 150,605 | $ | 149,166 | $ | 1,439 | 1.0 | |||||||||
Wholesale Revenues – Company Generation
|
6,299 | 9,193 | (2,894 | ) | (31.5 | ) | ||||||||||
Net Revenue – Energy Trading Activity
|
978 | 2,526 | (1,548 | ) | (61.3 | ) | ||||||||||
Other Revenues
|
11,745 | 8,094 | 3,651 | 45.1 | ||||||||||||
Total Operating Revenues
|
$ | 169,627 | $ | 168,979 | $ | 648 | 0.4 | |||||||||
Production Fuel
|
36,657 | 37,401 | (744 | ) | (2.0 | ) | ||||||||||
Purchased Power – System Use
|
20,271 | 22,476 | (2,205 | ) | (9.8 | ) | ||||||||||
Other Operation and Maintenance Expenses
|
57,395 | 57,719 | (324 | ) | (0.6 | ) | ||||||||||
Depreciation and Amortization
|
20,059 | 20,075 | (16 | ) | (0.1 | ) | ||||||||||
Property Taxes
|
4,826 | 4,951 | (125 | ) | (2.5 | ) | ||||||||||
Operating Income
|
$ | 30,419 | $ | 26,357 | $ | 4,062 | 15.4 |
Six Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Wind Tower Revenues
|
$ | 102,010 | $ | 76,604 | $ | 25,406 | 33.2 | |||||||||
Transportation Revenues
|
20,517 | 17,771 | 2,746 | 15.5 | ||||||||||||
Total Operating Revenues
|
$ | 122,527 | $ | 94,375 | 28,152 | 29.8 | ||||||||||
Cost of Goods Sold
|
103,728 | 66,657 | 37,071 | 55.6 | ||||||||||||
Operating Expenses
|
25,933 | 23,078 | 2,855 | 12.4 | ||||||||||||
Depreciation and Amortization
|
5,583 | 5,476 | 107 | 2.0 | ||||||||||||
Operating Loss
|
$ | (12,717 | ) | $ | (836 | ) | $ | (11,881 | ) | -- |
●
|
Revenues at DMI increased as a result of a 38.8% increase in tower production.
|
●
|
Revenues at Wylie increased $2.7 million including: (1) $2.2 million related to a 6.9% increase in miles driven by company-owned trucks combined with an increase in fuel surcharge revenues related to a 34.5% increase in the average cost per gallon of fuel consumed, and (2) a $0.5 million increase in brokerage revenues.
|
● | Cost of goods sold at DMI increased $37.1 million reflecting $23.6 million in increased costs related to the increase in towers produced, productivity losses of $9.3 million due to rework and underutilization of plant capacity, a $3.1 million increase in outsourced quality control costs to satisfy expanded customer requirements, and $1.1 million from the absorption of higher steel costs when a supplier did not fulfill its delivery requirements. |
●
|
Operating expenses at DMI increased $0.1 million between the periods.
|
●
|
Operating expenses at Wylie increased $2.8 million as a result of a $2.3 million increase in fuel costs related to higher fuel prices and an increase in miles driven by company-owned trucks, and a $0.5 million increase in brokerage settlements.
|
Six Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Revenues
|
$ | 114,671 | $ | 87,538 | $ | 27,133 | 31.0 | |||||||||
Cost of Goods Sold
|
86,325 | 64,945 | 21,380 | 32.9 | ||||||||||||
Operating Expenses
|
11,240 | 14,082 | (2,842 | ) | (20.2 | ) | ||||||||||
Asset Impairment Charge
|
-- | 19,740 | (19,740 | ) | -- | |||||||||||
Depreciation and Amortization
|
6,401 | 6,529 | (128 | ) | (2.0 | ) | ||||||||||
Operating Income (Loss)
|
$ | 10,705 | $ | (17,758 | ) | $ | 28,463 | 160.3 |
●
|
Revenues at BTD increased $24.4 million as a result of higher sales volume due to improved customer demand.
|
●
|
Revenues at T.O. Plastics increased by $1.4 million due to increased sales of horticultural and industrial products.
|
●
|
Revenues at ShoreMaster increased $1.3 million mainly as a result of higher sales of residential products due to improving dealer confidence and expanded distribution in Canada.
|
●
|
Cost of goods sold at BTD increased $19.3 million mainly as a result of increased sales volume.
|
●
|
Cost of goods sold at T.O. Plastics increased $0.9 million as a result of the increase in sales of horticultural and industrial products.
|
●
|
Cost of goods sold at ShoreMaster increased $1.2 million related to an increase in sales of residential products and inventory write downs on discounted products.
|
●
|
Operating expenses at BTD increased $0.7 million mainly due to increased salary and benefit costs related to workforce expansion.
|
●
|
Operating expenses at T.O. Plastics increased $0.2 million due to increased salary and benefit costs.
|
●
|
Operating expenses at ShoreMaster decreased $3.8 million, reflecting a $2.9 million increase to its allowance for doubtful accounts in its residential and commercial businesses in the first half of 2010, a $0.7 million decrease in sales, marketing and benefit expenses and a $0.2 million gain on the sale of fixed assets in the first half of 2010.
|
Six Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Revenues
|
$ | 86,648 | $ | 47,923 | $ | 38,725 | 80.8 | |||||||||
Cost of Goods Sold
|
79,397 | 43,783 | 35,614 | 81.3 | ||||||||||||
Operating Expenses
|
6,121 | 6,242 | (121 | ) | (1.9 | ) | ||||||||||
Depreciation and Amortization
|
940 | 956 | (16 | ) | (1.7 | ) | ||||||||||
Operating Income (Loss)
|
$ | 190 | $ | (3,058 | ) | $ | 3,248 | 106.2 |
●
|
Revenues at Foley Company increased $39.4 million due to an increase in the magnitude and volume of jobs in progress.
|
●
|
Revenues at Aevenia decreased $0.7 million between the periods.
|
●
|
Cost of goods sold at Foley Company increased $36.1 million, mainly in the areas of material and subcontractor costs related to the increase in Foley’s work volume between the periods.
|
●
|
Cost of goods sold at Aevenia decreased $0.5 million between the periods, commensurate with their decrease in revenues.
|
Six Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Revenues
|
$ | 62,851 | $ | 49,826 | $ | 13,025 | 26.1 | |||||||||
Cost of Goods Sold
|
52,940 | 43,432 | 9,508 | 21.9 | ||||||||||||
Operating Expenses
|
2,657 | 2,422 | 235 | 9.7 | ||||||||||||
Depreciation and Amortization
|
1,667 | 1,559 | 108 | 6.9 | ||||||||||||
Operating Income
|
$ | 5,587 | $ | 2,413 | $ | 3,174 | 131.5 |
Six Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Revenues
|
$ | 45,478 | $ | 48,816 | $ | (3,338 | ) | (6.8 | ) | |||||||
Cost of Goods Sold
|
30,309 | 38,404 | (8,095 | ) | (21.1 | ) | ||||||||||
Operating Expenses
|
9,272 | 8,762 | 510 | 5.8 | ||||||||||||
Depreciation and Amortization
|
3,881 | 2,356 | 1,525 | 64.7 | ||||||||||||
Operating Income (Loss)
|
$ | 2,016 | $ | (706 | ) | $ | 2,722 | 385.6 |
Six Months Ended
|
||||||||||||||||
June 30,
|
%
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
Change
|
Change
|
||||||||||||
Operating Expenses
|
$ | 5,393 | $ | 7,112 | $ | (1,719 | ) | (24.2 | ) | |||||||
Depreciation and Amortization
|
280 | 278 | 2 | 0.7 |
Six Months Ended
June 30,
|
||||||||||||
(in thousands)
|
2011
|
2010
|
Variance
|
|||||||||
Income (Loss) Before Income Taxes – Continuing Operations
|
$ | 13,717 | $ | (18,833 | ) | $ | 32,550 | |||||
Income Tax Expense (Benefit) - Continuing Operations
|
2,085 | (6,018 | ) | 8,103 | ||||||||
Effective Income Tax Rate – Continuing Operations
|
15.2 | % | 32.0 | % |
Six Months Ended
|
||||||||||||||||||||||||
June 30, 2011
|
June 30, 2010
|
|||||||||||||||||||||||
(in thousands)
|
IPH
|
Wylie-Wind
|
Total
|
IPH
|
Wylie-Wind
|
Total
|
||||||||||||||||||
Operating Revenues
|
$ | 28,125 | $ | 5,448 | $ | 33,573 | $ | 37,170 | $ | 2,654 | $ | 39,824 | ||||||||||||
Income (Loss) Before Income Taxes
|
$ | 3,840 | $ | (4,564 | ) | $ | (724 | ) | $ | 5,123 | $ | 47 | $ | 5,170 | ||||||||||
Gain on Disposition - Pretax
|
16,767 | -- | 16,767 | -- | -- | -- | ||||||||||||||||||
Income Tax Expense (Benefit)
|
4,977 | (1,826 | ) | 3,151 | 1,837 | 19 | 1,856 | |||||||||||||||||
Net Income
|
$ | 15,630 | $ | (2,738 | ) | $ | 12,892 | $ | 3,286 | $ | 28 | $ | 3,314 |
(in thousands)
|
Line Limit
|
In Use on
June 30, 2011
|
Restricted due to Outstanding Letters of Credit
|
Available on
June 30, 2011
|
Available on
December 31, 2010
|
|||||||||||||||
Otter Tail Corporation Credit Agreement
|
$ | 200,000 | $ | 16,661 | 1 | $ | 1,674 | $ | 181,665 | $ | 144,350 | |||||||||
OTP Credit Agreement
|
170,000 | 16,052 | 1,050 | 152,898 | 144,436 | |||||||||||||||
Total
|
$ | 370,000 | $ | 32,713 | 1 | $ | 2,724 | $ | 334,563 | $ | 288,786 | |||||||||
1In use amount includes $2,351,000 assigned to the heavy haul and specialized shipment and transportation of wind turbine components business of Wylie and reflected in Liabilities of Discontinued Operations on the Company’s June 30, 2011 consolidated balance sheet.
|
●
|
Under the Otter Tail Corporation Credit Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), as provided in the Credit Agreement. As of June 30, 2011 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement was 1.57 to 1.00.
|
●
|
Under the Cascade Note Purchase Agreement, we may not permit our ratio of Consolidated Debt to Consolidated Total Capitalization to be greater than 0.60 to 1.00 or our Interest Charges Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), permit the ratio of OTP’s Debt to OTP’s Total Capitalization to be greater than 0.60 to 1.00, or permit Priority Debt to exceed 20% of Varistar Consolidated Total Capitalization, as provided in the Cascade Note Purchase Agreement. As of June 30, 2011 our Interest Charges Coverage Ratio calculated under the requirements of the Cascade Note Purchase Agreement was 1.51 to 1.00
|
●
|
Under the OTP Credit Agreement and, upon the issuance of the 2021 Notes, under the 2011 Note Purchase Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, as provided in the related agreement. As of June 30, 2011 OTP’s Interest and Dividend Coverage Ratio calculated under the requirements of each such agreement was 3.40 to 1.00.
|
●
|
Under the 2001 Note Purchase Agreement, the 2007 Note Purchase Agreement and the financial guaranty insurance policy with Ambac Assurance Corporation relating to certain pollution control refunding bonds, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio (or, in the case of the 2001 Note Purchase Agreement, its Interest Charges Coverage Ratio) to be less than 1.50 to 1.00, in each case as provided in the related borrowing or insurance agreement. In addition, under the 2001 Note Purchase Agreement, the 2007 Note Purchase Agreement and, upon the issuance of the 2021 Notes, under the 2011 Note Purchase Agreement, OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of June 30, 2011 OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of each such agreement was 3.40 to 1.00.
|
2011 Earnings Per Share Guidance Range
|
||||||||||||||||
Previous Guidance
|
Current Guidance
|
|||||||||||||||
Low
|
High
|
Low
|
High
|
|||||||||||||
Electric
|
$ | .99 | $ | 1.04 | $ | 1.01 | $ | 1.06 | ||||||||
Wind Energy
|
(.40 | ) | (.25 | ) | (.80 | ) | (.50 | ) | ||||||||
Manufacturing
|
.25 | .29 | .25 | .30 | ||||||||||||
Construction
|
.05 | .08 | .05 | .08 | ||||||||||||
Plastics
|
.05 | .08 | .10 | .13 | ||||||||||||
Health Services
|
.00 | .04 | .01 | .05 | ||||||||||||
Corporate
|
(.20 | ) | (.18 | ) | (.20 | ) | (.18 | ) | ||||||||
Total – Continuing Operations
|
$ | .74 | $ | 1.10 | $ | .42 | $ | .94 | ||||||||
Earnings – Discontinued Operations:
|
||||||||||||||||
IPH
|
.06 | .07 | .07 | .07 | ||||||||||||
E.W. Wylie Heavy Haul - Wind
|
(.12 | ) | (.08 | ) | ||||||||||||
Gain on Sale of IPH
|
.35 | .38 | .35 | .37 | ||||||||||||
Total
|
$ | 1.15 | $ | 1.55 | $ | .72 | $ | 1.30 |
●
|
We expect an increase in net income from our Electric segment in 2011 compared to 2010 and from previously announced guidance. This is based on anticipated sales growth and rate and rider recovery increases, an increase in capitalized interest costs related to larger construction expenditures and reductions in operating and maintenance expense in 2011 due to lower benefit costs.
|
|
●
|
Our 2011 earnings guidance for our Wind Energy segment reflects the following factors:
|
|
o
|
We expect losses at DMI resulting from productivity challenges, a decrease in the number of towers produced, increased price pressure on new orders, and potential exposure to liquidated damages, warranty claims, or remediation costs related to past production issues. We anticipate that tower production for the remainder of 2011 will decrease from previous forecasts. This forecast decrease in tower demand primarily results from a general softening in the wind industry. The resulting decrease in production levels will offset productivity gains achieved over the past quarter and increase the fixed charge allocation to the remaining towers produced. Additionally, DMI continues to face pressures to reduce price due to over capacity in the U.S. market, and significantly lower steel costs available to Asian manufacturers.
|
|
o
|
We exited Wylie’s wind-heavy haul business in the second quarter of 2011. Accordingly, the results of operations from this part of the business have been reclassified to discontinued operations. We expect the continuing flatbed trucking operations to be near breakeven levels for 2011
|
|
o | Backlog in the Wind Energy segment is $82 million for 2011 compared with $68 million one year ago. |
●
|
We expect earnings from our Manufacturing segment to increase from our original 2011 guidance as a result of increased order volume and continuing improvement in economic conditions in the industries BTD serves. ShoreMaster is expecting significantly improved performance as a result of bringing costs in line with current revenue levels and absent last year’s $15.6 million net-of-tax noncash impairment charge. T.O. Plastics is expected to have slightly better earnings in 2011 compared with 2010. Backlog for the manufacturing companies for 2011 is approximately $62 million compared with $47 million one year ago.
|
●
|
We expect higher net income from our Construction segment in 2011 as the economy improves and the construction companies record earnings on a higher volume of jobs in progress. Backlog for the construction businesses is $84 million for 2011 compared with $65 million one year ago.
|
●
|
We are increasing our earnings expectations for our Plastics segment given its strong second quarter 2011 performance.
|
●
|
We expect a slight increase in earnings from our previously issued guidance for our Health Services segment in 2011 as the benefits of implementing its asset reduction plan continue to be realized.
|
●
|
Corporate general and administrative costs are expected to decrease in 2011, compared with 2010, as a result of recent reductions in employee count and associated decreases in benefit costs.
|
●
|
The net earnings and the gain on sale of IPH are now reflective of the actual results as the sale of the business closed in May 2011. In addition, we exited the wind-heavy haul operations of E.W. Wylie in the second quarter of 2011. The net loss reflected in the guidance table is the result of actual operating activity of this business and an estimate of any other potential costs that could occur as the business winds down. There was no gain or loss incurred on disposal of the asset fleet associated with Wylie’s wind-heavy haul business.
|
(in millions)
|
2011
|
2012
|
2013
|
|||||||||
Capital Expenditures:
|
||||||||||||
Electric Segment:
|
||||||||||||
Transmission
|
$ | 23 | $ | 31 | $ | 65 | ||||||
Environmental
|
4 | 49 | 97 | |||||||||
Other
|
40 | 50 | 57 | |||||||||
Total Electric Segment
|
$ | 67 | $ | 130 | $ | 219 | ||||||
Nonelectric Segments
|
40 | 41 | 48 | |||||||||
Total Capital Expenditures
|
$ | 107 | $ | 171 | $ | 267 | ||||||
Total Electric Utility Average Rate Base
|
$ | 651 | $ | 722 | $ | 876 |
●
|
We are subject to federal and state legislation, regulations and actions that may have a negative impact on our business and results of operations.
|
●
|
Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs.
|
●
|
Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and could increase borrowing costs and pension plan and postretirement health care expenses.
|
●
|
We rely on access to both short- and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If we are not able to access capital at competitive rates, our ability to implement our business plans may be adversely affected.
|
●
|
We may experience fluctuations in revenues and expenses related to our operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to our shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.
|
●
|
Disruptions, uncertainty or volatility in the financial markets can also adversely impact our results of operations, the ability of our customers to finance purchases of goods and services, and our financial condition, as well as exert downward pressure on stock prices and/or limit our ability to sustain our current common stock dividend level.
|
●
|
We are not currently required to make any contributions to our defined benefit pension plan in 2011. We could make discretionary contributions to the plan or could be required to contribute additional capital to the pension plan in future years if the market value of pension plan assets significantly declines in the future, plan assets do not earn in line with our long-term rate of return assumptions or relief under the Pension Protection Act is no longer granted.
|
●
|
Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income.
|
●
|
A sustained decline in our common stock price below book value or declines in projected operating cash flows at any of our operating companies may result in goodwill impairments that could adversely affect our results of operations and financial position, as well as financing agreement covenants.
|
●
|
The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on us.
|
●
|
Economic conditions could negatively impact our businesses.
|
●
|
If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.
|
● | Our plans to grow and realign our diversified business mix through capital projects, acquisitions and dispositions may not be successful, which could result in poor financial performance. |
● | Our plans to grow and operate our nonelectric businesses could be limited by state law. |
● |
Our subsidiaries enter into production and construction contracts, including contracts for new product designs, which could expose them to unforeseen costs and costs not within their control, which may not be recoverable and could adversely affect our results of operations and financial condition.
|
● | Significant warranty claims in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition. Also, expenses associated with remediation activities in the wind energy segment could be substantial. The potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. If we are required to cover remediation expenses in addition to regular warranty coverage, we could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect our consolidated results of operations and financial condition. |
●
|
We are subject to risks associated with energy markets.
|
●
|
We are subject to risks and uncertainties related to the timing and recovery of deferred tax assets which could have a negative impact on our net income in future periods.
|
●
|
Certain of our operating companies sell products to consumers that could be subject to recall.
|
●
|
Competition is a factor in all of our businesses.
|
●
|
Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.
|
●
|
OTP could be required to absorb a disproportionate share of costs for investments in transmission infrastructure required to provide independent power producers access to the transmission grid. These costs may not be recoverable through a transmission tariff and could result in reduced returns on invested capital and/or increased rates to OTP's retail electric customers.
|
●
|
OTP’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.
|
●
|
Wholesale sales of electricity from excess generation could be affected by reductions in coal shipments to the Big Stone and Hoot Lake plants due to supply constraints or rail transportation problems beyond our control.
|
●
|
Changes to regulation of generating plant emissions, including but not limited to carbon dioxide (CO2) emissions, could affect OTP’s operating costs and the costs of supplying electricity to its customers.
|
●
|
The U.S. wind industry is reliant on tax and other economic incentives and political and governmental policies. A significant change in these incentives and policies could negatively impact our results of operations and growth.
|
●
|
Our wind tower manufacturing business is substantially dependent on a few significant customers.
|
●
|
Prolonged periods of low utilization of DMI’s wind tower production plants, due to a continuing softening of demand for its product, could cause DMI to idle certain facilities. Should this softened demand for wind towers continue, these events may result in impairment charges on certain of DMI’s facilities if future cash flow estimates, based on information available to management at the time, indicate that the plants carrying values may not be recoverable or, if any plant assets are sold below their carrying values, significant losses may be incurred.
|
●
|
Competition from foreign and domestic manufacturers, cost management in a fixed price contract project environment, the price and availability of raw materials and diesel fuel, the ability of suppliers to deliver materials at contracted prices, fluctuations in foreign currency exchange rates and general economic conditions could affect the revenues and earnings of our wind energy and manufacturing businesses.
|
●
|
A significant failure or an inability to properly bid or perform on projects by our wind energy, construction or manufacturing businesses could lead to adverse financial results and could lead to the possibility of delay or liquidated damages.
|
●
|
Our Plastics segment is highly dependent on a limited number of vendors for PVC resin, many of which are located in the Gulf Coast regions, and a limited supply of resin. The loss of a key vendor, or an interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for this segment.
|
●
|
Our plastic pipe companies compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish the pipe companies’ products from those of its competitors.
|
●
|
Reductions in PVC resin prices can negatively impact PVC pipe prices, profit margins on PVC pipe sales and the value of PVC pipe held in inventory.
|
●
|
Changes in the rates or method of third-party reimbursements for diagnostic imaging services could result in reduced demand for those services or create downward pricing pressure, which would decrease revenues and earnings for our Health Services segment.
|
●
|
Our health services businesses may be unable to continue to maintain agreements with Philips Medical from which the businesses derive significant revenues from the sale and service of Philips Medical diagnostic imaging equipment.
|
●
|
Technological change in the diagnostic imaging industry could reduce the demand for diagnostic imaging services and require our health services operations to incur significant costs to upgrade its equipment.
|
●
|
Actions by regulators of our health services operations could result in monetary penalties or restrictions in our health services operations.
|
(in thousands)
|
June 30,
2011
|
December 31,
2010
|
||||||
Current Asset – Marked-to-Market Gain
|
$ | 4,832 | $ | 6,875 | ||||
Regulatory Asset – Deferred Marked-to-Market Loss
|
14,646 | 12,054 | ||||||
Total Assets
|
19,478 | 18,929 | ||||||
Current Liability – Marked-to-Market Loss
|
(18,683 | ) | (17,991 | ) | ||||
Regulatory Liability – Deferred Marked-to-Market Gain
|
(149 | ) | (175 | ) | ||||
Total Liabilities
|
(18,832 | ) | (18,166 | ) | ||||
Net Fair Value of Marked-to-Market Energy Contracts
|
$ | 646 | $ | 763 |
(in thousands)
|
Year-to-Date
June 30, 2011
|
|||
Fair Value at Beginning of Year
|
$ | 763 | ||
Less: Amounts Realized on Contracts Entered into in 2009 and Settled in 2011
|
(145 | ) | ||
Amounts Realized on Contracts Entered into in 2010 and Settled in 2011
|
(6 | ) | ||
Changes in Fair Value of Contracts Entered into in 2009 in 2011
|
(14 | ) | ||
Changes in Fair Value of Contracts Entered into in 2010 in 2011
|
(72 | ) | ||
Net Fair Value of Contracts Entered into in 2009 and 2010 at End of Period
|
526 | |||
Changes in Fair Value of Contracts Entered into in 2011
|
120 | |||
Net Fair Value End of Period
|
$ | 646 |
(in thousands)
|
3rd Quarter
2011
|
4th Quarter
2011
|
2012
|
Total
|
||||||||||||
Net Gain
|
$ | 32 | $ | 145 | $ | 469 | $ | 646 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
(in thousands)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Net Gains (Losses) on Forward Electric Energy Contracts
|
$ | 139 | $ | (24 | ) | $ | 131 | $ | 1,801 |
Calendar Month
|
Total Number of Shares Purchased
|
Average Price Paid per Share
|
||||||
April 2011
|
6,641 | $ | 22.83 | |||||
May 2011
|
-- | -- | ||||||
June 2011
|
-- | -- | ||||||
Total
|
6,641 |
4.1
|
Note Purchase Agreement dated as of July 29, 2011, between Otter Tail Power Company and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on August 3, 2011).
|
31.1
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
31.2
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32.1
|
Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
32.2
|
Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
101.INS
|
XBRL Instance Document.
|
101.SCH
|
XBRL Taxonomy Extension Schema Document.
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
101.LAB
|
XBRL Taxonomy Extension Label Linkbase Document.
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
101.DEF
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
OTTER TAIL CORPORATION
|
By: /s/ Kevin G. Moug
|
Kevin G. Moug
|
Chief Financial Officer
|
(Chief Financial Officer/Authorized Officer)
|
Exhibit Number | Description | |
4.1
|
Note Purchase Agreement dated as of July 29, 2011, between Otter Tail Power Company and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on August 3, 2011).
|
|
31.1
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31.2
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32.1
|
Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32.2
|
Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
101.INS
|
XBRL Instance Document.
|
|
101.SCH
|
XBRL Taxonomy Extension Schema Document.
|
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
|
101.LAB
|
XBRL Taxonomy Extension Label Linkbase Document.
|
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
|
101.DEF
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ John D. Erickson
|
|
John D. Erickson | |
President and Chief Executive Officer | |
August 9, 2011
|
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ Kevin G. Moug
|
|
Kevin G. Moug | |
Chief Financial Officer | |
August 9, 2011
|
Supplemental Disclosure of Cash Flow Information (Detail) (USD $)
In Thousands |
6 Months Ended | |
---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Schedule of Cash Flow, Supplemental [Line Items] | ||
Increases in Accounts Payable Related to Capital Expenditures | $ 237 | $ 745 |
Consolidated Balance Sheets (Parenthetical) (USD $)
|
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Common Shares, Par Value | $ 5 | $ 5 |
Common Shares, Authorized | 50,000,000 | 50,000,000 |
Common Shares, Outstanding | 36,061,173 | 36,002,739 |
Cumulative Preferred Shares
|
||
Cumulative Shares, Authorized | 1,500,000 | 1,500,000 |
Cumulative Shares, Without Par Value | $ 0 | $ 0 |
Cumulative Shares, Outstanding | 155,000 | 155,000 |
Cumulative Preference Shares
|
||
Cumulative Shares, Authorized | 1,000,000 | 1,000,000 |
Cumulative Shares, Without Par Value | $ 0 | $ 0 |
Cumulative Shares, Outstanding | 0 | 0 |
Status of our Lines of Credit (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
|||
---|---|---|---|---|---|
Line of Credit Facility [Line Items] | |||||
Line Limit | $ 370,000 | ||||
In Use | 32,713 | [1] | |||
Restricted due to Outstanding Letters of Credit | 2,724 | ||||
Available | 334,563 | 288,786 | |||
Otter Tail Corporation Credit Agreement
|
|||||
Line of Credit Facility [Line Items] | |||||
Line Limit | 200,000 | ||||
In Use | 16,661 | [1] | |||
Restricted due to Outstanding Letters of Credit | 1,674 | ||||
Available | 181,665 | 144,350 | |||
OTP Credit Agreement
|
|||||
Line of Credit Facility [Line Items] | |||||
Line Limit | 170,000 | ||||
In Use | 16,052 | ||||
Restricted due to Outstanding Letters of Credit | 1,050 | ||||
Available | $ 152,898 | $ 144,436 | |||
|
Pro forma Summary Presentations of the Company's Consolidated Income Statements Reflecting the Classification of IPH's Results as Discontinued Operations (Detail) (USD $)
In Thousands, except Per Share data |
3 Months Ended | 6 Months Ended | 12 Months Ended | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
Dec. 31, 2010
As Previously Reported
|
Dec. 31, 2009
As Previously Reported
|
Dec. 31, 2010
IPH
|
Dec. 31, 2009
IPH
|
Dec. 31, 2010
With IPH classified as Discontinued Operations
|
Dec. 31, 2009
With IPH classified as Discontinued Operations
|
|||||
Operating Revenues | $ 316,975 | $ 251,314 | $ 598,333 | $ 494,263 | $ 1,119,084 | $ 1,039,512 | $ 77,202 | [1] | $ 78,632 | [1] | $ 1,041,882 | $ 960,880 | ||
Operating Expenses: | ||||||||||||||
Cost of Goods Sold | 193,830 | 137,012 | 349,539 | 254,496 | 600,956 | 565,192 | 56,619 | [1] | 58,718 | [1] | 544,337 | 506,474 | ||
Other Operating Expenses | 402,919 | 355,322 | 3,729 | [1] | 3,330 | [1] | 399,190 | 351,992 | ||||||
Depreciation Expense | 19,725 | 18,655 | 38,811 | 37,229 | 80,696 | 73,608 | 4,703 | [1] | 4,333 | [1] | 75,993 | 69,275 | ||
Total Operating Expenses | 302,398 | 266,512 | 567,806 | 495,241 | 1,084,571 | 994,122 | 65,051 | [1] | 66,381 | [1] | 1,019,520 | 927,741 | ||
Operating Income (Loss) | 14,577 | (15,198) | 30,527 | (978) | 34,513 | 45,390 | 12,151 | [1] | 12,251 | [1] | 22,362 | 33,139 | ||
Other Income (Deductions) | 1,107 | 552 | 1,828 | 565 | 5,126 | 4,550 | (408) | [1] | (404) | [1] | 5,534 | 4,954 | ||
Interest Charges | 9,149 | 9,398 | 18,638 | 18,420 | 37,032 | 28,514 | 29 | [1] | 30 | [1] | 37,003 | 28,484 | ||
Income Tax Expense (Benefit) - Continuing Operations | 537 | (7,769) | 2,085 | (6,018) | 3,951 | (4,605) | 3,716 | [1] | 4,410 | [1] | 235 | (9,015) | ||
Net Income (Loss) from Continuing Operations | 5,998 | (16,275) | 11,632 | (12,815) | (1,344) | 26,031 | 7,998 | [1] | 7,407 | [1] | (9,342) | 18,624 | ||
Net Income - Discontinued Operations | 12,830 | 2,057 | 12,892 | 3,314 | 7,998 | 7,407 | ||||||||
Total Net Income (Loss) | 18,828 | (14,218) | 24,524 | (9,501) | (1,344) | 26,031 | 7,998 | [1] | 7,407 | [1] | (1,344) | 26,031 | ||
Preferred Dividend Requirements | 833 | 736 | 833 | 736 | ||||||||||
Earnings Available for Common Shares | $ 18,322 | $ (14,497) | $ 23,834 | $ (9,964) | $ (2,177) | $ 25,295 | $ 7,998 | [1] | $ 7,407 | [1] | $ (2,177) | $ 25,295 | ||
Basic Earnings Per Common Share: | ||||||||||||||
Continuing Operations (net of preferred dividend requirement) | $ 0.16 | $ (0.46) | $ 0.31 | $ (0.37) | $ (0.06) | $ 0.71 | $ 0.22 | [1] | $ 0.21 | [1] | $ (0.28) | $ 0.50 | ||
Discontinued Operations | $ 0.35 | $ 0.06 | $ 0.35 | $ 0.09 | $ 0.22 | $ 0.21 | ||||||||
Earnings Per Share, Basic | $ 0.51 | $ (0.40) | $ 0.66 | $ (0.28) | $ (0.06) | $ 0.71 | ||||||||
Diluted Earnings Per Common Share: | ||||||||||||||
Continuing Operations (net of preferred dividend requirement) | $ 0.16 | $ (0.46) | $ 0.31 | $ (0.37) | $ (0.06) | $ 0.71 | $ 0.22 | [1] | $ 0.21 | [1] | $ (0.28) | $ 0.50 | ||
Discontinued Operations | $ 0.35 | $ 0.06 | $ 0.35 | $ 0.09 | $ 0.22 | $ 0.21 | ||||||||
Earnings Per Share, Diluted | $ 0.51 | $ (0.40) | $ 0.66 | $ (0.28) | $ (0.06) | $ 0.71 | ||||||||
|
Summary of Significant Accounting Policies (Tables)
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
|
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Percents of the Company's Consolidated Revenues Recorded under the Percentage-of-Completion Method | Following
are the percentages of the Company’s consolidated revenues
recorded under the percentage-of-completion method:
|
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Summary of Costs Incurred and Billings and Estimated Earnings Recognized on Uncompleted Contracts | The
following table summarizes costs incurred and billings and
estimated earnings recognized on uncompleted
contracts:
|
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Summary of Uncompleted Contracts Included in Company's Consolidated Balance Sheets | The
following amounts are included in the Company’s consolidated
balance sheets. Billings in excess of costs and estimated earnings
on uncompleted contracts are included in Accounts
Payable:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Receivable Retained by Customers Pending Project Completion | Accounts
Receivable include the following amounts, billed under contracts by
the Company’s subsidiaries, that have been retained by
customers pending project completion:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amounts of Accounts Receivable Sold and Discounts, Fees and Commissions Paid | Following
are the amounts of accounts receivable sold and discounts, fees and
commissions paid under DMI’s receivables sales agreement with
General Electric Capital Corporation:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | The
following table presents, for each of these hierarchy levels, the
Company’s assets and liabilities that are measured at fair
value on a recurring basis as of June 30, 2011 and December 31,
2010:
|
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Corrected Classification Resulting in Increases in Operating Revenues and Operating Income and Decreases in Other Income | The
Company has corrected this classification resulting in the
following increases in Operating Revenues and Operating Income and
decreases in Other Income:
|
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Summary of Inventories | Inventories
consist of the following:
|
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Summary of Changes to Goodwill by Business Segment | The
following table summarizes changes to goodwill by business segment
during 2011:
|
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Other Intangible Assets | The
following table summarizes the components of the Company’s
intangible assets at June 30, 2011 and
December 31, 2010:
|
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Amortization Expense - Intangible Assets |
|
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Schedule of Expected Amortization Expense |
|
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Comprehensive Income |
Comprehensive Income
|
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Supplemental Disclosure of Cash Flow Information |
Supplemental Disclosures of Cash Flow
Information
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
DMI Industries, Inc
|
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Costs and Estimated Earnings in Excess of Billings | Included
in Costs and Estimated Earnings in Excess of Billings are the
following Costs and Estimated Earnings in Excess of Billings at DMI
Industries, Inc. (DMI), the Company’s wind tower
manufacturer:
|
Income Taxes Expense (Benefit) - Continuing Operations - Additional Information (Detail) (USD $)
In Millions |
3 Months Ended | 6 Months Ended |
---|---|---|
Jun. 30, 2011
|
Jun. 30, 2011
|
|
Income Taxes [Line Items] | ||
Increase in federal production credits (PTCs) earned | $ 1.9 | $ 3.9 |
DMI Industries, Inc
|
||
Income Taxes [Line Items] | ||
Deferred tax benefits on Canadian operating losses | $ 1.0 | $ 1.8 |
Document and Entity Information
|
6 Months Ended | |
---|---|---|
Jun. 30, 2011
|
Jul. 31, 2011
|
|
Document Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2011 | |
Document Fiscal Year Focus | 2011 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | OTTR | |
Entity Registrant Name | OTTER TAIL CORP | |
Entity Central Index Key | 0001466593 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 36,061,873 |
Schedule of Expected Amortization Expense (Detail) (USD $)
In Thousands |
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Expected Amortization Expense [Line Items] | |
2011 | $ 887 |
2012 | 911 |
2013 | 947 |
2014 | 947 |
2015 | $ 931 |
Forward Contracts Classified as Derivatives (Tables)
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2011
|
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Balance Sheet Location and Fair Values of Forward Contracts for the Purchase and Sale of Electricity |
The
following tables show the effect of marking to market forward
contracts for the purchase and sale of electricity and the location
and fair value amounts of the related derivatives reported on the
Company’s consolidated balance sheets as of
June 30, 2011 and December 31, 2010, and the change in
the Company’s consolidated balance sheet position from
December 31, 2010 to June 30, 2011:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in the Company's Consolidated Balance Sheet Position on Forward Contracts for the Purchase and Sale of Electricity |
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Recognized but Unrealized Net Gains on the Forward Energy and Capacity Purchases and Sales Expected to be Realized on Settlement |
The
June 30, 2011 balance of recognized but unrealized net
mark-to-market gains on the forward energy and capacity purchases
and sales is expected to be realized on settlement as scheduled
over the following periods in the amounts listed:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Realized and Unrealized Net (Losses)/Gains on Forward Energy Contracts Included in Electric Operating Revenues | The
following realized and unrealized net (losses)/gains on forward
energy contracts are included in electric operating revenues on the
Company’s consolidated statements of income:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Information on OTP's Credit Risk Exposure on Delivered and Marked-to-market Forward Contracts | The
following table provides information on OTP’s credit risk
exposure on delivered and marked-to-market forward contracts as of
June 30, 2011 and December 31, 2010:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in a Marked-to-market Loss Position | The
following table provides a breakdown of OTP’s credit risk
standing on forward energy contracts in a marked-to-market loss
positions as of June 30, 2011 and December 31, 2010:
|
Amortization Expense - Intangible Assets (Detail) (USD $)
In Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Finite-Lived Intangible Assets [Line Items] | ||||
Amortization Expense - Intangible Assets | $ 224 | $ 263 | $ 448 | $ 546 |
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Common Shares and Earnings Per Share
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2011
|
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Common Shares and Earnings Per Share |
6. Common Shares and Earnings Per Share
Common Shares
Following
is a reconciliation of the Company’s common shares
outstanding from December 31, 2010 through June 30,
2011:
Earnings Per Share
Basic
earnings per common share are calculated by dividing earnings
available for common shares by the weighted average number of
common shares outstanding during the period. Diluted earnings per
common share are calculated by adjusting outstanding shares,
assuming conversion of all potentially dilutive stock options.
Stock options with exercise prices greater than the market price
are excluded from the calculation of diluted earnings per common
share. Nonvested restricted shares granted to the Company’s
directors and employees are considered dilutive for the purpose of
calculating diluted earnings per share but are considered
contingently returnable and not outstanding for the purpose of
calculating basic earnings per share. Underlying shares related to
nonvested restricted stock units granted to employees are
considered dilutive for the purpose of calculating diluted earnings
per share. Shares expected to be awarded for stock performance
awards granted to executive officers are considered dilutive for
the purpose of calculating diluted earnings per share.
Excluded
from the calculation of diluted earnings per share are the
following outstanding stock options which had exercise prices
greater than the average market prices:
|
Common Shares and Earnings Per Share (Tables)
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2011
|
||||||||||||||||||||||||||||||||||||||||
Reconciliation of the Company's Common Shares Outstanding | Following
is a reconciliation of the Company’s common shares
outstanding from December 31, 2010 through June 30,
2011:
|
|||||||||||||||||||||||||||||||||||||||
Stock Options with Exercise Prices Greater than the Market Price Excluded from the Calculation of Diluted Earnings per Common Share | Excluded
from the calculation of diluted earnings per share are the
following outstanding stock options which had exercise prices
greater than the average market prices:
|
Corrected Classification Resulting in Increases in Operating Revenues and Operating Income and Decreases in Other Income (Detail) (USD $)
In Thousands |
3 Months Ended | 6 Months Ended |
---|---|---|
Jun. 30, 2010
|
Jun. 30, 2010
|
|
MNCIP Incentives reclassified from Other Income to Operating Revenue | $ 1,239 | $ 1,601 |
Costs and Estimated Earnings in Excess of Billings (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Uncompleted Contracts [Line Items] | ||
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts | $ 71,688 | $ 67,352 |
DMI Industries, Inc
|
||
Uncompleted Contracts [Line Items] | ||
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts | $ 60,410 | $ 58,990 |
Regulatory Assets and Liabilities (Tables)
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Amount of Regulatory Assets and Liabilities Recorded on the Company's Consolidated Balance Sheet | The
following table indicates the amount of regulatory assets and
liabilities recorded on the Company’s consolidated balance
sheet:
|
Pension Plan and Other Postretirement Benefits
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Pension Plan and Other Postretirement Benefits |
12. Pension Plan and Other Postretirement Benefits
Pension Plan—Components of net periodic pension
benefit cost of the Company's noncontributory funded pension plan
are as follows:
The
Company did not make a contribution to its pension plan in the six
months ended June 30, 2011 and is not currently required to make a
contribution in 2011.
Executive Survivor and Supplemental Retirement
Plan—Components of net periodic pension benefit cost
of the Company’s unfunded, nonqualified benefit plan for
executive officers and certain key management employees are as
follows:
Postretirement Benefits—Components of net periodic
postretirement benefit cost for health insurance and life insurance
benefits for retired OTP and corporate employees are as
follows:
|
Segment Information
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Segment Information |
2. Segment Information
The
Company's businesses have been classified into six segments to be
consistent with its business strategy and the reporting and review
process used by the Company’s chief operating decision
makers. These businesses reach customers in all 50 states and
international markets. The six segments are: Electric, Wind Energy,
Manufacturing, Construction, Plastics and Health
Services.
Electric
includes the production, transmission, distribution and sale of
electric energy in Minnesota, North Dakota and South Dakota by OTP.
In addition, OTP is an active wholesale participant in the Midwest
Independent Transmission System Operator (MISO) markets.
OTP’s operations have been the Company’s primary
business since 1907. Additionally, the electric segment includes
Otter Tail Energy Services Company (OTESCO), which provides
technical and engineering services, wind farm site development and
energy efficient lighting primarily in North Dakota and
Minnesota.
Wind
Energy consists of two businesses: a steel fabrication company
primarily involved in the production of wind towers sold in the
United States and Canada, with manufacturing facilities in North
Dakota, Oklahoma and Ontario, Canada, and a trucking company
headquartered in West Fargo, North Dakota, specializing in flatbed
services and operating in 49 states and six Canadian provinces.
Prior to the realignment of the Company’s business segments,
the wind tower production company was included in Manufacturing and
the trucking company was included in Other Business
Operations.
Manufacturing
consists of businesses in the following manufacturing activities:
contract machining, metal parts stamping and fabrication, and
production of waterfront equipment, material and handling trays and
horticultural containers. These businesses have manufacturing
facilities in Florida, Illinois, Minnesota and Missouri and sell
products primarily in the United States.
Construction
consists of businesses involved in residential, commercial and
industrial electric contracting and construction of fiber optic and
electric distribution systems, water, wastewater and HVAC systems
primarily in the central United States. Construction operations
were included in Other Business Operations prior to the realignment
of the Company’s business segments.
Plastics
consists of businesses producing polyvinyl chloride (PVC) pipe in
the upper Midwest and Southwest regions of the United
States.
Health
Services consists of businesses involved in the sale of diagnostic
medical equipment, patient monitoring equipment and related
supplies and accessories. These businesses also provide equipment
maintenance, diagnostic imaging equipment and technical staff to
various medical institutions located throughout the United
States.
Food
Ingredient Processing is no longer a reportable segment as a result
of the sale of IPH on May 6, 2011. The results of operations,
financial position and cash flows of IPH are reported as
discontinued operations in the Company’s consolidated
financial statements.
OTP
and OTESCO are wholly owned subsidiaries of the Company. All of the
Company’s other businesses are owned by its wholly owned
subsidiary, Varistar Corporation (Varistar).
Corporate
includes items such as corporate staff and overhead costs, the
results of the Company’s captive insurance company and other
items excluded from the measurement of operating segment
performance. Corporate assets consist primarily of cash, prepaid
expenses, investments and fixed assets. Corporate is not an
operating segment. Rather, it is added to operating segment totals
to reconcile to totals on the Company’s consolidated
financial statements.
The
Company had no single external customer that accounted for 10% or
more of the Company’s consolidated revenues in 2010. One
customer of DMI has accounted for 11.7% of the Company’s
consolidated revenues in the first six months of 2011.
Substantially all of the Company’s long-lived assets are
within the United States except for a wind tower manufacturing
plant in Fort Erie, Ontario, Canada.
The
following table presents the percent of consolidated sales revenue
by country:
The
Company evaluates the performance of its business segments and
allocates resources to them based on earnings contribution and
return on total invested capital. Information for the business
segments for three and six month periods ended June 30, 2011
and 2010 and total assets by business segment as of June 30, 2011
and December 31, 2010 are presented in the following
tables:
Operating Revenue
Interest Charges
Income Tax Expense (Benefit) - Continuing
Operations
Earnings Available for Common Shares
Total Assets
|
Percents of the Company's Consolidated Revenues Recorded under the Percentage-of-Completion Method (Detail)
|
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Revenue Recorded under Percentage of Completion Method [Line Items] | ||||
Percentage-of-Completion Revenues | 33.90% | 27.60% | 32.80% | 26.70% |
Commitments and Contingencies
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
|
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Commitments and Contingencies |
9. Commitments and Contingencies
Electric Utility Capacity and Energy Requirements and Coal and
Delivery Contracts
In
the first quarter of 2011, OTP entered into additional energy
purchase agreements increasing its commitments for capacity and
energy requirements. Amounts of commitments for OTP’s
capacity and energy requirements under agreements extending through
2032 were as follows:
OTP
has contracts providing for the purchase and delivery of a
significant portion of its current coal requirements. In the first
half of 2011, OTP extended its contract for the purchase of coal
for Hoot Lake Plant resulting in an increase in minimum purchase
commitments. OTP’s current coal purchase agreements under
contracts expire in 2012 and 2016. OTP is now committed to the
minimum purchase, dating from January 1, 2011, or to make payments
in lieu thereof in the following amounts:
The
FCA mechanism lessens the risk of loss from market price changes
because it provides for recovery of most fuel costs.
Other
The
Company is a party to litigation arising in the normal course of
business. The Company regularly analyzes current information and,
as necessary, provides accruals for liabilities that are probable
of occurring and that can be reasonably estimated. The Company
believes the effect on its consolidated results of operations,
financial position and cash flows, if any, for the disposition of
all matters pending as of June 30, 2011 will not be
material.
Contingencies, by their nature, relate to uncertainties that
require the Company’s management to exercise judgment both in
assessing the likelihood that a liability has been incurred as well
as in estimating the amount of potential loss. The most significant
contingencies impacting the Company’s consolidated financial
statements are those related to product warranty, environmental
remediation, litigation matters, possible liquidated damages and
the resolution of matters related to open tax years.
Should any of these items result in a liability being incurred, the
range of loss could be as high as $9.0 million.
Additionally, we may become subject to significant claims of which
we are unaware, or the claims of which we are aware may result in
our incurring a significantly greater liability than we
anticipate.
|
Income Tax Expense (Benefit) - Continuing Operations
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
|
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Income Tax Expense (Benefit) - Continuing Operations |
15. Income Tax Expense (Benefit) – Continuing
Operations
The
increase in Income Tax Expense (Benefit) - Continuing Operations
for the three months ended June 30, 2011 compared with the three
months ended June 30, 2010 is mainly due to the increase in income
before income taxes between the quarters, but also due to DMI
deferring recognition of tax benefits in the second quarter of 2011
on the operating losses of its Canadian wind tower manufacturing
company until those operations become profitable. DMI’s
deferred tax benefits totaled $1.0 million in the second quarter of
2011. The Company’s effective income tax rate for the three
months ended June 30, 2011 was decreased mainly as a result of
recording $1.9 million in federal production tax credits
(PTCs) earned on kilowatt-hours (kwh) generated from tax credit
qualified wind turbines owned by OTP.
The increase in Income Tax Expense (Benefit) - Continuing
Operations for the six months ended June 30, 2011 compared with the
six months ended June 30, 2010 is mainly due to the increase in
income before income taxes between the periods but also due to DMI
deferring recognition of tax benefits in the first six months of
2011 on the operating losses of its Canadian wind tower
manufacturing company until those operations become profitable.
DMI’s deferred tax benefits totaled
$1.8 million in the first half of 2011. The Company’s
effective income tax rate for the six months ended June 30,
2011 decreased as a result of recording $3.9 million in
federal PTCs earned on
kwhs generated from tax credit qualified wind turbines owned
by OTP.
|
Short-Term and Long-Term Borrowings - Additional Information (Detail) (USD $)
|
1 Months Ended | 6 Months Ended | 6 Months Ended | 1 Months Ended | |||
---|---|---|---|---|---|---|---|
Mar. 18, 2011
|
Jun. 30, 2011
|
Jun. 30, 2011
Minimum
OTP Credit Agreement
|
Jun. 30, 2011
Maximum
OTP Credit Agreement
|
Jun. 30, 2011
OTP Credit Agreement
|
Jun. 30, 2011
OTP Credit Agreement
Letter of Credit
|
Apr. 06, 2011
North Dakota Development Fund
|
|
Line of Credit Facility [Line Items] | |||||||
Amended and Restated Credit Agreement date of initiation | On March 3, 2011 | ||||||
Line Limit | $ 370,000,000 | $ 250,000,000 | $ 170,000,000 | $ 50,000,000 | |||
Line of credit interest rate | LIBOR plus 1.5% | ||||||
Line of credit interest rate spread | 1.50% | ||||||
Amended and Restated Credit Agreement date of Expiry | On March 3, 2016 | ||||||
Line of credit covenant, debt to total capitalization ratio | 0.60 | ||||||
Line of credit covenant, interest and dividend coverage ratio | 1.50 | ||||||
Note payable, long term | 500,000 | ||||||
Borrowings under a Partnership in assisting Community Expansion Loan | $ 1,500,000 | ||||||
Loan expiration period, in years | 10Y | 7Y | |||||
Debt effective interest rate | 2.54% | 3.95% | |||||
Debt term of payment | monthly principal and interest payments | monthly principal and interest payments | |||||
Principal and interest payment, due date | Apr. 01, 2018 | ||||||
Unsecured notes due date | 2021-03 |
Short-Term and Long-Term Borrowings
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
|
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Short-Term and Long-Term Borrowings |
10. Short-Term and Long-Term Borrowings
The
following table presents the status of our lines of credit as of
June 30, 2011 and December 31, 2010:
On
March 3, 2011 OTP entered into an Amended and Restated Credit
Agreement (the OTP Credit Agreement) with the Banks named therein.
The OTP Credit Agreement provides for a $170 million line of credit
that may be increased to $250 million on the terms and subject to
the conditions described in the OTP Credit Agreement. The OTP
Credit Agreement is an unsecured revolving credit facility that OTP
can draw on to support the working capital needs and other capital
requirements of its operations, including letters of credit in an
aggregate amount not to exceed $50 million outstanding at any time.
Borrowings under the line of credit currently bear interest at
LIBOR plus 1.5%, subject to adjustment based on the ratings of
OTP’s senior unsecured debt. Under the OTP Credit Agreement
OTP is required to pay the Banks’ commitment fees based on
the average daily unused amount available to be drawn under the
revolving credit facility. The OTP Credit Agreement expires on
March 3, 2016.
The
OTP Credit Agreement contains a number of restrictions on the
business of OTP, including restrictions on its ability to merge,
sell assets, create or incur liens on assets, guarantee the
obligations of any other party, and engage in transactions with
related parties. The OTP Credit Agreement also contains affirmative
covenants and events of default. The OTP Credit Agreement does not
include provisions for the termination of the agreement or the
acceleration of repayment of amounts outstanding due to changes in
OTP’s credit ratings. The OTP Credit
Agreement amends and restates the $170 million Credit Agreement
dated as of July 30, 2008 among OTP (formerly known as Otter Tail
Corporation, dba Otter Tail Power Company), the Banks named
therein, as amended by a First Amendment to Credit Agreement dated
as of April 21, 2009 and a Second Amendment to Credit Agreement
dated as of June 22, 2009.
The
OTP Credit Agreement also contains certain financial covenants.
Specifically, OTP may not permit the ratio of its Interest-bearing
Debt to Total Capitalization (as defined in the OTP Credit
Agreement) to be greater than 0.60 to 1.00 or permit its Interest
and Dividend Coverage Ratio (as defined in the OTP Credit
Agreement) to be less than 1.50 to 1.00.
On
March 18, 2011 Otter Tail Corporation borrowed $1.5 million under a
Partnership in Assisting Community Expansion loan to finance
capital investments at Northern Pipe Products, Inc. (NPP), the
Company’s PVC pipe manufacturing subsidiary located in Fargo,
North Dakota. The ten-year unsecured note bears interest at 2.54%
with monthly principal and interest payments through
March 2021. On April 6, 2011 Otter Tail Corporation borrowed
$0.5 million under a North Dakota Development Fund loan to finance
additional capital investments at NPP. The seven-year unsecured
note bears interest at 3.95% with monthly principal and interest
payments through April 1, 2018.
The
following table provides a breakdown of the assignment of the
Company’s consolidated short-term and long-term debt
outstanding as of June 30, 2011:
|
Subsequent Events - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified |
6 Months Ended | |||||
---|---|---|---|---|---|---|
Mar. 18, 2011
|
Jun. 30, 2011
Issuance of Debt
Senior Unsecured Notes 4.63 Percent Due December 1, 2021
|
Jun. 30, 2011
Senior Unsecured Notes 6.63%, due December 1, 2011
Settlement of Debt
|
Jun. 30, 2011
Pollution Control Refunding Revenue Bonds, Variable, 2.10% at June 30, 2011, due December 1, 2012
Settlement of Debt
|
Jun. 30, 2011
Senior Unsecured Notes 6.63%, due December 1, 2011
|
Jun. 30, 2011
Pollution Control Refunding Revenue Bonds, Variable, 2.10% at June 30, 2011, due December 1, 2012
|
|
Subsequent Event [Line Items] | ||||||
Date of Note Purchase Agreement | Jul. 29, 2011 | |||||
Proceeds from Senior Unsecured Notes to be used to pay debt | $ 90.0 | $ 10.4 | ||||
Senior Unsecured Notes amount | $ 140 | |||||
Long-Term Debt, Interest Rate | 2.54% | 4.63% | 6.63% | 6.63% | 2.10% | |
Long-Term Debt, Due Date | Dec. 01, 2021 | Dec. 01, 2011 | Dec. 01, 2012 | Dec. 01, 2011 | Dec. 01, 2012 | |
Senior Unsecured Notes, expected issuance date | 2011-12-01 |
Fair Value of Financial Instruments (Tables)
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Fair Value of Financial Instruments | The
Company’s long-term debt subject to variable interest rates
approximates fair value.
|
Share-Based Payments
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Share-Based Payments |
7. Share-Based Payments
The
Company has five share-based payment programs.
Stock Incentive Awards
On
April 11, 2011 the Company’s Board of Directors granted the
following stock incentive awards to the Company’s
non-employee directors, executive officers and key employees under
the 1999 Stock Incentive Plan, as amended:
The
restricted shares granted to the Company’s nonemployee
directors and executive officers (which includes OTP’s
president) are eligible for full dividend and voting rights. The
grant date fair value of each share of restricted stock was the
average of the high and low market price per share on the date of
grant.
Under
the performance share awards, the Company’s executive
officers could earn up to an aggregate of 97,200 common shares
based on the Company’s total shareholder return relative to
the total shareholder return of the companies that comprise the
Edison Electric Institute Index over the performance measurement
period of January 1, 2011 through December 31, 2013. The aggregate
target share award is 48,600 shares. Actual payment may range from
zero to 200% of the target amount. The executive officers have no
voting or dividend rights related to these shares until the shares,
if any, are issued at the end of the performance period. The grant
date fair value of the target amount of common shares projected to
be awarded was determined under a Monte Carlo simulation valuation
method. The terms of these awards are such that the entire award
will be classified and accounted for as a liability, as required
under ASC 718-10-25-18, and will be measured over the performance
period based on the fair value of the award at the end of each
reporting period subsequent to the grant date.
The
grant date fair value of each restricted stock unit was based on
the market value of one share of the Company’s common stock
on the grant date, discounted for the value of the dividend
exclusion over the four-year vesting period.
As
of June 30, 2011 the remaining unrecognized compensation expense
related to stock-based compensation was approximately $3.2 million
(before income taxes) which will be amortized over a
weighted-average period of 2.8 years.
Compensation
expense recognized under the Company’s stock-based payment
programs:
|
Percentage of Consolidated Sales Revenue by Country (Detail)
|
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
United States of America
|
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Percentage of sales revenue | 97.80% | 98.60% | 98.20% | 97.90% |
Canada
|
||||
Percentage of sales revenue | 2.00% | 1.20% | 1.70% | 2.00% |
All Other Countries
|
||||
Percentage of sales revenue | 0.20% | 0.20% | 0.10% | 0.10% |
Rate and Regulatory Matters
|
6 Months Ended |
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Jun. 30, 2011
|
|
Rate and Regulatory Matters |
3. Rate and Regulatory Matters
Minnesota
2010 General Rate Case Filing—OTP filed a general rate
case on April 2, 2010 requesting an 8.01% base rate increase with a
3.8% interim rate increase request. On May 27, 2010,
the Minnesota Public Utilities Commission (MPUC) issued an order
accepting the filing, suspending rates, and approving an interim
rate increase of 3.8% to be effective with customer usage on and
after June 1, 2010. The MPUC held a hearing to decide on the issues
in the rate case on March 25, 2011 and issued a written order on
April 25, 2011. The MPUC authorized a revenue increase of
approximately $5.0 million, or 3.76% in base rate revenues,
excluding the effect of moving recovery of wind investments to base
rates. The MPUC’s written order included: (1) recovery of Big
Stone II costs over five years (see discussion below), (2) moving
recovery of wind farm assets from rider recovery to base rate
recovery, (3) transfer of a portion of MNCIP costs from rider
recovery to base rate recovery, (4) transfer of the investment in
two transmission lines from rider recovery to base rate recovery,
and (5) changing the mechanism for providing customers with a
credit for margins earned on asset-based wholesale sales of
electricity from a credit to base rates to a credit to the
Minnesota fuel clause adjustment (FCA). When these changes to
recovery mechanisms are taken into account, the overall increase to
customers will be approximately 1.6% compared to the authorized
interim rate increase of 3.8%, which will result
in an interim rate refund of approximately $3.9 million. OTP
accrued a $2.3 million refund liability in the first quarter of
2011 and an additional $1.2 million in the second quarter of 2011
for revenue billed under interim rates from June 1, 2010 through
June 30, 2011. OTP expects the refund to be distributed to
Minnesota customers during the fourth quarter of 2011. Pursuant to
the order, OTP’s allowed rate of return on rate base will
increase from 8.33% to 8.61% and its allowed rate of return on
equity will increase from 10.43% to 10.74%. OTP's rates of return
will be based on a capital structure of 48.28% long term debt and
51.72% common equity. On May 16, 2011, OTP requested that the MPUC
reconsider its decisions on test year pension costs, the impact of
accumulated pension contributions, a sales adjustment, and
clarification of the expenses related to pension and other
benefits. The
MPUC denied all of OTP’s petitions for reconsideration and
clarification on June 23, 2011. Final rates are anticipated to
become effective October 1, 2011.
OTP
has a regulatory asset of $4.1 million for revenues that are
eligible for recovery through the Minnesota Renewable Resource
Adjustment (MNRRA) rider that have not been billed to Minnesota
customers as of June 30, 2011. Except for the balance of this
regulatory asset and any amount necessary to true-up amounts
undercollected while the current MNRRA rider rate has been in
effect, the recovery of MNRRA costs will be moved to base rates in
October 2011 under the MPUC’s April 25, 2011 general
rate case order.
In
its April 25, 2011 general rate case order, the MPUC approved
the transfer of transmission costs currently being recovered
through OTP’s Minnesota Transmission Cost Recovery (TCR)
rider to recovery in base rates. The transmission investments for
two projects currently in the TCR will continue to be recovered
through OTP’s Minnesota TCR rider until final rates go into
effect in October 2011. OTP filed a request for an update to its
Minnesota TCR rider on October 5, 2010. Comments and reply comments
have been filed but the MPUC has not yet scheduled a hearing on the
request.
North Dakota
Transmission Cost Recovery Rider—North Dakota law
provides a mechanism for automatic adjustment outside of a general
rate proceeding to recover jurisdictional capital and operating
costs incurred by a public utility for new or modified electric
transmission facilities. OTP requested recovery of such costs in
its general rate case filed in November 2008 and was granted
recovery of such costs by the North Dakota Public Service
Commission (NDPSC) in its November 25, 2009 order. OTP filed a
request for an initial North Dakota TCR rider with the NDPSC on
April 29, 2011.
South Dakota
2010 General Rate Case Filing—On August 20, 2010 OTP
filed a general rate case with the South Dakota Public Utilities
Commission (SDPUC) requesting an overall revenue increase of
approximately $2.8 million, or just under 10.0%, which includes,
among other things, recovery of investments and expenses related to
renewable resources. On September 28, 2010 the SDPUC suspended
OTP’s proposed rates for a period of 180 days to allow time
to review OTP’s proposal. On January 19, 2011 OTP submitted a
proposal to use current rate design to implement an interim rate in
South Dakota to be effective on and after February 17, 2011. On
January 26, 2011 OTP submitted an amended proposal to also use a
lower interim rate increase than originally proposed. At its
February 1, 2011 meeting, the SDPUC approved OTP’s request to
implement interim rates using current rate design and the lower
interim increase to be effective on and after February 17, 2011. On
April 21, 2011, the SDPUC issued its written order approving a
revenue increase of approximately $643,000 with an overall rate of
return on rate base of 8.50%. Final rates went into effect on June
1, 2011.
Transmission Cost Recovery Rider—South Dakota law
provides a mechanism for automatic adjustment outside of a general
rate proceeding to recover jurisdictional capital and operating
costs incurred by a public utility for new or modified electric
transmission facilities. OTP submitted a request for an initial
South Dakota TCR rider to the SDPUC on November 5, 2010. The South
Dakota TCR request is expected to be on the SDPUC agenda in fall
2011.
Capacity Expansion 2020 (CapX2020)
CapX2020
is a joint initiative of 11 investor-owned, cooperative, and
municipal utilities in Minnesota and the surrounding region to
upgrade and expand the electric transmission grid to ensure
continued reliable and affordable service. The CapX2020 companies
identified four major transmission projects for the region: (1) the
Fargo–Monticello 345 kiloVolt (kV) Project (the Fargo
Project), (2) the Brookings–Southeast Twin Cities 345 kV
Project (the Brookings Project), (3) the Bemidji – Grand
Rapids Project (the Bemidji Project), and (4) the Twin
Cities–LaCrosse 345 kV Project. OTP is an investor in the
Fargo Project, the Brookings Project and the Bemidji
Project.
On
April 16, 2009 the MPUC approved Certificates of Need (CONs) for
the three 345 kV Group 1 CapX2020 line projects: the Fargo Project,
the Brookings Project and the Twin Cities–LaCrosse 345 kV
Project.
The Fargo Project—The route permit application for the
Monticello to St. Cloud portion of the Fargo Project was filed in
April 2009. The MPUC approved the route permit application and
issued a written order on July 12, 2010. Required permits from the
Minnesota Department of Transportation, Minnesota Department of
Natural Resources and the U.S. Army Corps of Engineers were
received in 2010. A Transmission Capacity Exchange Agreement,
allocating transmission capacity rights to owners across the
Monticello to St. Cloud portion of the Fargo Project, was accepted
by the Federal Energy Regulatory Commission (FERC) in the third
quarter of 2010. The Monticello to St. Cloud portion of the Fargo
Project is scheduled for completion in December 2011.
The
Minnesota route permit application for the St. Cloud to Fargo
portion of the Fargo Project was filed on October 1, 2009.
Minnesota State Environmental Impact Statement (EIS) scoping
meetings were held in September 2010 and public hearings were held
in November 2010.The MPUC approved the route permit on June 24,
2011. Construction is expected to begin in the fall of 2011 on the
line section between St. Cloud and Alexandria,
Minnesota.
On
October 8, 2010, OTP submitted its application for a Certificate of
Public Convenience and Necessity (CPCN) from the NDPSC for the
North Dakota portion of the Fargo Project. The NDPSC approved the
CPCN in January 2011. The application for the North Dakota
Certificate of Corridor Compatibility (CCC) was filed on December
30, 2010 and was revised in March 2011. The June 23, 2011 hearing
for the North Dakota CCC application was postponed. It is expected
that a route permit application will be filed with the NDPSC in the
third quarter of 2011. Due to the postponement of the CCC hearing,
the NDPSC will conduct a joint process going forward pertaining to
the CCC and North Dakota route permit applications.
The Brookings Project—The Minnesota route permit
application for the Brookings Project was filed in the fourth
quarter of 2008. The MPUC approved the final line segment route
permit for the Brookings Project on February 3, 2011.
An
application for a South Dakota facility route permit was filed with
the SDPUC on November 22, 2010. The SDPUC conducted a public
hearing in January 2011 and the South Dakota route permit was
approved in June 2011. The MISO board of directors granted
conditional approval of the Multi-Value Project (MVP) cost
allocation designation under the MISO Tariff for the Brookings
Project. Once the MISO board finalizes its analysis of all of the
MVP projects in its study portfolio, the MISO board will be in a
position to remove the condition, which is anticipated to occur in
December 2011.
The Bemidji Project—OTP serves as the lead utility for
the Bemidji Project, which has an expected in-service date in late
2012. The MPUC approved the CON for this project on July 9, 2009. A
route permit application was filed with the MPUC in the second
quarter of 2008 and approved on October 28, 2010. The
joint state and federal EIS was published by federal agencies on
September 7, 2010, and the project’s Transmission Capacity
Exchange Agreement was accepted and approved by the FERC in the
third quarter of 2010. On March 25, 2011, the Leech Lake Band of
Ojibwe (LLBO) submitted a petition to the MPUC, requesting the
revocation or suspension of the project’s route permit. The
request is based on the LLBO’s allegation that it has
jurisdiction to require the project to obtain its permission to
cross through the historical boundaries of the Leech Lake
Reservation. The owners of the Bemidji
Project, including OTP, filed reply comments in opposition
to the LLBO’s request. On April 25, 2011, the Bemidji
Project owners filed a declaratory judgment in the U.S.
District Court for Minnesota against the LLBO seeking that no
consent from the LLBO is required for the
project to run through the LLBO reservation boundaries since
the project is located exclusively on non LLBO lands. On June 22,
2011, Federal District Judge Frank issued a preliminary injunction
which ordered the LLBO to cease and desist from pursuing its claims
of jurisdiction over the project in tribal court or the MPUC or
from taking any other actions to interfere with the routing or
construction of the
project. The parties have engaged in mediated settlement
discussions with the
federal magistrate judge. The LLBO’s motion to dismiss
the declaratory judgment action is currently scheduled to be heard
on September 16, 2011.
CapX2020 Request for Advance Determination of
Prudence—On October 5, 2009 OTP filed an application
for an advance determination of prudence with the NDPSC for its
proposed participation in three of the four Group 1 projects: the
Fargo Project, the Brookings Project and the Bemidji Project. An
administrative law judge conducted an evidentiary hearing on the
application in May 2010. On October 6, 2010 the NDPSC adopted an
order approving a settlement between OTP and intervener NDPSC
advocacy staff, and issued an advance determination of prudence to
OTP for participation in the three Group 1 projects. The order
is subject to a number of terms and conditions in addition to the
settlement agreement, including the provision of additional
information on the eventual resolution of cost allocation issues
relevant to the Brookings Project and its associated impact on
North Dakota. On April 29, 2011, OTP filed its compliance filing
with the NDPSC, seeking a determination of continued prudence for
OTP’s investment in the Brookings Project. The NDPSC hearing
occurred on July 25, 2011 and the NDPSC scheduled a working session
for August 5, 2011 to discuss the matter.
Big Stone Air Quality Control System
The
South Dakota Department of Environment and Natural Resources (DENR)
determined that the Big Stone Plant is subject to Best Available
Retrofit Technology (BART) requirements of the Clean Air Act (CAA),
based on air dispersion modeling indicating that Big Stone’s
emissions reasonably contribute to visibility impairment in
national parks and wilderness areas in Minnesota, North Dakota,
South Dakota and Michigan. Under the U.S. Environmental Protection
Agency’s (EPA) regional haze regulations, South Dakota
developed and submitted its implementation plan and associated
implementation rules to the EPA on January 21, 2011. Under the
South Dakota Implementation Plan, and its implementing rules that
became effective in December 2010, the Big Stone Plant must install
and operate a new BART compliant air quality control system to
reduce emissions as expeditiously as practicable, but no later than
five years after the EPA’s approval of South Dakota’s
implementation plan. Although studies and evaluations are
continuing, the current project cost is estimated to be
approximately $490 million (OTP’s share would be $264
million). On January 14, 2011 OTP filed a petition asking the MPUC
for advance determination of prudence (ADP) for the design,
construction and operation of the BART compliant air quality
control system at Big Stone Plant attributable to serving
OTP’s Minnesota customers. On June 1, 2011, the MPUC referred
the matter to the Office of Administrative Hearings for contested
case proceedings before an administrative law judge (ALJ). On June
17, 2011, the ALJ entered a scheduling order that calls for
evidentiary hearings from August 17-19, 2011, with an ALJ report
and recommendation by September 30, 2011. Because of the Minnesota
government shutdown in July 2011, these dates have changed to a
hearing date of September 14-16, 2011 with an ALJ report by
November 4, 2011.
OTP filed an application for an ADP with the NDPSC on May 20, 2011
with a decision expected by December 20, 2011. The Big Stone Plant
is currently operating within all presently applicable federal and
state air quality and emission standards.
Big Stone II Project
On
June 30, 2005 OTP and a coalition of six other electric providers
entered into several agreements for the development of a second
electric generating unit, named Big Stone II, at the site of the
existing Big Stone Plant near Milbank, South Dakota. On September
11, 2009 OTP announced its withdrawal—both as a participating
utility and as the project’s lead developer—from Big
Stone II, due to a number of factors. On November 2, 2009, the
remaining Big Stone II participants announced the cancellation of
the Big Stone II project.
OTP
requested recovery of the Minnesota portion of its Big Stone II
development costs over a five-year period as part of its general
rate case filed in Minnesota on April 2, 2010. In a written order
issued on April 25, 2011, the MPUC authorized recovery of the
Minnesota portion of Big Stone II generation development costs from
Minnesota ratepayers over a 60-month recovery period expected to
begin in October 2011. The amount of Big Stone II generation costs
incurred by OTP that were deemed recoverable from Minnesota
ratepayers was $3,199,000 (which excludes $3,246,000 of project
transmission-related costs). Because the MPUC denied OTP an
investment return on these deferred costs over the 60-month
recovery period, the recoverable amount has been discounted to its
present value of $2,758,000, in accordance with ASC 980,
Regulated
Operations, accounting requirements.
On
December 30, 2010 OTP filed a request for an extension of the
Minnesota Route Permit for the Big Stone transmission facilities.
The request asks to extend the deadline for filing a CON for these
transmission facilities until March 17, 2013. The April 25, 2011
MPUC order instructed OTP to transfer the $3,246,000 Minnesota
share of Big Stone II transmission costs to Construction Work in
Progress (CWIP) and to create a tracker account through which any
over or under recoveries could be accumulated for refund or
recovery determination in future rate cases as a regulatory
liability or asset. If determined eligible for recovery under the
FERC-approved MISO regional transmission tariff, the Minnesota
portion of Big Stone II transmission costs and accumulated
Allowance for Funds Used During Construction (AFUDC) will receive
rate base treatment and recovery through the FERC-approved MISO
regional transmission rates. Any amounts over or under collected
through MISO rates will be reflected in the tracker
account.
OTP
requested recovery of the South Dakota portion of its Big Stone II
development costs over a five-year period as part of its general
rate case filed in South Dakota on August 20, 2010. In the first
quarter of 2011, the SDPUC approved recovery of the South Dakota
portion of Big Stone II generation development costs totaling
approximately $1.0 million from South Dakota ratepayers over a
ten-year period beginning in February 2011 with the implementation
of interim rates. OTP will be allowed to earn a return on the
amount subject to recovery over the ten-year recovery period.
Therefore, the South Dakota settlement amount is not discounted.
OTP transferred the remaining Big Stone II transmission costs to
CWIP, with such costs subject to AFUDC and recovery in future
FERC-approved MISO rates or retail rates.
|
Accounts Receivable Retained by Customers Pending Project Completion (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable Retained by Customers | $ 10,643 | $ 11,848 |
Pension Plan and Other Postretirement Benefits (Tables)
|
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Jun. 30, 2011
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Funded Defined Benefit Pension Plans
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Components of Net Periodic Benefit Cost |
Pension Plan—Components of net periodic pension
benefit cost of the Company's noncontributory funded pension plan
are as follows:
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Unfunded Defined Benefit Pension Plans
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Components of Net Periodic Benefit Cost |
Executive Survivor and Supplemental Retirement
Plan—Components of net periodic pension benefit cost
of the Company’s unfunded, nonqualified benefit plan for
executive officers and certain key management employees are as
follows:
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Other Postretirement Benefit Plans, Defined Benefit
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Components of Net Periodic Benefit Cost |
Postretirement Benefits—Components of net periodic
postretirement benefit cost for health insurance and life insurance
benefits for retired OTP and corporate employees are as
follows:
|
Change in the Company's Consolidated Balance Sheet Position on Forward Contracts for the Purchase and Sale of Electricity (Detail) (Forward Contracts, USD $)
In Thousands |
6 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2011
|
Dec. 31, 2010
|
Jun. 30, 2011
Contracts Entered into in 2009 and Settled in 2011
|
Jun. 30, 2011
Contracts Entered into in 2010 and Settled in 2011
|
Jun. 30, 2011
Contracts Entered into in 2009 in 2011
|
Jun. 30, 2011
Contracts Entered into in 2010 in 2011
|
Jun. 30, 2011
Contracts Entered into in 2009 and 2010
|
Jun. 30, 2011
Contracts Entered into in 2011
|
|
Derivatives, Fair Value [Line Items] | ||||||||
Fair Value at Beginning of Year | $ 646 | $ 763 | $ 526 | $ 120 | ||||
Net Fair Value End of Period | 646 | 763 | 526 | 120 | ||||
Amounts Realized | (145) | (6) | ||||||
Changes in Fair Value | $ (14) | $ (72) |
Realized and Unrealized Net (Losses)/Gains on Forward Energy Contracts Included in Electric Operating Revenues (Detail) (USD $)
In Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Net Gains (Losses) on Forward Electric Energy Contracts | $ 139 | $ (24) | $ 131 | $ 1,801 |
Segment Information - Additional Information (Detail)
|
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Segment Reporting Information [Line Items] | |
Percentage of revenue of one customer of DMI | 11.70% |
Stock Options with Exercise Prices Greater than the Market Price Excluded from the Calculation of Diluted Earnings per Common Share (Detail) (Stock Options, USD $)
|
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Stock Options
|
||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Options Outstanding | 172,460 | 388,960 | 172,460 | 388,960 |
Range of Exercise Prices, Lower Range | $ 24.93 | $ 24.93 | $ 24.93 | $ 24.93 |
Range of Exercise Prices, Upper Range | $ 31.34 | $ 31.34 | $ 31.34 | $ 31.34 |
Regulatory Assets and Liabilities
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
|
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Regulatory Assets and Liabilities |
4. Regulatory Assets and Liabilities
As
a regulated entity, OTP accounts for the financial effects of
regulation in accordance with ASC 980, Regulated Operations.
This accounting standard allows for the recording of a regulatory
asset or liability for costs that will be collected or refunded in
the future as required under regulation. The following table
indicates the amount of regulatory assets and liabilities recorded
on the Company’s consolidated balance sheet:
The
regulatory asset related to the unrecognized transition obligation,
prior service costs and actuarial losses on pensions and other
postretirement benefits represents benefit costs and actuarial
losses subject to recovery through rates as they are expensed over
the remaining service lives of active employees included in the
plans. These unrecognized benefit costs and actuarial losses are
required to be recognized as components of Accumulated Other
Comprehensive Income in equity under ASC 715, Compensation—Retirement
Benefits, but are eligible for treatment as regulatory
assets based on their probable recovery in future retail electric
rates.
All
Deferred Marked-to-Market Gains and Losses recorded as of June 30,
2011 are related to forward purchases of energy scheduled for
delivery through August 2015.
Deferred
Conservation Program Costs & Accrued Incentives represent
mandated conservation expenditures and incentives recoverable
through retail electric rates.
Minnesota
Renewable Resource Rider Accrued Revenues relate to revenues earned
on qualifying 2008 through 2011 renewable resource costs incurred
to serve Minnesota customers that have not been billed to Minnesota
customers as of June 30, 2011.
Big
Stone II Unrecovered Project Costs – North Dakota are the
North Dakota share of costs incurred by OTP related to its
participation in the abandoned Big Stone II generation
project.
Big
Stone II Unrecovered Project Costs – Minnesota are the
Minnesota share of costs incurred by OTP related to its
participation in the abandoned Big Stone II generation
project.
Debt
Reacquisition Premiums are being recovered from OTP customers over
the remaining original lives of the reacquired debt issues, the
longest of which is 255 months.
The
Accumulated Asset Retirement Obligation (ARO)
Accretion/Depreciation Adjustment will accrete and be amortized
over the lives of property with asset retirement
obligations.
The
regulatory assets and liabilities related to Deferred Income Taxes
result from changes in statutory tax rates accounted for in
accordance with ASC 740, Income
Taxes.
North
Dakota Renewable Resource Rider Accrued Revenues relate to revenues
earned on qualifying renewable resource costs incurred to serve
North Dakota customers that have not been billed to North Dakota
customers as of June 30, 2011.
Big
Stone II Unrecovered Project Costs – South Dakota are the
South Dakota share of costs incurred by OTP related to its
participation in the abandoned Big Stone II generation
project.
South
Dakota – Asset-Based Margin Sharing Shortfall represents
differences in OTP’s South Dakota share of actual profit
margins on wholesale sales of electricity from company-owned
generating units and estimated profit margins from those sales that
were used in determining current South Dakota retail electric
rates. Net asset-based margin sharing accumulated shortfalls will
be subject to recovery or refund through future retail rate
adjustments in South Dakota.
Minnesota
Transmission Rider Accrued Revenues are expected to be recovered
from Minnesota retail electric customers over 12 months beginning
in January 2012.
The
Accumulated Reserve for Estimated Removal Costs – Net of
Salvage is reduced as actual removal costs, net of salvage
revenues, are incurred.
No
schedule has been set for the return of the June 30, 2011 Minnesota
Transmission Rider Accrued Refund balance.
South
Dakota – Nonasset-Based Margin Sharing Excess represents 25%
of OTP’s South Dakota share of actual profit margins on
nonasset-based wholesale sales of electricity. The excess margins
accumulated annually will be subject to refund through future
retail rate adjustments in South Dakota in the following
year.
If
for any reason, OTP ceases to meet the criteria for application of
guidance under ASC 980 for all or part of its operations, the
regulatory assets and liabilities that no longer meet such criteria
would be removed from the consolidated balance sheet and included
in the consolidated statement of income as an extraordinary expense
or income item in the period in which the application of guidance
under ASC 980 ceases.
|
Class B Stock Options of Subsidiary - Additional Information (Detail) (USD $)
|
6 Months Ended | 1 Months Ended | |
---|---|---|---|
Jun. 30, 2011
|
May 06, 2011
Common Class B
|
Jun. 30, 2011
Common Class B
|
|
Class of Stock [Line Items] | |||
Number of Common shares options cancelled | 6,641 | 363 | |
Common stock fair value ,per share | $ 2,973.90 | ||
Common stock value ,book value per share | $ 2,085.88 | ||
Adjustment to Retained earnings | $ (322,000) |
Assets and Liabilities Measured at Fair Value on a Recurring Basis (Detail) (Fair Value, Measurements, Recurring, USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Fair Value, Inputs, Level 1
|
||
Assets: | ||
Money Market and Mutual Funds and Cash | $ 804 | $ 800 |
Corporate Debt Securities | 8,885 | 8,467 |
Total Assets | 9,820 | 9,325 |
Fair Value, Inputs, Level 1 | Forward Gasoline Purchase Contracts
|
||
Assets: | ||
Derivative Assets | 131 | 58 |
Fair Value, Inputs, Level 2
|
||
Assets: | ||
Regulatory Asset - Deferred Mark-to-Market Losses on Forward Energy Contracts | 14,646 | 12,054 |
Total Assets | 19,478 | 18,929 |
Liabilities: | ||
Regulatory Liability - Deferred Mark-to-Market Gains on Forward Energy Contracts | 149 | 175 |
Total Liabilities | 18,832 | 18,166 |
Fair Value, Inputs, Level 2 | Forward Energy Contracts
|
||
Assets: | ||
Derivative Assets | 4,832 | 6,875 |
Liabilities: | ||
Derivative Liabilities | $ 18,683 | $ 17,991 |
Share-Based Payments (Tables)
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
|
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Stock Incentive Awards | On
April 11, 2011 the Company’s Board of Directors granted the
following stock incentive awards to the Company’s
non-employee directors, executive officers and key employees under
the 1999 Stock Incentive Plan, as amended:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amounts of Compensation Expense Recognized under the Company's Stock-Based Payment Programs | Compensation
expense recognized under the Company’s stock-based payment
programs:
|
Stock Incentive Awards (Detail) (USD $)
|
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Director | Restricted Stock
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | 24,000 |
Grant-Date Fair Value per Share | $ 22.51 |
Vesting | 25% per year through April 8, 2015 |
Executive Officer | Restricted Stock
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | 24,600 |
Grant-Date Fair Value per Share | $ 22.51 |
Vesting | 25% per year through April 8, 2015 |
Executive Officer | Performance Awards
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | 48,600 |
Grant-Date Fair Value per Share | $ 23.61 |
Vesting | December 31, 2013 |
Employee | Restricted Stock Units (RSUs)
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | 19,800 |
Grant-Date Fair Value per Share | $ 18.03 |
Vesting | 100% on April 8, 2015 |
Fair Value of Financial Instruments (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Carrying Amount
|
||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and Short-Term Investments | $ 0 | |
Long-Term Debt | (433,715) | (434,812) |
Fair Value
|
||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-Term Debt | $ (466,010) | $ (474,307) |
Breakdown of OTP's Credit Risk Standing on Forward Energy Contracts in a Marked-to-market Loss Position (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
||||
---|---|---|---|---|---|---|
Current Liability - Marked-to-Market Loss | ||||||
Loss Contracts Covered by Deposited Funds | $ 427 | |||||
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade | 4,112 | [1] | 10,904 | [1] | ||
Loss Contracts with No Ratings Triggers or Deposit Requirements | 14,571 | 6,660 | ||||
Total Current Liability - Marked-to-Market Loss | 18,683 | 17,991 | ||||
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade | 4,112 | [1] | 10,904 | [1] | ||
Offsetting Gains with Counterparties under Master Netting Agreements | (4,112) | (6,219) | ||||
Net Deposit Requirements on Contracts with Credit Risk Related Features | 4,685 | |||||
Covered by Deposited Funds | ||||||
Reporting Date Deposit Requirement if Credit Risk Feature Triggered | $ 4,685 | |||||
|
Income Tax Expense (Benefit) - Continuing Operations (Tables)
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
|
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Income Tax Expense (Benefit) - Continuing Operations Effective Income Tax Rate |
|
Amounts of Accounts Receivable Sold and Discounts, Fees and Commissions Paid (Detail) (USD $)
In Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Receivables [Line Items] | ||||
Accounts Receivable Sold | $ 9,092 | $ 18,500 | $ 28,140 | $ 29,300 |
Discounts, Fees and Commissions Paid on Sale of Accounts Receivable | $ 135 | $ 75 | $ 253 | $ 107 |
Short-Term and Long-Term Borrowings (Tables)
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
|
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Status of our Lines of Credit | The
following table presents the status of our lines of credit as of
June 30, 2011 and December 31, 2010:
|
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Breakdown of the Assignment of the Company's Consolidated Short-term and Long-term Debt Outstanding | The
following table provides a breakdown of the assignment of the
Company’s consolidated short-term and long-term debt
outstanding as of June 30, 2011:
|
Fair Value of Financial Instruments
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2011
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Financial Instruments |
13. Fair Value of Financial Instruments
The
following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is
practicable to estimate that value:
Cash and Short-Term Investments—The carrying amount
approximates fair value because of the short-term maturity of those
instruments.
Long-Term Debt—The fair value of the Company's
long-term debt is estimated based on the current rates available to
the Company for the issuance of debt. The Company’s long-term
debt subject to variable interest rates approximates fair
value.
|
Regulatory Assets and Liabilities - Additional Information (Detail)
|
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Debt Reacquisition Premiums - Issue with longest recovery period
|
|
Schedule of Regulatory Assets and Liabilities [Line Items] | |
Regulatory Assets - Long Term, Remaining Recovery/Refund Period | 255 months |
South Dakota - Nonasset-Based Margin Sharing Excess
|
|
Schedule of Regulatory Assets and Liabilities [Line Items] | |
Share of actual profit margins on nonasset-based wholesale sales of electricity | 25.00% |
Discontinued Operations - Additional Information (Detail) (USD $)
|
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Proceeds from Sale of Discontinued Operations | $ 84,363,000 |
IPH
|
|
Proceeds from Sale of Discontinued Operations | 87,000,000 |
Proceeds from sale of discontinued operations, deposited in an escrow account | $ 3,000,000 |
Breakdown of the Assignment of the Company's Consolidated Short-term and Long-term Debt Outstanding (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Short-Term Debt - Credit Lines | $ 30,362 | $ 79,490 |
Long-Term Debt | 437,060 | |
Current Maturities | 3,340 | 604 |
Unamortized Debt Discount | 5 | |
Total Long-Term Debt | 433,715 | 434,812 |
Total Short-Term and Long-Term Debt (with current maturities) | 469,768 | |
Otter Tail Power Company
|
||
Long-Term Debt | 280,705 | |
Total Long-Term Debt | 280,705 | |
Total Short-Term and Long-Term Debt (with current maturities) | 296,757 | |
Otter Tail Power Company | Line of Credit
|
||
Short-Term Debt - Credit Lines | 16,052 | |
Otter Tail Power Company | Senior Unsecured Notes 6.63%, due December 1, 2011
|
||
Long-Term Debt | 90,000 | |
Otter Tail Power Company | Pollution Control Refunding Revenue Bonds, Variable, 2.10% at June 30, 2011, due December 1, 2012
|
||
Long-Term Debt | 10,400 | |
Otter Tail Power Company | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
|
||
Long-Term Debt | 33,000 | |
Otter Tail Power Company | Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017
|
||
Long-Term Debt | 5,090 | |
Otter Tail Power Company | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
|
||
Long-Term Debt | 30,000 | |
Otter Tail Power Company | Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022
|
||
Long-Term Debt | 20,215 | |
Otter Tail Power Company | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
|
||
Long-Term Debt | 42,000 | |
Otter Tail Power Company | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
|
||
Long-Term Debt | 50,000 | |
Varistar Corporation
|
||
Long-Term Debt | 4,387 | |
Current Maturities | 3,181 | |
Total Long-Term Debt | 1,206 | |
Total Short-Term and Long-Term Debt (with current maturities) | 4,387 | |
Varistar Corporation | Other Obligations - Various up to 13.31% at June 30, 2011
|
||
Long-Term Debt | 4,387 | |
Otter Tail Corporation
|
||
Long-Term Debt | 151,968 | |
Current Maturities | 159 | |
Unamortized Debt Discount | 5 | |
Total Long-Term Debt | 151,804 | |
Total Short-Term and Long-Term Debt (with current maturities) | 168,624 | |
Otter Tail Corporation | Line of Credit
|
||
Short-Term Debt - Credit Lines | 16,661 | |
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
|
||
Long-Term Debt | 100,000 | |
Otter Tail Corporation | Senior Unsecured Note 8.89%, due November 30, 2017
|
||
Long-Term Debt | 50,000 | |
Otter Tail Corporation | Other Obligations - Various up to 13.31% at June 30, 2011
|
||
Long-Term Debt | 1,968 | |
Line of Credit
|
||
Short-Term Debt - Credit Lines | 32,713 | |
Senior Unsecured Notes 6.63%, due December 1, 2011
|
||
Long-Term Debt | 90,000 | |
Pollution Control Refunding Revenue Bonds, Variable, 2.10% at June 30, 2011, due December 1, 2012
|
||
Long-Term Debt | 10,400 | |
9.000% Notes, due December 15, 2016
|
||
Long-Term Debt | 100,000 | |
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
|
||
Long-Term Debt | 33,000 | |
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017
|
||
Long-Term Debt | 5,090 | |
Senior Unsecured Note 8.89%, due November 30, 2017
|
||
Long-Term Debt | 50,000 | |
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
|
||
Long-Term Debt | 30,000 | |
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022
|
||
Long-Term Debt | 20,215 | |
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
|
||
Long-Term Debt | 42,000 | |
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
|
||
Long-Term Debt | 50,000 | |
Other Obligations - Various up to 13.31% at June 30, 2011
|
||
Long-Term Debt | $ 6,355 |
Information on OTP's Credit Risk Exposure on Delivered and Marked-to-market Forward Contracts (Detail) (USD $)
In Thousands, unless otherwise specified |
Jun. 30, 2011
Entity
|
Dec. 31, 2010
Entity
|
---|---|---|
Forward Energy Contracts
|
||
Derivative [Line Items] | ||
Exposure | $ 1,732 | $ 1,129 |
Counterparties | 4 | 4 |
Net Credit Risk to Single Largest Counterparty
|
||
Derivative [Line Items] | ||
Exposure | $ 970 | $ 585 |
Forward Contracts Classified as Derivatives
|
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Jun. 30, 2011
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Forward Contracts Classified as Derivatives |
5. Forward Contracts Classified as Derivatives
Electricity Contracts
All
of OTP’s wholesale purchases and sales of energy under
forward contracts that do not meet the definition of capacity
contracts are considered derivatives subject to mark-to-market
accounting. OTP’s objective in entering into forward
contracts for the purchase and sale of energy is to optimize the
use of its generating and transmission facilities and leverage its
knowledge of wholesale energy markets in the region to maximize
financial returns for the benefit of both its customers and
shareholders. OTP’s intent in entering into certain of these
contracts is to settle them through the physical delivery of energy
when physically possible and economically feasible. OTP also enters
into certain contracts for trading purposes with the intent to
profit from fluctuations in market prices through the timing of
purchases and sales.
The
market prices used to value OTP’s forward contracts for the
purchases and sales of electricity and electricity generating
capacity are determined by survey of counterparties or brokers used
by OTP’s power services’ personnel responsible for
contract pricing, as well as prices gathered from daily settlement
prices published by the Intercontinental Exchange and CME Globex.
For certain contracts, prices at illiquid trading points are based
on a basis spread between that trading point and more liquid
trading hub prices. These basis spreads are determined based on
available market price information and the use of forward price
curve models. The fair value measurements of these forward energy
contracts fall into level 2 of the fair value hierarchy set forth
in ASC 820-10-35.
The
following tables show the effect of marking to market forward
contracts for the purchase and sale of electricity and the location
and fair value amounts of the related derivatives reported on the
Company’s consolidated balance sheets as of
June 30, 2011 and December 31, 2010, and the change in
the Company’s consolidated balance sheet position from
December 31, 2010 to June 30, 2011:
The
June 30, 2011 balance of recognized but unrealized net
mark-to-market gains on the forward energy and capacity purchases
and sales is expected to be realized on settlement as scheduled
over the following periods in the amounts listed:
The
following realized and unrealized net (losses)/gains on forward
energy contracts are included in electric operating revenues on the
Company’s consolidated statements of income:
OTP
has credit risk associated with the nonperformance or nonpayment by
counterparties to its forward energy and capacity purchases and
sales agreements. We have established guidelines and limits to
manage credit risk associated with wholesale power and capacity
purchases and sales. Specific limits are determined by a
counterparty’s financial strength.
The
following table provides information on OTP’s credit risk
exposure on delivered and marked-to-market forward contracts as of
June 30, 2011 and December 31, 2010:
OTP
had no exposure at June 30, 2011 or December 31, 2010 to
counterparties with credit ratings below investment grade.
Counterparties with investment grade credit ratings have minimum
credit ratings of BBB- (Standard & Poor’s), Baa3
(Moody’s) or BBB- (Fitch). The credit risk exposures include
net amounts due to OTP on receivables/payables from completed
transactions billed and unbilled plus marked-to-market gains/losses
on forward contracts for the purchase and sale of electricity
scheduled for delivery subsequent to the reporting date. Individual
counterparty exposures are offset according to legally enforceable
netting arrangements.
The
following table provides a breakdown of OTP’s credit risk
standing on forward energy contracts in a marked-to-market loss
positions as of June 30, 2011 and December 31, 2010:
|
Subsequent Events
|
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Subsequent Events |
18. Subsequent Events
On
July 29, 2011, OTP entered into a Note Purchase Agreement (the 2011
Note Purchase Agreement) with the Purchasers named therein,
pursuant to which OTP has agreed to issue to the Purchasers in a
private placement transaction $140 million aggregate principal
amount of OTP’s 4.63% Senior Unsecured Notes due
December 1, 2021 (the 2021 Notes). The 2021 Notes
are expected to be issued on December 1, 2011, subject to the
satisfaction of certain customary conditions to
closing. OTP intends to use a portion of the proceeds of
the 2021 Notes to retire $90 million aggregate principal amount of
OTP’s 6.63% Senior Notes due December 1, 2011 and $10.4
million aggregate principal amount of its pollution control
refunding revenue bonds due December 1, 2012. The
remaining proceeds of the 2021 Notes will be used to repay
short-term debt of OTP, to pay fees and expenses related to the
issuance of the 2021 Notes and for other general corporate
purposes.
|
Reconciliation of the Company's Common Shares Outstanding (Detail)
|
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Common stock roll-forward [Line Items] | |
Common Shares Outstanding, December 31, 2010 | 36,002,739 |
Vesting of Restricted Stock Units | 16,475 |
Shares Withheld for Individual Income Tax Requirements | (6,641) |
Common Shares Outstanding, June 30, 2011 | 36,061,173 |
Employee
|
|
Common stock roll-forward [Line Items] | |
Restricted Stock Issued | 24,600 |
Director
|
|
Common stock roll-forward [Line Items] | |
Restricted Stock Issued | 24,000 |
Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)
|
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Significant Accounting Policies [Line Items] | |
Product warranty reserve balance | $ 2,956,000 |
DMI Industries, Inc
|
|
Significant Accounting Policies [Line Items] | |
Receivable Sales Agreement | $ 40,000,000 |
Receivables sales agreement, discount rate basis description | The current discount rate is 3-month LIBOR plus 4%. |
Receivables sales agreement, spread rate | 4.00% |
Minimum
|
|
Significant Accounting Policies [Line Items] | |
Product warranty period (in years) | 1 |
Maximum
|
|
Significant Accounting Policies [Line Items] | |
Product warranty period (in years) | 15 |
Commitments and Contingencies - Additional Information (Detail) (USD $)
In Millions |
Jun. 30, 2011
|
---|---|
Loss Contingencies [Line Items] | |
Loss Contingency, Range of Possible Loss, Maximum | $ 9.0 |
Commitments and Contingencies (Tables)
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Jun. 30, 2011
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Amounts of Commitments for OTP's Capacity and Energy Requirements | In
the first quarter of 2011, OTP entered into additional energy
purchase agreements increasing its commitments for capacity and
energy requirements. Amounts of commitments for OTP’s
capacity and energy requirements under agreements extending through
2032 were as follows:
OTP
has contracts providing for the purchase and delivery of a
significant portion of its current coal requirements. In the first
half of 2011, OTP extended its contract for the purchase of coal
for Hoot Lake Plant resulting in an increase in minimum purchase
commitments. OTP’s current coal purchase agreements under
contracts expire in 2012 and 2016. OTP is now committed to the
minimum purchase, dating from January 1, 2011, or to make payments
in lieu thereof in the following amounts:
|
Consolidated Statements of Income (Parenthetical) (USD $)
In Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Income (Loss) from Discontinued Operations, income tax expense (benefit) | $ (342) | $ 1,227 | $ (364) | $ 1,856 |
Gain on Disposition of Discontinued Operations, income taxes | $ 3,515 | $ 3,515 |
Summary of Significant Accounting Policies (Policies)
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Revenue Recognition |
Revenue Recognition
Due
to the diverse business operations of the Company, revenue
recognition depends on the product produced and sold or service
performed. The Company recognizes revenue when the earnings process
is complete, evidenced by an agreement with the customer, there has
been delivery and acceptance, and the price is fixed or
determinable. In cases where significant obligations remain after
delivery, revenue recognition is deferred until such obligations
are fulfilled. Provisions for sales returns and warranty costs are
recorded at the time of the sale based on historical information
and current trends. In the case of derivative instruments, such as
Otter Tail Power Company’s (OTP) forward energy contracts,
marked-to-market and realized gains and losses are recognized on a
net basis in revenue in accordance with Accounting Standards
Codification (ASC) 815-10-45-9. Gains and losses on forward energy
contracts subject to regulatory treatment, if any, are deferred and
recognized on a net basis in revenue in the period
realized.
For
the Company’s operating companies recognizing revenue on
certain products when shipped, those operating companies have no
further obligation to provide services related to such product. The
shipping terms used in these instances are FOB shipping
point.
Some
of the operating businesses in the Company’s Wind Energy,
Manufacturing and Construction segments enter into fixed-price
construction contracts. Revenues under these contracts are
recognized on a percentage-of-completion basis. The method used to
determine the progress of completion is based on the ratio of labor
hours incurred to total estimated labor hours at the
Company’s wind tower manufacturer and costs incurred to total
estimated costs on all other construction projects. If a loss is
indicated at a point in time during a contract, a projected loss
for the entire contract is estimated and recognized. Following are
the percentages of the Company’s consolidated revenues
recorded under the percentage-of-completion method:
The
following table summarizes costs incurred and billings and
estimated earnings recognized on uncompleted
contracts:
The
following amounts are included in the Company’s consolidated
balance sheets. Billings in excess of costs and estimated earnings
on uncompleted contracts are included in Accounts
Payable:
Included
in Costs and Estimated Earnings in Excess of Billings are the
following Costs and Estimated Earnings in Excess of Billings at DMI
Industries, Inc. (DMI), the Company’s wind tower
manufacturer:
These
amounts are related to costs incurred on wind towers in the process
of completion on major contracts under which the customer is not
billed until towers are completed and ready for
shipment.
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Warranty Reserves |
Warranty Reserves
The Company establishes reserves for estimated product warranty
costs at the time revenue is recognized based on historical
warranty experience and additionally for any known product warranty
issues. Certain Company products carry one to fifteen year
warranties. The warranty reserve balance was $2,956,000 as of June
30, 2011. Although the Company engages in extensive product quality
programs and processes, the Company’s warranty obligations
have been and may in the future be affected by product failure
rates, repair or field replacement costs and additional development
costs incurred in correcting product
failures.
Expenses associated with remediation activities in the Wind Energy
segment could be substantial. The potential exists for multiple
claims based on one defect repeated throughout the production
process or for claims where the cost to repair or replace the
defective part is highly disproportionate to the original cost of
the part. If the Company is required to cover remediation expenses
in addition to regular warranty coverage, the Company could be
required to accrue additional expenses and experience additional
unplanned cash expenditures which could adversely affect the
Company’s consolidated results of operations and financial
condition.
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Retainage |
Retainage
Accounts
Receivable include the following amounts, billed under contracts by
the Company’s subsidiaries, that have been retained by
customers pending project completion:
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Sales of Receivables |
Sales of Receivables
DMI
is a party to a $40 million receivables sales agreement whereby
designated customer accounts receivable may be sold to General
Electric Capital Corporation on a revolving basis.
The agreement is subject to renewal in March 2012. The current
discount rate is 3-month LIBOR plus 4%. In compliance with
guidance under ASC 860-20, Sales of Financial
Assets, sales of accounts receivable are reflected as a
reduction of accounts receivable in the consolidated balance sheets
and the proceeds are included in the cash flows from operating
activities in the consolidated statements of cash flows. Following
are the amounts of accounts receivable sold and discounts, fees and
commissions paid under DMI’s receivables sales agreement with
General Electric Capital Corporation:
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Fair Value Measurements |
Fair Value Measurements
The
Company follows ASC 820, Fair Value Measurements and
Disclosures, for recurring fair value measurements. ASC 820
provides a single definition of fair value and requires enhanced
disclosures about assets and liabilities measured at fair value.
ASC 820-10-35 establishes a hierarchal framework for disclosing the
observability of the inputs utilized in measuring assets and
liabilities at fair value. The three levels defined by the
hierarchy and examples of each level are as follows:
Level
1 – Quoted prices are available in active markets for
identical assets or liabilities as of the reported date. The types
of assets and liabilities included in Level 1 are highly liquid and
actively traded instruments with quoted prices, such as equities
listed by the New York Stock Exchange and commodity derivative
contracts listed on the New York Mercantile Exchange.
Level
2 – Pricing inputs are other than quoted prices in active
markets, but are either directly or indirectly observable as of the
reported date. The types of assets and liabilities included in
Level 2 are typically either comparable to actively traded
securities or contracts, such as treasury securities with pricing
interpolated from recent trades of similar securities, or priced
with models using highly observable inputs, such as commodity
options priced using observable forward prices and
volatilities.
Level
3 – Significant inputs to pricing have little or no
observability as of the reporting date. The types of assets and
liabilities included in Level 3 are those with inputs requiring
significant management judgment or estimation and may include
complex and subjective models and forecasts.
The
following table presents, for each of these hierarchy levels, the
Company’s assets and liabilities that are measured at fair
value on a recurring basis as of June 30, 2011 and December 31,
2010:
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Inventories |
Inventories
Inventories
consist of the following:
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Goodwill |
Goodwill
The
following table summarizes changes to goodwill by business segment
during 2011:
|
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Other Intangible Assets |
Other Intangible Assets
The
following table summarizes the components of the Company’s
intangible assets at June 30, 2011 and
December 31, 2010:
|
Summary of Inventories (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Schedule of Inventory [Line Items] | ||
Finished Goods | $ 30,519 | $ 29,113 |
Work in Process | 11,428 | 7,171 |
Raw Material, Fuel and Supplies | 44,288 | 42,986 |
Total Inventories | $ 86,235 | $ 79,270 |
Segment Information (Tables)
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Percentage of Consolidated Sales Revenue by Country | The
following table presents the percent of consolidated sales revenue
by country:
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Information for the Business Segments | Information
for the business segments for three and six month periods ended
June 30, 2011 and 2010 and total assets by business segment as
of June 30, 2011 and December 31, 2010 are presented in the
following tables:
Operating Revenue
Interest Charges
Income Tax Expense (Benefit) - Continuing
Operations
Earnings Available for Common Shares
Total Assets
|
Status of our Lines of Credit (Parenthetical) (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
---|---|
Line of Credit Facility [Line Items] | |
Short-Term Debt | $ 2,351 |
Wylie-Wind
|
|
Line of Credit Facility [Line Items] | |
Short-Term Debt | $ 2,351 |
Amounts of Compensation Expense Recognized under the Company's Stock-Based Payment Programs (Parenthetical) (Detail) (Employee Stock Purchase Plan)
|
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Employee Stock Purchase Plan
|
||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock Compensation Expense, discount rate | 15.00% | 15.00% | 15.00% | 15.00% |
Summary of Significant Accounting Policies
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Summary of Significant Accounting Policies |
1. Summary of Significant Accounting Policies
Revenue Recognition
Due
to the diverse business operations of the Company, revenue
recognition depends on the product produced and sold or service
performed. The Company recognizes revenue when the earnings process
is complete, evidenced by an agreement with the customer, there has
been delivery and acceptance, and the price is fixed or
determinable. In cases where significant obligations remain after
delivery, revenue recognition is deferred until such obligations
are fulfilled. Provisions for sales returns and warranty costs are
recorded at the time of the sale based on historical information
and current trends. In the case of derivative instruments, such as
Otter Tail Power Company’s (OTP) forward energy contracts,
marked-to-market and realized gains and losses are recognized on a
net basis in revenue in accordance with Accounting Standards
Codification (ASC) 815-10-45-9. Gains and losses on forward energy
contracts subject to regulatory treatment, if any, are deferred and
recognized on a net basis in revenue in the period
realized.
For
the Company’s operating companies recognizing revenue on
certain products when shipped, those operating companies have no
further obligation to provide services related to such product. The
shipping terms used in these instances are FOB shipping
point.
Some
of the operating businesses in the Company’s Wind Energy,
Manufacturing and Construction segments enter into fixed-price
construction contracts. Revenues under these contracts are
recognized on a percentage-of-completion basis. The method used to
determine the progress of completion is based on the ratio of labor
hours incurred to total estimated labor hours at the
Company’s wind tower manufacturer and costs incurred to total
estimated costs on all other construction projects. If a loss is
indicated at a point in time during a contract, a projected loss
for the entire contract is estimated and recognized. Following are
the percentages of the Company’s consolidated revenues
recorded under the percentage-of-completion method:
The
following table summarizes costs incurred and billings and
estimated earnings recognized on uncompleted
contracts:
The
following amounts are included in the Company’s consolidated
balance sheets. Billings in excess of costs and estimated earnings
on uncompleted contracts are included in Accounts
Payable:
Included
in Costs and Estimated Earnings in Excess of Billings are the
following Costs and Estimated Earnings in Excess of Billings at DMI
Industries, Inc. (DMI), the Company’s wind tower
manufacturer:
These
amounts are related to costs incurred on wind towers in the process
of completion on major contracts under which the customer is not
billed until towers are completed and ready for
shipment.
Warranty Reserves
The Company establishes reserves for estimated product warranty
costs at the time revenue is recognized based on historical
warranty experience and additionally for any known product warranty
issues. Certain Company products carry one to fifteen year
warranties. The warranty reserve balance was $2,956,000 as of June
30, 2011. Although the Company engages in extensive product quality
programs and processes, the Company’s warranty obligations
have been and may in the future be affected by product failure
rates, repair or field replacement costs and additional development
costs incurred in correcting product
failures.
Expenses associated with remediation activities in the Wind Energy
segment could be substantial. The potential exists for multiple
claims based on one defect repeated throughout the production
process or for claims where the cost to repair or replace the
defective part is highly disproportionate to the original cost of
the part. If the Company is required to cover remediation expenses
in addition to regular warranty coverage, the Company could be
required to accrue additional expenses and experience additional
unplanned cash expenditures which could adversely affect the
Company’s consolidated results of operations and financial
condition.
Retainage
Accounts
Receivable include the following amounts, billed under contracts by
the Company’s subsidiaries, that have been retained by
customers pending project completion:
Sales of Receivables
DMI
is a party to a $40 million receivables sales agreement whereby
designated customer accounts receivable may be sold to General
Electric Capital Corporation on a revolving basis.
The agreement is subject to renewal in March 2012. The current
discount rate is 3-month LIBOR plus 4%. In compliance with
guidance under ASC 860-20, Sales of Financial
Assets, sales of accounts receivable are reflected as a
reduction of accounts receivable in the consolidated balance sheets
and the proceeds are included in the cash flows from operating
activities in the consolidated statements of cash flows. Following
are the amounts of accounts receivable sold and discounts, fees and
commissions paid under DMI’s receivables sales agreement with
General Electric Capital Corporation:
Fair Value Measurements
The
Company follows ASC 820, Fair Value Measurements and
Disclosures, for recurring fair value measurements. ASC 820
provides a single definition of fair value and requires enhanced
disclosures about assets and liabilities measured at fair value.
ASC 820-10-35 establishes a hierarchal framework for disclosing the
observability of the inputs utilized in measuring assets and
liabilities at fair value. The three levels defined by the
hierarchy and examples of each level are as follows:
Level
1 – Quoted prices are available in active markets for
identical assets or liabilities as of the reported date. The types
of assets and liabilities included in Level 1 are highly liquid and
actively traded instruments with quoted prices, such as equities
listed by the New York Stock Exchange and commodity derivative
contracts listed on the New York Mercantile Exchange.
Level
2 – Pricing inputs are other than quoted prices in active
markets, but are either directly or indirectly observable as of the
reported date. The types of assets and liabilities included in
Level 2 are typically either comparable to actively traded
securities or contracts, such as treasury securities with pricing
interpolated from recent trades of similar securities, or priced
with models using highly observable inputs, such as commodity
options priced using observable forward prices and
volatilities.
Level
3 – Significant inputs to pricing have little or no
observability as of the reporting date. The types of assets and
liabilities included in Level 3 are those with inputs requiring
significant management judgment or estimation and may include
complex and subjective models and forecasts.
The
following table presents, for each of these hierarchy levels, the
Company’s assets and liabilities that are measured at fair
value on a recurring basis as of June 30, 2011 and December 31,
2010:
Reclassifications and Changes to Presentation
The
Company’s consolidated balance sheet as of December 31, 2010,
and consolidated income statement and consolidated statement of
cash flows for the three and six months ended June 30, 2010 reflect
the reclassifications of the assets and liabilities, operating
results and cash flows of Idaho Pacific Holdings, Inc. (IPH) and
E.W. Wylie’s (Wylie) heavy haul and specialized shipment and
transportation of wind turbine components business to discontinued
operations as a result of second quarter 2011 decisions to sell IPH
and to exit the heavy haul and specialized shipment and
transportation of wind turbine components business. The Company
reached an agreement to sell IPH on May 6, 2011. The
reclassifications had no impact on the Company’s total
assets, consolidated net income or cash flows for the three and six
months ended June 30, 2010.
In
2011 management reported Minnesota Conservation Improvement Program
(MNCIP) incentives in Operating Revenues – Electric rather
than Other Income as they had been classified prior to 2011. The
Company has corrected this classification resulting in the
following increases in Operating Revenues and Operating Income and
decreases in Other Income:
The
correction had no impact on the Company’s net income, total
assets, or operating cash flows for the three and six months ended
June 30, 2010.
Inventories
Inventories
consist of the following:
Goodwill
The
following table summarizes changes to goodwill by business segment
during 2011:
Other Intangible Assets
The
following table summarizes the components of the Company’s
intangible assets at June 30, 2011 and
December 31, 2010:
Comprehensive Income
Supplemental Disclosures of Cash Flow Information
|
Class B Stock Options of Subsidiary
|
6 Months Ended |
---|---|
Jun. 30, 2011
|
|
Class B Stock Options of Subsidiary |
11. Class B Stock Options of Subsidiary
In
conjunction with the sale of IPH on May 6, 2011, all 363
outstanding IPH Class B common share options were cancelled by
mutual agreement between the issuer and the holders of the options
and a liability to the holders of the options was established based
on the fair value of the options on May 6, 2011. The liability was
assumed by the new owner of IPH. The options were adjusted to their
fair value based on the fair value of an underlying share of Class
B Common Stock of $2,973.90 per share on May 6, 2011. The book
value of IPH Class B common share options prior to their
cancellation on May 6, 2011 was based on an IPH Class B common
share value of $2,085.88 per share. The $322,000 difference between
the fair value and book value of the options was charged to
retained earnings and earnings available for common shares were
reduced by $322,000 in the second quarter of 2011.
|
Recognized but Unrealized Net Gains on the Forward Energy and Capacity Purchases and Sales Expected to be Realized on Settlement (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
---|---|
Net Gain | $ 646 |
3rd Quarter 2011
|
|
Net Gain | 32 |
4th Quarter 2011
|
|
Net Gain | 145 |
2012
|
|
Net Gain | $ 469 |
Amounts of Commitments for OTP's Capacity and Energy Requirements (Detail) (Otter Tail Power Company, USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Capacity and Energy Requirements
|
||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
2011 | $ 21,268 | $ 20,134 |
2012 | 25,025 | 21,637 |
2013 | 21,868 | 16,492 |
2014 | 24,701 | 15,388 |
2015 | 18,915 | 12,307 |
Beyond 2015 | 78,879 | 78,879 |
Total | 190,656 | 164,837 |
Increase | ||
2011 | 1,134 | |
2012 | 3,388 | |
2013 | 5,376 | |
2014 | 9,313 | |
2015 | 6,608 | |
Beyond 2015 | ||
Total | 25,819 | |
Coal and Freight Purchase Commitments
|
||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
2011 | 52,819 | 47,122 |
2012 | 48,692 | 34,958 |
2013 | 9,855 | 9,855 |
2014 | 9,854 | 9,854 |
2015 | 9,854 | 9,854 |
Beyond 2015 | 4,106 | 4,106 |
Total | 135,180 | 115,749 |
Increase | ||
2011 | 5,697 | |
2012 | 13,734 | |
Beyond 2015 | ||
Total | $ 19,431 |
Discontinued Operations (Tables)
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Results of Discontinued Operations | Following
are summary presentations of the results of discontinued operations
for the three and six month periods ended June 30, 2011 and 2010
and of the major components of assets and liabilities of
discontinued operations as of June 30, 2011 and December 31,
2010:
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Major Components of Assets and Liabilities of Discontinued Operations |
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Pro forma Summary Presentations of the Company's Consolidated Income Statements Reflecting the Classification of IPH's Results as Discontinued |
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Discontinued Operations
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2011
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Discontinued Operations |
17. Discontinued Operations
On
May 6, 2011, the Company completed the sale of IPH to affiliates of
Novacap Industries III, L.P. for approximately $87.0 million
in cash. The proceeds from the sale, net of $3.0 million deposited
in an escrow account, were used to pay down borrowings under the
Otter Tail Corporation Credit Agreement. In the second quarter of
2011, Wylie decided to exit its heavy haul/specialized shipment and
transportation of wind turbine components business, determining
that the risks associated with continuing to provide these services
outweighed any potential profits to be derived from these
operations. The financial position, results of operations, and cash
flows of IPH and Wylie’s specialized shipment and
transportation of wind turbine components business are reported as
discontinued operations in the Company’s consolidated
financial statements as of June 30, 2011 and December 31, 2010, and
for the three and six month periods ended June 30, 2011 and 2010.
Following are summary presentations of the results of discontinued
operations for the three and six month periods ended June 30, 2011
and 2010 and of the major components of assets and liabilities of
discontinued operations as of June 30, 2011 and December 31,
2010:
Because
IPH was a material subsidiary, the Company is providing the
following pro forma summary presentations of its consolidated
income statements for the years ended December 31, 2010 and 2009,
reflecting the classification of IPH’s results as
discontinued operations:
|
Summary of Costs Incurred and Billings and Estimated Earnings Recognized on Uncompleted Contracts (Detail) (USD $)
In Thousands |
Jun. 30, 2011
|
Dec. 31, 2010
|
---|---|---|
Uncompleted Contracts [Line Items] | ||
Costs Incurred on Uncompleted Contracts | $ 464,849 | $ 460,125 |
Less Billings to Date | (418,120) | (430,471) |
Plus Estimated Earnings Recognized | 22,085 | 31,231 |
Net Costs Incurred in Excess of Billings and Accrued Revenues on Uncompleted Contracts | $ 68,814 | $ 60,885 |
Income Tax Expense (Benefit) - Continuing Operations Effective Income Tax Rate (Detail) (USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2011
|
Jun. 30, 2010
|
Jun. 30, 2011
|
Jun. 30, 2010
|
|
Income Taxes [Line Items] | ||||
Income (Loss) Before Income Taxes - Continuing Operations | $ 6,535 | $ (24,044) | $ 13,717 | $ (18,833) |
Income Tax Expense (Benefit) - Continuing Operations | 537 | (7,769) | 2,085 | (6,018) |
Effective Income Tax Rate - Continuing Operations | 8.20% | 32.30% | 15.20% | 32.00% |
Income (Loss) Before Income Taxes - Continuing Operations, Variance | 30,579 | 32,550 | ||
Income Tax Expense (Benefit) - Continuing Operations, Variance | $ 8,306 | $ 8,103 |
Breakdown of the Assignment of the Company's Consolidated Short-term and Long-term Debt Outstanding (Parenthetical) (Detail)
|
6 Months Ended | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Mar. 18, 2011
|
Jun. 30, 2011
Senior Unsecured Notes 6.63%, due December 1, 2011
|
Jun. 30, 2011
Pollution Control Refunding Revenue Bonds, Variable, 2.10% at June 30, 2011, due December 1, 2012
|
Jun. 30, 2011
9.000% Notes, due December 15, 2016
|
Jun. 30, 2011
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
|
Jun. 30, 2011
Grant County, South Dakota Pollution Control Refunding Revenue Bonds 4.65%, due September 1, 2017
|
Jun. 30, 2011
Senior Unsecured Note 8.89%, due November 30, 2017
|
Jun. 30, 2011
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
|
Jun. 30, 2011
Mercer County, North Dakota Pollution Control Refunding Revenue Bonds 4.85%, due September 1, 2022
|
Jun. 30, 2011
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
|
Jun. 30, 2011
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
|
Jun. 30, 2011
Other Obligations - Various up to 13.31% at June 30, 2011
|
|
Long-Term Debt, Interest Rate | 2.54% | 6.63% | 2.10% | 9.00% | 5.95% | 4.65% | 8.89% | 6.15% | 4.85% | 6.37% | 6.47% | 13.31% |
Long-Term Debt, Due Date | Dec. 01, 2011 | Dec. 01, 2012 | Dec. 15, 2016 | Aug. 20, 2017 | Sep. 01, 2017 | Nov. 30, 2017 | Aug. 20, 2022 | Sep. 01, 2022 | Aug. 20, 2027 | Aug. 20, 2037 | Jun. 30, 2011 |