Business Description and Significant Accounting Policies Business Description (Policies)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Segment Reporting, Policy [Policy Text Block]

Business Description

Black Hills Corporation is a diversified energy company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, operates in two primary business groups: Utilities and Non-regulated Energy.

The Utilities Group includes our Electric Utilities and Gas Utilities segments. Electric Utilities include the operating results of the regulated electric utility operations of Black Hills Power and Colorado Electric, and the electric and natural gas utility operations of Cheyenne Light, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility services to Cheyenne, Wyoming and vicinity. Gas Utilities consist of the operating results of the regulated natural gas utility operations of Colorado Gas, Nebraska Gas, Iowa Gas, and Kansas Gas all doing business as Black Hills Energy.

The Non-regulated Energy Group includes our Oil and Gas, Power Generation and Coal Mining segments. Oil and Gas, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities located in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. Power Generation, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Coal Mining, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. These businesses are aggregated for reporting purposes as Non-regulated Energy.

In January 2012, we entered into a definitive agreement to sell Enserco, our non-regulated Energy Marketing segment, which resulted in this segment being reported as discontinued operations. Our Energy Marketing segment engages in marketing natural gas, crude oil, coal, power and environmental products in the United States and Canada. See Notes 23 and 25 for additional information.

For further descriptions of our reportable business segments, see Note 17.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Management evaluates its estimates and related assumptions regularly, including, but not limited to, those related to the market value of derivatives, intangible asset valuations and useful lives, long-lived asset values and useful lives, proved oil and gas reserve volumes, actuarially determined employee benefit costs, valuation of deferred taxes and contingencies. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Consolidation, Policy [Policy Text Block]

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 17.

Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in the jointly owned Black Hills Power transmission tie, the Wyodak power plant, the Wygen I power plant, the Wygen III power plant, and the BHEP gas processing plant. See Note 7 for additional information.

As a result of the pending sale of our Energy Marketing segment, amounts associated with this segment have been reclassified as discontinued operations on the accompanying Consolidated Financial Statements. See note 23 for additional information.

Restatement - Subsequent to the issuance of the Company's 2010 consolidated financial statements, the Company's management determined that certain intercompany transactions with our rate regulated operations had not been properly eliminated in consolidation, resulting in an overstatement of Utility and Non-regulated revenue and Fuel, purchased power and cost of gas sold of $59.6 million and $57.5 million in aggregate for the year ended December 31, 2010 and December 31, 2009, respectively.  As such, the Consolidated Financial Statements have been restated for the correction of this error.  The error did not have an impact on our gross margin, net income, total assets or cash flows.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents and Restricted Cash

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

The Black Hills Wyoming project financing requires that cash accounts are maintained for various specified purposes. We do not readily have access to these accounts and can only withdraw funds upon meeting certain requirements. Therefore, we have classified these amounts as restricted cash.

Trade and Other Accounts Receivable, Policy [Policy Text Block]

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable for our Utilities Group consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Non-regulated Energy Group consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity.

Our Utilities Group utilizes master netting agreements which consists of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.

We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer's inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered. Sales tax collected from our customers is recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on systematic meter readings throughout a month. Meters that are not read during a given month are estimated and trued-up to actual use in a future period. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and the corresponding unbilled revenue is recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.

For long-term power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition for regulated operations, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition for a regulated operation, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.

Inventory, Policy [Policy Text Block]

Natural gas in storage at our regulated Gas Utilities primarily represents gas purchased for use by our customers. All of our Materials, supplies and fuel are valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, results in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property are charged to operations as incurred.

Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, a unit-of-production methodology based on plant hours run is used.

Industry Specific Policies, Oil and Gas [Policy Text Block]

Oil and Gas Operations

We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized.

Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement which varies in length.

Under the full cost method, net capitalized costs are subject to a ceiling test which limits these costs to the present value of future net cash flows discounted at 10%, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the net capitalized costs. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost "ceiling" at period end, a permanent non-cash write-down would be charged to earnings in that period. No ceiling test write-down was recorded in 2011 or 2010. As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment. See Note 12 for additional information.

The SEC definition of "reliable technology" permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We elected to include PUDs of only one location away from a producing well in our volume reserve estimate. See information on our oil and gas drilling activities in Note 21.

Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report on these additional reserve categories.

Goodwill and Intangible Assets, Policy [Policy Text Block]

Goodwill and Intangible Assets

Under accounting standards for goodwill and intangible assets, goodwill and intangible assets with indefinite lives are not amortized but the carrying values are reviewed at least annually for impairment. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform this annual review of goodwill and intangible assets during the fourth quarter of each year (or more frequently if impairment indicators arise).

We performed our annual goodwill impairment tests during the fourth quarter. We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method, and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, and long-term earnings and merger multiples for comparable companies. We believe that the goodwill amount reflects the value of the relatively stable, long-lived cash flows of the regulated gas utility business, considering the regulatory environment and market growth potential and the value of the significant rate base growth opportunities at our electric utility in Colorado.

Asset Retirement Obligations, Policy [Policy Text Block]

Asset Retirement Obligations

We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method. Additional information is included in Note 10.

Fair Value of Financial Instruments, Policy [Policy Text Block]

Fair Value Measurements

Accounting standards for fair value measurements and accounting for compensation - retirement benefits require, among other things, disclosures regarding assets and liabilities carried at fair value and also provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As permitted under accounting standards for fair value measurements, we utilize a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing a significant portion of the assets and liabilities measured and reported at fair value.

Disclosures are required based on a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). We are able to classify fair value balances based on the observability of inputs.

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities and listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management's best estimate of fair value using their own judgments about the assumptions a market participant would use in pricing the asset or liability.

We utilize several different valuation techniques to measure the fair value of assets and liabilities.

• Commodity derivatives - Oil and Gas: Our derivative option contracts are valued under the income approach using option pricing models based on data either readily observable in public markets, derived from public markets or provided by counterparties who regularly trade in public markets. Our derivative swap contracts are valued under the income approach using a discounted cash flow model based on data either readily observable or derived from public markets.

• Commodity derivatives - Utilities: Our gas hedge portfolio for our Utilities generally consists of futures, basis swaps and option contracts. The fair value of these financial instruments is estimated based on market trading information, where available. Absent published market values for an instrument or other asset, management uses observable market data to arrive at its estimates of fair value. These contracts have been classified as Level 2 measurements.

• Interest rate swaps: The fair value of our interest rate swap contracts are determined using standard valuation models. The significant inputs used in these models are readily available in public markets or can be derived from observable market transactions and; therefore, these derivative contracts have been classified as Level 2. Inputs used in these standard valuation models include the applicable market forward rates and discount rates.

Additional information is included in Note 4.

Derivatives, Policy [Policy Text Block]

Derivatives and Hedging Activities

The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value, and that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when we believe a legal right of offset exists.

Accounting standards for derivatives and hedging require that the unrealized gains or losses on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting unrealized loss or gain on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument must be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Debt, Policy [Policy Text Block]

Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the term of the related debt.

Property, Plant and Equipment, Preproduction Design and Development Costs [Policy Text Block]

Development Costs

According to accounting standards for business combinations, we expense, when incurred, development and acquisition costs associated with corporate development activities prior to acquiring or beginning construction of a project. Expensed development costs are included in Other operating expenses on the accompanying Consolidated Statements of Income.

Legal Costs, Policy [Policy Text Block]

Legal Costs

Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred, and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred.

Public Utilities, Policy [Policy Text Block]

Regulatory Accounting

Our Utilities Group is subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses.

Our financial statements follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various jurisdictions regulating the utilities. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply. Our regulatory assets represent amounts for which we will recover the cost, but are not allowed a return. In the event we determine that Black Hills Power, Cheyenne Light, Colorado Gas, Colorado Electric, Nebraska Gas, Iowa Gas or Kansas Gas no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to the Company could be an extraordinary non-cash charge to operations, which could be material.

We had the following regulatory assets and liabilities (in thousands):

	Maximum Recovery or	As of		As of
	Settlement Period (in years)	December 31, 2011		December 31, 2010
Regulatory assets
Deferred energy and fuel costs adjustments - current	1	$	33,526	$	30,298
Deferred gas cost adjustments and gas price derivatives	1	26,208		39,407
AFUDC	45	12,482		13,391
Employee benefit plans	13	120,708		83,144
Environmental	subject to approval	1,770		2,353
Asset retirement obligations	44	3,097		3,066
Bond issue cost	25	3,704		3,847
Renewable energy standard adjustment	5	20,095		14,254
Flow through accounting	35	12,191		7,491
Other regulatory assets	various	8,349		7,583
		$	242,130	$	204,834
Regulatory liabilities
Deferred energy and gas costs	1	$	16,961	$	1,200
Employee benefit plans	13	59,455		36,155
Cost of removal	44	42,257		39,638
Revenue subject to refund	1	443		1,016
Other regulatory liabilities	various	5,332		10,545
		$	124,448	$	88,554

Regulatory assets represent items we expect to recover from customers through probable future rates.

Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our electric utility customers in excess of current rates and which will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission.

Deferred Gas Cost Adjustment and Gas Price Derivatives - Our regulated gas utilities have PGA provisions that allow them to pass the cost of gas on to their customers. In addition, as allowed by state utility commissions, we have entered into certain exchange-traded natural gas futures and options to reduce our customers' underlying exposure to fluctuations in gas prices. Cheyenne Light files monthly with the WPSC a GCA to be included in tariff rates. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts.

AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator's action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plans and post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income, including costs being amortized from the Aquila Transaction.

Environmental - Environmental is associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown.

Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 10 for additional details.

Bond Issue Costs - Bond issue costs are recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.

Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers' bills.

Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached with respect to Black Hills Power in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Deferred Energy and Gas Costs - Deferred energy costs related to over-recovery in purchased power, transmission and natural gas costs charged to Cheyenne Light customers through a PCA and GCA mechanism.

Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement aspect of a rate regulated environment.

Cost of Removal - Cost of removal for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal. Liabilities will be settled and trued up following completion of the related activities.

Revenues Subject To Refund - Revenues subject to refund represent a portion of the revenues collected from customers based on approved interim rates which are contingent on the outcome of final rate orders.

Income Tax, Policy [Policy Text Block]

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Income taxes for consolidated subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss.

We use the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities.

It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify.  Another acceptable accounting method and an exception to this general policy currently in our regulated businesses is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property which gave rise to the credits. 

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income.

We account for uncertainty in income taxes recognized in the financial statements in accordance with accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. See Note 14 for additional information.

Earnings Per Share, Policy [Policy Text Block]

Earnings per Share of Common Stock

Basic earnings per share from continuing operations is computed by dividing Income (loss) from continuing operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share gives effect to all dilutive potential common shares outstanding during a period.

Discontinued Operations, Policy [Policy Text Block]

Discontinued Operations

Assets of discontinued operations are recorded at the lower of their carrying amount or fair value less cost to sell. Additionally, in accordance with GAAP, indirect corporate costs previously allocated to a disposal group cannot be reclassified to discontinued operations. As of December 31, 2011, Assets of discontinued operations and Liabilities of discontinued operations on the accompanying Consolidated Balance Sheets included the assets and liabilities of Enserco Energy, Inc. See Note 23 for additional information.