View Filing Data

492,147

407,066

574,989

Non-regulated energy operations and maintenance

261,919

242,367

247,496

83,762

85,830

93,453

(29,129)

^[1]

141,217

154,632

135,591

Taxes - property, production and severance

26,868

^[2]

40,012

40,487

33,710

Other operating expenses

1,243

2,052

710

Total operating expenses

1,020,300

930,173

1,085,949

Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)

255,552

243,711

186,239

Interest charges -

(113,979)

(117,754)

(116,684)

Allowance for funds used during construction - borrowed

1,130

3,462

14,041

Capitalized interest

1,061

682

11,260

30,169

1,882

(42,010)

Allowance for funds used during construction - equity

1,723

1,957

2,017

607

540

932

Other expense

(694)

(71)

(817)

Other income

1,971

2,486

2,490

Total other income (expense)

(78,012)

(106,816)

(128,771)

Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes

177,540

136,895

57,468

Equity in earnings (loss) of unconsolidated subsidiaries

(86)

1,121

(61,608)

(48,400)

(18,224)

Income (loss) from discontinued operations, net of tax

115,846

88,505

40,365

(884)

(6,977)

9,365

Income (loss) from continuing operations, per share

$ 114,962

$ 81,528

$ 49,730

Earnings (loss) per share, Basic -

$ 2.62

$ 2.02

$ 1.01

Income (loss) from discontinued operations, per share

(0.02)

(0.16)

0.24

Total income (loss) per share, Basic

2.60

1.86

1.25

Earnings (loss) per share, Diluted -

Income (loss) from continuing operations, per share

2.61

2.01

1.01

Income (loss) from discontinued operations, per share

(0.02)

(0.16)

0.23

Total income (loss) per share, Diluted

$ 2.59

$ 1.85

$ 1.24

Weighted average common shares outstanding:

Basic

44,163

43,820

39,864

Diluted

44,419

44,073

40,081

Utilities Group [Member]

Revenue:

Total revenue

$ 1,191,133

$ 1,064,813

$ 1,155,519

Non Regulated Energy Group [Member]

Revenue:

Total revenue

$ 84,719

$ 109,071

$ 116,669

[1]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[2]	Oil and Gas includes a ceiling test impairment (see Note 12).

Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income (loss) available for common stock	$ 114,962	$ 81,528	$ 49,730
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Benefit plan liability adjustments - net gain (loss) (net of tax of $(3,813), $296 and $4,135, respectively)	8,237	(542)	(7,609)
Benefit plan liability adjustments - prior service (costs) (net of tax of $185, $86 and $176, respectively)	(406)	(157)	(325)
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(971))	1,820	0	0
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $88)	(165)	0	0
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(2,445), $887 and $1,708, respectively)	4,534	(1,268)	(2,831)
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $(2,016), $534 and $(709), respectively)	4,046	(643)	1,468
Other comprehensive income (loss), net of tax	18,066	(2,610)	(9,297)
Comprehensive income (loss)	133,028	78,918	40,433
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent, Parenthetical Disclosures [Abstract]
Benefit plan liability adjustments - net gain (loss), Tax	(3,813)	296	4,135
Benefit plan liability adjustments - prior service (costs), Tax	185	86	176
Reclassification adjustment of benefit plan liability - net gain (loss) tax	(971)	0	0
Reclassification adjustment of benefit plan liability - prior service cost, tax	88	0	0
Fair value adjustment on derivatives designated as cash flow hedges, Tax	(2,445)	887	1,708
Reclassification adjustment of cash flow hedges settled and included in net income (loss), Tax	$ (2,016)	$ 534	$ (709)

Consolidated Balance Sheets - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

Current assets:

Restricted cash and equivalents

$ 7,841

$ 15,462

7,916

Accounts receivable, net

177,573

163,698

Materials, supplies and fuel

88,478

77,643

Income tax receivable, net

717

3,236

1,460

Deferred income tax assets, net, current

18,889

77,231

Regulatory assets, current

24,451

31,125

Other current assets

25,877

28,795

Total current assets

345,288

405,106

Investments

16,697

16,402

Property, plant and equipment

4,259,445

3,930,772

Less accumulated depreciation and depletion

(1,269,148)

(1,188,023)

2,990,297

2,742,749

Other assets:

Goodwill

353,396

Intangible assets, net

3,397

^[1]

3,620

Regulatory assets, non-current

510

138,197

188,268

Other assets, non-current

27,906

19,420

Total other assets, non-current

522,896

565,214

TOTAL ASSETS

3,875,178

3,729,471

Current liabilities:

Accounts payable

130,416

84,422

Accrued liabilities

151,277

154,389

Regulatory liabilities, current

3,474

96,541

Accrued income tax, net

4,936

10,727

13,628

Current maturities of long-term debt

82,500

277,000

103,973

Total current liabilities

378,394

734,889

Long-term debt, net of current maturities

1,396,948

938,877

Deferred credits and other liabilities:

Deferred income tax liabilities, net, non-current

432,287

385,908

Regulatory liabilities, non-current

5,614

16,941

109,429

127,656

Benefit plan liabilities

111,479

167,397

Other deferred credits and other liabilities

133,279

125,294

Total deferred credits and other liabilities

792,088

823,196

Stockholders’ equity:

Common stock $1 par value; 100,000,000 shares authorized; issued: 44,550,239 and 44,278,189 shares, respectively

44,550

44,278

Additional paid-in capital

742,344

733,095

Retained earnings

540,244

492,869

Treasury stock at cost - 50,877 and 71,782 shares, respectively

(1,968)

(2,245)

Accumulated other comprehensive income (loss)

(17,422)

(35,488)

Total stockholders’ equity

1,307,748

1,232,509

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

$ 3,875,178

$ 3,729,471

[1]	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of the next five years.

Consolidated Balance Sheets Balance Sheet Parantheticals - $ / shares	Dec. 31, 2013	Dec. 31, 2012
Common Stock, Par or Stated Value Per Share	$ 1.00	$ 1.00
Common Stock, Shares, Outstanding	44,499,362	44,206,408
Treasury Stock, Shares	50,877	71,782
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Issued	44,550,239	44,278,189

Consolidated Statements of Cash Flows - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Operating activities:

(Income) loss from discontinued operations, net of tax

$ 114,962

$ 81,528

$ 49,730

884

6,977

(9,365)

Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:

115,846

88,505

40,365

Deferred financing cost amortization

141,217

154,632

135,591

6,763

5,555

5,655

26,868

^[1]

(29,129)

^[2]

Stock compensation

12,595

8,271

5,643

Change in certain operating assets and liabilities:

(30,169)

(1,882)

42,010

Deferred income taxes

63,784

39,716

33,600

Employee benefit plans

22,194

20,973

14,586

Other adjustments, net

9,826

4,929

(5,799)

Materials, supplies and fuel

(5,770)

6,343

(21,385)

Accounts receivable, unbilled revenues and other current assets

(13,921)

13,739

22,290

Accounts payable and other current liabilities

15,336

(10,713)

(31,091)

Contributions to defined benefit pension plans

(12,500)

(25,350)

(11,050)

Other operating activities, net

312

(6,670)

(13,721)

Net cash provided by operating activities of continuing operations

325,513

295,787

216,694

Net cash provided by (used in) operating activities of discontinued operations

(884)

21,184

7,010

Net cash provided by operating activities

324,629

316,971

223,704

Investing activities:

Property, plant and equipment additions

(354,749)

(349,129)

(440,698)

Proceeds from sale of assets

253,791

583

Other investing activities

5,471

(180)

(4,533)

Net cash provided by (used in) investing activities of continuing operations

(349,278)

(95,518)

(444,648)

Proceeds from sale of business operations

107,511

Net cash provided by (used in) investing activities of discontinued operations

(824)

(2,359)

Net cash provided by (used in) investing activities

(349,278)

11,169

(447,007)

Financing activities:

Dividends paid on common stock

(67,587)

(65,262)

(59,202)

Common stock issued

4,354

4,726

123,041

Short-term borrowings - issuances

337,650

203,753

1,017,300

Short-term borrowings - repayments

(532,150)

(271,753)

(821,300)

Long-term debt - issuance

800,000

Long-term debt - repayments

(445,906)

(240,077)

(8,382)

De-designated interest rate swap settlement

(63,939)

Other financing activities

(15,394)

(2,833)

(1,666)

Net cash provided by (used in) financing activities of continuing operations

17,028

(371,446)

249,791

Net cash provided by (used in) financing activities of discontinued operations

(158)

Net cash provided by (used in) financing activities

17,028

(371,446)

249,633

Net change in cash and cash equivalents

(7,621)

(43,306)

26,330

Cash and cash equivalents:

Cash and cash equivalents beginning of year

15,462

58,768

^[3]

32,438

^[3]

Cash and cash equivalents end of year

$ 7,841

$ 15,462

58,768

^[3]

Discontinued Operation, Additional Disclosures [Abstract]

Cash and Cash Equivalents of Discontinued Operations

$ 37,000

[1]	Oil and Gas includes a ceiling test impairment (see Note 12).
[2]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[3]	Cash and cash equivalents include cash of discontinued operations of $37 million and $16 million at Dec. 31, 2011 and 2010 respectively.

Consolidated Statement of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Shares, Issued Period Start at Dec. 31, 2010		39,280,048
Stockholders' Equity Attributable to Parent Period Start at Dec. 31, 2010	$ 1,100,270	$ 39,280	$ (309)	$ 598,805	$ 486,075	$ (23,581)
Treasury Stock, Shares, Period Start at Dec. 31, 2010			10,962
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available for common stock	49,730	0	$ 0	0	49,730	0
Other comprehensive income (loss), net of tax	(9,297)	$ 0	$ 0	0	0	(9,297)
Dividends on common stock, shares		0	0
Dividends on common stock	(59,202)	$ 0	$ 0	0	(59,202)	0
Share-based compensation, shares		161,424	21,804
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	5,076	$ 161	$ (661)	5,576	0	0
Tax effect of share-based compensation	(28)	$ 0	$ 0	(28)	0	0
Issuance of common stock, Shares		4,413,519
Issuance of common stock, Value	119,630	$ 4,414		115,216
Dividend reinvestment and stock purchase plan, shares		102,511	0
Dividend reinvestment an stock purchase plan	3,202	$ 103	$ 0	3,099	0	0
Other stock transactions, shares		0	0
Other stock transactions	(45)	$ 0	$ 0	(45)	0	0
Shares, Issued Period End at Dec. 31, 2011		43,957,502
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2011	$ 1,209,336	$ 43,958	$ (970)	722,623	476,603	(32,878)
Treasury Stock, Shares, Period End at Dec. 31, 2011			32,766
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$ 1.46
Net income (loss) available for common stock	$ 81,528	0	$ 0	0	81,528	0
Other comprehensive income (loss), net of tax	(2,610)	$ 0	$ 0	0	0	(2,610)
Dividends on common stock, shares		0	0
Dividends on common stock	(65,262)	$ 0	$ 0	0	(65,262)	0
Share-based compensation, shares		219,946	39,016
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	6,040	$ 220	$ (1,275)	7,095	0	0
Tax effect of share-based compensation	117	$ 0	$ 0	117	0	0
Dividend reinvestment and stock purchase plan, shares		100,741	0
Dividend reinvestment an stock purchase plan	3,382	$ 100	$ 0	3,282	0	0
Other stock transactions, shares		0	0
Other stock transactions	(22)	$ 0	$ 0	(22)	0	0
Shares, Issued Period End at Dec. 31, 2012		44,278,189
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2012	$ 1,232,509	$ 44,278	$ (2,245)	733,095	492,869	(35,488)
Treasury Stock, Shares, Period End at Dec. 31, 2012	71,782		71,782
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$ 1.48
Net income (loss) available for common stock	$ 114,962	0	$ 0	0	114,962	0
Other comprehensive income (loss), net of tax	18,066	$ 0	$ 0	0	0	18,066
Dividends on common stock, shares		0	0
Dividends on common stock	(67,587)	$ 0	$ 0	0	(67,587)	0
Share-based compensation, shares		190,172	(20,905)
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	5,867	$ 190	$ 277	5,400	0	0
Tax effect of share-based compensation	410	$ 0	$ 0	410	0	0
Dividend reinvestment and stock purchase plan, shares		66,878	0
Dividend reinvestment an stock purchase plan	3,129	$ 67	$ 0	3,062	0	0
Other stock transactions, shares		(15,000)	0
Other stock transactions	392	$ 15	$ 0	377	0	0
Shares, Issued Period End at Dec. 31, 2013		44,550,239
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2013	$ 1,307,748	$ 44,550	$ (1,968)	$ 742,344	$ 540,244	$ (17,422)
Treasury Stock, Shares, Period End at Dec. 31, 2013	50,877		50,877
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$ 1.52

Business Description and Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Business Description and Significant Accounting Policies [Text Block]

BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

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, Wyo. 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.

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

On Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. See Note 21 for additional information.

For further descriptions of our reportable business segments, see Note 4.

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. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled 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 inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company revenues, see Note 4.

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 any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 3 for additional information.

As a result of the 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 21 for additional information.

Cash and Cash Equivalents

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

Restricted Cash and Equivalents

The Black Hills Wyoming project financing required that we maintain cash accounts for various specified purposes. We did not readily have access to these accounts and could only withdraw funds upon meeting certain requirements. Therefore, we had classified these amounts as restricted cash. This project financing was repaid in 2013.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable for our Utilities Group primarily 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.

We maintain an allowance for doubtful accounts which reflects our estimate of 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.

We utilize master netting agreements which consist 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.

Following is a summary of accounts receivable as of Dec. 31 (in thousands):



2013	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	52,437	$	23,823	$	(666	)	$	75,594
Gas Utilities	49,162		41,195		(558		)	89,799
Power Generation	1,722		—		—			1,722
Coal Mining	1,711		—		—			1,711
Oil and Gas	8,156		—		(13		)	8,143
Corporate	604		—		—			604
Total	$	113,792	$	65,018	$	(1,237	)	$	177,573



2012	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	54,482	$	23,843	$	(527	)	$	77,798
Gas Utilities	31,495		39,962		(222		)	71,235
Power Generation	16		—		—			16
Coal Mining	2,247		—		—			2,247
Oil and Gas	11,622		—		(19		)	11,603
Corporate	799		—		—			799
Total	$	100,661	$	63,805	$	(768	)	$	163,698

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and 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. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month, and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.

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

Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of (in thousands):



	Dec. 31, 2013		Dec. 31, 2012
Materials and supplies	$	50,196	$	43,397
Fuel - Electric Utilities	6,213		8,589
Natural gas in storage held for distribution	32,069		25,657
Total materials, supplies and fuel	$	88,478	$	77,643

Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas, and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas 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

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 regulated utility 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 regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility 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 plus cost of removal, 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, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various class of property. 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.

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 typically treated as adjustments to the cost of the properties with no gain or loss recognized. However, we recognized a gain on the sale of a majority of our Williston Basin assets in 2012. See Note 21 for further discussion.

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 an SEC required rate, 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. As a result of lower natural gas prices, we recorded a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment in 2012. No ceiling test write-down was recorded in 2013 or 2011. 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 20.

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

Goodwill and intangible assets with indefinite lives are not amortized but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform this annual review of goodwill and indefinite lived intangible assets as of Nov. 30 each year (or more frequently if impairment indicators arise).

We performed our annual goodwill impairment tests as of Nov. 30, 2013. 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.

Goodwill at our Electric and Gas Utilities primarily arose from the acquisition of one regulated electric and four regulated gas utilities in the Aquila Transaction. This goodwill from the Aquila Transaction was allocated approximately $246 million, or 72 percent, to Colorado Electric and $94 million, or 28 percent, to the Gas Utilities. 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 long-lived cash flow and rate base growth opportunities at our electric utility in Colorado. Goodwill balances were as follows (in thousands):



	Electric Utilities		Gas Utilities		Power Generation		Total
Ending balance at Dec. 31, 2011	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2012	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2013	$	250,487	$	94,144	$	8,765	$	353,396

Our intangible assets represent easements, rights-of-way and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized over 20 years. Changes to intangible assets for the years ended Dec. 31, were as follows (in thousands):



	2013			2012			2011
Intangible assets, net, beginning balance	$	3,620		$	3,843		$	4,069
Additions (adjustments)	—			—			—
Amortization expense *	(223		)	(223		)	(226		)
Intangible assets, net, ending balance	$	3,397		$	3,620		$	3,843

_________________


*	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of the next five years.

Asset Retirement Obligations

Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.

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 our non-regulated operations, other than Oil and Gas. 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 7.

Fair Value Measurements

Derivative Financial Instruments

Assets and liabilities are classified and disclosed in one of the following fair value 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 or 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 its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

Oil and Gas Segment:


•	The commodity option contracts for the Oil and Gas segment are valued under the market approach and include calls and puts. Fair value was derived using quoted prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure.


•	The commodity basis swaps for the Oil and Gas segment are valued under the market approach using the instrument’s current forward price strip hedged for the same quantity and date and discounted based on the three-month LIBOR. We utilize observable inputs which support Level 2 disclosure.

Utilities Segment:

•

The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant since these instruments are not traded on an exchange.

Corporate Segment:

•

The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

Additional information is included in Note 9.

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 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.

Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the estimated useful life of the related debt.

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

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.

When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. If the loss contingency at issue is not both probable and reasonably estimable, we do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable.

Regulatory Accounting

Our Utilities Group follows accounting standards for regulated operations and reflects the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. 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. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which would require these net assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

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



	Maximum
	Amortization	As of		As of
	(in years)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)	1	$	16,775	$	16,005
Deferred gas cost adjustments and gas price derivatives^(a)	7	12,366		20,741
AFUDC^(b)	45	12,315		12,416
Employee benefit plans ^(c)	13	67,059		115,521
Environmental^(a)	subject to approval	1,800		1,792
Asset retirement obligations^(a)	44	3,266		3,247
Bond issue cost^(a)	24	3,419		3,561
Renewable energy standard adjustment ^(a)	5	14,186		19,484
Flow through accounting^(d)	35	20,916		16,620
Other regulatory assets^(a)	15	10,546		10,006
		$	162,648	$	219,393

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	11,708	$	21,091
Employee benefit plans^(e)	13	34,431		59,362
Cost of removal^(a)	44	64,970		53,526
Other regulatory liabilities^(f)	25	9,047		7,305
		$	120,156	$	141,284

__________


(a)	Recovery of costs, but not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery of costs, we are allowed a return on approximately $25 million.


(d)	In addition to recovery of costs, we are allowed a return on approximately $5.4 million.


(e)	Approximately $13 million is included in our rate base calculations as a reduction to rate base.


(f)	Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.

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 that is either higher or lower than the current rates and 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 GCA provisions that allow them to pass the cost of gas on to their customers. In addition, as allowed or required 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. 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 with state utility commissions.

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 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 7 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 and gas costs related to over-recovery of purchased power, transmission and natural gas costs.

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 represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each tax paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments 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 as allowed by our rate-regulated jurisdictions. 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.

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 of Common Stock

Basic earnings per share from continuing and discontinued operations is computed by dividing Income (loss) from continuing or discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to outstanding stock options, restricted stock and performance shares under our equity compensation plans.

A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):



	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Income (loss) from continuing operations	$	115,846	$	88,505	$	40,365

Weighted average shares - basic	44,163		43,820		39,864
Dilutive effect of:
Equity compensation	256		250		214
Other	—		3		3
Weighted average shares - diluted	44,419		44,073		40,081

Income (loss) from continuing operations, per share - Diluted	$	2.61	$	2.01	$	1.01

The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):



	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity compensation	22	163	141
Other	—	—	—
Anti-dilutive shares excluded from computation of earnings (loss) per share	22	163	141

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. 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 21 for additional information.

Recently Adopted Accounting Standards

Inclusion of the Fed Funds Effective Swap Rate as a Benchmark Interest Rate for Hedge Accounting Purposes, ASU 2013-10

In July 2013, the FASB issued an amendment to accounting for derivatives and hedges to permit the Fed Funds Effective Swap Rate to be used as a U.S. benchmark interest rate for hedge accounting purposes effective for new or re-designated hedging relationships entered into on or after July 17, 2013. The amendment also removed the restriction on using different benchmark rates for similar hedges. The adoption had no impact on our consolidated financial position, results of operations or cash flows.

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, ASU 2013-01

In December 2011, the FASB issued revised accounting guidance to amend ASC 210, Balance Sheet, related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company’s netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance was effective on a retrospective basis for interim and annual periods beginning Jan. 1, 2013. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and Deferral of the Effective Date for Amendments to the Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending accounting standards for comprehensive income to improve the comparability, consistency and transparency of reporting. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU 2011-05 requires retrospective application, and it was effective for fiscal years, and interim periods within those years, beginning after Dec. 15, 2011, with early adoption permitted. In Dec. 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income. Ultimately FASB chose not to reinstate the reclassification adjustment requirements in ASU 2011-05 but instead issued ASU 2013-02 in February 2013. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, ASU 2013-02

In February 2013, the FASB issued new disclosure requirements for items reclassified out of AOCI to expand the disclosure requirements in ASC 220, Comprehensive Income, for presentation of changes in AOCI. ASU 2013-02 requires disclosure (1) of changes in components of other comprehensive income, (2) for items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) of cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2012. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 33-9286, 33-9338, 34-67717, and 34-67716

In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition, many of the transactions which were previously classified as swaps have been converted to exchange-traded futures contracts, which are subject to futures margin posting requirements.

In August 2012, under Dodd-Frank, the SEC adopted new requirements for companies that manufacture or contract to manufacture products that contain certain minerals and metals, known as conflict minerals. The final rule requires all issuers that file reports with the SEC and use conflict minerals to report supply chain and sourcing information on an annual basis. We completed due diligence efforts in 2013, and we do not believe that our products contain conflict minerals as defined by the rule.

Recently Issued Accounting Pronouncements and Legislation

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, ASU 2013-11

In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after Dec. 15, 2013, and interim periods within those years and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard is not expected to have an impact on our financial position, results of operations or cash flows.

Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, ASU 2013-04

In March 2013, the FASB issued new disclosure requirements for recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements including disclosure of the nature and amount of the obligations. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2013. The amendment requires enhanced disclosures in the notes to financial statements, but will not have any other impact on our consolidated financial statements.

Final Tangible Personal Property Regulations, IRS Treasury Decision 9636

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations have the effect of a change in law and as a result the impact should be taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after Jan. 1, 2014, with early adoption permitted. We expect that implementation of most, if not all, of the provisions of the final regulations in 2014. Procedural guidance is expected from IRS in early 2014 to facilitate implementation. Analysis performed to date indicates no material impact to our consolidated financial statements.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure [Text Block]

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at Dec. 31 consisted of the following (dollars in thousands):



Utilities Group	2013			2012			Lives ( in years)
Electric Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Electric plant:
Production	$	951,138	45	$	959,636	45	25	65
Electric transmission	238,542		50	234,279		50	40	65
Electric distribution	666,589		44	631,654		44	15	65
Plant acquisition adjustment ^(a)	4,870		32	4,870		32	32	32
General	138,263		22	137,584		22	3	60
Capital lease - plant in service ^(b)	261,441		20	260,874		19	20	20
Total electric plant in service	$	2,260,843		$	2,228,897
Construction work in progress	203,760			48,008
Total electric plant	2,464,603			2,276,905
Less accumulated depreciation and amortization	472,970			439,772
Electric plant net of accumulated depreciation and amortization	$	1,991,633		$	1,837,133

_____________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 17 years remaining.


(b)	Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on Dec. 31, 2031.



	2013			2012			Lives (in years)
Gas Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Gas plant:
Production	$	13	37	$	13	37	37	37
Gas transmission	24,984		54	18,071		54	53	57
Gas distribution	507,318		46	474,998		46	41	56
General	85,841		19	68,856		19	16	22
Total gas plant in service	618,156			561,938
Construction work in progress	9,417			6,305
Total gas plant	627,573			568,243
Less accumulated depreciation and amortization	84,679			68,530
Gas plant net of accumulated depreciation and amortization	$	542,894		$	499,713



2013											Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	143,026	$	10,491	$	153,517	$	43,069	$	110,448	36	2	40
Coal Mining	149,067		1,156		150,223		86,306		63,917		14	2	59
Oil and Gas	852,384		—		852,384		585,334		267,050		24	3	25
	$	1,144,477	$	11,647	$	1,156,124	$	714,709	$	441,415



2012											Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	139,396	$	1,323	$	140,719	$	38,541	$	102,178	35	2	40
Coal Mining	148,045		7,023		155,068		80,210		74,858		14	2	59
Oil and Gas	785,594		—		785,594		562,926		222,668		24	3	25
	$	1,073,035	$	8,346	$	1,081,381	$	681,677	$	399,704



2013												Lives ( in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	5,498	$	5,647	$	11,145	$	(3,210	)	$	14,355	6	2	30

___________


(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.



2012												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	368	$	3,875	$	4,243	$	(1,956	)	$	6,199	6	2	30

___________


(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.

Jointly Owned Facilities

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Jointly Owned Facilities [Text Block]

JOINTLY OWNED FACILITIES

Utility Plant

Our consolidated financial statements include our share of several jointly-owned utility facilities as described below. Our share of the facilities expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.

•

Black Hills Power owns a 20 percent interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. Black Hills Power receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying Black Hills Power with coal for its share of the Wyodak Plant, our Coal Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.

•

Black Hills Power also owns a 35 percent interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the tie is 400 megawatts - 200 megawatts West to East and 200 megawatts from East to West. Black Hills Power is committed to pay its proportionate share of the additions and replacements to and operating and maintenance expenses of the transmission tie.

•

Black Hills Power owns 52 percent of the Wygen III coal-fired generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations. Our Coal Mining subsidiary supplies coal to Wygen III for the life of the plant.


•	Colorado Electric owns 50 percent of the Busch Ranch Wind Project while AltaGas owns the remaining undivided ownership interest and is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind project for the life of the facility. We retain responsibility for operations of the wind farm.

Non-Regulated Plants

Our consolidated financial statements include our share of a jointly-owned non-regulated power generation facility as described below. Our share of direct expenses for the jointly-owned facility is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income. Each of the respective owners is responsible for providing its own financing.


•	Black Hills Wyoming owns 76.5 percent of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Coal Mining subsidiary during the life of the facility. We retain responsibility for plant operations.

At Dec. 31, 2013, our interests in jointly-owned generating facilities and transmission systems were (in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,800	$	192	$	50,595
Transmission Tie	$	19,648	$	—	$	4,741
Wygen I	$	106,489	$	1,412	$	28,432
Wygen III	$	131,468	$	713	$	10,593
Busch Ranch Wind Project	$	18,590	$	—	$	841

Business Segments

12 Months Ended

Dec. 31, 2013

Segment Reporting Information, Additional Information [Abstract]

Summary of Information Relating to Segments of our Business

BUSINESS SEGMENTS INFORMATION

Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. All of our operations and assets are located within the United States.

On Feb. 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being reclassified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been classified as discontinued operations have been reclassified to our Corporate segment. For further information see Note 21.

Segment information was as follows (in thousands):



Total Assets (net of inter-company eliminations) as of Dec. 31,	2013		2012
Utilities:
Electric ^(a)	$	2,525,947	$	2,387,458
Gas	805,617		765,165
Non-regulated Energy:
Power Generation^(a)	95,692		119,170
Coal Mining	78,825		83,810
Oil and Gas	288,366		258,460
Corporate	80,731		115,408
Total assets	$	3,875,178	$	3,729,471

__________________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.



Capital Expenditures and Asset Acquisitions^(a) for the years ended Dec. 31,	2013		2012
Utilities:
Electric Utilities	$	222,262	$	167,263
Gas Utilities	63,205		45,711
Non-regulated Energy:
Power Generation	13,533		5,547
Coal Mining	5,528		13,420
Oil and Gas	64,687		107,839
Corporate	10,319		7,376
Total capital expenditures and asset acquisitions of continuing operations	379,534		347,156
Total capital expenditures of discontinued operations	—		824
Total capital expenditures and asset acquisitions	$	379,534	$	347,980

_________________


(a)	Includes accruals for property, plant and equipment.



Property, Plant and Equipment as of Dec. 31,	2013		2012
Utilities:
Electric Utilities ^(a)	$	2,464,603	$	2,276,905
Gas Utilities	627,573		568,243
Non-regulated Energy:
Power Generation ^(a)	153,517		140,719
Coal Mining	150,223		155,068
Oil and Gas	852,384		785,594
Corporate	11,145		4,243
Total property, plant and equipment	$	4,259,445	$	3,930,772

_______________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded for at Colorado Electric under accounting for a capital lease.



	Consolidating Income Statement
Year ended Dec. 31, 2013	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	651,445		$	539,689		$	4,648		$	25,186		$	54,884		$	—		$	—		$	1,275,852
Inter-company revenue	13,863			—			78,389			31,442			—			220,620			(344,314		)	—
Total revenue	665,308			539,689			83,037			56,628			54,884			220,620			(344,314		)	1,275,852

Fuel, purchased power and cost of natural gas sold	294,048			310,463			—			—			—			125			(112,489		)	492,147
Operations and maintenance	159,961			126,073			30,186			39,519			40,365			202,809			(211,977		)	386,936
Gain on sale of operating assets	—			—			—			—			—			—			—			—
Depreciation, depletion and amortization	77,704			26,381			5,091			11,523			21,770			11,624			(12,876		)	141,217
Operating income (loss)	133,595			76,772			47,760			5,586			(7,251		)	6,062			(6,972		)	255,552

Interest expense ^(a)	(61,537		)	(25,234		)	(21,178		)	(641		)	(2,253		)	(85,195		)	84,250			(111,788		)
Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			30,169			—			30,169
Interest income	5,277			976			785			10			1,639			69,760			(76,724		)	1,723
Other income (expense), net	633			(60		)	1			2,304			108			41,453			(42,641		)	1,798
Income tax benefit (expense)	(25,834		)	(19,747		)	(11,080		)	(932		)	3,545			(7,778		)	218			(61,608		)
Income (loss) from continuing operations	$	52,134		$	32,707		$	16,288		$	6,327		$	(4,212	)	$	54,471		$	(41,869	)	$	115,846

________________


(a)	Power Generation includes costs associated with interest rate swaps settled and write-off of deferred financing costs upon repayment of Black Hills Wyoming Project Financing and Corporate includes a the write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt (see Note 5).



	Consolidating Income Statement
Year ended Dec. 31, 2012	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	610,732		$	454,081		$	4,189		$	25,810		$	79,072		$	—		$	—		$	1,173,884
Inter-company revenue	16,234			—			75,200			31,968			—			196,453			(319,855		)	—
Total revenue	626,966			454,081			79,389			57,778			79,072			196,453			(319,855		)	1,173,884

Fuel, purchased power and cost of natural gas sold	273,474			245,349			—			—			—			—			(111,757		)	407,066
Operations and maintenance	146,527			117,390			29,991			42,553			43,267			179,059			(188,051		)	370,736
Gain on sale of operating assets ^(a)	—			—			—			—			(29,129		)	—			—			(29,129		)
Depreciation, depletion and amortization	75,244			25,163			4,599			13,060			38,494			10,936			(12,864		)	154,632
Impairment of long-lived assets^(b)	—			—			—			—			26,868			—			—			26,868
Operating income (loss)	131,721			66,179			44,799			2,165			(428		)	6,458			(7,183		)	243,711

Interest expense ^(c)	(59,194		)	(26,746		)	(15,452		)	(238		)	(4,539		)	(92,650		)	85,209			(113,610		)
Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			1,882			—			1,882
Interest income	8,153			2,765			695			1,168			604			64,695			(76,123		)	1,957
Other income (expense), net	1,182			105			7			2,616			207			48,769			(49,921		)	2,965
Income tax benefit (expense)	(30,264		)	(14,313		)	(8,721		)	(85		)	1,927			3,187			(131		)	(48,400		)
Income (loss) from continuing operations	$	51,598		$	27,990		$	21,328		$	5,626		$	(2,229	)	$	32,341		$	(48,149	)	$	88,505

________________


(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).


(b)	Oil and Gas includes a ceiling test impairment (see Note 12).


(c)	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 5).



	Consolidating Income Statement
Year ended Dec. 31, 2011	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	600,935		$	554,584		$	4,059		$	32,802		$	79,808		$	—		$	—		$	1,272,188
Inter-company revenue	13,396			—			27,613			34,090			—			192,250			(267,349		)	—
Total revenue	614,331			554,584			31,672			66,892			79,808			192,250			(267,349		)	1,272,188

Fuel, purchased power and cost of natural gas sold	310,352			331,961			—			—			—			97			(67,421		)	574,989
Operations and maintenance	142,815			121,980			16,538			56,617			41,380			170,947			(174,908		)	375,369
Gain on sale of operating assets ^(a)	(768		)	—			—			—			—			1			767			—
Depreciation, depletion and amortization	52,475			24,307			4,199			18,670			35,690			11,205			(10,955		)	135,591
Operating income (loss)	109,457			76,336			10,935			(8,395		)	2,738			10,000			(14,832		)	186,239

Interest expense	(53,770		)	(31,621		)	(8,903		)	(9		)	(5,896		)	(93,314		)	102,130			(91,383		)
Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			(42,010		)	—			(42,010		)
Interest income	14,794			5,645			1,529			3,897			2			64,299			(88,149		)	2,017
Other income (expense), net	481			217			1,094			2,192			(216		)	46,510			(46,552		)	3,726
Income tax benefit (expense)	(23,271		)	(16,408		)	(1,644		)	1,891			1,651			19,289			268			(18,224		)
Income (loss) from continuing operations	$	47,691		$	34,169		$	3,011		$	(424	)	$	(1,721	)	$	4,774		$	(47,135	)	$	40,365

_________________


(a)	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Long-term Debt, Unclassified [Abstract]

Long-Term Debt

12 Months Ended

Dec. 31, 2013

Long-term Debt [Text Block]

LONG-TERM DEBT

Long-term debt outstanding was as follows (dollars in thousands) as of:



		Interest Rate at
	Due Date	Dec. 31, 2013	Dec. 31, 2013			Dec. 31, 2012
Corporate
Senior unsecured notes due 2023	Nov. 30, 2023	4.25%	$	525,000		$	—
Senior unsecured notes due 2014^(a)	May 15, 2014	9.00%	—			250,000
Senior unsecured notes due 2020	July 15, 2020	5.88%	200,000			200,000
Corporate term loan due 2013 ^(a)	Sept. 30, 2013	NA	—			100,000
Corporate term loan due 2015 ^(b)	June 19, 2015	1.31%	275,000			—
Total Corporate Debt			1,000,000			550,000

Electric Utilities
First Mortgage Bonds due 2032	Aug. 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	Nov. 1, 2039	6.13%	180,000			180,000
Unamortized discount on First Mortgage Bonds due 2039			(107		)	(111		)
Pollution control revenue bonds due 2024	Oct. 1, 2024	5.35%	12,200			12,200
First Mortgage Bonds due 2037	Nov. 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021, variable rate ^(c)	Sept. 1, 2021	0.11%	7,000			7,000
Industrial development revenue bonds due 2027, variable rate ^(c)	March 1, 2027	0.11%	10,000			10,000
Series 94A Debt, variable rate ^(c)	June 1, 2024	0.75%	2,855			2,855
Total Electric Utilities			396,948			396,944

Power Generation
Black Hills Wyoming project financing, variable rate ^(a)	Dec. 9, 2016	3.59%	—			95,906

Total long-term debt			1,396,948			1,042,850
Less current maturities			—			103,973
Long-term debt, net of current maturities			$	1,396,948		$	938,877

_______________


(a)	This debt repaid. See Debt Transactions discussed below.


(b)	Variable interest rates, based on LIBOR plus a spread.

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2014	$	—
2015	$	275,000
2016	$	—
2017	$	—
2018	$	—
Thereafter	$	1,122,055

Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at Dec. 31, 2013.

Substantially all of the tangible utility property of Black Hills Power and Cheyenne Light is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of Black Hills Power and Cheyenne Light may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by Black Hills Power and Cheyenne Light are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds.

Debt Transactions

On Nov. 19, 2013, we entered into a $525 million, 4.25 percent senior unsecured note expiring on Nov. 30, 2023. The proceeds from this new debt were used to:


•	Redeem our $250 million senior unsecured 9.0 percent notes originally due on May 15, 2014. This repayment occurred on Dec. 19, 2013, for approximately $261 million which included a make-whole provision of approximately $8.5 million and accrued interest which are included in Interest expense on the accompanying Consolidated Statements of Income;


•	Repay our variable interest rate Black Hills Wyoming project financing with a remaining balance of approximately $87 million originally due on Dec. 9, 2016, as well as the interest rate swaps designated to this project financing of $8.5 million which is included in Interest expense on the accompanying Consolidated Statements of Income;


•	Settle the $250 million notional de-designated interest rate swaps for approximately $64 million;


•	Pay down approximately $55 million of the Revolving Credit Facility;


•	Remainder was used for general corporate purposes.

On June 21, 2013, we entered into a new long-term Corporate Term Loan for $275 million expiring on June 19, 2015. The proceeds from this new term loan was used to repay the $150 million term loan due on June 24, 2013, the $100 million corporate term loan due on Sept. 30, 2013, and approximately $25 million in short-term borrowing under our Revolving Credit Facility. The covenants of the new term loan are substantially the same as the Revolving Credit Facility. At Dec. 31, 2013, the cost of borrowing under this new term loan was 1.3125 percent (LIBOR plus a margin of 1.125 percent).

On Oct. 31, 2012, we redeemed $225 million of senior unsecured 6.5 percent notes, which were originally scheduled to mature on May 15, 2013, for approximately $239 million. The payment included accrued interest and a make-whole provision of $7.1 million which are included in Interest expense on the accompanying Consolidated Statements of Income.

Amortization Expense

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):



	Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheets at		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2013		2013		2012		2011
Senior unsecured notes due 2023	$	6,846	$	86	$	—	$	—
Senior unsecured notes due 2014	$	—	$	635	$	462	$	462
Senior unsecured notes due 2020	$	1,093	$	167	$	167	$	167
First mortgage bonds due 2032	$	618	$	33	$	33	$	33
First mortgage bonds due 2039	$	1,961	$	76	$	76	$	76
First mortgage bonds due 2037	$	736	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016^(a)	$	—	$	3,177	$	1,037	$	1,012
Other	$	664	$	57	$	57	$	70

_____________

(a) This project financing was repaid in 2013 and the deferred financing costs were written-off.

Dividend Restrictions

Our credit facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of Dec. 31, 2013, we were in compliance with these covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at Dec. 31, 2013:


•	Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of Dec. 31, 2013, the restricted net assets at our Utilities Group were approximately $88 million.

Notes Payable

12 Months Ended

Dec. 31, 2013

Notes Payable [Abstract]

Notes Payable

NOTES PAYABLE

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of Dec. 31, 2013, we were in compliance with all of these covenants.

We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):



	Balance Outstanding at
	Dec. 31, 2013		Dec. 31, 2012
Revolving Credit Facility	$	82,500	$	127,000
Corporate Term Loan due June 2013	—		150,000
Total	$	82,500	$	277,000

Revolving Credit Facility

On Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017. The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million. The Revolving Credit Facility can be used for the issuance of letters of credit, to fund working capital needs and for other corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.375 percent, 1.375 percent and 1.375 percent, respectively, at Dec. 31, 2013. The facility contains a commitment fee that is charged on the unused amount of the Revolving Credit Facility. Based upon current credit ratings, the fee is 0.25 percent. As of Dec. 31, 2013 and 2012, we had outstanding letters of credit totaling approximately $22 million and approximately $36 million, respectively.

Deferred financing costs on the new facility of $2.8 million are being amortized over the estimated useful life of the Revolving Credit Facility and included in Interest expense on the accompanying Consolidated Statements of Income. Upon entering into the Revolving Credit Facility, $1.5 million of deferred financing costs relating to the previous credit facility were written off through Interest expense. The deferred financing costs on the new facility are being amortized as follows (in thousands):



	Deferred Financing Costs Remaining on Balance Sheets as of		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2013		2013		2012		2011
Revolving Credit Facility	$	1,316	$	752	$	2,187	$	1,891

Debt Covenants

Our Revolving Credit Facility and our new Term Loan require compliance with the following financial covenant at the end of each quarter:

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

ASSET RETIREMENT OBLIGATIONS

We have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in the Oil and Gas segment, reclamation of coal mining sites at the Coal Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment and asbestos at our regulated utilities segments. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials and equipment.

The following tables present the details of ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):



	Dec. 31, 2012		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates^(a)			Dec. 31, 2013
Electric Utilities	$	6,981	$	—	$	—		$	168	$	(227	)	$	6,922
Gas Utilities	259		—		—			15		—			274
Coal Mining	20,286		3		(714		)	1,052		—			20,627
Oil and Gas	23,022		143		(1,903		)	1,450		1,316			24,028
Total	$	50,548	$	146	$	(2,617	)	$	2,685	$	1,089		$	51,851



	Dec. 31, 2011		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates^(a)		Dec. 31, 2012
Electric Utilities	$	3,064	$	3,626	$	—		$	291	$	—	$	6,981
Gas Utilities	270		—		(22		)	11		—		259
Coal Mining	17,158		1,627		—			921		580		20,286
Oil and Gas	22,422		158		(1,059		)	1,345		156		23,022
Total	$	42,914	$	5,411	$	(1,081	)	$	2,568	$	736	$	50,548

_____________________


(a)	The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.

We also have legally required AROs related to certain assets within our electric and gas utility transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a value for the cost of these obligations cannot be measured at this time.

Risk Management Activities

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management Activities

RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1.

Market Risk

Market risk is the potential loss that may occur as a result of an adverse change in market price or rate. We are exposed to the following market risks, including, but not limited to:


•	Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production and fuel procurement for certain of our gas-fired generation assets; and


•	Interest rate risk associated with our variable rate debt and our other short-term and long-term debt instruments.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

As of Dec. 31, 2013, our credit exposure included a $0.5 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 9.

Oil and Gas Exploration and Production

We produce natural gas and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows.

To mitigate commodity price risk and preserve cash flows, we primarily use over-the-counter swaps, exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Consolidated Statements of Income (Loss).

The contract or notional amounts, terms of our commodity derivatives, and the derivative balances for our Oil and Gas segment reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	Dec. 31, 2013				Dec. 31, 2012
	Crude oil futures, swaps and options		Natural gas futures, swaps and options		Crude oil futures, swaps and options		Natural gas futures, swaps and options
Notional ^(a)	412,500		7,082,500		528,000		8,215,500
Maximum terms in years ^(b)	0.25		0.08		1		0.75
Derivative assets, current	$	55	$	—	$	1,405	$	1,831
Derivative assets, non-current	$	—	$	—	$	297	$	170
Derivative liabilities, current	$	—	$	—	$	847	$	507
Derivative liabilities, non-current	$	—	$	—	$	—	$	—

________________________


(a)	Crude in Bbls, gas in MMBtu.


(b)	Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.

Based on Dec. 31, 2013 market prices, a $1.0 million loss would be reclassified from AOCI during 2014. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

Utilities

The operations of our utilities, including power purchase arrangements where our utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices; therefore, as allowed or required, by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. Unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. Accordingly, the hedging activity is recognized in the Consolidated Statements of Income (Loss) or the Consolidated Statements of Comprehensive Income (Loss) when the related costs are recovered through our rates.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Gas Utilities were as follows, as of:



	Dec. 31, 2013		Dec. 31, 2012
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	17,930,000	84	15,350,000	83
Natural gas options purchased	3,890,000	8	2,430,000	2
Natural gas basis swaps purchased	14,785,000	60	12,020,000	72

We had the following derivative balances related to the hedges in our Utilities reflected in our Consolidated Balance Sheets as of (in thousands):



	Dec. 31, 2013		Dec. 31, 2012
Derivative assets, current	$	662	$	—
Derivative assets, non-current	$	—	$	43
Derivative liabilities, current	$	—	$	—
Derivative liabilities, non-current	$	—	$	—
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	7,567	$	9,596

Financing Activities

We entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	Dec. 31, 2013			Dec. 31, 2012
	Interest Rate Swaps ^(a)			Interest Rate Swaps ^(b)			De-designated Interest Rate Swaps^(c)
Notional	$	75,000		$	150,000		$	250,000
Weighted average fixed interest rate	4.97		%	5.04		%	5.67		%
Maximum terms in years	3.0			4.0			1.0
Derivative liabilities, current	$	3,474		$	7,039		$	88,148
Derivative liabilities, non-current	$	5,614		$	16,941		$	—

___________________


(a)	These swaps are designated to borrowings on our Revolving Credit Facility. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps.

(b)

At Dec. 31, 2012, $75 million of these interest rate swaps were designated to borrowings on our Revolving Credit Facility and $75 million were designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps. The portion of the swaps that were designated to Black Hills Wyoming were settled upon repayment of the Black Hills Wyoming project financing. See Note 5.


(c)	Maximum terms in years reflect the amended early termination dates. If the early termination dates were not extended, the swaps would have required cash settlement based on the swap value at the termination date. These swaps were settled during the fourth quarter of 2013.

Based on Dec. 31, 2013 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $3.5 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and realized gains or losses will change during future periods as market interest rates change.

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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Fair Value of Financial Instruments

Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances during 2013 or 2012. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

A discussion of fair value of financial instruments is included in Note 10. The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands):



	As of Dec. 31, 2013
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		130		—		(75		)	55
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		815		—		(815		)	—
Commodity derivatives - Utilities	—		3,030		—		(2,368		)	662
Total	$	—	$	3,975	$	—	$	(3,258	)	$	717

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		1,229		—		(1,229		)	—
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		531		—		(531		)	—
Commodity derivatives - Utilities	—		9,100		—		(9,100		)	—
Interest rate swaps	—		9,088		—		—			9,088
Total	$	—	$	19,948	$	—	$	(10,860	)	$	9,088



	As of Dec. 31, 2012
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	378	$	—	$	—		$	378
Basis Swaps -- Oil	—		1,325		—		—			1,325
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		2,000		—		—			2,000
Commodity derivatives - Utilities	—		—		43		—			43
Total	$	—	$	3,703	$	43	$	—		$	3,746

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	1,131	$	—	$	(336	)	$	795
Basis Swaps -- Oil	—		502		—		(450		)	52
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		1,127		—		(620		)	507
Commodity derivatives - Utilities	—		8,576		—		(8,576		)	—
Interest rate swaps	—		118,088		—		(5,960		)	112,128
Total	$	—	$	129,424	$	—	$	(15,942	)	$	113,482

The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Commodity derivatives - Utilities ^(a)	$	43	Independent price quotes	Long-term natural gas prices - Basis Differential	$	(0.13	)

_____________

(a)

The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.

The following tables present the changes in Level 3 recurring fair value (in thousands):



	As of Dec. 31, 2013			As of Dec. 31, 2012
Assets:	Commodity Derivatives -- Utilities			Commodity Derivatives -- Utilities
Balances as of beginning of period	$	43		$	—
Total gain (loss) included in AOCI/ Regulatory Asset	—			(54		)
Purchases	—			192
Transfers out of Level 3^(a)	(43		)	(95		)
Balances at end of period	$	—		$	43

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	(54	)

__________


(a)	Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Fair Value Measures by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis reflecting the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions. However, the amounts do not include net cash collateral on deposit in margin accounts at Dec. 31, 2013 and 2012, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 8.

The following tables present the fair value and balance sheet classification of our derivative instruments as of Dec. 31, (in thousands):



		2013				2012
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives		Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets - current	$	248	$	—	$	2,874	$	—
Commodity derivatives	Derivative assets - non-current	698		—		510		—
Commodity derivatives	Derivative liabilities - current	—		1,541		—		1,993
Commodity derivatives	Derivative liabilities - non-current	—		219		—		821
Interest rate swaps	Derivative liabilities - current	—		3,474		—		7,038
Interest rate swaps	Derivative liabilities - non-current	—		5,614		—		16,941
Total derivatives designated as hedges		$	946	$	10,848	$	3,384	$	26,793

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	662	$	—	$	362	$	—
Commodity derivatives	Derivative assets - non-current	—		—		—		—
Commodity derivatives	Derivative liabilities - current	—		—		1,180		4,957
Commodity derivatives	Derivative liabilities - non-current	—		6,732		406		5,153
Interest rate swaps	Derivative liabilities - current	—		—		—		94,108
Interest rate swaps	Derivative liabilities - non-current	—		—		—		—
Total derivatives not designated as hedges		$	662	$	6,732	$	1,948	$	104,218

Derivatives Offsetting

It is our policy to offset in our Consolidated Balance Sheets contracts which provide for legally enforceable netting for our accounts receivable and payable and derivative activities.

As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Consolidated Balance Sheets in the following tables include the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at Dec. 31, 2013 and Dec. 31, 2012, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure.

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at Dec. 31, 2013 was as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	$	75	$	(75	)	$	—
Oil and Gas - Crude Options	—		—			—
Oil and Gas - Natural Gas Basis Swaps	815		(815		)	—
Utilities	3,030		(2,368		)	662
Total derivative assets subject to a master netting agreement or similar arrangement	3,920		(3,258		)	662

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	55		—			55
Oil and Gas - Crude Options	—		—			—
Oil and Gas - Natural Gas Basis Swaps	—		—			—
Utilities	—		—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	55		—			55

Total derivative assets	$	3,975	$	(3,258	)	$	717



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	$	1,229	$	(1,229	)	$	—
Oil and Gas - Crude Options	—		—			—
Oil and Gas - Natural Gas Basis Swaps	531		(531		)	—
Utilities	9,100		(9,100		)	—
Interest Rate Swaps	—		—			—
Total derivative liabilities subject to a master netting agreement or similar arrangement	10,860		(10,860		)	—

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	—		—			—
Oil and Gas - Crude Options	—		—			—
Oil and Gas - Natural Gas Basis Swaps	—		—			—
Utilities	—		—			—
Interest Rate Swaps	9,088		—			9,088
Total derivative liabilities not subject to a master netting agreement or similar arrangement	9,088		—			9,088

Total derivative liabilities	$	19,948	$	(10,860	)	$	9,088

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of Dec. 31, 2012 were as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	$	76	$	—		$	76
Oil and Gas - Crude Options	93		—			93
Oil and Gas - Natural Gas Basis Swaps	172		—			172
Utilities	1,629		(1,586		)	43
Total derivative assets subject to a master netting agreement or similar arrangement	1,970		(1,586		)	384

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	1,249		—			1,249
Oil and Gas - Crude Options	285		—			285
Oil and Gas - Natural Gas Basis Swaps	1,828		—			1,828
Utilities	—		—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	3,362		—			3,362

Total derivative assets	$	5,332	$	(1,586	)	$	3,746



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	$	449	$	(449	)	$	—
Oil and Gas - Crude Options	337		(337		)	—
Oil and Gas - Natural Gas Basis Swaps	620		(620		)	—
Utilities	8,576		(8,576		)	—
Interest Rate Swaps	—		—			—
Total derivative liabilities subject to a master netting agreement or similar arrangement	9,982		(9,982		)	—

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	52		—			52
Oil and Gas - Crude Options	795		—			795
Oil and Gas - Natural Gas Basis Swaps	507		—			507
Utilities	—		—			—
Interest Rate Swaps	118,088		(5,960		)	112,128
Total derivative liabilities not subject to a master netting agreement or similar arrangement	119,442		(5,960		)	113,482

Total derivative liabilities	$	129,424	$	(15,942	)	$	113,482

Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of Dec. 31, 2013 were (in thousands):



				Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Assets		Cash Collateral Received		Net Amount with Counterparty
Assets:
Oil and Gas	Counterparty A	$	—	$	—	$	—
Oil and Gas	Counterparty B	55		—		55
Utilities	Counterparty A	662		—		662
		$	717	$	—	$	717



				Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Liabilities		Cash Collateral Paid			Net Amount with Counterparty
Liabilities:
Oil and Gas	Counterparty A	$	—	$	(1,631	)	$	(1,631	)
Oil and Gas	Counterparty B	—		—			—
Utilities	Counterparty A	—		(3,390		)	(3,390		)
Interest Rate Swaps	Counterparty F	9,088		—			9,088
		$	9,088	$	(5,021	)	$	4,067

Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of Dec. 31, 2012 were (in thousands):



				Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Assets		Cash Collateral Received		Net Amount with Counterparty
Assets:
Oil and Gas	Counterparty A	$	341	$	—	$	341
Oil and Gas	Counterparty B	3,362		—		3,362
Utilities	Counterparty A	43		—		43
		$	3,746	$	—	$	3,746



				Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Liabilities		Cash Collateral Paid			Net Amount with Counterparty
Liabilities:
Oil and Gas	Counterparty A	$	—	$	(1,787	)	$	(1,787	)
Oil and Gas	Counterparty B	1,354		—			1,354
Utilities	Counterparty A	—		(4,354		)	(4,354		)
Interest Rate Swap	Counterparty D	4,588		—			4,588
Interest Rate Swap	Counterparty E	29,245		—			29,245
Interest Rate Swap	Counterparty F	12,721		—			12,721
Interest Rate Swap	Counterparty G	26,520		—			26,520
Interest Rate Swap	Counterparty H	16,809		—			16,809
Interest Rate Swap	Counterparty I	22,245		—			22,245
		$	113,482	$	(6,141	)	$	107,341

A description of our derivative activities is included in Note 8. The following tables present the impact that derivatives had on our Consolidated Statements of Income (Loss).

Cash Flow Hedges

The impact of cash flow hedges on our Consolidated Statements of Income (Loss) for years ended were as follows (in thousands):



	Dec. 31, 2013
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	7,935		Interest expense	$	6,989			$	—
Commodity derivatives	(956		)	Revenue	(927		)		—
Total	$	6,979			$	6,062			$	—



	Dec. 31, 2012
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(4,794	)	Interest expense	$	(7,607	)		$	—
Commodity derivatives	2,639			Revenue	8,784				—
Total	$	(2,155	)		$	1,177			$	—



	Dec. 31, 2011
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(12,280	)	Interest expense	$	(7,664	)		$	—
Commodity derivatives	7,741			Revenue	5,487				—
Total	$	(4,539	)		$	(2,177	)		$	—

Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended Dec. 31 were as follows (in thousands):



		2013			2012			2011
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income

Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swap, net	$	30,169		$	1,882		$	(42,010	)
Interest rate swaps - realized	Interest expense	(12,902		)	(12,959		)	(13,373		)
		$	17,267		$	(11,077	)	$	(55,383	)

Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 9, were as follows at Dec. 31 (in thousands):



	2013				2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	7,841	$	7,841	$	15,462	$	15,462
Restricted cash and equivalents ^(a)	$	2	$	2	$	7,916	$	7,916
Notes payable ^(a)	$	82,500	$	82,500	$	277,000	$	277,000
Long-term debt, including current maturities ^(b)	$	1,396,948	$	1,491,422	$	1,042,850	$	1,231,559

_______________


(a)	Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.


(b)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Cash and Cash Equivalents

Included in cash and cash equivalents is cash, overnight repurchase agreement accounts, money market funds and term deposits. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.

Restricted Cash and Equivalents

Restricted cash and cash equivalents represent restricted cash and uninsured term deposits.

Notes Payable

2013 Notes Payable represents our Revolving Credit Facility while 2012 also includes certain corporate term loans.

Long-Term Debt

For additional information on our long-term debt, see Note 5.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Common Stocks, Including Additional Paid in Capital, Net of Discount [Abstract]

Stock

12 Months Ended

Dec. 31, 2013

Common Stock

STOCK

Equity Compensation Plans

Our 2005 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 768,953 shares available to grant at Dec. 31, 2013.

Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of Dec. 31, 2013, total unrecognized compensation expense related to non-vested stock awards was approximately $9.9 million and is expected to be recognized over a weighted-average period of 1.7 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follows for the years ended Dec. 31 (in thousands):



	2013		2012		2011
Stock-based compensation expense	$	12,595	$	8,271	$	5,643

Stock Options

We have granted options with an option exercise price equal to the fair market value of the stock on the day of the grant. The options granted vest proportionately over 3 years and expire 10 years after the grant date.

A summary of the status of the stock options at Dec. 31, 2013 was as follows:



	Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)				(in years)	(in thousands)
Balance at beginning of period	121		$	31.23
Granted ^(a)	10		40.39
Forfeited/canceled	—		—
Expired	(4	)	29.09
Exercised	(66	)	30.87
Balance at end of period	61		$	33.25	7.3	$	1,165

Exercisable at end of period	26		$	31.69	6.5	$	534

___________________________


(a)	The grant date fair value of the 2013 awards was $7.65 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 1.4 percent risk free interest rate, 29.3 percent expected price volatility, 3.8 percent expected dividend yield and a 7 year expected life.

The table below provides details of our option plans at Dec. 31 (in thousands):



	2013		2012		2011
Summary of Stock Options
Unrecognized compensation expense	$	130	$	218	$	479
Intrinsic value of options exercised^(a)	$	789	$	623	$	94
Net cash received from exercise of options	$	2,046	$	2,839	$	1,009
Tax benefit realized from exercise of shares ^(b)	$	276	$	218	$	33

_____________________


(a)	The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.


(b)	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.

As of Dec. 31, 2013, the unrecognized compensation expense related to non-vested stock options is expected to be recognized over a weighted-average period of 1.1 years.

Restricted Stock

The fair value of restricted stock awards equals the market price of our stock on the date of grant.

The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.

A summary of the status of the restricted stock at Dec. 31, 2013, was as follows:



	Restricted Stock		Weighted-Average Grant Date Fair Value
	(in thousands)
Restricted Stock balance at beginning of period	287		$	32.23
Granted	120		40.56
Vested	(138	)	30.62
Forfeited	(7	)	35.50
Restricted Stock at end of period	262		$	36.76

The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended Dec. 31, was as follows:



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2013	$	40.56	$	5,842
2012	$	34.99	$	3,781
2011	$	30.33	$	3,211

As of Dec. 31, 2013, there was $5.8 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 1.8 years.

Performance Share Plan

Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.

The performance awards are paid 50 percent in cash and 50 percent in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100 percent in cash. If it is determined that a change-in-control is probable, the equity portion of $1.9 million at Dec. 31, 2013 would be reclassified as a liability.

Outstanding performance periods at Dec. 31 were as follows (shares in thousands):



			Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares	Minimum	Maximum
Jan. 1, 2011	Jan. 1, 2011 - Dec. 31, 2013	62	0%	175%
Jan. 1, 2012	Jan. 1, 2012 - Dec. 31, 2014	64	0%	200%
Jan. 1, 2013	Jan. 1, 2013 - Dec. 31, 2015	61	0%	200%

A summary of the status of the Performance Share Plan at Dec. 31 was as follows:



	Equity Portion				Liability Portion
			Weighted-Average Grant Date Fair Value				Weighted-Average Fair Value at
	Shares		Weighted-Average Grant Date Fair Value		Shares		Dec. 31, 2013
	(in thousands)				(in thousands)
Performance Shares balance at beginning of period	96		$	27.49	96
Granted	31		35.85		31
Forfeited	(1	)	33.85		(1	)
Vested	(33	)	24.26		(33	)
Performance Shares balance at end of period	93		$	31.34	93		$	95.79

The grant date fair values for the performance shares granted in 2013, 2012 and 2011 were determined by Monte Carlo simulation using a blended volatility of 20 percent, 21 percent and 30 percent, respectively, comprised of 50 percent historical volatility and 50 percent implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows:



	Weighted Average Grant Date Fair Value
Dec. 31, 2013	$	35.85
Dec. 31, 2012	$	32.26
Dec. 31, 2011	$	25.92

Performance plan payouts have been as follows (dollars and shares in thousands):



Performance Period	Year of Payment	Stock Issued	Cash Paid		Total Intrinsic Value
Jan. 1, 2010 to Dec. 31, 2012	2013	63	$	2,267	$	4,533
Jan. 1, 2009 to Dec. 31, 2011	2012	—	$	—	$	—
Jan. 1, 2008 to Dec. 31, 2010	2011	—	$	—	$	—

On Jan. 29, 2014, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the Jan. 1, 2011 through Dec. 31, 2013 performance period was at the 94^th percentile of its peer group and confirmed a payout equal to 175 percent of target shares, valued at $6.0 million. The payout was fully accrued at Dec. 31, 2013.

As of Dec. 31, 2013, there was $3.9 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.6 years.

Shareholder Dividend Reinvestment and Stock Purchase Plan

We have a DRIP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100 percent of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We are currently issuing new shares.

A summary of the Dividend Reinvestment and Stock Purchase Plan for the years ended and at Dec. 31 is as follows (shares in thousands):



	2013		2012
Shares Issued	67		101

Weighted Average Price	$	46.78	$	33.58

Unissued Shares Available	286		353

Equity Issuance

On Nov. 10, 2010, we entered into an Equity Forward Agreement with J.P. Morgan in connection with a public offering of 4,000,000 shares of Black Hills Corporation common stock. Subsequently, the underwriters exercised the over-allotment option to purchase 413,519 additional shares under the same terms as the original Forward Equity Agreement. On Nov. 1, 2011 we issued 4,413,519 shares of common stock in return for proceeds of approximately $120 million under an Equity Forward Agreement.

Preferred Stock

Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Leases of Lessee Disclosure [Text Block]

Impairment of Long-Lived Assets	12 Months Ended
Impairment of Long-Lived Assets	Dec. 31, 2013
Asset Impairment Charges [Abstract]
Asset Impairment Charges [Text Block]	IMPAIRMENT OF LONG-LIVED ASSETS Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development, and acquisition of crude oil and natural gas reserves, all costs attributable to these activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge. As a result of continued low commodity prices in the second quarter of 2012, we recorded a $27 million non-cash impairment of oil and gas assets included in the Oil and Gas segment. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead; for crude oil, the average NYMEX price was $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead.

Operating Leases

12 Months Ended

Dec. 31, 2013

Leases, Operating [Abstract]

OPERATING LEASES

We have entered into lease agreements for vehicles, equipment and office facilities. Rental expense incurred under these operating leases, including month to month leases, for the years ended Dec. 31 was as follows (in thousands):



	2013		2012		2011
Rent expense	$	7,169	$	6,839	$	6,125

The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):



2014	$	2,782
2015	$	2,583
2016	$	1,938
2017	$	1,747
2018	$	1,697
Thereafter	$	5,452

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

Income tax expense (benefit) from continuing operations for the years ended Dec. 31 was (in thousands):



	2013			2012			2011
Current:
Current federal income tax expense (benefit)	$	(2,003	)	$	4,972		$	(14,539	)
Current state income tax expense (benefit)	(173		)	3,712			(837		)
	(2,176		)	8,684			(15,376		)
Deferred:
Deferred federal income tax expense (benefit)	56,963			39,876			30,876
Deferred state income tax expense (benefit)	7,033			68			2,970
Tax credit amortization expense (benefit)	(212		)	(228		)	(246		)
	63,784			39,716			33,600

Total income tax expense (benefit)	$	61,608		$	48,400		$	18,224

The temporary differences, which gave rise to the net deferred tax liability, for the years ended Dec. 31 were as follows (in thousands):



	2013			2012
Deferred tax assets:
Regulatory liabilities	$	33,172		$	57,471
Employee benefits	28,724			23,767
Items of other comprehensive income (loss)	9,733			20,038
Derivative fair value adjustments	1,594			35,947
Federal net operating loss	166,095			147,153
Asset impairment	55,124			55,971
State tax credits	14,948			15,546
Other deferred tax assets	32,803			36,502
Less: Valuation allowance	(1,806		)	(6,192		)
Total deferred tax assets	340,387			386,203

Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(598,415		)	(571,262		)
Regulatory assets	(24,581		)	(23,537		)
Mining development and oil exploration	(69,799		)	(48,411		)
Deferred costs	(15,593		)	(17,723		)
State deferred tax liability	(30,293		)	(19,986		)
Other deferred tax liabilities	(15,104		)	(13,961		)
Total deferred tax liabilities	(753,785		)	(694,880		)

Net deferred tax liability	$	(413,398	)	$	(308,677	)

The effective tax rate differs from the federal statutory rate for the years ended Dec. 31, as follows:



	2013		2012		2011
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	2.4		2.0		1.8
Amortization of excess deferred and investment tax credits	(0.1	)	(0.2	)	(0.5	)
Percentage depletion in excess of cost	(1.0	)	(1.3	)	(2.5	)
Equity AFUDC	—		—		(0.5	)
Tax credits	(0.5	)	—		—
Accounting for uncertain tax positions adjustment	0.7		0.8		2.8
Flow-through adjustments^(a)	(0.9	)	(1.3	)	(4.5	)
Other tax differences	(0.9	)	0.4		(0.5	)
	34.7	%	35.4	%	31.1	%

_________________________

(a)

The flow-through adjustments relate primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit consistent with the flow-through method. Such tax benefit has remained somewhat constant, but its impact on the effective tax rate is predicated on the level of pre-tax net income as evidenced in 2011.

At Dec. 31, 2013, we had federal and state NOL carryforwards which will expire at various dates as follows (in thousands):



Net Operating Loss Carryforward	Amounts		Expiration Dates
Federal	$	482,989	2019	to	2033
State	$	423,570	2013	to	2033

As of Dec. 31, 2013, we had a $0.5 million valuation allowance against the state NOL carryforwards. The re-evaluation of our ability to utilize such NOLs resulted in a decrease of the valuation allowance of approximately $1.7 million of which $0.7 million resulted in a decrease to tax expense. The valuation allowance adjustment was primarily attributable to NOLs whose carryforward period has expired resulting in an offset to the deferred tax asset. Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.

The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):



	Changes in Uncertain Tax Positions
Beginning balance at Jan. 1, 2011	$	50,135
Additions for prior year tax positions	2,725
Reductions for prior year tax positions	(3,533		)
Ending balance at Dec. 31, 2011	49,327
Additions for prior year tax positions	111
Reductions for prior year tax positions	(8,906		)
Additions for current year tax positions	151
Settlements	—
Ending balance at Dec. 31, 2012	40,683
Additions for prior year tax positions	1,526
Reductions for prior year tax positions	(4,578		)
Additions for current year tax positions	—
Settlements	—
Ending balance at Dec. 31, 2013	$	37,631

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $1.7 million.

We recognized interest expense of $1.6 million, $1.4 million and $1.4 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively.

We had approximately $9.9 million pre-tax and $8.3 million pre-tax of accrued interest associated with income taxes at Dec. 31, 2013 and 2012, respectively.

We file income tax returns with the IRS and various state jurisdictions. We are currently under examination by the IRS for the 2007 to 2009 tax years and recently received notification to audit the 2010 to 2012 tax years. We remain subject to examination by Canadian income tax authorities for tax years as early as 1999.

We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS has challenged our position with respect to the like-kind exchange and it is reasonably possible that the total unrecognized tax benefits attributable to such transaction could change significantly due to a settlement with the IRS that is anticipated to occur on or before Dec. 31, 2014. However, based on the information currently available, it is difficult to determine any reasonable estimate of the financial statement impact including the impact on the effective tax rate.

Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At Dec. 31, 2013, we had foreign tax credit carryforwards of approximately $0.5 million, which expire between 2015 and 2017.

As of Dec. 31, 2013, we had a $0.5 million valuation allowance against the foreign tax credit carryforwards. In addition, the carryforward balance reflects the expected utilization of approximately $1.8 million of foreign tax credits to be included as computational adjustments upon finalization of our current IRS examination covering tax years 2007 to 2009. Such foreign tax credits have been reflected as an offset to liabilities for unrecognized tax benefits in recognition of the estimated impact the resolution of material uncertain tax positions could have with respect to utilization.

State tax credits have been generated and are available to offset future state income taxes. At Dec. 31, 2013, we had the following state tax credit carryforwards (in thousands):



State Tax Credit Carryforwards			Expiration Years
Investment tax credit	$	14,793	2023	to	2025
Research and development	$	155	No expiration

As of Dec. 31, 2013, we had a $0.8 million valuation allowance against the state tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in a decrease of the valuation allowance of approximately $2.6 million of which approximately $1.1 million resulted in a decrease to tax expense. The remaining $1.5 million decrease is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to an increase in forecasted apportionment factors. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.

Comprehensive Income

12 Months Ended

Dec. 31, 2013

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Comprehensive Income (Loss)

OTHER COMPREHENSIVE INCOME

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):



	Location on the Consolidated Statements of Income	Amount Reclassified from AOCI
	Location on the Consolidated Statements of Income	Dec. 31, 2013			Dec. 31, 2012
Gains and losses on cash flow hedges:
Interest rate swaps	Interest expense	$	6,989		$	7,607
Commodity contracts	Revenue	(927		)	(8,784		)
		6,062			(1,177		)
Income tax	Income tax benefit (expense)	(2,016		)	534
Total reclassification adjustments related to cash flow hedges, net of tax		$	4,046		$	(643	)

Amortization of defined benefit plans:
Prior service cost	Utilities - Operations and maintenance	$	(125	)	$	—
	Non-regulated energy operations and maintenance	(128		)	—

Actuarial gain (loss)	Utilities - Operations and maintenance	1,693			—
	Non-regulated energy operations and maintenance	1,098			—
		2,538			—
Income tax	Income tax benefit (expense)	(883		)	—
Total reclassification adjustments related to defined benefit plans, net of tax		$	1,655		$	—

Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets were as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of Dec. 31, 2012	$	(16,313	)	$	600		$	(19,775	)	$	(35,488	)
Other comprehensive income (loss)	9,688			(1,108		)	9,486			18,066
As of Dec. 31, 2013	$	(6,625	)	$	(508	)	$	(10,289	)	$	(17,422	)

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of Dec. 31, 2011	$	(18,140	)	$	4,338		$	(19,076	)	$	(32,878	)
Other comprehensive income (loss)	1,827			(3,738		)	(699		)	(2,610		)
As of Dec. 31, 2012	$	(16,313	)	$	600		$	(19,775	)	$	(35,488	)

The entire disclosure for comprehensive income, which includes, but is not limited to, 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 220
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2013

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Years ended Dec. 31,	2013			2012			2011
	(in thousands)
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$	59,811		$	35,556		$	37,529
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	1,235		$	5,743		$	(1,525	)

Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	$	(108,361	)	$	(116,593	)	$	(103,110	)
Income taxes, net	$	(4,573	)	$	(3,027	)	$	9,854

Employee Benefit Plans

12 Months Ended

Dec. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50 percent of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company Matching Contribution for all eligible participants and for certain eligible participants a Company Retirement Contribution based on the participant’s age and years of service. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20 percent per year with 100 percent vesting when the participant has 5 years of service with the Company.

Funded Status of Benefit Plans

The funded status of postretirement benefit plans is required to be recognized in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. Except for our regulated utilities, the unrecognized net periodic benefit cost is recorded within Accumulated other comprehensive income (loss), net of tax. For our regulated utilities, these costs are recoverable in our rates, and accordingly, the unrecognized net periodic benefit cost was alternatively recorded as a regulatory asset or regulatory liability, net of tax (see Note 1). The measurement date for all plans is Dec. 31. As of Dec. 31, 2013, the unfunded status of our Defined Benefit Pension Plans was $41 million; the unfunded status of our Supplemental Non-qualified Defined Benefit Plans was $33 million; and the unfunded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $41 million.

Defined Benefit Pension Plans (Pension Plans)

We have two defined benefit pension plans. Our BHC Pension Plan covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC, BHEP and Cheyenne Light. The Black Hills Utility Holdings, Inc. Pension Plan covers certain eligible employees of Black Hills Energy. The benefits for the Pension Plans are based on year of service and calculations of average earnings during a specific time period prior to retirement. As of Jan. 1, 2010, both Pension Plans were frozen to new employees and certain employees who did not meet age and service based criteria at the time the Pension Plans were frozen.

Pension Plan assets are held in a Master Trust. Each Plan holds an undivided interest in the Master Trust. Our Board of Directors has approved the Plans’ investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plans’ beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Plans’ benefit payment obligations. The Pension Plans’ assets consist primarily of equity, fixed income and hedged investments. The expected long-term rate of return for investments was 7.25 percent and 7.25 percent for the 2013 and 2012 plan years, respectively. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements.

In 2011, the Cheyenne Light Pension Plan was amended to freeze the benefits of certain bargaining unit employees. This amendment was effective as of Jan. 1, 2012. Additionally, effective Oct. 1, 2012, the Cheyenne Light Pension Plan was merged into the BHC Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.

Plan Assets

The percentages of total plan asset fair value by investment category for our Pension Plans at Dec. 31 were as follows:



	2013		2012
Equity	26	%	47	%
Real estate	4		8
Fixed income	58		44
Cash	1		1
Hedge funds	11		—
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.

Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor three retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans is pre-funded via VEBAs. Effective Jan. 1, 2014, health care coverage for Medicare-eligible retirees will be provided through an individual market health care exchange for BHC and Black Hills Utility Holdings retirees.

Plan Assets

We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Energy Plan provides for partial pre-funding via VEBAs. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees of Black Hills Energy located in the states of Kansas and Iowa. We do not pre-fund the Postretirement Healthcare Plans for those employees outside Kansas and Iowa.

Plan Contributions

Contributions to the Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended Dec. 31 were as follows (in thousands):



	2013		2012
Defined Contribution Plan
Company Retirement Contribution	$	2,775	$	2,639
Matching contributions - Defined Contribution Plans	$	8,524	$	8,981



	2013		2012
Defined Benefit Plans
Defined Benefit Pension Plans	$	12,500	$	25,350
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	5,123	$	5,191
Supplemental Non-Qualified Defined Benefit Plans	$	1,345	$	1,270

We do not anticipate making contributions to our Pension Plans in 2014.

Fair Value Measurements

As required by accounting standards for Compensation - Retirement Benefits, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels.

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):



Defined Benefit Pension Plans	Dec. 31, 2013
	Level 1		Level 2		Level 3		Total
AXA Equitable General Fixed Income	$	—	$	1,056	$	—	$	1,056
Common Collective Trust - Cash and Cash Equivalents	—		1,253		—		1,253
Common Collective Trust - Equity	—		73,726		—		73,726
Common Collective Trust - Fixed Income	—		162,747		—		162,747
Common Collective Trust - Real Estate	—		3,392		8,541		11,933
Hedge Funds	—		—		29,647		29,647
Total investments measured at fair value	$	—	$	242,174	$	38,188	$	280,362



Defined Benefit Pension Plans	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	1,486	$	—	$	—	$	1,486
Common Collective Trust - Cash and Cash Equivalents	—		1,118		—		1,118
Common Collective Trust - Equity	—		126,105		—		126,105
Common Collective Trust - Fixed Income	—		114,440		—		114,440
Common Collective Trust - Real Estate	—		13,361		7,770		21,131
Structured Products	—		4,536		—		4,536
Total investments measured at fair value	$	1,486	$	259,560	$	7,770	$	268,816



Non-pension Defined Benefit Postretirement Healthcare Plans	Dec. 31, 2013
	Level 1		Level 2		Level 3		Total
Registered Investment Company Trust - Money Market Mutual Fund	$	—	$	4,546	$	—	$	4,546
Total investments measured at fair value	$	—	$	4,546	$	—	$	4,546



Non-pension Defined Benefit Postretirement Healthcare Plans	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Registered Investment Company Trust - Money Market Mutual Fund	$	—	$	4,351	$	—	$	4,351
Total investments measured at fair value	$	—	$	4,351	$	—	$	4,351

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended Dec. 31 (in thousands):



	2013			2012
Balance, beginning of period	$	7,770		$	7,043

Purchase	29,000			—
Unrealized gain (loss)	1,508			727
Realized gain (loss)	(77		)	—
Settlements	(13		)	—

Balance, end of period	$	38,188		$	7,770

The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Level 3	Range (Weighted)
	Dec. 31, 2013		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate ^(a)	$	8,541	Market Approach	Redemption Restriction	N/A
Hedge Funds ^(b)	$	29,647	Market Approach	Redemption Restriction	N/A

_____________

(a)

The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. As part of the Trustee's valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with the professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the Trustee along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The fund does contain a participant withdrawal policy.

(b)

The fair value of Level 3 is determined based on pricing provided or reviewed by third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds will be reviewed at the time they are issued.

Additional information about assets of the Pension Plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:

AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately place bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates at which loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service provides with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer.

Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.

Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments, and rely on these reports for pricing the units of the fund. Certain of the funds’ assets contain participant withdrawal policy and, therefore, are categorized as Level 3. The funds without participant withdrawal limitations are categorized as Level 2.

Hedge Funds: Hedge funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, after a lockup period of one-year, with a 65 day notice and is limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.

Structured Products: Investments are created through the process of financial engineering, (that is, by combining underlying securities like equity, bonds, or indices with derivatives). The value of derivative securities, such as options, forwards and swaps is determined by (respectively, derives from) the prices of the underlying securities.

Registered Investment Companies: Investments are valued at the closing price reported on the active market on which the individual securities are traded.

Other Plan Information

The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the statement of financial position, components of the net periodic expense and elements of accumulated other comprehensive income (in thousands):

Benefit Obligations



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2013			2012			2013			2012			2013			2012
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	363,235		$	325,944		$	34,393		$	30,223		$	46,681		$	50,141
Service cost	6,433			5,720			1,392			889			1,674			1,610
Interest cost	15,300			14,747			1,328			1,410			1,669			2,093
Actuarial (gain) loss	(38,252		)	28,639			(2,808		)	3,140			(3,379		)	(4,430		)
Amendments ^(a)	—			—			—			—			1,585			—
Benefits paid	(25,316		)	(11,815		)	(1,345		)	(1,269		)	(5,123		)	(5,190		)
Plan curtailment liability reduction	—			—			—			—			—			—
Medicare Part D accrued	—			—			—			—			470			289
Plan participants’ contributions	—			—			—			—			2,201			2,168
Projected benefit obligation at end of year	$	321,400		$	363,235		$	32,960		$	34,393		$	45,778		$	46,681

____________________


(a)	Reflects Board of Directors approval of an increase to Company’s contribution to RMSA accounts.

A reconciliation of the fair value of Plan assets was as follows (in thousands):



	Defined Benefit Pension Plans							Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans ^(a)
	2013				2012			2013		2012		2013			2012
Beginning market value of plan assets	$	268,816			$	221,722		$	—	$	—	$	4,351		$	4,319
Investment income (loss)	24,362				33,559			—		—		8			(3		)
Employer contributions	12,500				25,350			—		—		1,923			2,172
Retiree contributions	—				—			—		—		1,533			1,458
Benefits paid	(25,316		)	^(b)	(11,815		)	—		—		(3,269		)	(3,595		)
Plan administrative expenses	—				—			—		—		—			—
Ending market value of plan assets	$	280,362			$	268,816		$	—	$	—	$	4,546		$	4,351

____________________


(a)	Assets of VEBA


(b)	2013 Benefits paid includes a one-time $13 million payment made to terminated vested employees who elected a lump-sum offering.

Amounts recognized in the Consolidated Balance Sheets at Dec. 31 consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2013		2012		2013		2012		2013		2012
Regulatory assets	$	48,419	$	94,199	$	—	$	—	$	5,535	$	6,438
Current liabilities	$	—	$	—	$	1,491	$	1,286	$	2,802	$	2,573
Non-current liabilities	$	41,034	$	94,410	$	32,033	$	33,180	$	38,412	$	39,807
Regulatory liabilities	$	—	$	—	$	—	$	—	$	3,141	$	2,174

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2013		2012		2013		2012		2013		2012
Accumulated benefit obligation - Black Hills Corporation	$	110,847	$	124,143	$	27,380	$	28,056	$	12,101	$	12,309
Accumulated benefit obligation - Black Hills Energy	182,295		202,897		513		453		25,467		25,868
Accumulated benefit obligation - Cheyenne Light	—		—		—		—		8,210		8,504
Total Accumulated Benefit Obligation	$	293,142	$	327,040	$	27,893	$	28,509	$	45,778	$	46,681

Components of Net Periodic Expense



(in thousands)	Defined Benefit Pension Plans									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2013			2012			2011			2013		2012		2011		2013			2012			2011
Service cost	$	6,433		$	5,720		$	5,421		$	1,392	$	889	$	1,028	$	1,674		$	1,610		$	1,498
Interest cost	15,300			14,747			14,929			1,328		1,410		1,298		1,669			2,093			2,168
Expected return on assets	(18,615		)	(16,334		)	(16,955		)	—		—		—		(79		)	(78		)	(164		)
Amortization of prior service cost	63			89			99			2		3		3		(500		)	(500		)	(479		)
Recognized net actuarial loss (gain)	12,250			9,630			4,540			793		807		510		482			887			677
Curtailment expense	—			—			13			—		—		—		—			—			—
Net periodic expense	$	15,431		$	13,852		$	8,047		$	3,515	$	3,109	$	2,839	$	3,246		$	4,012		$	3,700

Accumulated Other Comprehensive Income

In accordance with accounting standards for defined benefit plans, amounts included in Accumulated other comprehensive income (loss), after-tax, that have not yet been recognized as components of net periodic benefit cost at Dec. 31 were as follows (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2013		2012		2013		2012		2013			2012
Net (gain) loss	$	4,842	$	12,090	$	4,939	$	7,283	$	1,648		$	2,097
Prior service cost (gain)	64		78		9		11		(1,213		)	(1,784		)
Total accumulated other comprehensive (income) loss	$	4,906	$	12,168	$	4,948	$	7,294	$	435		$	313

The amounts in Accumulated other comprehensive income (loss), Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2014 are as follows (in thousands):



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss	$	3,124	$	323	$	99
Prior service cost (credit)	41		1		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2014	$	3,165	$	324	$	(119	)

Assumptions



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine benefit obligations:	2013		2012		2011		2013		2012		2011		2013		2012		2011

Discount rate	5.05	%	4.30	%	4.65	%	4.21	%	3.44	%	4.30	%	4.62	%	3.85	%	4.42	%
Rate of increase in compensation levels	3.78	%	3.84	%	3.77	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2013		2012		2011		2013		2012		2011		2013		2012		2011
Discount rate:
Black Hills Corporation	4.35	%	4.68	%	5.50	%	3.88	%	4.70	%	5.00	%	3.65	%	4.35	%	5.00	%
Black Hills Energy	4.25	%	4.60	%	5.40	%	3.00	%	3.90	%	4.40	%	3.50	%	4.35	%	4.60	%
Cheyenne Light	N/A		N/A		5.55	%	N/A		N/A		N/A		4.40	%	4.65	%	5.50	%

Expected long-term rate of return on assets ^(a)	7.25	%	7.25	%	7.75	%	N/A		N/A		N/A		2.00	%	2.00	%	4.00	%
Rate of increase in compensation levels	3.78	%	3.75	%	3.79	%	5.00	%	5.00	%	5.00	%	NA		NA		NA

_____________________________


(a)	The expected rate of return on plan assets is 6.75 percent for the calculation of the 2014 net periodic pension cost.

The healthcare benefit obligation was determined at Dec. 31 as follows:



	Black Hills Corporation		Black Hills Energy		Cheyenne Light
2013
Healthcare trend rate pre-65
Trend for next year	7.50	%	7.50	%	7.50	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

Healthcare trend rate post-65
Trend for next year	6.25	%	6.25	%	6.25	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2026		2026		2026

2012
Healthcare trend rate pre-65
Trend for next year	7.75	%	7.75	%	7.75	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

Healthcare trend rate post-65
Trend for next year	6.50	%	6.50	%	6.50	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2026		2026		2026

We do not pre-fund our non-qualified pension plans or two of the three postretirement benefit plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Retiree Healthcare Plans (in thousands):



Change in Assumed Trend Rate	Impact on Dec. 31, 2013 Accumulated Postretirement Benefit Obligation			Impact on 2013 Service and Interest Cost
Increase 1%	$	1,914		$	136
Decrease 1%	$	(1,644	)	$	(116	)

The following benefit payments, which reflect future service, are expected to be paid (in thousands):



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plan		Non-Pension Defined Benefit Postretirement Healthcare Plans
2014	$	13,721	$	1,491	$	3,340
2015	$	14,572	$	1,490	$	3,397
2016	$	15,608	$	1,542	$	3,477
2017	$	16,562	$	1,588	$	3,495
2018	$	17,627	$	1,622	$	3,572
2019-2023	$	105,252	$	8,146	$	17,520

Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties:


•	Black Hills Power’s PPA with PacifiCorp, expiring Dec. 31, 2023, for the purchase of 50 megawatts of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.


•	Black Hills Power has a firm point-to-point transmission service agreement with PacifiCorp that expires Dec. 31, 2023. The agreement provides 50 megawatts of capacity and energy to be transmitted annually by PacifiCorp.


•	Cheyenne Light’s PPA with Duke Energy’s Happy Jack wind site, expiring Sept. 3, 2028, provides up to 30 megawatts of wind energy from Happy Jack to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility output to Black Hills Power.


•	Cheyenne Light’s PPA with Duke Energy’s Silver Sage wind site, expiring Sept. 30, 2029, provides up to 30 megawatts of wind energy. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 megawatts of energy from Silver Sage to Black Hills Power.


•	Colorado Electric’s PPA with Cargill expiring Dec. 31, 2014, whereby Colorado Electric purchases 50 megawatts of economy energy.


•	Colorado Electric’s REPA with AltaGas expiring Oct. 16, 2037, provides up to 14.5 megawatts of wind energy from the Busch Ranch Wind Project in which Colorado Electric owns a 50 percent undivided ownership interest.


•	Cheyenne Light renewed and received FERC approval for an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through Sept. 30, 2014.

Costs under these power purchase contracts for the years ended Dec. 31 were as follows (in thousands):



	2013		2012		2011
PPA with PacifiCorp	$	13,026	$	13,224	$	12,515
PPA with PSCo^(a)	$	—	$	—	$	97,988
Transmission services agreement with PacifiCorp	$	1,384	$	1,215	$	1,215
PPA with Happy Jack	$	3,772	$	1,988	$	1,955
PPA with Silver Sage	$	4,809	$	3,269	$	3,281
Busch Ranch Wind Project	$	1,856	$	502	$	—

_______________________


(a)	This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.

Other Gas Supply Agreements

Our Utilities also purchase natural gas, including transportation capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2017.

Natural Gas Delivery Commitment

In 2012, we entered into a ten-year gas gathering contract for natural gas production from our properties in the Piceance Basin in Colorado, under which we pay a gathering fee per Mcf. The contract requires us to deliver a minimum of 20,000 Mcf per day. The gatherer is in the process of building the necessary infrastructure to handle the committed volumes. The agreement becomes effective when the infrastructure is placed in commercial service, which we estimate to be first quarter of 2014. We believe that our reserves dedicated to the gathering system, and the projected volumes are adequate to satisfy our delivery commitments under this agreement.

Future Minimum Payments

The following is a schedule of future minimum payments required under the power purchase, transmission services, coal and gas supply agreements, and natural gas delivery commitments (in thousands):



2014	$	203,131
2015	$	148,874
2016	$	136,503
2017	$	125,492
2018	$	110,930
Thereafter	$	148,362

Purchase Sale Agreement

On May 6, 2013, Black Hills Wyoming entered into an agreement to sell its 40 megawatt CTII natural gas-fired generating unit to the City of Gillette, Wyo. for approximately $22 million, upon expiration of the PPA with Cheyenne Light in August 2014. As part of the sale, Black Hills Wyoming will provide services to the City of Gillette through an economy energy PPA. The sale is subject to FERC approval and certain other requirements included in the contract.

Construction Obligations

Construction of Cheyenne Prairie, a 132 megawatt natural gas-fired electric generating facility jointly owned by Cheyenne Light and Black Hills Power is expected to cost approximately $222 million. Construction is expected to be completed by Sept. 30, 2014. As of Dec. 31, 2013, committed contracts for equipment purchases and for construction were 100 percent and 75 percent complete, respectively.

Future Purchase Agreement - Related Party

Cheyenne Light’s PPA for 60 megawatts of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on Dec. 31, 2022, includes an option for Cheyenne Light to purchase Black Hills Wyoming’s ownership in the Wygen I facility. The purchase price related to the option is $2.6 million per megawatt which is the equivalent per megawatt of the pre-construction estimated cost of the Wygen III plant, which was completed in April 2010. This option purchase price is adjusted for capital additions and reduced by an amount equal to annual depreciation based on a 35-year life starting Jan. 1, 2009.

Power Sales Agreements

Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:


•	During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 megawatts from our other generation facilities or from system purchases with reimbursement of costs by MDU.

•

During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 megawatts from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves.


•	Cheyenne Light renewed and received FERC approval for an agreement with Basin Electric whereby Cheyenne Light will provide 40 megawatts of capacity and energy to Basin Electric through Sept. 30, 2014.


•	Black Hills Power has a PPA with MEAN expiring April 1, 2015. Under this contract, MEAN purchases 5 megawatts of unit-contingent capacity from Neil Simpson II and 5 megawatts of unit-contingent capacity from Wygen III.


•	Black Hills Power has a PPA with MEAN expiring May 31, 2023. This contract is unit-contingent on up to 10 megawatts from Neil Simpson II and up to 10 megawatts from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.

Related Party Lease

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on Dec. 31, 2031, provides 200 megawatts of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations.

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.

Air

Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO₂, NO_x, mercury particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT II, Lange CT, Wygen I, Wygen II, Wygen III, Wyodak and Pueblo Airport Generating Station plants. Title IV of the Clean Air Act created an SO₂ allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2043.

The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which impose emission limits, fuel requirements and monitoring requirements. The rule has a compliance deadline of March 21, 2014. In anticipation of this rule we suspended operations at the Osage plant in October 2010 and as a result of this rule, we suspended operations at the Ben French facility on Aug. 31, 2012. We plan to retire Ben French, Osage and Neil Simpson I on or before March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than Dec. 31, 2013. This facility suspended operations Dec. 31, 2012 and was retired on Dec. 31, 2013. While the net book value of these plants is estimated to be immaterial at the time of retirement, we would reasonably not expect a disallowance of the remaining value.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, at which operations have been suspended, has an on-site ash impoundment that is near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 and post closure monitoring activities will continue for 30 years.

In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed and post closure monitoring will continue for 30 years.

Our W.N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages.

Reclamation Liability

For our Pueblo Airport Generation site, we posted a bond of $3.9 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

Under its land lease for Busch Ranch, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

See Note 7 for additional information.

Manufactured Gas Processing

As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.3 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas agreed to remediate the Blair and Plattsmouth sites in Nebraska. Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska's Voluntary Cleanup Program. Site remediation was completed in September 2012, however there is a potential for additional minimal remediation work at Plattsmouth where monitoring is required until 2015. Both Nebraska sites will be required to monitor groundwater quality for a minimum two year period.

As of Dec. 31, 2013, our estimated liabilities for all of the MGP sites currently range from approximately $2.9 million to $6.3 million for which we had $2.9 million accrued for remediation of sites as of Dec. 31, 2013 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets.

Prior to Black Hills Corporation's ownership, Aquila received rate orders that enabled recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of these current and future costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.

Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations, will not exceed the amounts reflected in the consolidated financial statements.

In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A fire investigator concluded that the fire was caused by the failure of a transmission structure owned, operated and maintained by Black Hills Power. On April 16, 2013, thirty-five private parties filed suit in the United States District Court for the District of Wyoming, asserting claims for damages against Black Hills Power based upon allegations of negligence, negligence per se, common law nuisance, and trespass. Although not currently included in the lawsuit, Black Hills Power also received written damage claims from an additional landowner and from the State of Wyoming. Altogether the claims seek recovery for fire suppression, reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate, for a current total amount of $15 million. In addition to claims for these compensatory damages, the lawsuit seeks recovery of punitive damages. Our investigation of the cause and origin of the fire is ongoing. We have denied and will vigorously defend all claims arising out of the fire, pending the completion of our investigation. Given the uncertainty of litigation, however, a loss related to the fire, the litigation and related claims, is reasonably possible. We cannot reasonably estimate the amount of a potential loss because our investigation is ongoing, and because damage claims are currently incomplete or undocumented. Further claims may be presented by these and other parties. We cannot predict the outcome of our investigation, the viability of alleged claims or the outcome of the litigation. Based upon information currently available, however, management does not expect the claims, if determined adversely to us, to have a material adverse effect upon our financial condition, results of operations or cash flows.

Sale of Enserco Energy Inc.

After the sale of Enserco, our Energy Marketing segment, on Feb. 29, 2012, and pursuant to the provisions of the Stock Purchase Agreement, the buyer requested certain purchase price adjustments, which we disputed. The buyer filed a petition in the Colorado District Court for the City and County of Denver, Colo., seeking an order compelling binding arbitration on all of the disputed claims. Following a hearing in July 2013, the court entered an order remanding all but one of the disputed claims to binding arbitration. Arbitration was completed terminating the purchase price dispute in January 2014. See additional disclosures included in Note 21 of these Notes to Consolidated Financial Statements.

Guarantees

12 Months Ended

Dec. 31, 2013

Guarantees [Abstract]

Guarantees [Text Block]

GUARANTEES

We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include guarantees of debt obligations, contractual performance obligations and indemnification for reclamation and surety bonds.

We had the following guarantees in place as of (in thousands):



	Maximum Exposure at
Nature of Guarantee	Dec. 31, 2013		Expiration
Guarantees of payment obligations arising from commodity-related physical and financial transactions of Black Hills Utility Holdings ⁽¹⁾	$	70,000	Ongoing
Indemnification for subsidiary reclamation/surety bonds ⁽²⁾	64,449		Ongoing
	$	134,449

_______________________

(1)

We have guaranteed some of the obligations of Black Hills Utility Holdings for payment obligations arising from commodity-related physical and financial transactions with BP Energy Company and/or BP Canada Energy Marketing Corp, Northern Natural Gas Company and PSCo. These commodity transactions secure natural gas supply for our regulated gas utilities. The guarantee is a continuing guarantee that may be terminated upon 30 days written notice to the counterparty.


(2)	We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

Oil and Gas Reserves (Unaudited)

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

OIL AND GAS RESERVES (Unaudited)

BHEP has operating and non-operating interests in 1,224 gross developed oil and gas wells in 10 states and holds leases on approximately 235,517 net acres.

Costs Incurred

Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended Dec. 31 (in thousands):



	2013		2012		2011
Acquisition of properties:
Proved	$	234	$	2,437	$	673
Unproved	6,022		33,052		8,317
Exploration costs	12,817		115		44,384
Development costs	48,641		73,877		38,638
Asset retirement obligations incurred	143		158		43
Total costs incurred	$	67,857	$	109,639	$	92,055

Reserves

The following table summarizes BHEP’s quantities of proved developed and undeveloped oil and natural gas reserves, estimated using SEC-defined product prices, as of Dec. 31, 2013, 2012 and 2011, and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.



	2013						2012						2011
	Oil			Gas			Oil			Gas			Oil			Gas
	(in Mbbls of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	4,116			55,985			6,223			95,904			5,940			95,456
Production ^(a)	(336		)	(6,984		)	(560		)	(8,686		)	(452		)	(8,526		)
Additions - acquisitions (sales)^(b)	(30		)	(46		)	(2,025		)	(3,070		)	(84		)	—
Additions - extensions and discoveries	379			10,456			449			2,898			927			29,664
Revisions to previous estimates	(208		)	3,779			29			(31,061		)	(108		)	(20,690		)
Balance at end of year	3,921			63,190			4,116			55,985			6,223			95,904

Proved developed reserves at end of year included above	3,689			60,224			3,929			55,708			4,830			71,867

Proved undeveloped reserves at the end of year included in above	232			2,966			187			279			1,393			24,037

NYMEX prices	$	96.94		$	3.67		$	94.71		$	2.76		$	96.19		$	4.12

Well-head reserve prices	$	89.79		$	3.45		$	85.31		$	2.24		$	88.49		$	3.59

________________________


(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGLs).


(b)	Reflects the sale of the majority of the Williston Basin assets during 2012.

Reserve additions totaled 12.7 Bcfe, replacing 90 percent of production. Additions mainly resulted from drilling in the Piceance, Williston and Powder River Basins. Drilling in Piceance Basin (Mancos Shale) accounted for 10.2 Bcfe, Williston Basin (Bakken Shale) accounted for 2.1 Bcfe, and recompletions in the Powder River Basin (0.2 Bcfe) and in the Anadarko Basin of Oklahoma (0.2 Bcfe). Capital spending in 2013 was primarily for evaluation drilling in the Piceance Basin (Mancos Shale) and further development of our holdings in the Williston Bakken Basins. Additionally, exploratory investments were made to develop future oil opportunities. Future capital spending rates are anticipated to be dependent on product prices and success in other future drilling.

In 2013, we had positive revisions (2.5 Bcfe) to previous reserve estimates. Most of the positive revisions were due to higher oil and natural gas prices received at the wellhead (5.0 Bcfe). Additionally, better well performance resulted in 0.4 Bcfe positive revision to year-end 2012 proved reserves. Increased operating costs in the San Juan Basin and reduced expectations of performance in one Williston Basin gross PUD location resulted in a slight negative revision of 2.1 Bcfe

SEC regulations require that proved undeveloped locations meet the test of being developed within five years of being categorized as proved. In 2013, we had no PUD locations that were required to be dropped because of the five year rule.

Companies are required to include a narrative disclosure of the total quantity of PUD locations at year end, any material changes in PUD locations during the year, and investment and progress made in converting the PUD locations during the year.


•	In 2012, we had 11 gross PUD locations for 1.4 Bcfe; all were in the Williston Basin. In 2013, five of those PUD locations were drilled and we invested $3.6 million and developed 0.6 Bcfe.


•	Six gross PUD locations remain undrilled as of Dec. 31, 2013. The remaining 2012 PUD locations require approximately $2.1 million of future investment when drilled will develop approximately 0.5 Bcfe reserves in the Williston Basin.


•	In 2013, we added 15 gross PUD locations for future Williston Basin Bakken drilling, one well in the San Juan Basin and one Piceance Mancos Shale well PUD location.


•	Analysis of offset well performance resulted in dropping one gross PUD location in the Williston Basin.


•	The number of locations, proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of Dec. 31, 2013 were:



	Proved Reserves (in Bcfe)	Gross PUD Locations	Future Development Costs (in millions)
Existing:
Williston Basin	0.5	6	$	2.1

Added:
Williston Basin	1.2	15	6.5
Piceance Basin	2.1	1	6.4
San Juan Basin	0.6	1	0.9
2013 Add Total	3.9	17	13.8

Total Proved Undeveloped	4.4	23	$	15.9


•	None of our PUD locations have been reflected in our reserves for five or more years. Consistent with the SEC guidance, these PUD locations will be monitored and reported each year until they are drilled or revised.

Capitalized Costs

Following is information concerning capitalized costs for the years ended Dec. 31 (in thousands):



	2013			2012			2011
Unproved oil and gas properties	$	62,553		$	59,526		$	28,656
Proved oil and gas properties	725,345			662,444			674,494
Gross capitalized costs	787,898			721,970			703,150

Accumulated depreciation, depletion and amortization and valuation allowances ^(a)	(555,263		)	(534,777		)	(361,173		)
Net capitalized costs	$	232,635		$	187,193		$	341,977

__________________


(a)	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.

Results of Operations

Following is a summary of results of operations for producing activities for the years ended Dec. 31 (in thousands):



	2013			2012			2011
Revenue	$	54,884		$	79,072		$	79,808

Production costs	20,140			23,483			23,820
Gain on sale of assets	—			(29,129		)	—
Depreciation, depletion and amortization and valuation provisions	20,611			37,323			34,415
Impairment of long-lived assets	—			26,868			—
Total costs	40,751			58,545			58,235
Results of operations from producing activities before tax	14,133			20,527			21,573

Income tax benefit (expense)	(4,876		)	(7,082		)	(7,442		)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	9,257		$	13,445		$	14,131

Unproved properties not subject to amortization at Dec. 31, 2013, 2012 and 2011 consisted mainly of exploration cost on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $1.1 million, $0.7 million and $0.9 million of interest during 2013, 2012 and 2011, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. We expect the exploration cost listed below to be added to the cost pool in the next year.

The table below sets forth the cost of unproved properties excluded from the amortization base as of Dec. 31, 2013 and notes the year in which the associated costs were incurred (in thousands):



	2013		2012		2011		Prior		Total
Leasehold acquisition cost	$	2,279	$	35,689	$	2,219	$	17,444	$	57,631
Exploration cost	10,930		—		—		—		10,930
Capitalized interest	748		360		637		3,177		4,922
Total	$	13,957	$	36,049	$	2,856	$	20,621	$	73,483

Standardized Measure of Discounted Future Net Cash Flows

Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended Dec. 31 (in thousands):



	2013			2012			2011
Future cash inflows	$	602,501		$	502,769		$	931,637
Future production costs	(213,578		)	(186,695		)	(280,910		)
Future development costs, including plugging and abandonment	(40,557		)	(8,462		)	(92,233		)
Future income tax expense	(81,566		)	(69,877		)	(157,922		)
Future net cash flows	266,800			237,735			400,572
10 percent annual discount for estimated timing of cash flows	(107,375		)	(101,632		)	(197,215		)
Standardized measure of discounted future net cash flows	$	159,425		$	136,103		$	203,357

The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended Dec. 31 (in thousands):



	2013			2012			2011
Standardized measure - beginning of year	$	136,103		$	203,357		$	168,108
Sales and transfers of oil and gas produced, net of production costs	(35,932		)	(48,905		)	(52,914		)
Net changes in prices and production costs	15,126			(42,639		)	57,087
Extensions, discoveries and improved recovery, less related costs	29,574			19,870			31,179
Changes in future development costs	(12,216		)	43,854			43,809
Development costs incurred during the period	3,554			21,931			18,940
Revisions of previous quantity estimates	12,851			(86,277		)	(58,211		)
Accretion of discount	15,126			25,509			19,655
Net change in income taxes	(3,892		)	36,578			(23,283		)
Purchases of reserves	—			—			—
Sales of reserves ^(a)	(869		)	(37,175		)	(1,013		)
Standardized measure - end of year	$	159,425		$	136,103		$	203,357

________


(a)	Reflects sale of Williston Basin assets in 2012.

Changes in the standardized measure from “revisions of previous quantity estimates” are driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications are generally made at the well level each year through the reserve review process. These production profile modifications are based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments are reviewed each year and are often modified in response to current market conditions for items such as permitting, and service availability.

Sale of Operating Assets and Discontinued Operations

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

SALE OF OPERATING ASSETS AND DISCONTINUED OPERATIONS

Sale of Operating Assets

Partial Sale of Electric Utilities Assets

On Sept. 18, 2012, Colorado Electric completed the sale of an undivided 50 percent ownership interest in the Busch Ranch Wind project for $25 million. Colorado Electric retains the remaining undivided interest and is the operator of this jointly owned facility. Commercial operation of the newly constructed wind farm commenced on Oct. 16, 2012. Colorado Electric will purchase our partner’s interest in the energy produced by the wind farm through a REPA. See Note 18 for further information.

Partial Sale of Oil and Gas Assets

On Sept. 27, 2012, our Oil and Gas segment sold a majority of its Bakken and Three Forks shale assets in the Williston Basin in North Dakota. An effective date of July 1, 2012, was used to determine the sales price.

Our Oil and Gas segment follows the full-cost method of accounting for oil and gas activities. Typically, this methodology does not allow for gain or loss on sale and proceeds from sale are credited against the full cost pool. Gain or loss recognition is allowed when such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Williston Basin asset sale significantly altered the relationship and accordingly we recorded a gain of $29 million with the remainder of the proceeds recorded as a reduction in the full cost pool. As a result of the reduction in the full cost pool from the sale of these assets, the depreciation, depletion, and amortization rate declined during 2013.

Net cash proceeds, subsequent to the true-up of all post-closing adjustments, were as follows (in thousands):



Cash proceeds received on date of sale	$	243,314
Less:
Post close adjustments	2,793
Transaction adviser fees	(1,400		)
Estimated payment for contractual obligation related to “back-in” fee *	(16,847		)
Net cash proceeds	$	227,860

_____________


*	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Discontinued Operations

Results of operations for discontinued operations have been classified as Income from discontinued operations, net of income taxes in the accompanying Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been classified and reflected on the accompanying Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassification on a consistent basis.

Energy Marketing Segment

On Feb. 29, 2012, we sold the outstanding stock of our Energy Marketing segment, Enserco Energy Inc. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds at date of sale were approximately $165 million, subject to final post-closing adjustments. Those proceeds represented $108 million received from the buyer and $58 million cash retained from Enserco before closing.

The buyer asserted certain purchase price adjustments, some that we accepted, and several that we disputed. The disputed claims were substantially resolved in our favor through a binding arbitration decision dated Jan. 17, 2014. We expensed $1.4 million in 2012, relative to purchase price adjustments we accepted through a partial settlement agreement with the buyer, and an additional $1.1 million in 2013 relative to the claims assigned to arbitration. Loss from discontinued operations was $0.9 million and $7.0 million for the twelve months ended Dec. 31, 2013 and 2012, respectively. Results for 2013 include the settlement of unresolved purchase price adjustments.

Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Consolidated Statements of Income were as follows (in thousands):



For the Years Ended Dec. 31,	2013			2012			2011

Revenue	$	—		$	(604	)	$	41,101

Pre-tax income (loss) from discontinued operations	—			(6,061		)	14,838
Pre-tax gain (loss) on sale	(1,391		)	(4,184		)	—
Income tax (expense) benefit	507			3,268			(5,473		)
Income (loss) from discontinued operations, net of tax^(a)	$	(884	)	$	(6,977	)	$	9,365

________


(a)	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended Dec. 31, 2012.

Total indirect corporate costs and inter-segment interest expenses previously allocated to Enserco were not reclassified to discontinued operations in accordance with GAAP and instead have been reclassified to our Corporate segment.

The entire disclosure for the facts and circumstances leading to the completed or expected disposal, manner and timing of disposal, the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the segment in which the disposal group was reported, and the classification (whether sold or classified as held for sale) and carrying value of the assets and liabilities comprising the disposal group. Includes all disposal groups, including those classified as components of the entity (discontinued operations).

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Quarterly Financial Information Disclosure [Abstract]

Quarterly Historical Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information [Text Block]

QUARTERLY HISTORICAL DATA (Unaudited)

The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2013 and 2012.



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2013
Revenue	$	380,671	$	279,826	$	259,907	$	355,448
Operating income	$	79,846	$	49,037	$	55,566	$	71,103
Income (loss) from continuing operations^{(a) (b)}	$	43,197	$	30,518	$	23,124	$	19,007
Income (loss) from discontinued operations	$	—	$	—	$	—	$	(884	)
Net income (loss) available for common stock ^{(a) (b)}	$	43,197	$	30,518	$	23,124	$	18,123

Income (loss) per share for continuing operations - Basic	$	0.98	$	0.69	$	0.52	$	0.43
Income (loss) per share for discontinued operations - Basic	—		—		—		(0.02		)
Income (loss) per share - Basic	$	0.98	$	0.69	$	0.52	$	0.41

Income (loss) per share for continuing operations - Diluted	$	0.97	$	0.69	$	0.52	$	0.43
Income (loss) per share for discontinued operations - Diluted	—		—		—		(0.02		)
Income (loss) per share - Diluted	$	0.97	$	0.69	$	0.52	$	0.41

Dividends paid per share	$	0.380	$	0.380	$	0.380	$	0.380

Common stock prices - High	$	44.32	$	50.53	$	55.09	$	54.83
Common stock prices - Low	$	36.89	$	43.19	$	46.62	$	47.00

__________________________


(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million, and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.

(b)

Fourth quarter 2013 includes $7.6 million after-tax for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt, and a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2012
Revenue	$	365,851		$	242,363		$	246,808		$	318,862
Operating income^(a)	$	70,048		$	20,591		$	77,810		$	75,262
Income (loss) from continuing operations ^{(b) (c) (d)}	$	35,271		$	(12,323	)	$	34,623		$	30,934
Income (loss) from discontinued operations	$	(5,484	)	$	(1,160	)	$	(166	)	$	(167	)
Net income (loss) available for common stock ^{(b) (c) (d)}	$	29,787		$	(13,483	)	$	34,457		$	30,767

Income (loss) per share for continuing operations - Basic	$	0.81		$	(0.28	)	$	0.79		$	0.70
Income (loss) per share for discontinued operations - Basic	(0.13		)	(0.03		)	—			—
Income (loss) per share - Basic	$	0.68		$	(0.31	)	$	0.79		$	0.70

Income (loss) per share for continuing operations - Diluted	$	0.80		$	(0.28	)	$	0.78		$	0.70
Income (loss) per share for discontinued operations - Diluted	(0.12		)	(0.03		)	—			—
Income (loss) per share - Diluted	$	0.68		$	(0.31	)	$	0.78		$	0.70

Dividends paid per share	$	0.370		$	0.370		$	0.370		$	0.370

Common stock prices - High	$	35.82		$	34.31		$	36.28		$	37.00
Common stock prices - Low	$	32.18		$	31.32		$	30.29		$	33.51

__________________________


(a)	Second quarter includes a pre-tax ceiling test impairment loss of $27 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27 million and $1.8 million, respectively.


(b)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.


(c)	Second quarter includes an after-tax ceiling test impairment loss of $17 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $18 million and $1.2 million, respectively.


(d)	Fourth quarter includes a $4.6 million after-tax make-whole provision for the early redemption of our $225 million notes.

Schedule I Disclosures for Parent Company Only

12 Months Ended

Dec. 31, 2013

Condensed Statement of Income [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF INCOME



	2013			2012			2011
	(in thousands)

Revenue	$	—		$	—		$	—
Operating expenses	1,339			831			772
Operating income (loss)	(1,339		)	(831		)	(772		)

Other income (expense):
Equity income (loss) in earnings of subsidiaries	100,690			93,479			87,150
Interest expense	(7,827		)	(19,665		)	(15,229		)
Unrealized gain (loss) on interest rate swaps, net	30,169			1,882			(42,010		)
Interest income	30			32			3
Other income (expense), net	(3		)	49			(42		)
Total other income (expense)	123,059			75,777			29,872
Income (loss) before income taxes	121,720			74,946			29,100
Income tax benefit (expense)	(6,758		)	6,582			20,630
Net income (loss) available for common stock	$	114,962		$	81,528		$	49,730

The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

Condensed Statement of Comprehensive Income [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



Years ended (in thousands)	Dec. 31, 2013			Dec. 31, 2012			Dec. 31, 2011

Net income (loss) available for common stock	$	114,962		$	81,528		$	49,730

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $(3,813), $296 and $4,135, respectively)	8,237			(542		)	(7,609		)
Benefit plan liability adjustments - prior service (costs) (net of tax of $185, $86 and $176, respectively)	(406		)	(157		)	(325		)
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(971), $0 and $0)	1,820			—			—
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $88, $0 and $0)	(165		)	—			—
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(2,445), $887 and $1,708, respectively)	4,534			(1,268		)	(2,831		)
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $(2,016), $534 and $(709), respectively)	4,046			(643		)	1,468
Other comprehensive income (loss), net of tax, including earnings (loss) of consolidated subsidiaries	18,066			(2,610		)	(9,297		)

Comprehensive income (loss)	$	133,028		$	78,918		$	40,433

The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

Condensed Balance Sheet [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED BALANCE SHEETS



At Dec. 31,	2013		2012
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,664	$	1,266
Accounts receivable — affiliates, current	1,000		2,194
Notes receivable — affiliates, current	393,586		637,586
Income tax receivable, net	14,530		5,843
Deferred income tax assets, net, current	—		29,779
Other current assets	4,705		4,887
Total current assets	415,485		681,555

Property and Equipment	6,259		1,135

Investments in subsidiaries	1,237,876		1,194,501

Notes receivable — affiliate, non-current	685,000		250,000
Deferred income tax assets, net, non-current	67,958		41,494
Other assets, non-current	9,256		4,014
Total other assets, non-current	762,214		295,508

TOTAL ASSETS	$	2,421,834	$	2,172,699

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable - affiliate, current	$	372	$	565
Derivative liabilities, current	3,474		91,617
Deferred income taxes	12,775		—
Notes payable	82,500		277,000
Notes payable — affiliate, current	—		1,032
Current maturities of long-term debt	—		100,000
Other current liabilities	9,351		9,943
Total current liabilities	108,472		480,157

Derivative liabilities, non-current	5,614		9,252

Long-term debt, net of current maturities	1,000,000		450,000
Note payable — affiliate, non-current	—		781
Total long-term debt	1,000,000		450,781

Total stockholders’ equity	1,307,748		1,232,509

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,421,834	$	2,172,699

The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

Condensed Statement of Cash Flows [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF CASH FLOWS



Years ended Dec. 31,	2013			2012			2011
	(in thousands)
Operating activities:
Net income (loss) available for common stock	$	114,962		$	81,528		$	49,730
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities —
Equity in earnings of subsidiaries	(100,690		)	(93,479		)	(87,150		)
Dividend from subsidiaries	—			—			14,500
Stock compensation	12,595			8,271			5,643
Unrealized gain (loss) on interest rate swaps, net	(30,169		)	(1,882		)	42,010
Deferred income taxes	10,504			(8,116		)	2,599
Other adjustments, net	3,099			3,909			4,376
Change in certain operating assets and liabilities:
Accounts receivable and other current assets	(3,184		)	6,541			(5,141		)
Accounts payable and other current liabilities	(7,881		)	(6,764		)	3,550
Other operating activities	20,386			(7,816		)	2,841
Net cash provided by (used in) operating activities	19,622			(17,808		)	32,958

Investing activities:
Property, plant and equipment additions	(5,124		)	—			(1,135		)
Decrease (increase) in advances to affiliates	(133,685		)	96,073			(258,117		)
Other investing activities	—			450			—
Net cash provided by (used in) investing activities	(138,809		)	96,523			(259,252		)

Financing activities:
Dividends paid on common stock	(67,587		)	(65,262		)	(59,202		)
Common stock issued	4,356			4,726			123,041
Short-term borrowings -- repayments	(532,150		)	(271,753		)	(821,300		)
Short-term borrowings -- issuances	337,650			203,753			1,017,300
Increase (decrease) in notes payable to affiliates	(1,813		)	275,806			(25,302		)
Long-term debt — issuance	800,000			—			—
Long-term debt — repayment	(350,000		)	(225,000		)	—
De-designated interest swap settlement	(63,939		)	—			—
Other financing activities	(6,932		)	(2,833		)	(5,348		)
Net cash provided by (used in) financing activities	119,585			(80,563		)	229,189
Net change in cash and cash equivalents	398			(1,848		)	2,895

Cash and cash equivalents beginning of year	1,266			3,114			219
Cash and cash equivalents end of year	$	1,664		$	1,266		$	3,114



Supplemental Cash Flow Information
Years ended	Dec. 31, 2013			Dec. 31, 2012			Dec. 31, 2011
	(in thousands)
Non-cash investing and financing activities-
Non-cash adjustment to notes receivable from affiliates	$	57,315		$	40,039		$	—
Non-cash adjustment to notes payable to affiliates	$	—		$	(277,560	)	$	—
Non-cash dividend, net of non-cash contributions, from affiliates	$	(57,315	)	$	237,521		$	—

Cash (paid) refunded during the period for-
Interest	$	(6,638	)	$	(18,550	)	$	(14,667	)
Income taxes	$	(4,510	)	$	3,911		$	23,830

The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

Condensed Footnotes Of Parent [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

NOTES TO BLACK HILLS CORPORATION (PARENT COMPANY) CONDENSED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Pursuant to rules and regulations of the SEC, the unconsolidated condensed financial statements of Black Hills Corporation do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Annual Report on Form 10-K.

Dividends paid and distributed to Black Hills Corporation (the Parent) from its subsidiaries were as follows (in thousands):



	2013			2012		2011
Cash dividends paid to Parent by subsidiaries	$	—		$	—	$	14,500
Non-Cash dividends, net of non-cash contributions, distributed to Parent by subsidiaries	$	(57,315	)	$	237,521	$	—

(2) NOTES RECEIVABLE AND NOTES PAYABLE

Black Hills Corporation has notes receivable and notes payable with affiliates under Utility Money Pool Agreements and Non-Utility Money Pool Agreements. Borrowings under these agreements bear interest at the weighted average daily cost of external funds as defined under the agreements.

Additionally, as of Dec. 31, 2013, Black Hills Corporation has a Revolving Credit Facility and a corporate term loan with various banks. Our credit facility and debt securities contain certain restrictive financial covenants. At Dec. 31, 2013, we were in compliance with all of these covenants. See Note 6 to Notes to Consolidated Financial Statements on this Annual Report on Form 10-K.

(3) LONG-TERM DEBT

Long-term debt outstanding at Dec. 31 was as follows (in thousands):



		Interest Rate at
	Due Date	Dec. 31, 2013	2013		2012

Senior unsecured notes due 2023 ^(a)	Nov. 30, 2023	4.25%	$	525,000	$	—
Senior unsecured notes due 2014 ^(b)	May 15, 2014	9.00%	—		250,000
Senior unsecured notes due 2020 ^(c)	July 15, 2020	5.88%	200,000		200,000
Long-term term loan^{(d) (f)}	Sept. 30, 2013	NA	—		100,000
Corporate term loan due 2015 ^{(e) (f)}	June 19, 2015	1.31%	275,000		—
Total long-term debt			1,000,000		550,000
Less current maturities			—		100,000
Net long-term debt			$	1,000,000	$	450,000

_______________


(a)	$410 million of this senior unsecured note has been recorded at Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.


(b)	For 2012, this senior unsecured note was recorded by Black Hills Utility Holdings and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets. This note was redeemed on Dec. 19, 2013 with proceeds from the issuance of the Senior unsecured notes due 2023.


(c)	This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012 and 2013.


(d)	This term loan was repaid on June 21, 2013, and replaced with the Long-term term loan due June 19, 2015. In 2012, this term loan was recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2013.


(e)	This debt has been recorded at our Power Generation segment and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets at 2013.

(f) Variable interest rate.

Certain debt instruments of the Company contain restrictions and covenants, all of which we were in compliance with at Dec. 31, 2013.

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2014	$	—
2015	$	275,000
2016	$	—
2017	$	—
2018	$	—
Thereafter	$	725,000

(4) GUARANTEES

(5) RISK MANAGEMENT ACTIVITIES AND FAIR VALUE MEASUREMENTS

We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. See Note 8 and 9 of Notes to Consolidated Financial Statements on this Annual Report on Form 10-K for further information.

On Dec. 31 our interest rate swaps and related balances were as follows (dollars in thousands):



	2013			2012
	Interest Rate Swaps			Interest Rate Swaps			De-designated Interest Rate Swaps ^{(a) (b)}
Notional	$	75,000		$	75,000		$	250,000
Weighted average fixed interest rate	4.97		%	4.97		%	5.67		%
Maximum terms in years	3.0			4.0			1.0
Current derivative liabilities	$	3,474		$	3,469		$	88,148
Non-current derivative liabilities	$	5,614		$	9,252		$	—
Pre-tax accumulated other comprehensive (loss)	(9,088		)	$	(12,721	)	$	—
Cash collateral receivable (payable) included in derivatives	$	—		$	—		$	5,960

________________________


(a)	Maximum terms in years reflect the amended early termination dates. These swaps were settled in 2013.


(b)	Included on the Condensed Statements of Income of the Parent is the non-cash mark-to-market gains recorded on these De-designated interest rate swaps of $30 million and $1.9 million for the twelve months ended Dec. 31, 2013 and 2012, respectively.

Based on Dec. 31, 2013 market interest rates and balances, a loss of approximately $3.5 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will change during the future periods as market interest rates fluctuate.

(6) FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at Dec. 31 were as follows (in thousands):



	2013				2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	1,664	$	1,664	$	1,266	$	1,266
Notes payable ^(a)	$	82,500	$	82,500	$	277,000	$	277,000
Long-term debt ^(b)	$	1,000,000	$	1,028,384	$	550,000	$	615,239

______________


(a)	Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.


(b)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Cash and Cash Equivalents

Notes Payable

2013 Notes Payable represents our Revolving Credit Facility while 2012 also includes certain corporate term loans.

Long-Term Debt

For additional information see Note 3 of these Black Hills Corporation (the Parent) Condensed Financial Statements.

(7) STOCK

Forward Equity Issuance

In November 2011, we settled the equity forward agreement. For additional information see Note 11 of the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

(8) COMMITMENTS AND CONTINGENCIES

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the condensed financial statements are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations, will not exceed the amounts reflected in the condensed financial statements.

Schedule II Consolidated Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2013

Valuation and Qualifying Accounts Disclosure [Line Items]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

SCHEDULE II



BLACK HILLS CORPORATION CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2013, 2012, AND 2011

Description	Balance at Beginning of Year		Adjustments		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions			Balance at End of Year
	(in thousands)
Allowance for doubtful accounts:
2013	$	768	$	—	$	2,780	$	4,999	$	(7,310	)	$	1,237
2012	$	1,661	$	—	$	1,913	$	3,822	$	(6,628	)	$	768
2011	$	2,295	$	—	$	3,042	$	5,369	$	(9,045	)	$	1,661

Business Description and Significant Accounting Policies Business Description (Policies)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [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, Wyo. 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. The Non-regulated Energy Group includes our Power Generation, Coal Mining and Oil and Gas segments. 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, Wyo. Oil and Gas, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. These businesses are aggregated for reporting purposes as Non-regulated Energy. On Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. See Note 21 for additional information.
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. 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 and controlled 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 inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company revenues, see Note 4. 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 any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 3 for additional information. As a result of the 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 21 for additional information.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash and Equivalents The Black Hills Wyoming project financing required that we maintain cash accounts for various specified purposes. We did not readily have access to these accounts and could only withdraw funds upon meeting certain requirements. Therefore, we had classified these amounts as restricted cash. This project financing was repaid in 2013.
Trade and Other Accounts Receivable, Policy [Policy Text Block]	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Utilities Group primarily 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. We maintain an allowance for doubtful accounts which reflects our estimate of 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. We utilize master netting agreements which consist 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.
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 and 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. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month, and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.
Inventory, Policy [Policy Text Block]	Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas, and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas 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 regulated utility 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 regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility 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 plus cost of removal, 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, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various class of property. 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 typically treated as adjustments to the cost of the properties with no gain or loss recognized. However, we recognized a gain on the sale of a majority of our Williston Basin assets in 2012. See Note 21 for further discussion. 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 an SEC required rate, 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. As a result of lower natural gas prices, we recorded a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment in 2012. No ceiling test write-down was recorded in 2013 or 2011. 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 20. 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 Goodwill and intangible assets with indefinite lives are not amortized but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform this annual review of goodwill and indefinite lived intangible assets as of Nov. 30 each year (or more frequently if impairment indicators arise). We performed our annual goodwill impairment tests as of Nov. 30, 2013. 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.
Asset Retirement Obligations, Policy [Policy Text Block]	Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset. 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 our non-regulated operations, other than Oil and Gas. 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.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value 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 or 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 its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
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 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.
Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block]	We utilize master netting agreements which consist 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.
Deferred Financing Costs, Policy [Policy Text Block]	Deferred Financing Costs Deferred financing costs are amortized using the effective interest method over the estimated useful life 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. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. If the loss contingency at issue is not both probable and reasonably estimable, we do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable.
Public Utilities, Policy [Policy Text Block]	Regulatory Accounting Our Utilities Group follows accounting standards for regulated operations and reflects the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. 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. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which would require these net assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.
Income Tax, Policy [Policy Text Block]	Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. Each tax paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments 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 as allowed by our rate-regulated jurisdictions. 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. 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.
Earnings Per Share, Policy [Policy Text Block]	Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Income (loss) from continuing or discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to outstanding stock options, restricted stock and performance shares under our equity compensation plans.
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. 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 21 for additional information.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Adopted Accounting Standards Inclusion of the Fed Funds Effective Swap Rate as a Benchmark Interest Rate for Hedge Accounting Purposes, ASU 2013-10 In July 2013, the FASB issued an amendment to accounting for derivatives and hedges to permit the Fed Funds Effective Swap Rate to be used as a U.S. benchmark interest rate for hedge accounting purposes effective for new or re-designated hedging relationships entered into on or after July 17, 2013. The amendment also removed the restriction on using different benchmark rates for similar hedges. The adoption had no impact on our consolidated financial position, results of operations or cash flows. Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, ASU 2013-01 In December 2011, the FASB issued revised accounting guidance to amend ASC 210, Balance Sheet, related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company’s netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance was effective on a retrospective basis for interim and annual periods beginning Jan. 1, 2013. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and Deferral of the Effective Date for Amendments to the Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05 and ASU 2011-12 FASB issued an accounting standards update amending accounting standards for comprehensive income to improve the comparability, consistency and transparency of reporting. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU 2011-05 requires retrospective application, and it was effective for fiscal years, and interim periods within those years, beginning after Dec. 15, 2011, with early adoption permitted. In Dec. 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income. Ultimately FASB chose not to reinstate the reclassification adjustment requirements in ASU 2011-05 but instead issued ASU 2013-02 in February 2013. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, ASU 2013-02 In February 2013, the FASB issued new disclosure requirements for items reclassified out of AOCI to expand the disclosure requirements in ASC 220, Comprehensive Income, for presentation of changes in AOCI. ASU 2013-02 requires disclosure (1) of changes in components of other comprehensive income, (2) for items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) of cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2012. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 33-9286, 33-9338, 34-67717, and 34-67716 In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition, many of the transactions which were previously classified as swaps have been converted to exchange-traded futures contracts, which are subject to futures margin posting requirements. In August 2012, under Dodd-Frank, the SEC adopted new requirements for companies that manufacture or contract to manufacture products that contain certain minerals and metals, known as conflict minerals. The final rule requires all issuers that file reports with the SEC and use conflict minerals to report supply chain and sourcing information on an annual basis. We completed due diligence efforts in 2013, and we do not believe that our products contain conflict minerals as defined by the rule. Recently Issued Accounting Pronouncements and Legislation Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, ASU 2013-11 In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after Dec. 15, 2013, and interim periods within those years and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard is not expected to have an impact on our financial position, results of operations or cash flows. Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, ASU 2013-04 In March 2013, the FASB issued new disclosure requirements for recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements including disclosure of the nature and amount of the obligations. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2013. The amendment requires enhanced disclosures in the notes to financial statements, but will not have any other impact on our consolidated financial statements. Final Tangible Personal Property Regulations, IRS Treasury Decision 9636 In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations have the effect of a change in law and as a result the impact should be taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after Jan. 1, 2014, with early adoption permitted. We expect that implementation of most, if not all, of the provisions of the final regulations in 2014. Procedural guidance is expected from IRS in early 2014 to facilitate implementation. Analysis performed to date indicates no material impact to our consolidated financial statements.

Business Description and Significant Accounting Policies Business Description (Tables)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Accounts Receivable and Allowance for Doubtful Accounts

Following is a summary of accounts receivable as of Dec. 31 (in thousands):



2013	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	52,437	$	23,823	$	(666	)	$	75,594
Gas Utilities	49,162		41,195		(558		)	89,799
Power Generation	1,722		—		—			1,722
Coal Mining	1,711		—		—			1,711
Oil and Gas	8,156		—		(13		)	8,143
Corporate	604		—		—			604
Total	$	113,792	$	65,018	$	(1,237	)	$	177,573



2012	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	54,482	$	23,843	$	(527	)	$	77,798
Gas Utilities	31,495		39,962		(222		)	71,235
Power Generation	16		—		—			16
Coal Mining	2,247		—		—			2,247
Oil and Gas	11,622		—		(19		)	11,603
Corporate	799		—		—			799
Total	$	100,661	$	63,805	$	(768	)	$	163,698

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of (in thousands):



	Dec. 31, 2013		Dec. 31, 2012
Materials and supplies	$	50,196	$	43,397
Fuel - Electric Utilities	6,213		8,589
Natural gas in storage held for distribution	32,069		25,657
Total materials, supplies and fuel	$	88,478	$	77,643

Goodwill

Goodwill balances were as follows (in thousands):



	Electric Utilities		Gas Utilities		Power Generation		Total
Ending balance at Dec. 31, 2011	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2012	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2013	$	250,487	$	94,144	$	8,765	$	353,396

Intangible Assets

Changes to intangible assets for the years ended Dec. 31, were as follows (in thousands):



	2013			2012			2011
Intangible assets, net, beginning balance	$	3,620		$	3,843		$	4,069
Additions (adjustments)	—			—			—
Amortization expense *	(223		)	(223		)	(226		)
Intangible assets, net, ending balance	$	3,397		$	3,620		$	3,843

_________________


*	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of the next five years.

Regulatory Assets and Liabilities

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



	Maximum
	Amortization	As of		As of
	(in years)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)	1	$	16,775	$	16,005
Deferred gas cost adjustments and gas price derivatives^(a)	7	12,366		20,741
AFUDC^(b)	45	12,315		12,416
Employee benefit plans ^(c)	13	67,059		115,521
Environmental^(a)	subject to approval	1,800		1,792
Asset retirement obligations^(a)	44	3,266		3,247
Bond issue cost^(a)	24	3,419		3,561
Renewable energy standard adjustment ^(a)	5	14,186		19,484
Flow through accounting^(d)	35	20,916		16,620
Other regulatory assets^(a)	15	10,546		10,006
		$	162,648	$	219,393

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	11,708	$	21,091
Employee benefit plans^(e)	13	34,431		59,362
Cost of removal^(a)	44	64,970		53,526
Other regulatory liabilities^(f)	25	9,047		7,305
		$	120,156	$	141,284

__________


(a)	Recovery of costs, but not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery of costs, we are allowed a return on approximately $25 million.


(d)	In addition to recovery of costs, we are allowed a return on approximately $5.4 million.


(e)	Approximately $13 million is included in our rate base calculations as a reduction to rate base.


(f)	Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.

Earnings Per Share Reconciliation

A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):



	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Income (loss) from continuing operations	$	115,846	$	88,505	$	40,365

Weighted average shares - basic	44,163		43,820		39,864
Dilutive effect of:
Equity compensation	256		250		214
Other	—		3		3
Weighted average shares - diluted	44,419		44,073		40,081

Income (loss) from continuing operations, per share - Diluted	$	2.61	$	2.01	$	1.01

Antidilutive Securities

The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):



	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity compensation	22	163	141
Other	—	—	—
Anti-dilutive shares excluded from computation of earnings (loss) per share	22	163	141

Property, Plant and Equipment Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

Property, plant and equipment at Dec. 31 consisted of the following (dollars in thousands):



Utilities Group	2013			2012			Lives ( in years)
Electric Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Electric plant:
Production	$	951,138	45	$	959,636	45	25	65
Electric transmission	238,542		50	234,279		50	40	65
Electric distribution	666,589		44	631,654		44	15	65
Plant acquisition adjustment ^(a)	4,870		32	4,870		32	32	32
General	138,263		22	137,584		22	3	60
Capital lease - plant in service ^(b)	261,441		20	260,874		19	20	20
Total electric plant in service	$	2,260,843		$	2,228,897
Construction work in progress	203,760			48,008
Total electric plant	2,464,603			2,276,905
Less accumulated depreciation and amortization	472,970			439,772
Electric plant net of accumulated depreciation and amortization	$	1,991,633		$	1,837,133

_____________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 17 years remaining.


(b)	Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on Dec. 31, 2031.



	2013			2012			Lives (in years)
Gas Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Gas plant:
Production	$	13	37	$	13	37	37	37
Gas transmission	24,984		54	18,071		54	53	57
Gas distribution	507,318		46	474,998		46	41	56
General	85,841		19	68,856		19	16	22
Total gas plant in service	618,156			561,938
Construction work in progress	9,417			6,305
Total gas plant	627,573			568,243
Less accumulated depreciation and amortization	84,679			68,530
Gas plant net of accumulated depreciation and amortization	$	542,894		$	499,713



2013											Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	143,026	$	10,491	$	153,517	$	43,069	$	110,448	36	2	40
Coal Mining	149,067		1,156		150,223		86,306		63,917		14	2	59
Oil and Gas	852,384		—		852,384		585,334		267,050		24	3	25
	$	1,144,477	$	11,647	$	1,156,124	$	714,709	$	441,415



2012											Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	139,396	$	1,323	$	140,719	$	38,541	$	102,178	35	2	40
Coal Mining	148,045		7,023		155,068		80,210		74,858		14	2	59
Oil and Gas	785,594		—		785,594		562,926		222,668		24	3	25
	$	1,073,035	$	8,346	$	1,081,381	$	681,677	$	399,704



2013												Lives ( in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	5,498	$	5,647	$	11,145	$	(3,210	)	$	14,355	6	2	30

___________


(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.



2012												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	368	$	3,875	$	4,243	$	(1,956	)	$	6,199	6	2	30

___________


(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.

Jointly Owned Facilities Jointly Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

At Dec. 31, 2013, our interests in jointly-owned generating facilities and transmission systems were (in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,800	$	192	$	50,595
Transmission Tie	$	19,648	$	—	$	4,741
Wygen I	$	106,489	$	1,412	$	28,432
Wygen III	$	131,468	$	713	$	10,593
Busch Ranch Wind Project	$	18,590	$	—	$	841

Business Segments Business Segments Information (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting Information, Additional Information [Abstract]

Segment information included in Condensed Consolidated Balance Sheets

Segment information was as follows (in thousands):



Total Assets (net of inter-company eliminations) as of Dec. 31,	2013		2012
Utilities:
Electric ^(a)	$	2,525,947	$	2,387,458
Gas	805,617		765,165
Non-regulated Energy:
Power Generation^(a)	95,692		119,170
Coal Mining	78,825		83,810
Oil and Gas	288,366		258,460
Corporate	80,731		115,408
Total assets	$	3,875,178	$	3,729,471

__________________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.



Capital Expenditures and Asset Acquisitions^(a) for the years ended Dec. 31,	2013		2012
Utilities:
Electric Utilities	$	222,262	$	167,263
Gas Utilities	63,205		45,711
Non-regulated Energy:
Power Generation	13,533		5,547
Coal Mining	5,528		13,420
Oil and Gas	64,687		107,839
Corporate	10,319		7,376
Total capital expenditures and asset acquisitions of continuing operations	379,534		347,156
Total capital expenditures of discontinued operations	—		824
Total capital expenditures and asset acquisitions	$	379,534	$	347,980

_________________


(a)	Includes accruals for property, plant and equipment.



Property, Plant and Equipment as of Dec. 31,	2013		2012
Utilities:
Electric Utilities ^(a)	$	2,464,603	$	2,276,905
Gas Utilities	627,573		568,243
Non-regulated Energy:
Power Generation ^(a)	153,517		140,719
Coal Mining	150,223		155,068
Oil and Gas	852,384		785,594
Corporate	11,145		4,243
Total property, plant and equipment	$	4,259,445	$	3,930,772

_______________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded for at Colorado Electric under accounting for a capital lease.

Segment information included in Condensed Consolidated Statements of Income



	Consolidating Income Statement
Year ended Dec. 31, 2013	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	651,445		$	539,689		$	4,648		$	25,186		$	54,884		$	—		$	—		$	1,275,852
Inter-company revenue	13,863			—			78,389			31,442			—			220,620			(344,314		)	—
Total revenue	665,308			539,689			83,037			56,628			54,884			220,620			(344,314		)	1,275,852

Fuel, purchased power and cost of natural gas sold	294,048			310,463			—			—			—			125			(112,489		)	492,147
Operations and maintenance	159,961			126,073			30,186			39,519			40,365			202,809			(211,977		)	386,936
Gain on sale of operating assets	—			—			—			—			—			—			—			—
Depreciation, depletion and amortization	77,704			26,381			5,091			11,523			21,770			11,624			(12,876		)	141,217
Operating income (loss)	133,595			76,772			47,760			5,586			(7,251		)	6,062			(6,972		)	255,552

Interest expense ^(a)	(61,537		)	(25,234		)	(21,178		)	(641		)	(2,253		)	(85,195		)	84,250			(111,788		)
Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			30,169			—			30,169
Interest income	5,277			976			785			10			1,639			69,760			(76,724		)	1,723
Other income (expense), net	633			(60		)	1			2,304			108			41,453			(42,641		)	1,798
Income tax benefit (expense)	(25,834		)	(19,747		)	(11,080		)	(932		)	3,545			(7,778		)	218			(61,608		)
Income (loss) from continuing operations	$	52,134		$	32,707		$	16,288		$	6,327		$	(4,212	)	$	54,471		$	(41,869	)	$	115,846

________________


(a)	Power Generation includes costs associated with interest rate swaps settled and write-off of deferred financing costs upon repayment of Black Hills Wyoming Project Financing and Corporate includes a the write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt (see Note 5).



	Consolidating Income Statement
Year ended Dec. 31, 2012	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	610,732		$	454,081		$	4,189		$	25,810		$	79,072		$	—		$	—		$	1,173,884
Inter-company revenue	16,234			—			75,200			31,968			—			196,453			(319,855		)	—
Total revenue	626,966			454,081			79,389			57,778			79,072			196,453			(319,855		)	1,173,884

Fuel, purchased power and cost of natural gas sold	273,474			245,349			—			—			—			—			(111,757		)	407,066
Operations and maintenance	146,527			117,390			29,991			42,553			43,267			179,059			(188,051		)	370,736
Gain on sale of operating assets ^(a)	—			—			—			—			(29,129		)	—			—			(29,129		)
Depreciation, depletion and amortization	75,244			25,163			4,599			13,060			38,494			10,936			(12,864		)	154,632
Impairment of long-lived assets^(b)	—			—			—			—			26,868			—			—			26,868
Operating income (loss)	131,721			66,179			44,799			2,165			(428		)	6,458			(7,183		)	243,711

Interest expense ^(c)	(59,194		)	(26,746		)	(15,452		)	(238		)	(4,539		)	(92,650		)	85,209			(113,610		)
Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			1,882			—			1,882
Interest income	8,153			2,765			695			1,168			604			64,695			(76,123		)	1,957
Other income (expense), net	1,182			105			7			2,616			207			48,769			(49,921		)	2,965
Income tax benefit (expense)	(30,264		)	(14,313		)	(8,721		)	(85		)	1,927			3,187			(131		)	(48,400		)
Income (loss) from continuing operations	$	51,598		$	27,990		$	21,328		$	5,626		$	(2,229	)	$	32,341		$	(48,149	)	$	88,505

________________


(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).


(b)	Oil and Gas includes a ceiling test impairment (see Note 12).


(c)	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 5).



	Consolidating Income Statement
Year ended Dec. 31, 2011	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	600,935		$	554,584		$	4,059		$	32,802		$	79,808		$	—		$	—		$	1,272,188
Inter-company revenue	13,396			—			27,613			34,090			—			192,250			(267,349		)	—
Total revenue	614,331			554,584			31,672			66,892			79,808			192,250			(267,349		)	1,272,188

Fuel, purchased power and cost of natural gas sold	310,352			331,961			—			—			—			97			(67,421		)	574,989
Operations and maintenance	142,815			121,980			16,538			56,617			41,380			170,947			(174,908		)	375,369
Gain on sale of operating assets ^(a)	(768		)	—			—			—			—			1			767			—
Depreciation, depletion and amortization	52,475			24,307			4,199			18,670			35,690			11,205			(10,955		)	135,591
Operating income (loss)	109,457			76,336			10,935			(8,395		)	2,738			10,000			(14,832		)	186,239

Interest expense	(53,770		)	(31,621		)	(8,903		)	(9		)	(5,896		)	(93,314		)	102,130			(91,383		)
Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			(42,010		)	—			(42,010		)
Interest income	14,794			5,645			1,529			3,897			2			64,299			(88,149		)	2,017
Other income (expense), net	481			217			1,094			2,192			(216		)	46,510			(46,552		)	3,726
Income tax benefit (expense)	(23,271		)	(16,408		)	(1,644		)	1,891			1,651			19,289			268			(18,224		)
Income (loss) from continuing operations	$	47,691		$	34,169		$	3,011		$	(424	)	$	(1,721	)	$	4,774		$	(47,135	)	$	40,365

_________________


(a)	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.

Long-Term Debt Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

Long-term debt outstanding was as follows (dollars in thousands) as of:



		Interest Rate at
	Due Date	Dec. 31, 2013	Dec. 31, 2013			Dec. 31, 2012
Corporate
Senior unsecured notes due 2023	Nov. 30, 2023	4.25%	$	525,000		$	—
Senior unsecured notes due 2014^(a)	May 15, 2014	9.00%	—			250,000
Senior unsecured notes due 2020	July 15, 2020	5.88%	200,000			200,000
Corporate term loan due 2013 ^(a)	Sept. 30, 2013	NA	—			100,000
Corporate term loan due 2015 ^(b)	June 19, 2015	1.31%	275,000			—
Total Corporate Debt			1,000,000			550,000

Electric Utilities
First Mortgage Bonds due 2032	Aug. 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	Nov. 1, 2039	6.13%	180,000			180,000
Unamortized discount on First Mortgage Bonds due 2039			(107		)	(111		)
Pollution control revenue bonds due 2024	Oct. 1, 2024	5.35%	12,200			12,200
First Mortgage Bonds due 2037	Nov. 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021, variable rate ^(c)	Sept. 1, 2021	0.11%	7,000			7,000
Industrial development revenue bonds due 2027, variable rate ^(c)	March 1, 2027	0.11%	10,000			10,000
Series 94A Debt, variable rate ^(c)	June 1, 2024	0.75%	2,855			2,855
Total Electric Utilities			396,948			396,944

Power Generation
Black Hills Wyoming project financing, variable rate ^(a)	Dec. 9, 2016	3.59%	—			95,906

Total long-term debt			1,396,948			1,042,850
Less current maturities			—			103,973
Long-term debt, net of current maturities			$	1,396,948		$	938,877

_______________


(a)	This debt repaid. See Debt Transactions discussed below.


(b)	Variable interest rates, based on LIBOR plus a spread.

Schedule of Maturities of Long-term Debt [Table Text Block]

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2014	$	—
2015	$	275,000
2016	$	—
2017	$	—
2018	$	—
Thereafter	$	1,122,055

Deferred Financing Costs [Table Text Block]

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):



	Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheets at		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2013		2013		2012		2011
Senior unsecured notes due 2023	$	6,846	$	86	$	—	$	—
Senior unsecured notes due 2014	$	—	$	635	$	462	$	462
Senior unsecured notes due 2020	$	1,093	$	167	$	167	$	167
First mortgage bonds due 2032	$	618	$	33	$	33	$	33
First mortgage bonds due 2039	$	1,961	$	76	$	76	$	76
First mortgage bonds due 2037	$	736	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016^(a)	$	—	$	3,177	$	1,037	$	1,012
Other	$	664	$	57	$	57	$	70

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Schedule of Short-term Debt

Notes Payable Notes Payable (Tables)

12 Months Ended

Dec. 31, 2013

Line of Credit Facility

We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):



	Balance Outstanding at
	Dec. 31, 2013		Dec. 31, 2012
Revolving Credit Facility	$	82,500	$	127,000
Corporate Term Loan due June 2013	—		150,000
Total	$	82,500	$	277,000

Deferred Financing Costs [Table Text Block]

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):



	Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheets at		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2013		2013		2012		2011
Senior unsecured notes due 2023	$	6,846	$	86	$	—	$	—
Senior unsecured notes due 2014	$	—	$	635	$	462	$	462
Senior unsecured notes due 2020	$	1,093	$	167	$	167	$	167
First mortgage bonds due 2032	$	618	$	33	$	33	$	33
First mortgage bonds due 2039	$	1,961	$	76	$	76	$	76
First mortgage bonds due 2037	$	736	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016^(a)	$	—	$	3,177	$	1,037	$	1,012
Other	$	664	$	57	$	57	$	70

Schedule of Credit Facility Covenants

Our Revolving Credit Facility and our new Term Loan require compliance with the following financial covenant at the end of each quarter:

Revolving Credit Facility [Member]

Line of Credit Facility

Deferred Financing Costs [Table Text Block]

The deferred financing costs on the new facility are being amortized as follows (in thousands):



	Deferred Financing Costs Remaining on Balance Sheets as of		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2013		2013		2012		2011
Revolving Credit Facility	$	1,316	$	752	$	2,187	$	1,891

Asset Retirement Obligations Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following tables present the details of ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):



	Dec. 31, 2012		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates^(a)			Dec. 31, 2013
Electric Utilities	$	6,981	$	—	$	—		$	168	$	(227	)	$	6,922
Gas Utilities	259		—		—			15		—			274
Coal Mining	20,286		3		(714		)	1,052		—			20,627
Oil and Gas	23,022		143		(1,903		)	1,450		1,316			24,028
Total	$	50,548	$	146	$	(2,617	)	$	2,685	$	1,089		$	51,851



	Dec. 31, 2011		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates^(a)		Dec. 31, 2012
Electric Utilities	$	3,064	$	3,626	$	—		$	291	$	—	$	6,981
Gas Utilities	270		—		(22		)	11		—		259
Coal Mining	17,158		1,627		—			921		580		20,286
Oil and Gas	22,422		158		(1,059		)	1,345		156		23,022
Total	$	42,914	$	5,411	$	(1,081	)	$	2,568	$	736	$	50,548

_____________________


(a)	The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.

Risk Management Activities Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Derivative Instruments [Table Text Block]

The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	Dec. 31, 2013			Dec. 31, 2012
	Interest Rate Swaps ^(a)			Interest Rate Swaps ^(b)			De-designated Interest Rate Swaps^(c)
Notional	$	75,000		$	150,000		$	250,000
Weighted average fixed interest rate	4.97		%	5.04		%	5.67		%
Maximum terms in years	3.0			4.0			1.0
Derivative liabilities, current	$	3,474		$	7,039		$	88,148
Derivative liabilities, non-current	$	5,614		$	16,941		$	—

___________________


(a)	These swaps are designated to borrowings on our Revolving Credit Facility. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps.

(b)


(c)	Maximum terms in years reflect the amended early termination dates. If the early termination dates were not extended, the swaps would have required cash settlement based on the swap value at the termination date. These swaps were settled during the fourth quarter of 2013.

Schedule of Derivative Instruments [Table Text Block]



	Dec. 31, 2013				Dec. 31, 2012
	Crude oil futures, swaps and options		Natural gas futures, swaps and options		Crude oil futures, swaps and options		Natural gas futures, swaps and options
Notional ^(a)	412,500		7,082,500		528,000		8,215,500
Maximum terms in years ^(b)	0.25		0.08		1		0.75
Derivative assets, current	$	55	$	—	$	1,405	$	1,831
Derivative assets, non-current	$	—	$	—	$	297	$	170
Derivative liabilities, current	$	—	$	—	$	847	$	507
Derivative liabilities, non-current	$	—	$	—	$	—	$	—

________________________


(a)	Crude in Bbls, gas in MMBtu.


(b)	Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.

Utilities Group [Member]

Schedule of Derivative Instruments [Table Text Block]

We had the following derivative balances related to the hedges in our Utilities reflected in our Consolidated Balance Sheets as of (in thousands):



	Dec. 31, 2013		Dec. 31, 2012
Derivative assets, current	$	662	$	—
Derivative assets, non-current	$	—	$	43
Derivative liabilities, current	$	—	$	—
Derivative liabilities, non-current	$	—	$	—
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	7,567	$	9,596

Contract or notional amounts and terms of marketing activities and derivative commodity instruments

The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Gas Utilities were as follows, as of:



	Dec. 31, 2013		Dec. 31, 2012
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	17,930,000	84	15,350,000	83
Natural gas options purchased	3,890,000	8	2,430,000	2
Natural gas basis swaps purchased	14,785,000	60	12,020,000	72

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

Fair Value Measurements Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments, Gain (Loss)



	As of Dec. 31, 2013
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		130		—		(75		)	55
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		815		—		(815		)	—
Commodity derivatives - Utilities	—		3,030		—		(2,368		)	662
Total	$	—	$	3,975	$	—	$	(3,258	)	$	717

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		1,229		—		(1,229		)	—
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		531		—		(531		)	—
Commodity derivatives - Utilities	—		9,100		—		(9,100		)	—
Interest rate swaps	—		9,088		—		—			9,088
Total	$	—	$	19,948	$	—	$	(10,860	)	$	9,088



	As of Dec. 31, 2012
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	378	$	—	$	—		$	378
Basis Swaps -- Oil	—		1,325		—		—			1,325
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		2,000		—		—			2,000
Commodity derivatives - Utilities	—		—		43		—			43
Total	$	—	$	3,703	$	43	$	—		$	3,746

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	1,131	$	—	$	(336	)	$	795
Basis Swaps -- Oil	—		502		—		(450		)	52
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		1,127		—		(620		)	507
Commodity derivatives - Utilities	—		8,576		—		(8,576		)	—
Interest rate swaps	—		118,088		—		(5,960		)	112,128
Total	$	—	$	129,424	$	—	$	(15,942	)	$	113,482

The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Commodity derivatives - Utilities ^(a)	$	43	Independent price quotes	Long-term natural gas prices - Basis Differential	$	(0.13	)

_____________

(a)

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following tables present the changes in Level 3 recurring fair value (in thousands):



	As of Dec. 31, 2013			As of Dec. 31, 2012
Assets:	Commodity Derivatives -- Utilities			Commodity Derivatives -- Utilities
Balances as of beginning of period	$	43		$	—
Total gain (loss) included in AOCI/ Regulatory Asset	—			(54		)
Purchases	—			192
Transfers out of Level 3^(a)	(43		)	(95		)
Balances at end of period	$	—		$	43

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	(54	)

__________


(a)	Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended Dec. 31 (in thousands):



	2013			2012
Balance, beginning of period	$	7,770		$	7,043

Purchase	29,000			—
Unrealized gain (loss)	1,508			727
Realized gain (loss)	(77		)	—
Settlements	(13		)	—

Balance, end of period	$	38,188		$	7,770

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The following tables present the fair value and balance sheet classification of our derivative instruments as of Dec. 31, (in thousands):



		2013				2012
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives		Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets - current	$	248	$	—	$	2,874	$	—
Commodity derivatives	Derivative assets - non-current	698		—		510		—
Commodity derivatives	Derivative liabilities - current	—		1,541		—		1,993
Commodity derivatives	Derivative liabilities - non-current	—		219		—		821
Interest rate swaps	Derivative liabilities - current	—		3,474		—		7,038
Interest rate swaps	Derivative liabilities - non-current	—		5,614		—		16,941
Total derivatives designated as hedges		$	946	$	10,848	$	3,384	$	26,793

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	662	$	—	$	362	$	—
Commodity derivatives	Derivative assets - non-current	—		—		—		—
Commodity derivatives	Derivative liabilities - current	—		—		1,180		4,957
Commodity derivatives	Derivative liabilities - non-current	—		6,732		406		5,153
Interest rate swaps	Derivative liabilities - current	—		—		—		94,108
Interest rate swaps	Derivative liabilities - non-current	—		—		—		—
Total derivatives not designated as hedges		$	662	$	6,732	$	1,948	$	104,218

Schedule of Derivative Offsetting on Balance Sheet [Table Text Block]

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at Dec. 31, 2013 was as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	$	75	$	(75	)	$	—
Oil and Gas - Crude Options	—		—			—
Oil and Gas - Natural Gas Basis Swaps	815		(815		)	—
Utilities	3,030		(2,368		)	662
Total derivative assets subject to a master netting agreement or similar arrangement	3,920		(3,258		)	662

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	55		—			55
Oil and Gas - Crude Options	—		—			—
Oil and Gas - Natural Gas Basis Swaps	—		—			—
Utilities	—		—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	55		—			55

Total derivative assets	$	3,975	$	(3,258	)	$	717



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	$	1,229	$	(1,229	)	$	—
Oil and Gas - Crude Options	—		—			—
Oil and Gas - Natural Gas Basis Swaps	531		(531		)	—
Utilities	9,100		(9,100		)	—
Interest Rate Swaps	—		—			—
Total derivative liabilities subject to a master netting agreement or similar arrangement	10,860		(10,860		)	—

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	—		—			—
Oil and Gas - Crude Options	—		—			—
Oil and Gas - Natural Gas Basis Swaps	—		—			—
Utilities	—		—			—
Interest Rate Swaps	9,088		—			9,088
Total derivative liabilities not subject to a master netting agreement or similar arrangement	9,088		—			9,088

Total derivative liabilities	$	19,948	$	(10,860	)	$	9,088

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of Dec. 31, 2012 were as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	$	76	$	—		$	76
Oil and Gas - Crude Options	93		—			93
Oil and Gas - Natural Gas Basis Swaps	172		—			172
Utilities	1,629		(1,586		)	43
Total derivative assets subject to a master netting agreement or similar arrangement	1,970		(1,586		)	384

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	1,249		—			1,249
Oil and Gas - Crude Options	285		—			285
Oil and Gas - Natural Gas Basis Swaps	1,828		—			1,828
Utilities	—		—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	3,362		—			3,362

Total derivative assets	$	5,332	$	(1,586	)	$	3,746



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	$	449	$	(449	)	$	—
Oil and Gas - Crude Options	337		(337		)	—
Oil and Gas - Natural Gas Basis Swaps	620		(620		)	—
Utilities	8,576		(8,576		)	—
Interest Rate Swaps	—		—			—
Total derivative liabilities subject to a master netting agreement or similar arrangement	9,982		(9,982		)	—

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	52		—			52
Oil and Gas - Crude Options	795		—			795
Oil and Gas - Natural Gas Basis Swaps	507		—			507
Utilities	—		—			—
Interest Rate Swaps	118,088		(5,960		)	112,128
Total derivative liabilities not subject to a master netting agreement or similar arrangement	119,442		(5,960		)	113,482

Total derivative liabilities	$	129,424	$	(15,942	)	$	113,482

Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of Dec. 31, 2013 were (in thousands):



				Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Assets		Cash Collateral Received		Net Amount with Counterparty
Assets:
Oil and Gas	Counterparty A	$	—	$	—	$	—
Oil and Gas	Counterparty B	55		—		55
Utilities	Counterparty A	662		—		662
		$	717	$	—	$	717



				Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Liabilities		Cash Collateral Paid			Net Amount with Counterparty
Liabilities:
Oil and Gas	Counterparty A	$	—	$	(1,631	)	$	(1,631	)
Oil and Gas	Counterparty B	—		—			—
Utilities	Counterparty A	—		(3,390		)	(3,390		)
Interest Rate Swaps	Counterparty F	9,088		—			9,088
		$	9,088	$	(5,021	)	$	4,067

Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of Dec. 31, 2012 were (in thousands):



				Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Assets		Cash Collateral Received		Net Amount with Counterparty
Assets:
Oil and Gas	Counterparty A	$	341	$	—	$	341
Oil and Gas	Counterparty B	3,362		—		3,362
Utilities	Counterparty A	43		—		43
		$	3,746	$	—	$	3,746



				Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Liabilities		Cash Collateral Paid			Net Amount with Counterparty
Liabilities:
Oil and Gas	Counterparty A	$	—	$	(1,787	)	$	(1,787	)
Oil and Gas	Counterparty B	1,354		—			1,354
Utilities	Counterparty A	—		(4,354		)	(4,354		)
Interest Rate Swap	Counterparty D	4,588		—			4,588
Interest Rate Swap	Counterparty E	29,245		—			29,245
Interest Rate Swap	Counterparty F	12,721		—			12,721
Interest Rate Swap	Counterparty G	26,520		—			26,520
Interest Rate Swap	Counterparty H	16,809		—			16,809
Interest Rate Swap	Counterparty I	22,245		—			22,245
		$	113,482	$	(6,141	)	$	107,341

Designated as Hedging Instrument [Member]

Derivative Instruments, Gain (Loss)

Schedule of Derivative Instruments, Gain (Loss) [Table Text Block]

The impact of cash flow hedges on our Consolidated Statements of Income (Loss) for years ended were as follows (in thousands):



	Dec. 31, 2013
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	7,935		Interest expense	$	6,989			$	—
Commodity derivatives	(956		)	Revenue	(927		)		—
Total	$	6,979			$	6,062			$	—



	Dec. 31, 2012
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(4,794	)	Interest expense	$	(7,607	)		$	—
Commodity derivatives	2,639			Revenue	8,784				—
Total	$	(2,155	)		$	1,177			$	—



	Dec. 31, 2011
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(12,280	)	Interest expense	$	(7,664	)		$	—
Commodity derivatives	7,741			Revenue	5,487				—
Total	$	(4,539	)		$	(2,177	)		$	—

Not Designated as Hedging Instrument [Member]

Derivative Instruments, Gain (Loss)

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The impact of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended Dec. 31 were as follows (in thousands):



		2013			2012			2011
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income

Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swap, net	$	30,169		$	1,882		$	(42,010	)
Interest rate swaps - realized	Interest expense	(12,902		)	(12,959		)	(13,373		)
		$	17,267		$	(11,077	)	$	(55,383	)

Fair Value of Financial Instruments Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair value of financial instruments

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 9, were as follows at Dec. 31 (in thousands):



	2013				2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	7,841	$	7,841	$	15,462	$	15,462
Restricted cash and equivalents ^(a)	$	2	$	2	$	7,916	$	7,916
Notes payable ^(a)	$	82,500	$	82,500	$	277,000	$	277,000
Long-term debt, including current maturities ^(b)	$	1,396,948	$	1,491,422	$	1,042,850	$	1,231,559

_______________


(a)	Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.


(b)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Stock Stock (Tables)

12 Months Ended

Dec. 31, 2013

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]

Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follows for the years ended Dec. 31 (in thousands):



	2013		2012		2011
Stock-based compensation expense	$	12,595	$	8,271	$	5,643

Schedule of Share-based Compensation, Employee Stock Purchase Plan, Activity [Table Text Block]

A summary of the Dividend Reinvestment and Stock Purchase Plan for the years ended and at Dec. 31 is as follows (shares in thousands):



	2013		2012
Shares Issued	67		101

Weighted Average Price	$	46.78	$	33.58

Unissued Shares Available	286		353

Employee Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

A summary of the status of the stock options at Dec. 31, 2013 was as follows:



	Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)				(in years)	(in thousands)
Balance at beginning of period	121		$	31.23
Granted ^(a)	10		40.39
Forfeited/canceled	—		—
Expired	(4	)	29.09
Exercised	(66	)	30.87
Balance at end of period	61		$	33.25	7.3	$	1,165

Exercisable at end of period	26		$	31.69	6.5	$	534

___________________________


(a)	The grant date fair value of the 2013 awards was $7.65 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 1.4 percent risk free interest rate, 29.3 percent expected price volatility, 3.8 percent expected dividend yield and a 7 year expected life.

The table below provides details of our option plans at Dec. 31 (in thousands):



	2013		2012		2011
Summary of Stock Options
Unrecognized compensation expense	$	130	$	218	$	479
Intrinsic value of options exercised^(a)	$	789	$	623	$	94
Net cash received from exercise of options	$	2,046	$	2,839	$	1,009
Tax benefit realized from exercise of shares ^(b)	$	276	$	218	$	33

_____________________


(a)	The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.


(b)	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.

Restricted Stock [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

A summary of the status of the restricted stock at Dec. 31, 2013, was as follows:



	Restricted Stock		Weighted-Average Grant Date Fair Value
	(in thousands)
Restricted Stock balance at beginning of period	287		$	32.23
Granted	120		40.56
Vested	(138	)	30.62
Forfeited	(7	)	35.50
Restricted Stock at end of period	262		$	36.76

The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended Dec. 31, was as follows:



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2013	$	40.56	$	5,842
2012	$	34.99	$	3,781
2011	$	30.33	$	3,211

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

Outstanding performance periods at Dec. 31 were as follows (shares in thousands):



			Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares	Minimum	Maximum
Jan. 1, 2011	Jan. 1, 2011 - Dec. 31, 2013	62	0%	175%
Jan. 1, 2012	Jan. 1, 2012 - Dec. 31, 2014	64	0%	200%
Jan. 1, 2013	Jan. 1, 2013 - Dec. 31, 2015	61	0%	200%

A summary of the status of the Performance Share Plan at Dec. 31 was as follows:



	Equity Portion				Liability Portion
			Weighted-Average Grant Date Fair Value				Weighted-Average Fair Value at
	Shares		Weighted-Average Grant Date Fair Value		Shares		Dec. 31, 2013
	(in thousands)				(in thousands)
Performance Shares balance at beginning of period	96		$	27.49	96
Granted	31		35.85		31
Forfeited	(1	)	33.85		(1	)
Vested	(33	)	24.26		(33	)
Performance Shares balance at end of period	93		$	31.34	93		$	95.79

The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows:



	Weighted Average Grant Date Fair Value
Dec. 31, 2013	$	35.85
Dec. 31, 2012	$	32.26
Dec. 31, 2011	$	25.92

Performance plan payouts have been as follows (dollars and shares in thousands):



Performance Period	Year of Payment	Stock Issued	Cash Paid		Total Intrinsic Value
Jan. 1, 2010 to Dec. 31, 2012	2013	63	$	2,267	$	4,533
Jan. 1, 2009 to Dec. 31, 2011	2012	—	$	—	$	—
Jan. 1, 2008 to Dec. 31, 2010	2011	—	$	—	$	—

Operating Leases Operating Leases (Tables)

12 Months Ended

Dec. 31, 2013

Leases, Operating [Abstract]

Operating Leases of Lessor Disclosure [Text Block]



	2013		2012		2011
Rent expense	$	7,169	$	6,839	$	6,125

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):



2014	$	2,782
2015	$	2,583
2016	$	1,938
2017	$	1,747
2018	$	1,697
Thereafter	$	5,452

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Operating Loss Carryforwards [Line Items]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Income tax expense (benefit) from continuing operations for the years ended Dec. 31 was (in thousands):



	2013			2012			2011
Current:
Current federal income tax expense (benefit)	$	(2,003	)	$	4,972		$	(14,539	)
Current state income tax expense (benefit)	(173		)	3,712			(837		)
	(2,176		)	8,684			(15,376		)
Deferred:
Deferred federal income tax expense (benefit)	56,963			39,876			30,876
Deferred state income tax expense (benefit)	7,033			68			2,970
Tax credit amortization expense (benefit)	(212		)	(228		)	(246		)
	63,784			39,716			33,600

Total income tax expense (benefit)	$	61,608		$	48,400		$	18,224

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The temporary differences, which gave rise to the net deferred tax liability, for the years ended Dec. 31 were as follows (in thousands):



	2013			2012
Deferred tax assets:
Regulatory liabilities	$	33,172		$	57,471
Employee benefits	28,724			23,767
Items of other comprehensive income (loss)	9,733			20,038
Derivative fair value adjustments	1,594			35,947
Federal net operating loss	166,095			147,153
Asset impairment	55,124			55,971
State tax credits	14,948			15,546
Other deferred tax assets	32,803			36,502
Less: Valuation allowance	(1,806		)	(6,192		)
Total deferred tax assets	340,387			386,203

Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(598,415		)	(571,262		)
Regulatory assets	(24,581		)	(23,537		)
Mining development and oil exploration	(69,799		)	(48,411		)
Deferred costs	(15,593		)	(17,723		)
State deferred tax liability	(30,293		)	(19,986		)
Other deferred tax liabilities	(15,104		)	(13,961		)
Total deferred tax liabilities	(753,785		)	(694,880		)

Net deferred tax liability	$	(413,398	)	$	(308,677	)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The effective tax rate differs from the federal statutory rate for the years ended Dec. 31, as follows:



	2013		2012		2011
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	2.4		2.0		1.8
Amortization of excess deferred and investment tax credits	(0.1	)	(0.2	)	(0.5	)
Percentage depletion in excess of cost	(1.0	)	(1.3	)	(2.5	)
Equity AFUDC	—		—		(0.5	)
Tax credits	(0.5	)	—		—
Accounting for uncertain tax positions adjustment	0.7		0.8		2.8
Flow-through adjustments^(a)	(0.9	)	(1.3	)	(4.5	)
Other tax differences	(0.9	)	0.4		(0.5	)
	34.7	%	35.4	%	31.1	%

_________________________

(a)

Summary of Operating Loss Carryforwards [Table Text Block]

At Dec. 31, 2013, we had federal and state NOL carryforwards which will expire at various dates as follows (in thousands):



Net Operating Loss Carryforward	Amounts		Expiration Dates
Federal	$	482,989	2019	to	2033
State	$	423,570	2013	to	2033

Summary of Income Tax Contingencies [Table Text Block]



	Changes in Uncertain Tax Positions
Beginning balance at Jan. 1, 2011	$	50,135
Additions for prior year tax positions	2,725
Reductions for prior year tax positions	(3,533		)
Ending balance at Dec. 31, 2011	49,327
Additions for prior year tax positions	111
Reductions for prior year tax positions	(8,906		)
Additions for current year tax positions	151
Settlements	—
Ending balance at Dec. 31, 2012	40,683
Additions for prior year tax positions	1,526
Reductions for prior year tax positions	(4,578		)
Additions for current year tax positions	—
Settlements	—
Ending balance at Dec. 31, 2013	$	37,631

State and Local Jurisdiction [Member]

Operating Loss Carryforwards [Line Items]

Summary of State Tax Carryforwards [Table Text Block]

State tax credits have been generated and are available to offset future state income taxes. At Dec. 31, 2013, we had the following state tax credit carryforwards (in thousands):



State Tax Credit Carryforwards			Expiration Years
Investment tax credit	$	14,793	2023	to	2025
Research and development	$	155	No expiration

Comprehensive Income Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2013

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):



	Location on the Consolidated Statements of Income	Amount Reclassified from AOCI
	Location on the Consolidated Statements of Income	Dec. 31, 2013			Dec. 31, 2012
Gains and losses on cash flow hedges:
Interest rate swaps	Interest expense	$	6,989		$	7,607
Commodity contracts	Revenue	(927		)	(8,784		)
		6,062			(1,177		)
Income tax	Income tax benefit (expense)	(2,016		)	534
Total reclassification adjustments related to cash flow hedges, net of tax		$	4,046		$	(643	)

Amortization of defined benefit plans:
Prior service cost	Utilities - Operations and maintenance	$	(125	)	$	—
	Non-regulated energy operations and maintenance	(128		)	—

Actuarial gain (loss)	Utilities - Operations and maintenance	1,693			—
	Non-regulated energy operations and maintenance	1,098			—
		2,538			—
Income tax	Income tax benefit (expense)	(883		)	—
Total reclassification adjustments related to defined benefit plans, net of tax		$	1,655		$	—

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets were as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of Dec. 31, 2012	$	(16,313	)	$	600		$	(19,775	)	$	(35,488	)
Other comprehensive income (loss)	9,688			(1,108		)	9,486			18,066
As of Dec. 31, 2013	$	(6,625	)	$	(508	)	$	(10,289	)	$	(17,422	)

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of Dec. 31, 2011	$	(18,140	)	$	4,338		$	(19,076	)	$	(32,878	)
Other comprehensive income (loss)	1,827			(3,738		)	(699		)	(2,610		)
As of Dec. 31, 2012	$	(16,313	)	$	600		$	(19,775	)	$	(35,488	)

Supplemental Cash Flow Information Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information



Years ended Dec. 31,	2013			2012			2011
	(in thousands)
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$	59,811		$	35,556		$	37,529
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	1,235		$	5,743		$	(1,525	)

Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	$	(108,361	)	$	(116,593	)	$	(103,110	)
Income taxes, net	$	(4,573	)	$	(3,027	)	$	9,854

Employee Benefit Plans Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets [Table Text Block]

The percentages of total plan asset fair value by investment category for our Pension Plans at Dec. 31 were as follows:



	2013		2012
Equity	26	%	47	%
Real estate	4		8
Fixed income	58		44
Cash	1		1
Hedge funds	11		—
Total	100	%	100	%

Schedule of Defined Contribution Plans Contributions [Table Text Block]

Contributions for the years ended Dec. 31 were as follows (in thousands):



	2013		2012
Defined Contribution Plan
Company Retirement Contribution	$	2,775	$	2,639
Matching contributions - Defined Contribution Plans	$	8,524	$	8,981



	2013		2012
Defined Benefit Plans
Defined Benefit Pension Plans	$	12,500	$	25,350
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	5,123	$	5,191
Supplemental Non-Qualified Defined Benefit Plans	$	1,345	$	1,270

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following tables present the changes in Level 3 recurring fair value (in thousands):



	As of Dec. 31, 2013			As of Dec. 31, 2012
Assets:	Commodity Derivatives -- Utilities			Commodity Derivatives -- Utilities
Balances as of beginning of period	$	43		$	—
Total gain (loss) included in AOCI/ Regulatory Asset	—			(54		)
Purchases	—			192
Transfers out of Level 3^(a)	(43		)	(95		)
Balances at end of period	$	—		$	43

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	(54	)

__________


(a)	Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended Dec. 31 (in thousands):



	2013			2012
Balance, beginning of period	$	7,770		$	7,043

Purchase	29,000			—
Unrealized gain (loss)	1,508			727
Realized gain (loss)	(77		)	—
Settlements	(13		)	—

Balance, end of period	$	38,188		$	7,770

Fair Value, Assets Measured on Recurring Basis [Table Text Block]

The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Level 3	Range (Weighted)
	Dec. 31, 2013		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate ^(a)	$	8,541	Market Approach	Redemption Restriction	N/A
Hedge Funds ^(b)	$	29,647	Market Approach	Redemption Restriction	N/A

_____________

(a)

(b)

Schedule of Changes in Projected Benefit Obligations [Table Text Block]

Benefit Obligations



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2013			2012			2013			2012			2013			2012
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	363,235		$	325,944		$	34,393		$	30,223		$	46,681		$	50,141
Service cost	6,433			5,720			1,392			889			1,674			1,610
Interest cost	15,300			14,747			1,328			1,410			1,669			2,093
Actuarial (gain) loss	(38,252		)	28,639			(2,808		)	3,140			(3,379		)	(4,430		)
Amendments ^(a)	—			—			—			—			1,585			—
Benefits paid	(25,316		)	(11,815		)	(1,345		)	(1,269		)	(5,123		)	(5,190		)
Plan curtailment liability reduction	—			—			—			—			—			—
Medicare Part D accrued	—			—			—			—			470			289
Plan participants’ contributions	—			—			—			—			2,201			2,168
Projected benefit obligation at end of year	$	321,400		$	363,235		$	32,960		$	34,393		$	45,778		$	46,681

____________________


(a)	Reflects Board of Directors approval of an increase to Company’s contribution to RMSA accounts.

Schedule of Changes in Fair Value of Plan Assets [Table Text Block]

A reconciliation of the fair value of Plan assets was as follows (in thousands):



	Defined Benefit Pension Plans							Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans ^(a)
	2013				2012			2013		2012		2013			2012
Beginning market value of plan assets	$	268,816			$	221,722		$	—	$	—	$	4,351		$	4,319
Investment income (loss)	24,362				33,559			—		—		8			(3		)
Employer contributions	12,500				25,350			—		—		1,923			2,172
Retiree contributions	—				—			—		—		1,533			1,458
Benefits paid	(25,316		)	^(b)	(11,815		)	—		—		(3,269		)	(3,595		)
Plan administrative expenses	—				—			—		—		—			—
Ending market value of plan assets	$	280,362			$	268,816		$	—	$	—	$	4,546		$	4,351

____________________


(a)	Assets of VEBA


(b)	2013 Benefits paid includes a one-time $13 million payment made to terminated vested employees who elected a lump-sum offering.

Schedule of Amounts Recognized in Balance Sheet [Table Text Block]

Amounts recognized in the Consolidated Balance Sheets at Dec. 31 consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2013		2012		2013		2012		2013		2012
Regulatory assets	$	48,419	$	94,199	$	—	$	—	$	5,535	$	6,438
Current liabilities	$	—	$	—	$	1,491	$	1,286	$	2,802	$	2,573
Non-current liabilities	$	41,034	$	94,410	$	32,033	$	33,180	$	38,412	$	39,807
Regulatory liabilities	$	—	$	—	$	—	$	—	$	3,141	$	2,174

Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2013		2012		2013		2012		2013		2012
Accumulated benefit obligation - Black Hills Corporation	$	110,847	$	124,143	$	27,380	$	28,056	$	12,101	$	12,309
Accumulated benefit obligation - Black Hills Energy	182,295		202,897		513		453		25,467		25,868
Accumulated benefit obligation - Cheyenne Light	—		—		—		—		8,210		8,504
Total Accumulated Benefit Obligation	$	293,142	$	327,040	$	27,893	$	28,509	$	45,778	$	46,681

Components of net periodic benefit cost

Components of Net Periodic Expense



(in thousands)	Defined Benefit Pension Plans									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2013			2012			2011			2013		2012		2011		2013			2012			2011
Service cost	$	6,433		$	5,720		$	5,421		$	1,392	$	889	$	1,028	$	1,674		$	1,610		$	1,498
Interest cost	15,300			14,747			14,929			1,328		1,410		1,298		1,669			2,093			2,168
Expected return on assets	(18,615		)	(16,334		)	(16,955		)	—		—		—		(79		)	(78		)	(164		)
Amortization of prior service cost	63			89			99			2		3		3		(500		)	(500		)	(479		)
Recognized net actuarial loss (gain)	12,250			9,630			4,540			793		807		510		482			887			677
Curtailment expense	—			—			13			—		—		—		—			—			—
Net periodic expense	$	15,431		$	13,852		$	8,047		$	3,515	$	3,109	$	2,839	$	3,246		$	4,012		$	3,700

Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block]



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2013		2012		2013		2012		2013			2012
Net (gain) loss	$	4,842	$	12,090	$	4,939	$	7,283	$	1,648		$	2,097
Prior service cost (gain)	64		78		9		11		(1,213		)	(1,784		)
Total accumulated other comprehensive (income) loss	$	4,906	$	12,168	$	4,948	$	7,294	$	435		$	313

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss	$	3,124	$	323	$	99
Prior service cost (credit)	41		1		(218		)
Total net periodic benefit cost expected to be recognized during calendar year 2014	$	3,165	$	324	$	(119	)

Schedule of Assumptions Used [Table Text Block]

Assumptions



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine benefit obligations:	2013		2012		2011		2013		2012		2011		2013		2012		2011

Discount rate	5.05	%	4.30	%	4.65	%	4.21	%	3.44	%	4.30	%	4.62	%	3.85	%	4.42	%
Rate of increase in compensation levels	3.78	%	3.84	%	3.77	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2013		2012		2011		2013		2012		2011		2013		2012		2011
Discount rate:
Black Hills Corporation	4.35	%	4.68	%	5.50	%	3.88	%	4.70	%	5.00	%	3.65	%	4.35	%	5.00	%
Black Hills Energy	4.25	%	4.60	%	5.40	%	3.00	%	3.90	%	4.40	%	3.50	%	4.35	%	4.60	%
Cheyenne Light	N/A		N/A		5.55	%	N/A		N/A		N/A		4.40	%	4.65	%	5.50	%

Expected long-term rate of return on assets ^(a)	7.25	%	7.25	%	7.75	%	N/A		N/A		N/A		2.00	%	2.00	%	4.00	%
Rate of increase in compensation levels	3.78	%	3.75	%	3.79	%	5.00	%	5.00	%	5.00	%	NA		NA		NA

_____________________________


(a)	The expected rate of return on plan assets is 6.75 percent for the calculation of the 2014 net periodic pension cost.

Schedule of Health Care Cost Trend Rates [Table Text Block]

The healthcare benefit obligation was determined at Dec. 31 as follows:



	Black Hills Corporation		Black Hills Energy		Cheyenne Light
2013
Healthcare trend rate pre-65
Trend for next year	7.50	%	7.50	%	7.50	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

Healthcare trend rate post-65
Trend for next year	6.25	%	6.25	%	6.25	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2026		2026		2026

2012
Healthcare trend rate pre-65
Trend for next year	7.75	%	7.75	%	7.75	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

Healthcare trend rate post-65
Trend for next year	6.50	%	6.50	%	6.50	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2026		2026		2026

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Retiree Healthcare Plans (in thousands):



Change in Assumed Trend Rate	Impact on Dec. 31, 2013 Accumulated Postretirement Benefit Obligation			Impact on 2013 Service and Interest Cost
Increase 1%	$	1,914		$	136
Decrease 1%	$	(1,644	)	$	(116	)

Schedule of Expected Benefit Payments [Table Text Block]

The following benefit payments, which reflect future service, are expected to be paid (in thousands):



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plan		Non-Pension Defined Benefit Postretirement Healthcare Plans
2014	$	13,721	$	1,491	$	3,340
2015	$	14,572	$	1,490	$	3,397
2016	$	15,608	$	1,542	$	3,477
2017	$	16,562	$	1,588	$	3,495
2018	$	17,627	$	1,622	$	3,572
2019-2023	$	105,252	$	8,146	$	17,520

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets [Table Text Block]

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):



Defined Benefit Pension Plans	Dec. 31, 2013
	Level 1		Level 2		Level 3		Total
AXA Equitable General Fixed Income	$	—	$	1,056	$	—	$	1,056
Common Collective Trust - Cash and Cash Equivalents	—		1,253		—		1,253
Common Collective Trust - Equity	—		73,726		—		73,726
Common Collective Trust - Fixed Income	—		162,747		—		162,747
Common Collective Trust - Real Estate	—		3,392		8,541		11,933
Hedge Funds	—		—		29,647		29,647
Total investments measured at fair value	$	—	$	242,174	$	38,188	$	280,362



Defined Benefit Pension Plans	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	1,486	$	—	$	—	$	1,486
Common Collective Trust - Cash and Cash Equivalents	—		1,118		—		1,118
Common Collective Trust - Equity	—		126,105		—		126,105
Common Collective Trust - Fixed Income	—		114,440		—		114,440
Common Collective Trust - Real Estate	—		13,361		7,770		21,131
Structured Products	—		4,536		—		4,536
Total investments measured at fair value	$	1,486	$	259,560	$	7,770	$	268,816

Defined Benefit Postretirement Health Coverage [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets [Table Text Block]



Non-pension Defined Benefit Postretirement Healthcare Plans	Dec. 31, 2013
	Level 1		Level 2		Level 3		Total
Registered Investment Company Trust - Money Market Mutual Fund	$	—	$	4,546	$	—	$	4,546
Total investments measured at fair value	$	—	$	4,546	$	—	$	4,546



Non-pension Defined Benefit Postretirement Healthcare Plans	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Registered Investment Company Trust - Money Market Mutual Fund	$	—	$	4,351	$	—	$	4,351
Total investments measured at fair value	$	—	$	4,351	$	—	$	4,351

Commitments and Contingencies Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]

Costs under these power purchase contracts for the years ended Dec. 31 were as follows (in thousands):



	2013		2012		2011
PPA with PacifiCorp	$	13,026	$	13,224	$	12,515
PPA with PSCo^(a)	$	—	$	—	$	97,988
Transmission services agreement with PacifiCorp	$	1,384	$	1,215	$	1,215
PPA with Happy Jack	$	3,772	$	1,988	$	1,955
PPA with Silver Sage	$	4,809	$	3,269	$	3,281
Busch Ranch Wind Project	$	1,856	$	502	$	—

_______________________


(a)	This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

The following is a schedule of future minimum payments required under the power purchase, transmission services, coal and gas supply agreements, and natural gas delivery commitments (in thousands):



2014	$	203,131
2015	$	148,874
2016	$	136,503
2017	$	125,492
2018	$	110,930
Thereafter	$	148,362

Guarantees Guarantees (Tables)

12 Months Ended

Dec. 31, 2013

Guarantees [Abstract]

Schedule of Guarantor Obligations [Table Text Block]

We had the following guarantees in place as of (in thousands):



	Maximum Exposure at
Nature of Guarantee	Dec. 31, 2013		Expiration
Guarantees of payment obligations arising from commodity-related physical and financial transactions of Black Hills Utility Holdings ⁽¹⁾	$	70,000	Ongoing
Indemnification for subsidiary reclamation/surety bonds ⁽²⁾	64,449		Ongoing
	$	134,449

_______________________

(1)


(2)	We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

Oil and Gas Reserves (Unaudited) Oil and Gas Exploration and Production Industries Disclosure (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended Dec. 31 (in thousands):



	2013		2012		2011
Acquisition of properties:
Proved	$	234	$	2,437	$	673
Unproved	6,022		33,052		8,317
Exploration costs	12,817		115		44,384
Development costs	48,641		73,877		38,638
Asset retirement obligations incurred	143		158		43
Total costs incurred	$	67,857	$	109,639	$	92,055

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.



	2013						2012						2011
	Oil			Gas			Oil			Gas			Oil			Gas
	(in Mbbls of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	4,116			55,985			6,223			95,904			5,940			95,456
Production ^(a)	(336		)	(6,984		)	(560		)	(8,686		)	(452		)	(8,526		)
Additions - acquisitions (sales)^(b)	(30		)	(46		)	(2,025		)	(3,070		)	(84		)	—
Additions - extensions and discoveries	379			10,456			449			2,898			927			29,664
Revisions to previous estimates	(208		)	3,779			29			(31,061		)	(108		)	(20,690		)
Balance at end of year	3,921			63,190			4,116			55,985			6,223			95,904

Proved developed reserves at end of year included above	3,689			60,224			3,929			55,708			4,830			71,867

Proved undeveloped reserves at the end of year included in above	232			2,966			187			279			1,393			24,037

NYMEX prices	$	96.94		$	3.67		$	94.71		$	2.76		$	96.19		$	4.12

Well-head reserve prices	$	89.79		$	3.45		$	85.31		$	2.24		$	88.49		$	3.59

________________________


(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGLs).


(b)	Reflects the sale of the majority of the Williston Basin assets during 2012.

Schedule of Oil and Gas In Process Activities [Table Text Block]

The number of locations, proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of Dec. 31, 2013 were:



	Proved Reserves (in Bcfe)	Gross PUD Locations	Future Development Costs (in millions)
Existing:
Williston Basin	0.5	6	$	2.1

Added:
Williston Basin	1.2	15	6.5
Piceance Basin	2.1	1	6.4
San Juan Basin	0.6	1	0.9
2013 Add Total	3.9	17	13.8

Total Proved Undeveloped	4.4	23	$	15.9

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Following is information concerning capitalized costs for the years ended Dec. 31 (in thousands):



	2013			2012			2011
Unproved oil and gas properties	$	62,553		$	59,526		$	28,656
Proved oil and gas properties	725,345			662,444			674,494
Gross capitalized costs	787,898			721,970			703,150

Accumulated depreciation, depletion and amortization and valuation allowances ^(a)	(555,263		)	(534,777		)	(361,173		)
Net capitalized costs	$	232,635		$	187,193		$	341,977

__________________


(a)	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

Following is a summary of results of operations for producing activities for the years ended Dec. 31 (in thousands):



	2013			2012			2011
Revenue	$	54,884		$	79,072		$	79,808

Production costs	20,140			23,483			23,820
Gain on sale of assets	—			(29,129		)	—
Depreciation, depletion and amortization and valuation provisions	20,611			37,323			34,415
Impairment of long-lived assets	—			26,868			—
Total costs	40,751			58,545			58,235
Results of operations from producing activities before tax	14,133			20,527			21,573

Income tax benefit (expense)	(4,876		)	(7,082		)	(7,442		)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	9,257		$	13,445		$	14,131

Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization [Table Text Block]

The table below sets forth the cost of unproved properties excluded from the amortization base as of Dec. 31, 2013 and notes the year in which the associated costs were incurred (in thousands):



	2013		2012		2011		Prior		Total
Leasehold acquisition cost	$	2,279	$	35,689	$	2,219	$	17,444	$	57,631
Exploration cost	10,930		—		—		—		10,930
Capitalized interest	748		360		637		3,177		4,922
Total	$	13,957	$	36,049	$	2,856	$	20,621	$	73,483

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended Dec. 31 (in thousands):



	2013			2012			2011
Future cash inflows	$	602,501		$	502,769		$	931,637
Future production costs	(213,578		)	(186,695		)	(280,910		)
Future development costs, including plugging and abandonment	(40,557		)	(8,462		)	(92,233		)
Future income tax expense	(81,566		)	(69,877		)	(157,922		)
Future net cash flows	266,800			237,735			400,572
10 percent annual discount for estimated timing of cash flows	(107,375		)	(101,632		)	(197,215		)
Standardized measure of discounted future net cash flows	$	159,425		$	136,103		$	203,357

Changes In Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserve Disclosures [Table Text Block]

The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended Dec. 31 (in thousands):



	2013			2012			2011
Standardized measure - beginning of year	$	136,103		$	203,357		$	168,108
Sales and transfers of oil and gas produced, net of production costs	(35,932		)	(48,905		)	(52,914		)
Net changes in prices and production costs	15,126			(42,639		)	57,087
Extensions, discoveries and improved recovery, less related costs	29,574			19,870			31,179
Changes in future development costs	(12,216		)	43,854			43,809
Development costs incurred during the period	3,554			21,931			18,940
Revisions of previous quantity estimates	12,851			(86,277		)	(58,211		)
Accretion of discount	15,126			25,509			19,655
Net change in income taxes	(3,892		)	36,578			(23,283		)
Purchases of reserves	—			—			—
Sales of reserves ^(a)	(869		)	(37,175		)	(1,013		)
Standardized measure - end of year	$	159,425		$	136,103		$	203,357

________


(a)	Reflects sale of Williston Basin assets in 2012.

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62352-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62246-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62136-109447

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=27015464&loc=d3e511914-122862

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62299-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62094-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62395-109447

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=8451751&loc=d3e63071-109448

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Williston Basin Assets [Member]

Sale of Operating Assets and Discontinued Operations Sale of Operating Assets and Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2013

Cash proceeds from sale of operating assets [Table Text Block]

Net cash proceeds, subsequent to the true-up of all post-closing adjustments, were as follows (in thousands):



Cash proceeds received on date of sale	$	243,314
Less:
Post close adjustments	2,793
Transaction adviser fees	(1,400		)
Estimated payment for contractual obligation related to “back-in” fee *	(16,847		)
Net cash proceeds	$	227,860

_____________


*	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Energy Marketing [Member]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]



For the Years Ended Dec. 31,	2013			2012			2011

Revenue	$	—		$	(604	)	$	41,101

Pre-tax income (loss) from discontinued operations	—			(6,061		)	14,838
Pre-tax gain (loss) on sale	(1,391		)	(4,184		)	—
Income tax (expense) benefit	507			3,268			(5,473		)
Income (loss) from discontinued operations, net of tax^(a)	$	(884	)	$	(6,977	)	$	9,365

________


(a)	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended Dec. 31, 2012.

Tabular disclosure of disposal groups, which may include the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the classification and carrying value of the assets and liabilities comprising the disposal group, and the segment in which the disposal group was reported. Also may include the amount of adjustments to amounts previously reported in discontinued operations such as resolution of contingencies arising from the disposal transaction or the operations of the component prior to disposal.

Quarterly Financial Information Disclosure [Abstract]

Quarterly Historical Data (Unaudited) Quarterly Historical Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Quarterly Financial Information [Table Text Block]

The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2013 and 2012.



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2013
Revenue	$	380,671	$	279,826	$	259,907	$	355,448
Operating income	$	79,846	$	49,037	$	55,566	$	71,103
Income (loss) from continuing operations^{(a) (b)}	$	43,197	$	30,518	$	23,124	$	19,007
Income (loss) from discontinued operations	$	—	$	—	$	—	$	(884	)
Net income (loss) available for common stock ^{(a) (b)}	$	43,197	$	30,518	$	23,124	$	18,123

Income (loss) per share for continuing operations - Basic	$	0.98	$	0.69	$	0.52	$	0.43
Income (loss) per share for discontinued operations - Basic	—		—		—		(0.02		)
Income (loss) per share - Basic	$	0.98	$	0.69	$	0.52	$	0.41

Income (loss) per share for continuing operations - Diluted	$	0.97	$	0.69	$	0.52	$	0.43
Income (loss) per share for discontinued operations - Diluted	—		—		—		(0.02		)
Income (loss) per share - Diluted	$	0.97	$	0.69	$	0.52	$	0.41

Dividends paid per share	$	0.380	$	0.380	$	0.380	$	0.380

Common stock prices - High	$	44.32	$	50.53	$	55.09	$	54.83
Common stock prices - Low	$	36.89	$	43.19	$	46.62	$	47.00

__________________________


(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million, and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.

(b)



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2012
Revenue	$	365,851		$	242,363		$	246,808		$	318,862
Operating income^(a)	$	70,048		$	20,591		$	77,810		$	75,262
Income (loss) from continuing operations ^{(b) (c) (d)}	$	35,271		$	(12,323	)	$	34,623		$	30,934
Income (loss) from discontinued operations	$	(5,484	)	$	(1,160	)	$	(166	)	$	(167	)
Net income (loss) available for common stock ^{(b) (c) (d)}	$	29,787		$	(13,483	)	$	34,457		$	30,767

Income (loss) per share for continuing operations - Basic	$	0.81		$	(0.28	)	$	0.79		$	0.70
Income (loss) per share for discontinued operations - Basic	(0.13		)	(0.03		)	—			—
Income (loss) per share - Basic	$	0.68		$	(0.31	)	$	0.79		$	0.70

Income (loss) per share for continuing operations - Diluted	$	0.80		$	(0.28	)	$	0.78		$	0.70
Income (loss) per share for discontinued operations - Diluted	(0.12		)	(0.03		)	—			—
Income (loss) per share - Diluted	$	0.68		$	(0.31	)	$	0.78		$	0.70

Dividends paid per share	$	0.370		$	0.370		$	0.370		$	0.370

Common stock prices - High	$	35.82		$	34.31		$	36.28		$	37.00
Common stock prices - Low	$	32.18		$	31.32		$	30.29		$	33.51

__________________________


(a)	Second quarter includes a pre-tax ceiling test impairment loss of $27 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27 million and $1.8 million, respectively.


(b)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.


(c)	Second quarter includes an after-tax ceiling test impairment loss of $17 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $18 million and $1.2 million, respectively.


(d)	Fourth quarter includes a $4.6 million after-tax make-whole provision for the early redemption of our $225 million notes.

Business Description and Significant Accounting Policies Business Description (Details)	12 Months Ended
	Dec. 31, 2013 Business_Group
Segment Reporting Information [Line Items]
Number of Business Groups	2

Business Description and Significant Accounting Policies Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (1,237)	$ (768)
Accounts receivable, net	177,573	163,698
Corporate, Non-Segment [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	604	799
Electric Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(666)	(527)
Accounts receivable, net	75,594	77,798
Gas Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(558)	(222)
Accounts receivable, net	89,799	71,235
Power Generation [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,722	16
Coal Mining [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,711	2,247
Oil and Gas [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(13)	(19)
Accounts receivable, net	8,143	11,603
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	113,792	100,661
Billed Revenues [Member] \| Corporate, Non-Segment [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	604	799
Billed Revenues [Member] \| Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	52,437	54,482
Billed Revenues [Member] \| Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	49,162	31,495
Billed Revenues [Member] \| Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,722	16
Billed Revenues [Member] \| Coal Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,711	2,247
Billed Revenues [Member] \| Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	8,156	11,622
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	65,018	63,805
Unbilled Revenues [Member] \| Corporate, Non-Segment [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] \| Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	23,823	23,843
Unbilled Revenues [Member] \| Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	41,195	39,962
Unbilled Revenues [Member] \| Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] \| Coal Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] \| Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$ 0	$ 0

Business Description and Significant Accounting Policies Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Materials and supplies	$ 50,196	$ 43,397
Fuel - Electric Utilities	6,213	8,589
Natural gas in storage held for distribution	32,069	25,657
Total materials, supplies and fuel	$ 88,478	$ 77,643

Business Description and Significant Accounting Policies Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013
Goodwill [Line Items]
Goodwill	$ 353,396	$ 353,396	$ 353,396
Goodwill [Roll Forward]
Goodwill, Beginning Balance	353,396	353,396
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	353,396	353,396
Electric Utilities [Member]
Goodwill [Line Items]
Goodwill	250,487	250,487	250,487
Goodwill [Roll Forward]
Goodwill, Beginning Balance	250,487	250,487
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	250,487	250,487
Gas Utilities [Member]
Goodwill [Line Items]
Goodwill	94,144	94,144
Goodwill [Roll Forward]
Goodwill, Beginning Balance	94,144	94,144
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance		94,144
Power Generation [Member]
Goodwill [Line Items]
Goodwill	8,765	8,765	8,765
Goodwill [Roll Forward]
Goodwill, Beginning Balance	8,765	8,765
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	8,765	$ 8,765
Aquila Transaction [Member] \| Electric Utilities [Member]
Goodwill [Line Items]
Goodwill	246,000		$ 246,000
Goodwill Allocation by Segment (percentage)			72.00%
Goodwill [Roll Forward]
Goodwill, Ending Balance	246,000
Aquila Transaction [Member] \| Gas Utilities [Member]
Goodwill [Line Items]
Goodwill	94,144		$ 94,144
Goodwill Allocation by Segment (percentage)			28.00%
Goodwill [Roll Forward]
Goodwill, Ending Balance	$ 94,144

Business Description and Significant Accounting Policies Schedule of Intangible Assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Finite-Lived Intangible Assets [Line Items]

Finite-Lived Intangible Assets, Useful Life, Maximum (years)

20 years

Finite-Lived Intangible Assets [Roll Forward]

Intangible assets, net, beginning balance

$ 3,620

$ 3,843

$ 4,069

Intangible asset, additions (adjustments)

Intangible assets, amortization expense

(223)

(226)

Intangible assets, net, ending balance

3,397

^[1]

$ 3,620

$ 3,843

Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]

Future Amortization Expense, Year One

200

Future Amortization Expense, Year Two

200

Future Amortization Expense, Year Three

200

Future Amortization Expense, Year Four

200

Future Amortization Expense, Year Five

$ 200

[1]	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of the next five years.

Business Description and Significant Accounting Policies Regulatory Assets and Liabilities (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Schedule of Regulatory Assets and Liabilities [line items]

$ 162,648

$ 219,393

Deferred energy, fuel and gas cost adjustments [Member]

$ 120,156

141,284

Schedule of Regulatory Assets and Liabilities [line items]

P1Y

Employee benefit plans [Member]

^[1]

$ 11,708

21,091

Schedule of Regulatory Assets and Liabilities [line items]

P13Y

Schedule of Regulatory Assets and Liabilities [line items]

^[2]

$ 34,431

59,362

Cost of removal [Member]

P44Y

Other regulatory liabilities [Member]

^[1]

$ 64,970

53,526

Schedule of Regulatory Assets and Liabilities [line items]

P25Y

Deferred energy, fuel and gas cost adjustments [Member]

^[3]

$ 9,047

7,305

Schedule of Regulatory Assets and Liabilities [line items]

P1Y

Deferred gas cost adjustments and gas price derivatives [Member]

^[1]

$ 16,775

16,005

Schedule of Regulatory Assets and Liabilities [line items]

P7Y

Allowance For Funds Used During Construction [Member]

^[1]

$ 12,366

20,741

Schedule of Regulatory Assets and Liabilities [line items]

P45Y

Employee benefit plans [Member]

^[4]

$ 12,315

12,416

Schedule of Regulatory Assets and Liabilities [line items]

P13Y

Schedule of Regulatory Assets and Liabilities [line items]

^[5]

$ 67,059

115,521

Environmental [Member]

subject to approval

Asset retirement obligations [Member]

^[1]

$ 1,800

1,792

Schedule of Regulatory Assets and Liabilities [line items]

P44Y

Bond issuance costs [Member]

^[1]

$ 3,266

3,247

Schedule of Regulatory Assets and Liabilities [line items]

P24Y

Renewable energy standard adjustment [Member]

^[1]

$ 3,419

3,561

Schedule of Regulatory Assets and Liabilities [line items]

P5Y

Flow through accounting [Member]

^[1]

$ 14,186

19,484

Schedule of Regulatory Assets and Liabilities [line items]

P35Y

Other regulatory assets [Member]

^[6]

$ 20,916

16,620

Schedule of Regulatory Assets and Liabilities [line items]

P15Y

Recovery Plus Rate of Return or Reduction to Rate Base, Regulatory Assets [Domain] | Employee benefit plans [Member]

^[1]

$ 10,546

$ 10,006

Schedule of Regulatory Assets and Liabilities [line items]

Recovery Plus Rate of Return or Reduction to Rate Base, Regulatory Assets [Domain] | Other regulatory liabilities [Member]

^[2]

13,000

Schedule of Regulatory Assets and Liabilities [line items]

Recovery Plus Rate of Return or Reduction to Rate Base, Regulatory Assets [Domain] | Employee benefit plans [Member]

^[3]

2,600

Schedule of Regulatory Assets and Liabilities [line items]

Recovery Plus Rate of Return or Reduction to Rate Base, Regulatory Assets [Domain] | Flow through accounting [Member]

^[5]

25,000

Schedule of Regulatory Assets and Liabilities [line items]

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

^[6]

$ 5,400

[1]	Recovery of costs, but not allowed a rate of return.
[2]	Approximately $13 million is included in our rate base calculations as a reduction to rate base.
[3]	Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.
[4]	In addition to recovery of costs, we are allowed a rate of return.
[5]	In addition to recovery of costs, we are allowed a return on approximately $25 million.
[6]	In addition to recovery of costs, we are allowed a return on approximately $5.4 million.

Business Description and Significant Accounting Policies Earnings per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Income (Loss) from Continuing Operations Attributable to Parent

$ 19,007

^[1],[2]

$ 23,124

^[2]

$ 30,518

^[2]

$ 43,197

^[2]

$ 30,934

^{[3],[4],[5],[6]}

$ 34,623

^[4],[6]

$ (12,323)

^[4],[5],[6]

$ 35,271

^[4]

$ 115,846

$ 88,505

$ 40,365

Weighted average shares - Basic

44,163

43,820

39,864

Dilutive effect of:

Equity compensation

256

250

214

Other diluted effects, shares

Weighted average common shares - diluted

44,419

44,073

40,081

Income (loss) from continuing operations, per share

$ 0.43

$ 0.52

$ 0.69

$ 0.97

$ 0.70

$ 0.78

$ (0.28)

$ 0.80

$ 2.61

$ 2.01

$ 1.01

[1]	Fourth quarter 2013 includes $7.6 million after-tax for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt, and a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.
[2]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million, and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.
[3]	Fourth quarter includes a $4.6 million after-tax make-whole provision for the early redemption of our $225 million notes.
[4]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.
[5]	Second quarter includes a pre-tax ceiling test impairment loss of $27 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27 million and $1.8 million, respectively.
[6]	Second quarter includes an after-tax ceiling test impairment loss of $17 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $18 million and $1.2 million, respectively.

Business Description and Significant Accounting Policies Anti-dilutive shares (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	22	163	141
Equity Compensation [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	22	163	141
Other Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	0	0	0

Property, Plant and Equipment Property, Plant and Equipment (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

$ 4,259,445

$ 3,930,772

1,269,148

1,188,023

Depreciation, Depletion And Amortization, Remaining Amortization Period

$ 2,990,297

2,742,749

17 years

$ 5,498

368

5,647

3,875

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

11,145

4,243

(3,210)

^[1]

(1,956)

^[2]

Corporate, Non-Segment [Member] | Weighted Average [Member]

$ 14,355

$ 6,199

Corporate, Non-Segment [Member] | Minimum [Member]

6 years

Corporate, Non-Segment [Member] | Maximum [Member]

2 years

30 years

Public Utilities, Property, Plant and Equipment, Generation or Processing

$ 951,138

$ 959,636

Public Utilities, Property, Plant and Equipment, Transmission

238,542

234,279

Public Utilities, Property, Plant and Equipment, Distribution

666,589

631,654

Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments

^[3]

4,870

Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment

138,263

137,584

Public Utilities, Property, Plant and Equipment, Capital Lease

^[4]

261,441

260,874

Public Utilities, Property, Plant and Equipment Excluding Construction in Progress

2,260,843

2,228,897

Public Utilities, Property, Plant and Equipment, Construction Work in Progress

203,760

48,008

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

^[5]

2,464,603

2,276,905

472,970

439,772

Electric Utilities [Member] | Weighted Average [Member] | Production, Electric [Member]

$ 1,991,633

$ 1,837,133

Electric Utilities [Member] | Weighted Average [Member] | Electric transmission [Member]

45 years

Electric Utilities [Member] | Weighted Average [Member] | Electric distribution [Member]

50 years

Electric Utilities [Member] | Weighted Average [Member] | Plant acquisition adjustment [Member]

44 years

Electric Utilities [Member] | Weighted Average [Member] | General [Member]

32 years

Electric Utilities [Member] | Weighted Average [Member] | Assets Held under Capital Leases [Member]

22 years

Electric Utilities [Member] | Minimum [Member] | Production, Electric [Member]

20 years

19 years

Electric Utilities [Member] | Minimum [Member] | Electric transmission [Member]

25 years

Electric Utilities [Member] | Minimum [Member] | Electric distribution [Member]

40 years

Electric Utilities [Member] | Minimum [Member] | Plant acquisition adjustment [Member]

15 years

Electric Utilities [Member] | Minimum [Member] | General [Member]

32 years

Electric Utilities [Member] | Minimum [Member] | Assets Held under Capital Leases [Member]

3 years

Electric Utilities [Member] | Maximum [Member] | Production, Electric [Member]

20 years

Electric Utilities [Member] | Maximum [Member] | Electric transmission [Member]

65 years

Electric Utilities [Member] | Maximum [Member] | Electric distribution [Member]

65 years

Electric Utilities [Member] | Maximum [Member] | Plant acquisition adjustment [Member]

65 years

Electric Utilities [Member] | Maximum [Member] | General [Member]

32 years

Electric Utilities [Member] | Maximum [Member] | Assets Held under Capital Leases [Member]

60 years

20 years

Public Utilities, Property, Plant and Equipment, Generation or Processing

$ 13

Public Utilities, Property, Plant and Equipment, Transmission

24,984

18,071

Public Utilities, Property, Plant and Equipment, Distribution

507,318

474,998

Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment

85,841

68,856

Public Utilities, Property, Plant and Equipment Excluding Construction in Progress

618,156

561,938

Public Utilities, Property, Plant and Equipment, Construction Work in Progress

9,417

6,305

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

627,573

568,243

84,679

68,530

Gas Utilities [Member] | Weighted Average [Member] | General [Member]

$ 542,894

$ 499,713

Gas Utilities [Member] | Weighted Average [Member] | Production, Gas [Member]

19 years

Gas Utilities [Member] | Weighted Average [Member] | Gas transmission [Member]

37 years

Gas Utilities [Member] | Weighted Average [Member] | Gas distribution [Member]

54 years

Gas Utilities [Member] | Minimum [Member] | General [Member]

46 years

Gas Utilities [Member] | Minimum [Member] | Production, Gas [Member]

16 years

Gas Utilities [Member] | Minimum [Member] | Gas transmission [Member]

37 years

Gas Utilities [Member] | Minimum [Member] | Gas distribution [Member]

53 years

Gas Utilities [Member] | Maximum [Member] | General [Member]

41 years

Gas Utilities [Member] | Maximum [Member] | Production, Gas [Member]

22 years

Gas Utilities [Member] | Maximum [Member] | Gas transmission [Member]

37 years

Gas Utilities [Member] | Maximum [Member] | Gas distribution [Member]

57 years

Non Regulated Energy Group [Member]

56 years

$ 1,144,477

$ 1,073,035

11,647

8,346

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

1,156,124

1,081,381

714,709

681,677

441,415

399,704

143,026

139,396

10,491

1,323

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

^[5]

153,517

140,719

43,069

38,541

Power Generation [Member] | Weighted Average [Member]

$ 110,448

$ 102,178

Power Generation [Member] | Minimum [Member]

36 years

35 years

Power Generation [Member] | Maximum [Member]

2 years

40 years

$ 149,067

$ 148,045

1,156

7,023

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

150,223

155,068

86,306

80,210

Coal Mining [Member] | Weighted Average [Member]

$ 63,917

$ 74,858

Coal Mining [Member] | Minimum [Member]

14 years

Coal Mining [Member] | Maximum [Member]

2 years

59 years

$ 852,384

$ 785,594

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

852,384

785,594

585,334

562,926

Oil and Gas [Member] | Weighted Average [Member]

$ 267,050

$ 222,668

Oil and Gas [Member] | Minimum [Member]

24 years

Oil and Gas [Member] | Maximum [Member]

3 years

25 years

[1]	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.
[2]	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.
[3]	The plant acquisition adjustment is included in rate base and is being recovered with 17 years remaining.
[4]	Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on Dec. 31, 2031.
[5]	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded for at Colorado Electric under accounting for a capital lease.

Jointly Owned Facilities Jointly Owned Facilities (Details) $ in Thousands	Dec. 31, 2013 USD ($)
Electric Utilities [Member] \| Wyodak Plant [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	20.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 109,800
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	192
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 50,595
Electric Utilities [Member] \| Transmission Tie [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	35.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 19,648
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 4,741
Electric Utilities [Member] \| Wygen I I I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	52.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 131,468
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	713
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 10,593
Electric Utilities [Member] \| Busch Ranch Wind Farm [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	50.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 18,590
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 841
Power Generation [Member] \| Wygen I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	76.50%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 106,489
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	1,412
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 28,432

Business Segments Segment Assets (Details) - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

$ 3,875,178

$ 3,729,471

80,731

115,408

^[1]

2,525,947

2,387,458

805,617

765,165

^[1]

95,692

119,170

78,825

83,810

$ 288,366

$ 258,460

[1]

The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

Business Segments Capital Expenditures and Asset Acquisitions (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Segment Continuing Operations [Member]

^[1]

$ 379,534

$ 347,980

Discontinued Operations [Member]

^[1]

379,534

347,156

824

^[1]

10,319

7,376

^[1]

222,262

167,263

^[1]

63,205

45,711

^[1]

13,533

5,547

^[1]

5,528

13,420

^[1]

$ 64,687

$ 107,839

[1]	Includes accruals for property, plant and equipment.

Business Segments Property, Plant and Equipment (Details) - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

$ 4,259,445

$ 3,930,772

11,145

4,243

^[1]

2,464,603

2,276,905

627,573

568,243

^[1]

153,517

140,719

150,223

155,068

$ 852,384

$ 785,594

[1]

The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded for at Colorado Electric under accounting for a capital lease.

Business Segments Information Relating to Segments Statement of Income (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

$ 355,448

$ 259,907

$ 279,826

$ 380,671

$ 318,862

$ 246,808

$ 242,363

$ 365,851

$ 1,275,852

$ 1,173,884

$ 1,272,188

492,147

407,066

574,989

386,936

370,736

375,369

1,800

27,000

29,129

^[1]

141,217

154,632

135,591

27,000

26,868

^[2]

$ 71,103

$ 55,566

$ 49,037

$ 79,846

$ 75,262

^[3]

$ 77,810

^[3]

$ 20,591

^[3]

$ 70,048

255,552

243,711

186,239

(111,788)

^[4]

(113,610)

^[5]

(91,383)

30,169

1,882

(42,010)

1,723

1,957

2,017

1,798

2,965

3,726

(61,608)

(48,400)

(18,224)

115,846

88,505

40,365

651,445

610,732

600,935

294,048

273,474

310,352

159,961

146,527

142,815

768

^[6]

77,704

75,244

52,475

133,595

131,721

109,457

(61,537)

(59,194)

(53,770)

5,277

8,153

14,794

633

1,182

481

(25,834)

(30,264)

(23,271)

52,134

51,598

47,691

539,689

454,081

554,584

310,463

245,349

331,961

126,073

117,390

121,980

26,381

25,163

24,307

76,772

66,179

76,336

(25,234)

(26,746)

(31,621)

976

2,765

5,645

(60)

105

217

(19,747)

(14,313)

(16,408)

32,707

27,990

34,169

4,648

4,189

4,059

30,186

29,991

16,538

5,091

4,599

4,199

47,760

44,799

10,935

(21,178)

^[4]

(15,452)

(8,903)

785

695

1,529

1,094

(11,080)

(8,721)

(1,644)

16,288

21,328

3,011

25,186

25,810

32,802

39,519

42,553

56,617

11,523

13,060

18,670

5,586

2,165

(8,395)

(641)

(238)

(9)

1,168

3,897

2,304

2,616

2,192

(932)

(85)

1,891

6,327

5,626

(424)

54,884

79,072

79,808

40,365

43,267

41,380

29,129

^[1]

21,770

38,494

35,690

^[2]

26,868

(7,251)

(428)

2,738

(2,253)

(4,539)

(5,896)

1,639

604

108

207

(216)

3,545

1,927

1,651

Intercompany Eliminations [Member]

(4,212)

(2,229)

(1,721)

(344,314)

(319,855)

(267,349)

(112,489)

(111,757)

(67,421)

(211,977)

(188,051)

(174,908)

(767)

^[6]

(12,876)

(12,864)

(10,955)

(6,972)

(7,183)

(14,832)

84,250

85,209

102,130

(76,724)

(76,123)

(88,149)

(42,641)

(49,921)

(46,552)

218

(131)

268

Intercompany Eliminations [Member] | Electric Utilities [Member]

(41,869)

(48,149)

(47,135)

Intercompany Eliminations [Member] | Gas Utilities [Member]

13,863

16,234

13,396

Intercompany Eliminations [Member] | Power Generation [Member]

Intercompany Eliminations [Member] | Coal Mining [Member]

78,389

75,200

27,613

Intercompany Eliminations [Member] | Oil and Gas [Member]

31,442

31,968

34,090

Operating Segments [Member] | Electric Utilities [Member]

Operating Segments [Member] | Gas Utilities [Member]

665,308

626,966

614,331

Operating Segments [Member] | Power Generation [Member]

539,689

454,081

554,584

Operating Segments [Member] | Coal Mining [Member]

83,037

79,389

31,672

Operating Segments [Member] | Oil and Gas [Member]

56,628

57,778

66,892

54,884

79,072

79,808

220,620

196,453

192,250

125

202,809

179,059

170,947

(1)

11,624

10,936

11,205

6,062

6,458

10,000

(85,195)

^[4]

(92,650)

^[5]

(93,314)

30,169

1,882

(42,010)

69,760

64,695

64,299

41,453

48,769

46,510

(7,778)

3,187

19,289

Consolidation, Eliminations [Member]

54,471

32,341

4,774

$ 0

[1]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[2]	Oil and Gas includes a ceiling test impairment (see Note 12).
[3]	Second quarter includes a pre-tax ceiling test impairment loss of $27 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27 million and $1.8 million, respectively.
[4]	Power Generation includes costs associated with interest rate swaps settled and write-off of deferred financing costs upon repayment of Black Hills Wyoming Project Financing and Corporate includes a the write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt (see Note 5).
[5]	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 5).
[6]	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.

Long-Term Debt Long-Term Debt (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Nov. 19, 2013

Jun. 21, 2013

Dec. 31, 2012

Long-term Debt, including current maturirities

$ 1,396,948

$ 1,042,850

Long-term Debt, Current Maturities

(103,973)

Long-term debt, net of current maturities

1,396,948

938,877

Electric Utilities [Member] | First Mortgage Bonds Due 2032 [Member]

$ 396,948

396,944

Aug. 15, 2032

7.23%

Electric Utilities [Member] | First Mortgage Bonds Due 2039 [Member]

$ 75,000

75,000

Nov. 01, 2039

6.13%

Debt Instrument, Unamortized Discount

$ 180,000

180,000

$ (107)

(111)

Electric Utilities [Member] | Polution Control Revenue Bonds Due 2024 [Member]

Oct. 01, 2024

5.35%

Electric Utilities [Member] | First Mortgage Bonds Due 2037 [Member]

$ 12,200

12,200

Nov. 20, 2037

6.67%

Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2021 [Member]

$ 110,000

110,000

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

Sep. 01, 2021

^[1]

0.11%

Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2027 [Member]

^[1]

$ 7,000

7,000

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

Mar. 01, 2027

^[1]

0.11%

Electric Utilities [Member] | Bonds Due 2024 [Member]

^[1]

$ 10,000

10,000

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

Jun. 01, 2024

^[1]

0.75%

Power Generation [Member] | Project Financing Debt Due 2016 [Member]

^[1]

$ 2,855

2,855

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

Dec. 09, 2016

3.59%

^[1],[2]

$ 0

95,906

Long-term Debt, Current Maturities

1,000,000

550,000

(100,000)

Long-term debt, net of current maturities

$ 1,000,000

450,000

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2023 [Member]

Nov. 30, 2023

4.25%

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2014 [Member]

$ 525,000

^[3]

$ 525,000

May 15, 2014

9.00%

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2020 [Member]

^[4]

$ 0

250,000

Jul. 15, 2020

5.88%

Black Hills Corporation [Member] | Corporate Term Loan due September 2013 [Member]

^[5]

$ 200,000

200,000

Sep. 30, 2013

Black Hills Corporation [Member] | Corporate Term Loan due June 2015 [Member] [Member]

^[2],[6]

$ 0

100,000

^[1],[7]

Jun. 19, 2015

$ 275,000

^{[1],[7],[8],[9]}

$ 275,000

$ 0

[1]	Variable interest rate.
[2]	This debt repaid. See Debt Transactions discussed below.
[3]	$410 million of this senior unsecured note has been recorded at Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.
[4]	For 2012, this senior unsecured note was recorded by Black Hills Utility Holdings and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets. This note was redeemed on Dec. 19, 2013 with proceeds from the issuance of the Senior unsecured notes due 2023.
[5]	This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012 and 2013.
[6]	This term loan was repaid on June 21, 2013, and replaced with the Long-term term loan due June 19, 2015. In 2012, this term loan was recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2013.
[7]	Variable interest rates, based on LIBOR plus a spread.
[8]	This debt has been recorded at our Power Generation segment and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets at 2013.
[9]	Variable interest rate.

Long-Term Debt Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	$ 0	$ 103,973
Long-term Debt, Maturities, Repayments of Principal in Year Two	275,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	$ 1,122,055

Long-Term Debt Debt Transactions (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 19, 2013

Nov. 19, 2013

Jun. 21, 2013

Oct. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Repayments of Lines of Credit

Derivative Liability

$ 9,088

$ 113,482

532,150

271,753

$ 821,300

Loans Payable [Member]

Revolving Credit Facility [Member]

150,000

Repayments of Lines of Credit

$ 55,000

$ 25,000

Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

250,000

Black Hills Corporation [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

1,000,000

550,000

Senior Unsecured Notes Due 2023 [Member] [Member] | Black Hills Corporation [Member]

^[1],[2]

250,000

Derivative Liability

64,000

525,000

$ 525,000

^[3]

4.25%

Senior Unsecured Notes Due 2014 [Member] | Black Hills Corporation [Member]

Nov. 30, 2023

^[4]

$ 0

250,000

9.00%

$ 250,000

Early Repayment of Senior Debt

May 15, 2014

$ 261,000

Interest Expense, Prepayment of Debt

$ 8,500

Project Financing Debt Due 2016 [Member] | Power Generation [Member]

^[5],[6]

$ 0

95,906

87,000

Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net

Dec. 09, 2016

$ 8,500

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

3.59%

Corporate Term Loan due September 2013 [Member]

Corporate Term Loan due September 2013 [Member] | Black Hills Corporation [Member]

$ 100,000

^[5],[7]

$ 0

$ 100,000

^[6],[8]

Senior Unsecured Notes Due 2013 [Member]

Sep. 30, 2013

Early Repayment of Senior Debt

$ 239,000

Interest Expense, Prepayment of Debt

7,100

Senior Unsecured Notes Due 2013 [Member] | Black Hills Corporation [Member]

$ 225,000

6.50%

Corporate Term Loan due June 2015 [Member] [Member] | Black Hills Corporation [Member]

May 15, 2013

$ 275,000

^{[6],[8],[9],[10]}

$ 0

Corporate Term Loan due June 2015 [Member] [Member] | Black Hills Corporation [Member] | LIBOR [Member]

Jun. 19, 2015

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

^[8],[10]

1.3125%

Debt Instrument, Basis Spread on Variable Rate

1.125%

[1]	Included on the Condensed Statements of Income of the Parent is the non-cash mark-to-market gains recorded on these De-designated interest rate swaps of $30 million and $1.9 million for the twelve months ended Dec. 31, 2013 and 2012, respectively.
[2]	Maximum terms in years reflect the amended early termination dates. These swaps were settled in 2013.
[3]	$410 million of this senior unsecured note has been recorded at Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.
[4]	For 2012, this senior unsecured note was recorded by Black Hills Utility Holdings and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets. This note was redeemed on Dec. 19, 2013 with proceeds from the issuance of the Senior unsecured notes due 2023.
[5]	This debt repaid. See Debt Transactions discussed below.
[6]	Variable interest rate.
[7]	This term loan was repaid on June 21, 2013, and replaced with the Long-term term loan due June 19, 2015. In 2012, this term loan was recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2013.
[8]	Variable interest rates, based on LIBOR plus a spread.
[9]	This debt has been recorded at our Power Generation segment and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets at 2013.
[10]	Variable interest rate.

Long-Term Debt Deferred Financing Costs (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Senior Unsecured Notes Due 2023 [Member] [Member]

$ 6,846

Senior Unsecured Notes Due 2014 [Member]

$ 0

Senior Unsecured Notes Due 2020 [Member]

635

462

1,093

First Mortgage Bonds Due 2032 [Member]

167

618

First Mortgage Bonds Due 2039 [Member]

1,961

First Mortgage Bonds Due 2037 [Member]

736

Project Financing Debt Due 2016 [Member]

^[1]

Deferred Financing Costs, Other [Member]

3,177

^[1]

1,037

1,012

664

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 57

$ 70

[1]	This project financing was repaid in 2013 and the deferred financing costs were written-off.

Long-Term Debt Dividend Restrictions (Details) $ in Millions	Dec. 31, 2013 USD ($)
Utilities Group [Member]
Debt Instrument [Line Items]
Restricted Net Assets for Subsidiaries	$ 88

Notes Payable Notes Payable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Line of Credit Facility
Notes payable	$ 82,500	$ 277,000
Loans Payable [Member]
Line of Credit Facility
Notes payable	0	150,000
Revolving Credit Facility [Member]
Line of Credit Facility
Notes payable	82,500	127,000
Line of Credit Facility [Abstract]
Line of Credit Facility, Current Borrowing Capacity	$ 500,000
Line of Credit Facility, Expiration Date	Feb. 01, 2017
Line of Credit Facility, Maximum Borrowing Capacity	$ 750,000
Line of Credit Facility, Commitment Fee Percentage	0.25%
Letters of Credit Outstanding, Amount	$ 22,000	36,000
Deferred Finance Costs [Abstract]
Deferred Finance Costs, Noncurrent, Gross	2,800
Write off of Deferred Debt Issuance Cost	1,500
Deferred Finance Costs, Noncurrent, Net	1,316
Amortization Expense for Deferred Financing Costs	$ 752	$ 2,187	$ 1,891
Debt Covenants Disclosure [Abstract]
Line of Credit Covenant Requirement, Recourse Leverage Ratio, Actual	55.00%
Line of Credit, Covenant Requirement, Recourse Leverage Ratio Maximum	65.00%
Revolving Credit Facility [Member] \| Base Rate Option [Member]
Line of Credit Facility [Abstract]
Line of Credit Facility, Interest Rate at Period End	0.375%
Revolving Credit Facility [Member] \| Eurodollar [Member]
Line of Credit Facility [Abstract]
Line of Credit Facility, Interest Rate at Period End	1.375%
Revolving Credit Facility [Member] \| Letter of Credit [Member]
Line of Credit Facility [Abstract]
Line of Credit Facility, Interest Rate at Period End	1.375%

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

$ 50,548

$ 42,914

146

5,411

(2,617)

(1,081)

Asset Retirement Obligation, Revision of Prior Estimate

2,685

2,568

^[1]

1,089

736

51,851

50,548

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

6,981

3,064

3,626

Asset Retirement Obligation, Revision of Prior Estimate

168

291

^[1]

(227)

6,922

6,981

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

259

270

(22)

Asset Retirement Obligation, Revision of Prior Estimate

^[1]

274

259

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

20,286

17,158

1,627

(714)

Asset Retirement Obligation, Revision of Prior Estimate

1,052

921

^[1]

580

20,627

20,286

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

23,022

22,422

143

158

(1,903)

(1,059)

Asset Retirement Obligation, Revision of Prior Estimate

1,450

1,345

^[1]

1,316

156

$ 24,028

$ 23,022

[1]	The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.

Risk Management Activities Risk Management Activities (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2013

USD ($)

bbl

MMBTU

Dec. 31, 2012

USD ($)

bbl

MMBTU

Nov. 19, 2013

USD ($)

Credit Exposure, Non-investment Grade Company

$ 500

717

$ 3,236

510

3,474

96,541

5,614

$ 16,941

Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months

$ (1,000)

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

3 years

4 years

$ 3,474

$ 7,039

5,614

16,941

$ 75,000

^[1]

$ 150,000

^[2]

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

4.97%

5.04%

$ 3,500

Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Power Generation [Member]

Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

75,000

$ 250,000

3,474

$ 91,617

Black Hills Corporation [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

5,614

9,252

3,469

$ 9,252

4 years

75,000

$ 75,000

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

4.97%

3,500

Black Hills Corporation [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

$ 88,148

$ 0

^[3]

1 year

^[4],[5]

$ 250,000

Natural Gas, Distribution [Member] | Utilities Group [Member]

5.67%

662

$ 0

Net Unrealized Gain (Loss) Included in Regulatory assets or Regulatory liabilities

$ 7,567

$ 9,596

Natural Gas, Distribution [Member] | Future [Member] | Purchase Contract [Member] | Utilities Group [Member]

17,930,000

15,350,000

Natural Gas, Distribution [Member] | Commodity Option [Member] | Purchase Contract [Member] | Utilities Group [Member]

84 months

83 months

3,890,000

2,430,000

Natural Gas, Distribution [Member] | Basis Swap [Member] | Purchase Contract [Member] | Utilities Group [Member]

8 months

2 months

14,785,000

12,020,000

Crude Oil [Member] | Swaps and Options [Member] | Oil and Gas [Member]

60 months

72 months

Derivative notional amount, commodities | bbl

^[6]

412,500

528,000

MaximumTerm Hedged in Cash Flow Hedge

^[7]

3 months

1 year

$ 55

$ 1,405

297

847

Natural Gas [Member] | Swap [Member] | Oil and Gas [Member]

$ 0

MaximumTerm Hedged in Cash Flow Hedge

^[6]

7,082,500

8,215,500

^[7]

1 month

9 months

$ 0

$ 1,831

170

507

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

$ 0

[1]	These swaps are designated to borrowings on our Revolving Credit Facility. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps.
[2]	At Dec. 31, 2012, $75 million of these interest rate swaps were designated to borrowings on our Revolving Credit Facility and $75 million were designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps. The portion of the swaps that were designated to Black Hills Wyoming were settled upon repayment of the Black Hills Wyoming project financing. See Note 5.
[3]	Maximum terms in years reflect the amended early termination dates. If the early termination dates were not extended, the swaps would have required cash settlement based on the swap value at the termination date. These swaps were settled during the fourth quarter of 2013.
[4]	Included on the Condensed Statements of Income of the Parent is the non-cash mark-to-market gains recorded on these De-designated interest rate swaps of $30 million and $1.9 million for the twelve months ended Dec. 31, 2013 and 2012, respectively.
[5]	Maximum terms in years reflect the amended early termination dates. These swaps were settled in 2013.
[6]	Crude in Bbls, gas in MMBtu.
[7]	Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.

Fair Value Measurements Fair Value Measurements (Details) - USD ($)

Dec. 31, 2013

Dec. 31, 2012

$ 717,000

$ 3,746,000

Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract]

9,088,000

113,482,000

Fair Value, Assets, Level 1 to Level 2 Transfers, Amount

Fair Value, Assets, Level 2 to Level 1 Transfers, Amount

Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount

Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

3,975,000

3,703,000

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

19,948,000

129,424,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

43,000

Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(3,258,000)

Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]

(10,860,000)

(15,942,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

717,000

3,746,000

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member]

9,088,000

113,482,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

9,088,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

9,088,000

118,088,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]

(5,960,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Utilities Group [Member]

112,128,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Utilities Group [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

3,030,000

Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Utilities Group [Member]

9,100,000

8,576,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

43,000

^[1]

Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Utilities Group [Member]

Basis Differential

(0.13)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(2,368,000)

Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Utilities Group [Member]

(9,100,000)

(8,576,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

662,000

43,000

Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

815,000

2,000,000

Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]

531,000

1,127,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(815,000)

Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Oil and Gas [Member]

(531,000)

(620,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

2,000,000

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]

507,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

378,000

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]

1,131,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Oil and Gas [Member]

(336,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

378,000

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]

795,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

130,000

1,325,000

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]

1,229,000

502,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(75,000)

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Oil and Gas [Member]

(1,229,000)

(450,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

55,000

1,325,000

Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation RollForward [Roll Forward]

$ 0

$ 52,000

[1]

Fair Value Measurements Fair Value Measurements Changes in Level 3 Recurring Fair Value (Details) - Natural Gas, Distribution [Member] - Utilities Group [Member] - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period Start

$ 43

$ 0

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)

(54)

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

192

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

^[1]

(43)

(95)

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period End

Changes in unrealized gains (losses) relating to instruments still held as of period-end, assets

$ 0

$ (54)

[1]	Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Fair Value Measurements Fair Value Measurements Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 3,975	$ 5,332
Derivative Liability, Fair Value, Gross Liability	19,948	129,424
Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	946	3,384
Derivative Liability, Fair Value, Net	10,848	26,793
Derivatives Not Designated as Hedge Instruments [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	662	1,948
Derivative Liability, Fair Value, Net	6,732	104,218
Commodity derivatives [Member] \| Designated as Hedging Instrument [Member] \| Derivative Assets, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	248	2,874
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] \| Designated as Hedging Instrument [Member] \| Derivative Assets, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	698	510
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] \| Designated as Hedging Instrument [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	1,541	1,993
Commodity derivatives [Member] \| Designated as Hedging Instrument [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	219	821
Commodity derivatives [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Assets, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	662	362
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Assets, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	1,180
Derivative Liability, Fair Value, Gross Liability	0	4,957
Commodity derivatives [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	406
Derivative Liability, Fair Value, Gross Liability	6,732	5,153
Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	3,474	7,038
Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	5,614	16,941
Interest Rate Swap [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	94,108
Interest Rate Swap [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 0

Fair Value Measurements Fair Value Balance Sheet Offsetting (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 3,975	$ 5,332
Gross Amounts Offset In Statement Of Financial Position Assets	(3,258)	(1,586)
Derivative Asset	717	3,746
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	19,948	129,424
Gross Amounts Offset In Statement Of Financial Position Liabilities	(10,860)	(15,942)
Derivative Liability	9,088	113,482
Contract Subject to Master Netting Arrangement [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	3,920	1,970
Gross Amounts Offset In Statement Of Financial Position Assets	(3,258)	(1,586)
Derivative Asset	662	384
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	10,860	9,982
Gross Amounts Offset In Statement Of Financial Position Liabilities	(10,860)	(9,982)
Derivative Liability	0	0
Contract Subject to Master Netting Arrangement [Member] \| Interest Rate Swap [Member]
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	0
Contract Not Subject to Master Netting Arrangement [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	55	3,362
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	55	3,362
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	9,088	119,442
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	(5,960)
Derivative Liability	9,088	113,482
Contract Not Subject to Master Netting Arrangement [Member] \| Interest Rate Swap [Member]
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	9,088	118,088
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	(5,960)
Derivative Liability	9,088	112,128
Crude Oil [Member] \| Contract Subject to Master Netting Arrangement [Member] \| Basis Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	75	76
Gross Amounts Offset In Statement Of Financial Position Assets	(75)	0
Derivative Asset	0	76
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	1,229	449
Gross Amounts Offset In Statement Of Financial Position Liabilities	(1,229)	(449)
Derivative Liability	0	0
Crude Oil [Member] \| Contract Subject to Master Netting Arrangement [Member] \| Commodity Option [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	93
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	93
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	337
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	(337)
Derivative Liability	0	0
Crude Oil [Member] \| Contract Not Subject to Master Netting Arrangement [Member] \| Basis Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	55	1,249
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	55	1,249
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	52
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	52
Crude Oil [Member] \| Contract Not Subject to Master Netting Arrangement [Member] \| Commodity Option [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	285
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	285
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	795
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	795
Natural Gas [Member] \| Contract Subject to Master Netting Arrangement [Member] \| Basis Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	815	172
Gross Amounts Offset In Statement Of Financial Position Assets	(815)	0
Derivative Asset	0	172
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	531	620
Gross Amounts Offset In Statement Of Financial Position Liabilities	(531)	(620)
Derivative Liability	0	0
Natural Gas [Member] \| Contract Not Subject to Master Netting Arrangement [Member] \| Basis Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	1,828
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	1,828
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	507
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	507
Natural Gas, Distribution [Member] \| Contract Subject to Master Netting Arrangement [Member] \| Purchase Contract [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	3,030	1,629
Gross Amounts Offset In Statement Of Financial Position Assets	(2,368)	(1,586)
Derivative Asset	662	43
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	9,100	8,576
Gross Amounts Offset In Statement Of Financial Position Liabilities	(9,100)	(8,576)
Derivative Liability	0	0
Natural Gas, Distribution [Member] \| Contract Not Subject to Master Netting Arrangement [Member] \| Purchase Contract [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	$ 0	$ 0

Fair Value Measurements Fair Value Balance Sheet Offsetting by Counterparty (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Derivative Asset [Abstract]
Derivative Asset	$ 717	$ 3,746
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Withing Derivative Assets	717	3,746
Derivative Liability [Abstract]
Derivative Liability	9,088	113,482
Derivative, Collateral, Right to Reclaim Cash	(5,021)	(6,141)
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	4,067	107,341
Counterparty D [Member]
Derivative Liability [Abstract]
Derivative Liability		4,588
Derivative, Collateral, Right to Reclaim Cash		0
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities		4,588
Counterparty E [Member]
Derivative Liability [Abstract]
Derivative Liability		29,245
Derivative, Collateral, Right to Reclaim Cash		0
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities		29,245
Counterparty F [Member]
Derivative Liability [Abstract]
Derivative Liability	9,088	12,721
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	9,088	12,721
Counterparty G [Member]
Derivative Liability [Abstract]
Derivative Liability		26,520
Derivative, Collateral, Right to Reclaim Cash		0
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities		26,520
Counterparty H [Member]
Derivative Liability [Abstract]
Derivative Liability		16,809
Derivative, Collateral, Right to Reclaim Cash		0
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities		16,809
Counterparty I [Member]
Derivative Liability [Abstract]
Derivative Liability		22,245
Derivative, Collateral, Right to Reclaim Cash		0
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities		22,245
Utilities Group [Member] \| Counterparty A [Member]
Derivative Asset [Abstract]
Derivative Asset	662	43
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Withing Derivative Assets	662	43
Derivative Liability [Abstract]
Derivative Liability	0	0
Derivative, Collateral, Right to Reclaim Cash	(3,390)	(4,354)
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	(3,390)	(4,354)
Oil and Gas [Member] \| Counterparty A [Member]
Derivative Asset [Abstract]
Derivative Asset	0	341
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Withing Derivative Assets	0	341
Derivative Liability [Abstract]
Derivative Liability	0	0
Derivative, Collateral, Right to Reclaim Cash	(1,631)	(1,787)
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	(1,631)	(1,787)
Oil and Gas [Member] \| Counterparty B [Member]
Derivative Asset [Abstract]
Derivative Asset	55	3,362
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Withing Derivative Assets	55	3,362
Derivative Liability [Abstract]
Derivative Liability	0	1,354
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Liabilty, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	$ 0	$ 1,354

Fair Value Measurements Fair Value Measurements Hedging Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	$ 17,267	$ (11,077)	$ (55,383)
Cash Flow Hedging [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	6,979	(2,155)	(4,539)
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	6,062	1,177	(2,177)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0
Cash Flow Hedging [Member] \| Interest Rate Swap [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	7,935	(4,794)	(12,280)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0
Cash Flow Hedging [Member] \| Interest Rate Swap [Member] \| Interest Expense
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	6,989	(7,607)	(7,664)
Cash Flow Hedging [Member] \| Commodity Contract [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(956)	2,639	7,741
Cash Flow Hedging [Member] \| Commodity Contract [Member] \| Sales Revenue, Goods, Net [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	(927)	8,784	5,487
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0
Not Designated as Hedging Instrument [Member] \| Interest Rate Swap [Member] \| Interest Expense
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	(12,902)	(12,959)	(13,373)
Not Designated as Hedging Instrument [Member] \| Interest Rate Swap [Member] \| Unrealized Gain (Loss) on Interest Rate Swaps [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	$ 30,169	$ 1,882	$ (42,010)

Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Cash and cash equivalents, at carrying value

$ 7,841

$ 15,462

Restricted cash, at carrying value

7,916

Notes payable, at carrying value

82,500

277,000

Long-term debt, including current maturities at carrying value

1,396,948

1,042,850

Carrying Amount

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Cash and cash equivalents, at carrying value

7,841

15,462

Restricted cash, at carrying value

7,916

Notes payable, at carrying value

82,500

277,000

Long-term debt, including current maturities at carrying value

1,396,948

1,042,850

Fair Value

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Cash and cash equivalents, at fair value

^[1]

7,841

15,462

Restricted Cash, at fair value

^[1]

7,916

Notes payable, fair value

^[1]

82,500

277,000

Long-term debt, including current maturities, at fair value

^[2]

$ 1,491,422

$ 1,231,559

[1]	Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.
[2]	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Stock Equity Compensation Plans Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	768,953
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 9,900
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	1 year 8 months
Stock compensation	$ 12,595	$ 8,271	$ 5,643

Stock Stock Option Activity (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

$ 9,900

Employee Share-based Compensation, Nonvested Awards, Weighted Average Period for Recognition (in years)

1 year 8 months

Employee Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Award, Award Vesting Period

3 years

Share-based Compensation Award, Stock Option Award Effective Term

10 years

Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number

121

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross

^[1]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period

Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period

(4)

StockIssuedDuringPeriodSharesStockOptionsExercised

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number

121

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable at end of period, Shares

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price

$ 31.23

Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price

^[1]

40.39

Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price

0.00

Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price

29.09

Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price

30.87

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price

33.25

$ 31.23

Share-based Compensation Award, Options, Exercisable, Weighted Average Exercise Price

$ 31.69

Share-based Compensation Award, Options, Exercisable, Weighted Average Remaining Contractual Term

7 years 3 months 6 days

Share-based Compensation Arrangement by Share-based Payment Award, Options, Aggregate Intrinsic Value

$ 1,165

Share-based Compensation, Stock Options, Exercisable at End of Period, Weighted Average Remaining Contractual Term

6 years 6 months

Share-based Compensation Award, Options, Exercisable at End of Period, Aggregate Intrinsic Value

$ 534

Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price

^[1]

$ 7.65

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate

1.40%

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate

29.30%

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate

3.80%

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term

7 years

Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

$ 130

$ 218

$ 479

Stock Options, Options, Total Intrinsic Value of Options Exercised

^[2]

789

623

Stock Options, Net Cash Received from Exercise of Stock Options

$ 2,046

2,839

1,009

Employee Share-based Compensation, Nonvested Awards, Weighted Average Period for Recognition (in years)

1 year 1 month

Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options

^[3]

$ 276

$ 218

$ 33

[1]	The grant date fair value of the 2013 awards was $7.65 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 1.4 percent risk free interest rate, 29.3 percent expected price volatility, 3.8 percent expected dividend yield and a 7 year expected life.
[2]	The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.
[3]	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.

Stock Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock Restrcited Stock Units, Weighted Average Price [Roll Forward]
Equity Compensation, Nonvested Awards, Unrecognized Compensation Expense	$ 9,900
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	1 year 8 months
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Share-based Compensation Award, Restricted Stock and Restricted Stock Units, Nonvested, Number, Beginning of Period	287
Restricted Stock and RSUs, Granted in Period, Shares	120
Restricted Stock and RSUs, Vested in Period, Shares	(138)
Restricted Stock and RSUs, Forfeited in Period, Shares	(7)
Share-based Compensation Award, Restricted Stock and Restricted Stock Units, Nonvested, Number, End of Period	262	287
Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock Restrcited Stock Units, Weighted Average Price [Roll Forward]
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	$ 32.23
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	40.56	$ 34.99	$ 30.33
Restricted Stock and RSUs, Vested in Period, Weighted Average Grant Date Fair Value	30.62
Restricted Stock or RSUs, Forfeitures and Expirations in Period, Weighted Average Exercise Price	35.50
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$ 36.76	$ 32.23
Restricted Stock and RSUs, Vested in Period, Total Fair Value	$ 5,842	$ 3,781	$ 3,211
Equity Compensation, Nonvested Awards, Unrecognized Compensation Expense	$ 5,800
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	1 year 9 months 12 days

Stock Performance Shares (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 9,900
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	1 year 8 months
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award Payout, Cash Percentage	50.00%
Performance Share Award Payout, Shares of Common Stock Percentage	50.00%
Performance Share Award, Payout, Change Of Control	100.00%
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 1,900
Performance Share Award, Percentage of Target	175.00%
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	64	62
Performance Shares, Number of Shares Authorized, End of Period	61	64	62
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Weighted Average Grant Date of Fair Value Share-Based Compensation Arrangement	$ 35.85	$ 32.26	$ 25.92
Performance Shares, Fair Value Assumptions, Weighted Average Volatility Rate	20.00%	21.00%	30.00%
Performance Shares Expected Volatility, Historical Cost	50.00%
Performance Shares Expected Volatility, Implied Cost	50.00%
Performance Shares Issued During Period, Shares, Treasury Stock Reissued	63	0	0
Performance Shares, Total Share-based Liabilities Paid	$ 2,267	$ 0	$ 0
Performance Shares, Vested in Period, Total Intrinsic Value	$ 4,533	$ 0	$ 0
Peer Percentile	0.94
Employee Service Share-based Compensation, Other Than Options, Total Payout Value	$ 6,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Share-based Awards Other than Options	$ 3,900
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	1 year 7 months
Performance Shares, Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	96
Performance Shares, Granted in Period	31
Performance Shares, Forfeited in Period	(1)
Performance Shares, Vested in Period	(33)
Performance Shares, Number of Shares Authorized, End of Period	93	96
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 95.79
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	96
Performance Shares, Granted in Period	31
Performance Shares, Forfeited in Period	(1)
Performance Shares, Vested in Period	(33)
Performance Shares, Number of Shares Authorized, End of Period	93	96
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Forfeited in Period, Weighted Average Grant Date Fair Value	$ 33.85
Peformance Shares, Vested in Period, Weighted Average Grant Date Fair Value	24.26
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 31.34	$ 27.49
Minimum [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	0.00%	0.00%	0.00%
Maximum [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	200.00%	200.00%	175.00%
Current Year [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Performance Shares, Award Requisite Service Period	3 years
Prior Year [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Performance Shares, Award Requisite Service Period	3 years
More Than Two Years Prior [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Performance Shares, Award Requisite Service Period	3 years
More Than Three Years Prior [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Performance Shares, Award Requisite Service Period	3 years

Stock Dividend Reinvestment and Stock Purchase Plan (Details) - Dividend Reinvestment Plan [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Common Stock Purchase Percentage of Recent Average Market Price	100.00%
Stock Issued During Period, Shares, Dividend Reinvestment Plan	67	101
Dividend Reinvestment Plan, Weighted Average Price	$ 46.78	$ 33.58
Dividend Reinvestment Plan, Unissued Shares Available	286	353

Stock Common Stock Equity Issuance (Details) - USD ($) $ in Thousands		12 Months Ended
	Nov. 10, 2010	Dec. 31, 2011
Forward Contract Indexed to Issuer's Equity [Line Items]
Stock Issued During Period, Value, New Issues		$ 119,630
Common Stock [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Stock Issued During Period, Value, New Issues		4,413,519
Stock Issued During Period, Value, New Issues		$ 4,414
Black Hills Corporation [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Stock Issued During Period, Value, New Issues	$ 120,000
Black Hills Corporation [Member] \| Common Stock [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Stock Issued During Period, Value, New Issues	4,413,519
Black Hills Corporation [Member] \| Forward Equity Agreement [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares	4,000,000
Black Hills Corporation [Member] \| Forward Equity Agreement Over Allotment Shares [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Equity Issuance OverAllotment	413,519

Stock Preferred Stock (Details)	Dec. 31, 2013 shares
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Preferred Stock, Shares Authorized	25,000,000
Preferred Stock, Shares Outstanding	0

Impairment of Long-Lived Assets Impairment of Long-Lived Assets (Details)
$ in Thousands

3 Months Ended

12 Months Ended

Jun. 30, 2012

USD ($)

Dec. 31, 2013

USD ($)

$ / bbl

$ / MMcf

Dec. 31, 2012

USD ($)

$ / bbl

$ / MMcf

Jun. 30, 2012

$ / bbl

$ / MMcf

Dec. 31, 2011

USD ($)

$ / bbl

$ / MMcf

Impaired Long-Lived Assets Held and Used [Line Items]

Impairment of long-lived assets | $

$ 27,000

$ 0

$ 26,868

^[1]

$ 0

Average Natural Gas Price Per MCF, NYMEX | $ / MMcf

3.67

2.76

4.12

Average Natural Gas Price Per MCF, Wellhead | $ / MMcf

3.45

2.24

3.59

Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl

96.94

94.71

96.19

Average Crude Oil Price Per Barrel, Wellhead | $ / bbl

89.79

85.31

88.49

Impaired Long-Lived Assets Held and Used [Line Items]

Impairment of long-lived assets | $

^[1]

$ 26,868

Average Natural Gas Price Per MCF, NYMEX | $ / MMcf

3.15

Average Natural Gas Price Per MCF, Wellhead | $ / MMcf

2.66

Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl

95.67

Average Crude Oil Price Per Barrel, Wellhead | $ / bbl

85.36

[1]	Oil and Gas includes a ceiling test impairment (see Note 12).

Operating Leases Operating Lease (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Leases, Rent Expense, Net [Abstract]
Operating Leases, Rent Expense	$ 7,169	$ 6,839	$ 6,125
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Current	2,782
Operating Leases, Future Minimum Payments, Due in Two Years	2,583
Operating Leases, Future Minimum Payments, Due in Three Years	1,938
Operating Leases, Future Minimum Payments, Due in Four Years	1,747
Operating Leases, Future Minimum Payments, Due in Five Years	1,697
Operating Leases, Future Minimum Payments, Due Thereafter	$ 5,452

Income Taxes Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Income Tax Expense (Benefit)	$ (2,003)	$ 4,972	$ (14,539)
Current State Income Tax Expense (Benefit)	(173)	3,712	(837)
Current Income Tax Expense (Benefit)	(2,176)	8,684	(15,376)
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	56,963	39,876	30,876
Deferred State Income Tax Expense (Benefit)	7,033	68	2,970
Tax Credit Amortization Expense (Benefit)	(212)	(228)	(246)
Deferred Income Tax Expense (Benefit)	63,784	39,716	33,600
Total Income Tax Expense (Benefit)	$ 61,608	$ 48,400	$ 18,224

Income Taxes Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Regulatory Assets and Liabilities	$ 33,172	$ 57,471
Deferred Tax Assets, Employee Benefits	28,724	23,767
Deferred Tax Assets, Other Comprehensive (Loss)	9,733	20,038
Deferred Tax Assets, Derivative Fair Value Adjustments	1,594	35,947
Deferred Tax Asset, Non-current, Federal Net Operating Loss	166,095	147,153
Deferred Tax Assets, Non-current, Asset Impairment	55,124	55,971
Deferred Tax Assets, State Tax Credits	14,948	15,546
Deferred Tax Assets, Other	32,803	36,502
Deferred Tax Assets, Valuation Allowance	(1,806)	(6,192)
Deferred Tax Assets, Net of Valuation Allowance	340,387	386,203
Deferred Tax Liabilities, Net [Abstract]
Deferred Tax Liabilities Non-current, Accelerated Depreciation, Amortization and Other Plant-Related Differences	(598,415)	(571,262)
Deferred Tax Liabilities Non-current, Regulatory Assets	(24,581)	(23,537)
Deferred Tax Liabilities, Development Operations	(69,799)	(48,411)
Deferred Tax Liabilities, Deferred Costs	(15,593)	(17,723)
Deferred Tax Liability Non-current, State Deferred Tax Liability	(30,293)	(19,986)
Deferred Tax Liabilities, Other Current	(15,104)	(13,961)
Deferred Tax Liabilities, Gross	(753,785)	(694,880)
Net Deferred Tax Assets (Liabilities)	$ 413,398	$ 308,677

Income Taxes Effective Tax Rate Differences From Statutory Tax Rates (Details)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Effective Tax Rate Reconciliation [Line Items]

Federal Statutory Rate

35.00%

State Income Tax (net of federal tax effect)

2.40%

2.00%

1.80%

Amortization Of Excess Deferred and Investment Tax Credits

(0.10%)

(0.20%)

(0.50%)

Percentage Depletion In Excess of Cost

(1.00%)

(1.30%)

(2.50%)

Equity AFUDC

0.00%

(0.50%)

Tax Credits

(0.50%)

0.00%

Accounting for Uncertain Tax Positions Adjustment

0.70%

0.80%

2.80%

Flow Through Adjustments

^[1]

(0.90%)

(1.30%)

(4.50%)

Other Tax Differences

(0.90%)

0.40%

(0.50%)

Effective Income Tax Rate, Continuing Operations

34.70%

35.40%

31.10%

[1]

Income Taxes Net Operating Loss Carryforwards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	$ 61,608	$ 48,400	$ 18,224
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	482,989
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 423,570
Minimum [Member] \| Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	Dec. 31, 2019
Minimum [Member] \| State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	Dec. 31, 2013
Maximum [Member] \| Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	Dec. 31, 2033
Maximum [Member] \| State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	Dec. 31, 2033
Valuation Allowance, Operating Loss Carryforwards [Member] \| State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Valuation Allowance	$ 500
Valuation Allowance, Deferred Tax Asset, Change in Amount	1,700
Income Tax Expense (Benefit)	$ 700

Income Taxes Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 40,683	$ 49,327	$ 50,135
Unrecognized Tax Benefits, Increases Resulting from Additions for Prior Period Tax Positions	1,526	111	2,725
Unrecognized Tax Benefits, Decreases Resulting from Reductions for Prior Period Tax Positions	(4,578)	(8,906)	(3,533)
Unrecognized Tax Benefits, Increases Resulting from Additions for Current Year Tax Positions	0	151
Unrecognized Tax Benefits, Increases Decreases Resulting from Settlements	0	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	37,631	$ 40,683	$ 49,327
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 1,700

Income Taxes Interest, Penalties and Audits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest Expense Included in Income Tax Expense	$ 1,600	$ 1,400	$ 1,400
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	9,900	8,300
Deferred Income Tax Expense (Benefit)	63,784	$ 39,716	$ 33,600
Like-Kind Exchange, Aquila and IPP Transactions [Member]
Income Tax Examination [Line Items]
Deferred Income Tax Expense (Benefit)	$ 125,000

Income Taxes Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	$ 14,948	$ 15,546
Income Tax Expense (Benefit)	61,608	$ 48,400	$ 18,224
Foreign Tax Authority [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	500
Tax Credit Carryforward, Valuation Allowance	500
State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	800
Investment Tax Credit Carryforward [Member] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	14,793
Research Tax Credit Carryforward [Member] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	155
Deferred Tax Asset [Domain] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	2,600
Income Tax Expense (Benefit)	$ 1,100
Minimum [Member] \| Internal Revenue Service (IRS) [Member]
Tax Credit Carryforward [Line Items]
Income Tax Examination, Year under Examination	2007
Minimum [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2015
Minimum [Member] \| Investment Tax Credit Carryforward [Member] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2023
Maximum [Member] \| Internal Revenue Service (IRS) [Member]
Tax Credit Carryforward [Line Items]
Income Tax Examination, Year under Examination	2009
Maximum [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2017
Maximum [Member] \| Investment Tax Credit Carryforward [Member] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2025
Settlement with Taxing Authority [Member] \| Internal Revenue Service (IRS) [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 1,800
Utilities Group [Member] \| Deferred Tax Asset [Domain] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 1,500

Comprehensive Income Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest expense									$ 113,979	$ 117,754	$ 116,684
Revenue	$ 355,448	$ 259,907	$ 279,826	$ 380,671	$ 318,862	$ 246,808	$ 242,363	$ 365,851	1,275,852	1,173,884	1,272,188
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes									177,540	136,895	57,468
Income tax benefit (expense)									(61,608)	(48,400)	(18,224)
Operations and maintenance									261,919	242,367	247,496
Non-regulated energy operations and maintenance									83,762	85,830	$ 93,453
Cash Flow Hedging \| Reclassification out of Accumulated Other Comprehensive Income [Member]
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes									6,062	(1,177)
Income tax benefit (expense)									(2,016)	534
Net income (loss) available for common stock									4,046	(643)
Cash Flow Hedging \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Interest Rate Contract [Member]
Interest expense									6,989	7,607
Cash Flow Hedging \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Commodity Contract [Member]
Revenue									(927)	(8,784)
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member]
Operations and maintenance									(125)	0
Non-regulated energy operations and maintenance									(128)	0
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member]
Operations and maintenance									1,693	0
Non-regulated energy operations and maintenance									1,098	0
Accumulated Defined Benefit Plans Adjustment [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member]
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes									2,538	0
Income tax benefit (expense)									(883)	0
Net income (loss) available for common stock									$ 1,655	$ 0

Comprehensive Income Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (35,488)	$ (32,878)
Other comprehensive income (loss), net of tax	18,066	(2,610)	$ (9,297)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(17,422)	(35,488)	(32,878)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Interest Rate Swap [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(16,313)	(18,140)
Other comprehensive income (loss), net of tax	9,688	1,827
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(6,625)	(16,313)	(18,140)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Commodity Contract [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	600	4,338
Other comprehensive income (loss), net of tax	(1,108)	(3,738)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(508)	600	4,338
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(19,775)	(19,076)
Other comprehensive income (loss), net of tax	9,486	(699)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	$ (10,289)	$ (19,775)	$ (19,076)

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 59,811	$ 35,556	$ 37,529
Increase (Decrease) in Capitalized Asset Retirement Costs Associated with Asset Retirement Obligations	1,235	5,743	(1,525)
Cash (paid) refunded during the period for continuing operations [Abstract]
Interest (net of amounts capitalized)	(108,361)	(116,593)	(103,110)
Income taxes	$ (4,573)	$ (3,027)	$ 9,854

Employee Benefit Plans Narrative (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent

50.00%

Defined Contribution Plan, Employee Vesting Period

5 years

Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]

Defined Benefit Plan, Measurement Date

December 31

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets

7.25%

Not Full Vested [Member]

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage

20.00%

Fully Vested [Member]

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage

100.00%

Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]

Defined Benefit Plan, Funded Status of Plan

$ (41)

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets

^[1]

7.25%

7.75%

Supplemental Employee Retirement Plans, Defined Benefit [Member]

Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]

Defined Benefit Plan, Funded Status of Plan

$ (33)

Other Postretirement Benefit Plans, Defined Benefit [Member]

Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]

Defined Benefit Plan, Funded Status of Plan

$ (41)

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets

2.00%

4.00%

Cheyenne Light [Member]

Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]

Defined Benefit Plan Curtailment Effective Date

Jan. 01, 2012

[1]	The expected rate of return on plan assets is 6.75 percent for the calculation of the 2014 net periodic pension cost.

Employee Benefit Plans Target Plan Assets Allocation (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	100.00%	100.00%
Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	26.00%	47.00%
Real Estate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	4.00%	8.00%
Fixed Income Funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	58.00%	44.00%
Cash and Cash Equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	1.00%	1.00%
Hedge Funds, Multi-strategy [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	11.00%	0.00%

Employee Benefit Plans Plan Contributions (Details) - USD ($)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 0
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	12,500,000	$ 25,350,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	5,123,000	5,191,000
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	1,345,000	1,270,000
Defined Contribution Plan, Company Retirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	2,775,000	2,639,000
Defined Contribution Plan, 401K [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	$ 8,524,000	$ 8,981,000

Employee Benefit Plans Changes in Level 3 Assets Measured at Fair Value on a Recurring Basis, Employee Benefits (Details) - Pension Plans, Defined Benefit [Member] - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Fair Value, Inputs, Level 3 [Member]

$ 280,362

$ 268,816

$ 221,722

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period Start

7,770

7,043

Purchases, Level 3, Defined Benefit Plans

29,000

Unrealized Gain (Loss), Level 3, Defined Benefit Assets

1,508

727

Realized Gain (loss), Level 3, Defined Benefit Assets

(77)

Settlements, Level 3, Defined Benefit Assets

(13)

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period End

38,188

7,770

Real Estate Funds [Member]

38,188

7,770

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member]

11,933

21,131

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Hedge Funds, Multi-strategy [Member]

8,541

^[1]

$ 7,770

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Hedge Funds, Multi-strategy [Member] | Fair Value, Inputs, Level 3 [Member]

29,647

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

^[2]

$ 29,647

[1]

[2]

Employee Benefit Plans Changes in Benefit Obligation (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Projected Benefit Obligation at Beginning of Year

$ 363,235

$ 325,944

Service Cost

6,433

5,720

$ 5,421

Interest Cost

15,300

14,747

14,929

Actuarial (Gain) Loss

(38,252)

28,639

Plan Amendments

Plan Curtailment Reduction

(25,316)

^[1]

(11,815)

Medicare Part D Accrued

Plan Participants' Contributions

Projected Benefit Obligation at End of Year

321,400

363,235

325,944

Supplemental Employee Retirement Plans, Defined Benefit [Member]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Projected Benefit Obligation at Beginning of Year

34,393

30,223

Service Cost

1,392

889

Interest Cost

1,328

1,410

Actuarial (Gain) Loss

(2,808)

3,140

Plan Amendments

Defined Benefit Plan Benefits Paid from Company Assets

1,345

1,269

Plan Curtailment Reduction

Medicare Part D Accrued

Plan Participants' Contributions

Projected Benefit Obligation at End of Year

32,960

34,393

30,223

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Projected Benefit Obligation at Beginning of Year

46,681

50,141

Service Cost

1,674

1,610

1,498

Interest Cost

1,669

2,093

2,168

Actuarial (Gain) Loss

(3,379)

(4,430)

Plan Amendments

1,585

^[2]

Defined Benefit Plan Benefits Paid From Plan and Company Assets

5,123

5,190

Plan Curtailment Reduction

Medicare Part D Accrued

470

289

Plan Participants' Contributions

2,201

2,168

Projected Benefit Obligation at End of Year

$ 45,778

$ 46,681

$ 50,141

[1]	2013 Benefits paid includes a one-time $13 million payment made to terminated vested employees who elected a lump-sum offering.
[2]	Reflects Board of Directors approval of an increase to Company’s contribution to RMSA accounts.

Employee Benefit Plans Changes in Plan Assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

$ 268,816

$ 221,722

Investment income (loss)

24,362

33,559

Employer Contributions

12,500

25,350

Plan Administrative Expenses

(25,316)

^[1]

(11,815)

Supplemental Employee Retirement Plans, Defined Benefit [Member]

280,362

268,816

Lump Sum Payment

13,000

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

4,351

(2,201)

(2,168)

Defined Benefit Plan VEBA [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

4,546

4,351

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

^[2]

4,351

4,319

Investment income (loss)

^[2]

(3)

Employer Contributions

^[2]

1,923

2,172

^[2]

(1,533)

(1,458)

Plan Administrative Expenses

^[2]

(3,269)

(3,595)

^[2]

Unfunded Benefit Plan [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

^[2]

4,546

4,351

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Investment income (loss)

Employer Contributions

Plan Administrative Expenses

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

$ 0

[1]	2013 Benefits paid includes a one-time $13 million payment made to terminated vested employees who elected a lump-sum offering.
[2]	Assets of VEBA

Employee Benefit Plans Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	$ 162,648	$ 219,393
Non-current Liabilities, Defined Benefit Plans	111,479	167,397
Regulatory Liabilities, Defined Benefit Plans	120,156	141,284
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	48,419	94,199
Current Liabilities, Defined Benefit Plans	0	0
Non-current Liabilities, Defined Benefit Plans	41,034	94,410
Regulatory Liabilities, Defined Benefit Plans	0	0
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	0	0
Current Liabilities, Defined Benefit Plans	1,491	1,286
Non-current Liabilities, Defined Benefit Plans	32,033	33,180
Regulatory Liabilities, Defined Benefit Plans	0	0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	5,535	6,438
Current Liabilities, Defined Benefit Plans	2,802	2,573
Non-current Liabilities, Defined Benefit Plans	38,412	39,807
Regulatory Liabilities, Defined Benefit Plans	$ 3,141	$ 2,174

Employee Benefit Plans Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 293,142	$ 327,040
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	27,893	28,509
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	45,778	46,681
Black Hills Corporation [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	110,847	124,143
Black Hills Corporation [Member] \| Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	27,380	28,056
Black Hills Corporation [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	12,101	12,309
Black Hills Utility Holdings [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	182,295	202,897
Black Hills Utility Holdings [Member] \| Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	513	453
Black Hills Utility Holdings [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	25,467	25,868
Cheyenne Light [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	0	0
Cheyenne Light [Member] \| Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	0	0
Cheyenne Light [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 8,210	$ 8,504

Employee Benefit Plans Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 6,433	$ 5,720	$ 5,421
Interest Cost	15,300	14,747	14,929
Expected return on plan assets	(18,615)	(16,334)	(16,955)
Amortization of prior service cost	63	89	99
Recognition of net actuarial loss (gain)	12,250	9,630	4,540
Curtailment Expense	0	0	13
Net periodic benefit expense	15,431	13,852	8,047
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,392	889	1,028
Interest Cost	1,328	1,410	1,298
Expected return on plan assets	0	0	0
Amortization of prior service cost	2	3	3
Recognition of net actuarial loss (gain)	793	807	510
Curtailment Expense	0	0	0
Net periodic benefit expense	3,515	3,109	2,839
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,674	1,610	1,498
Interest Cost	1,669	2,093	2,168
Expected return on plan assets	(79)	(78)	(164)
Amortization of prior service cost	(500)	(500)	(479)
Recognition of net actuarial loss (gain)	482	887	677
Curtailment Expense	0	0	0
Net periodic benefit expense	$ 3,246	$ 4,012	$ 3,700

Employee Benefit Plans Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	$ 4,842	$ 12,090
Accumulated Other Comprehensive Income Prior Service Cost (Gain), After Tax	64	78
Accumulated Other Comprehensive Income (Loss), Net of Tax	4,906	12,168
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	3,124
Prior Service Cost (Credit)	41
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	3,165
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	4,939	7,283
Accumulated Other Comprehensive Income Prior Service Cost (Gain), After Tax	9	11
Accumulated Other Comprehensive Income (Loss), Net of Tax	4,948	7,294
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	323
Prior Service Cost (Credit)	1
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	324
Other Postretirement Benefit Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	1,648	2,097
Accumulated Other Comprehensive Income Prior Service Cost (Gain), After Tax	(1,213)	(1,784)
Accumulated Other Comprehensive Income (Loss), Net of Tax	435	$ 313
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	99
Prior Service Cost (Credit)	(218)
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	$ (119)

Employee Benefit Plans Defined Benefit Plans Assumptions (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Assumptions, Expected Long-term Return on Assets

7.25%

Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]

Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation

$ 1,914

Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation

(1,644)

Effect of One Percentage Point Increase on Service and Interest Cost Components

136

Effect of One Percentage Point Decrease on Service and Interest Cost Components

$ (116)

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Assumptions, Discount Rate, Benefit Obligation

5.05%

4.30%

4.65%

Assumptions, Rate of Increase in Compensation Levels

3.78%

3.84%

3.77%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Assumptions, Expected Long-term Return on Assets

^[1]

7.25%

7.75%

Assumptions, Rate of Compensation Increase

3.78%

3.75%

3.79%

Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year

6.75%

Supplemental Employee Retirement Plans, Defined Benefit [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Assumptions, Discount Rate, Benefit Obligation

4.21%

3.44%

4.30%

Assumptions, Rate of Increase in Compensation Levels

5.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Assumptions, Rate of Compensation Increase

5.00%

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Assumptions, Discount Rate, Benefit Obligation

4.62%

3.85%

4.42%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Assumptions, Expected Long-term Return on Assets

2.00%

4.00%

Black Hills Corporation [Member] | Pension Plans, Defined Benefit [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Black Hills Corporation [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

4.35%

4.68%

5.50%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Black Hills Corporation [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

3.88%

4.70%

5.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Black Hills Utility Holdings [Member] | Pension Plans, Defined Benefit [Member]

3.65%

4.35%

5.00%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Black Hills Utility Holdings [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

4.25%

4.60%

5.40%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Black Hills Utility Holdings [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

3.00%

3.90%

4.40%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Cheyenne Light [Member] | Pension Plans, Defined Benefit [Member]

3.50%

4.35%

4.60%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Cheyenne Light [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

5.55%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Age, Lower Than Retirement [Member] | Black Hills Corporation [Member]

4.40%

4.65%

5.50%

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Health Care Cost Trend Rate Assumed for Next Fiscal Year

7.50%

7.75%

4.50%

Age, Lower Than Retirement [Member] | Black Hills Utility Holdings [Member]

2027

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Health Care Cost Trend Rate Assumed for Next Fiscal Year

7.50%

7.75%

4.50%

Age, Lower Than Retirement [Member] | Cheyenne Light [Member]

2027

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Health Care Cost Trend Rate Assumed for Next Fiscal Year

7.50%

7.75%

4.50%

Age, Greater Than Retirement [Member] | Black Hills Corporation [Member]

2027

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Health Care Cost Trend Rate Assumed for Next Fiscal Year

6.25%

6.50%

4.50%

Age, Greater Than Retirement [Member] | Black Hills Utility Holdings [Member]

2026

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Health Care Cost Trend Rate Assumed for Next Fiscal Year

6.25%

6.50%

4.50%

Age, Greater Than Retirement [Member] | Cheyenne Light [Member]

2026

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

Health Care Cost Trend Rate Assumed for Next Fiscal Year

6.25%

6.50%

4.50%

2026

[1]	The expected rate of return on plan assets is 6.75 percent for the calculation of the 2014 net periodic pension cost.

Employee Benefit Plans Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2013 USD ($)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 13,721
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	14,572
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	15,608
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	16,562
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	17,627
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	105,252
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	1,491
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	1,490
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1,542
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1,588
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1,622
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	8,146
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	3,340
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	3,397
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	3,477
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	3,495
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	3,572
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 17,520

Commitments and Contingencies Commitments and Contingencies (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2013

USD ($)

Dec. 31, 2012

USD ($)

Dec. 31, 2011

USD ($)

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Oct. 16, 2037

Contractual Obligation, Fiscal Year Maturity [Abstract]

Unrecorded Unconditional Purchase Obligation, Due within One Year

$ 203,131

Unrecorded Unconditional Purchase Obligation, Due within Two Years

148,874

Unrecorded Unconditional Purchase Obligation, Due within Three Years

136,503

Unrecorded Unconditional Purchase Obligation, Due within Four Years

125,492

Unrecorded Unconditional Purchase Obligation, Due within Five Years

110,930

Unrecorded Unconditional Purchase Obligation, Due after Five Years

$ 148,362

Purchase Commitment [Member]

Expiration Date of Contracts Maximum, Gas Supply

Dec. 31, 2017

Equipment [Member]

Long Term Purchase Commitment Percentage Committed

100.00%

Construction Contracts [Member]

Long Term Purchase Commitment Percentage Committed

75.00%

Cheyenne Prairie [Member]

Long-term Purchase Commitment, Amount

$ 222,000

PacifiCorp Purchase Power Agreement [Member]

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

$ 13,026

$ 13,224

$ 12,515

Dec. 31, 2023

Public Service of Colorado Purchase Power Agreement [Member]

PacifiCorp Transmission [Member]

$ 0

97,988

^[1]

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

$ 1,384

1,215

Dec. 31, 2023

Happy Jack Wind Purchase Power Agreeement [Member]

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Sep. 03, 2028

Silver Sage Wind Power Purchase Agreement [Member]

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Sep. 30, 2029

Busch Ranch Wind Farm [Member]

Number of M W Capacity Purchased Under Long-term Contract | MW

14.5

Cargill Power Purchase Agreement [Member]

$ 1,856

502

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Dec. 31, 2014

Basin Electric [Member]

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Sep. 30, 2014

Renewable Wind Energy, Cheyenne Light [Member] | Happy Jack Wind Purchase Power Agreeement [Member]

Renewable Wind Energy, Cheyenne Light [Member] | Silver Sage Wind Power Purchase Agreement [Member]

$ 3,772

1,988

1,955

Wygen I Generating Facility [Member] | Purchase Option, Property [Member]

$ 4,809

$ 3,269

$ 3,281

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Dec. 31, 2022

[1]

This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.

Commitments and Contingencies Purchase and Sale Agreement (Details) $ in Millions	May 06, 2013 USD ($)
Power Generation [Member] \| CTII Natural Gas Fired Generating Unit [Member]
Maximum Future Consideration From Sale of Asset	$ 22

Commitments and Contingencies Related Party (Details) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($) MW
Purchase Option, Property [Member] \| Wygen I Generating Facility [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of M W Capacity Purchased Under Long-term Contract	60
Asset Purchase Option \| $	$ 2.6
Power purchased [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of M W Capacity Purchased Under Long-term Contract	200
Lease Expiration Date	Dec. 31, 2031
Basin Electric [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of M W Capacity Purchased Under Long-term Contract	40

Commitments and Contingencies Power Sales Agreements (Details)	12 Months Ended
	Dec. 31, 2013 MW
M D U, Montana Dakota Utilities [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	25
City Of Gillette [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	23
Basin Electric [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	40
Long-term Contract To Sell Electric Power, Date of Contract Expiration	Sep. 30, 2014
Purchase Power Contract, MEAN, 5 M W [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration	Apr. 01, 2015
Purchase Power Contract, MEAN, 10 M W [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration	May 31, 2023
Neil Simpson I I [Member] \| Purchase Power Contract, MEAN, 5 M W [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	5
Neil Simpson I I [Member] \| Purchase Power Contract, MEAN, 10 M W [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	10
Wygen I I I Generating Facility [Member] \| Purchase Power Contract, MEAN, 5 M W [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	5
Wygen I I I Generating Facility [Member] \| Purchase Power Contract, MEAN, 10 M W [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	10

Commitments and Contingencies Environmental Contingencies (Details) $ in Millions	Dec. 31, 2013 USD ($)
Electric Utilities [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Net	$ 3.9
Manufactured Gas Plant [Member] \| Gas Utilities [Member]
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1.3
Loss Contingency, Range of Possible Loss, Minimum	2.9
Loss Contingency, Range of Possible Loss, Maximum	6.3
Loss Contingency Accrual, at Carrying Value	$ 2.9

Commitments and Contingencies Legal Proceedings (Details) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($)
Loss from Catastrophes [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 15

Guarantees Guarantees (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2013

USD ($)

Guarantor Obligations [Line Items]

Guarantor, Maximum Exposure

$ 134,449

Gas Utilities [Member] | Payment Guarantee [Member]

Guarantor Obligations [Line Items]

Guarantor, Maximum Exposure

$ 70,000

^[1]

Guarantor Obligations, Term

Ongoing

Coal Mining [Member] | Surety Bond [Member]

Guarantor Obligations [Line Items]

Guarantor, Maximum Exposure

$ 64,449

^[2]

Guarantor Obligations, Term

Ongoing

[1]

[2]

We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

Oil and Gas Reserves (Unaudited) Oil and Gas Narrative (Details) Mcfe in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($) a Gross-Well PUD_Location Mcfe State	Dec. 31, 2012 PUD_Location Mcfe
Reserve Quantities [Line Items]
Wells in Process of Drilling \| Gross-Well	1,224
Gas and Oil Acreage, Leased \| a	235,517
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	12.7
Reserves Replaced	90.00%
Proved Undeveloped Reserves, Revisions of Previous Estimates	0.0
Proved Undeveloped Reserve Locations \| PUD_Location	23
Proved Undeveloped Reserves	4.4
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 15.9
PUD Locations in Reserves for Five Or More Years \| PUD_Location	0
Oil and Gas [Member]
Reserve Quantities [Line Items]
Number of States in which Entity Operates \| State	10
Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	10.2
Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	2.1
PUD Developed, PUD location \| PUD_Location	5
Proved Undeveloped Reserve Locations \| PUD_Location		11
Proved Undeveloped Reserves	0.0
Capital Expenditure for Proved Undeveloped Reserve \| $	$ 3.6
Proved Developed Reserves (Energy)		0.0
Powder River Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	0.2
Oklahoma Basin [Member] [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	0.2
Commodity Prices [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	5.0
Oil and Gas Well Performance [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	0.4
Oil and Gas Reserve Revisions, Operating Costs [Member] [Member] \| Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	1
Oil and Gas Reserve Revisions, Operating Costs [Member] [Member] \| San Juan Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	0.0
Oil and Gas Reserve Revisions, Five Year Reserve Aging Limit [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	0
Prior Year [Member] \| Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	6
Proved Undeveloped Reserves	0.5
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 2.1
Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	17
Proved Undeveloped Reserves	3.9
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 13.8
Added Reserves [Member] \| Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	1
Proved Undeveloped Reserves	2.1
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 6.4
Added Reserves [Member] \| Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	15
Proved Undeveloped Reserves	1.2
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 6.5
Added Reserves [Member] \| San Juan Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	1
Proved Undeveloped Reserves	0.6
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.9

Oil and Gas Reserves (Unaudited) Costs Incurred Oil and Gas (Details) - Oil and Gas [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Acquisition of Oil and Gas Properties, Proved Reserves	$ 234	$ 2,437	$ 673
Acquisition of Oil and Gas Properties, Unproved	6,022	33,052	8,317
Exploration Costs	12,817	115	44,384
Development Costs	48,641	73,877	38,638
Asset Retirement Obligation Incurred	143	158	43
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 67,857	$ 109,639	$ 92,055

Oil and Gas Reserves (Unaudited) Proved Developed and Undeveloped Oil and Gas Reserve (Details)

12 Months Ended

Dec. 31, 2013

$ / bbl

$ / MMcf

MBbls

MMcf

Dec. 31, 2012

$ / bbl

$ / MMcf

MBbls

MMcf

Dec. 31, 2011

$ / bbl

$ / MMcf

MBbls

MMcf

Proved Developed And Undevleoped Reserves [Roll Forward]

Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl

96.94

94.71

96.19

Average Natural Gas Price Per MCF, NYMEX | $ / MMcf

3.67

2.76

4.12

Average Crude Oil Price Per Barrel, Wellhead | $ / bbl

89.79

85.31

88.49

Average Natural Gas Price Per MCF, Wellhead | $ / MMcf

3.45

2.24

3.59

Oil [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Proved Developed and Undeveloped Reserves, Balance at Beginning of Year | MBbls

4,116

6,223

5,940

Proved Developed and Undeveloped Reserves, Production | MBbls

^[1]

(336)

(560)

(452)

Proved Developed and Undeveloped Reserves, Additions, Acquisitions (Sales) | MBbls

(30)

(2,025)

^[2]

(84)

Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries (bcfe) | MBbls

379

449

927

Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MBbls

(208)

(108)

Proved Developed and Undeveloped Reserves, Balance at End of Year | MBbls

3,921

4,116

6,223

Proved Developed Reserves (Volume) | MBbls

3,689

3,929

4,830

Proved Undeveloped Reserve (Volume) | MBbls

232

187

1,393

Natural Gas [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Proved Developed and Undeveloped Reserves, Balance at Beginning of Year | MMcf

55,985

95,904

95,456

Proved Developed and Undeveloped Reserves, Production | MMcf

^[1]

(6,984)

(8,686)

(8,526)

Proved Developed and Undeveloped Reserves, Additions, Acquisitions (Sales) | MMcf

(46)

(3,070)

^[2]

Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries (bcfe) | MMcf

10,456

2,898

29,664

Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MMcf

3,779

(31,061)

(20,690)

Proved Developed and Undeveloped Reserves, Balance at End of Year | MMcf

63,190

55,985

95,904

Proved Developed Reserves (Volume) | MMcf

60,224

55,708

71,867

Proved Undeveloped Reserve (Volume) | MMcf

2,966

279

24,037

[1]	Production for reserve calculations does not include volumes for natural gas liquids (NGLs).
[2]	Reflects the sale of the majority of the Williston Basin assets during 2012.

Oil and Gas Reserves (Unaudited) Capitalized Costs (Details) - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]

Capitalized Costs, Unproved Oil and Gas Properties

$ 62,553

$ 59,526

$ 28,656

Capitalized Costs, Proved Oil and Gas Properties

725,345

662,444

674,494

Gross Capitalized Costs, Oil and Gas Producing Activities

787,898

721,970

703,150

Capitalized Costs, Oil and Gas, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance

(555,263)

(534,777)

^[1]

(361,173)

Net Capitalized Costs, Oil and Gas Producing Activities

$ 232,635

$ 187,193

$ 341,977

[1]	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.

Oil and Gas Reserves (Unaudited) Results of Operations Oil and Gas (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Results of Operations, Revenue	$ 54,884	$ 79,072	$ 79,808
Results of Operations, Production Costs	20,140	23,483	23,820
Gain (Loss) on Sale of Property Plant Equipment	0	(29,129)	0
Results of Operations, Depreciation, Depletion and Amortization, and Valuation Provisions	20,611	37,323	34,415
Impairment of long-lived assets	0	26,868	0
Results of Operations, Total Costs	40,751	58,545	58,235
Results of Operations from Producing Activities, before Tax	14,133	20,527	21,573
Results of Operations, Income Tax (Expense) Benefit	(4,876)	(7,082)	(7,442)
Results of Operations, Producing Activities (Excluding General and Administrative Costs and Interest Costs)	$ 9,257	$ 13,445	$ 14,131

Oil and Gas Reserves (Unaudited) Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	$ 57,631
Exploration Costs, Excluded from Amortization Base	10,930
Capitalized Interest, Excluded from Amortization Base	4,922
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	73,483
Current Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	2,279
Exploration Costs, Excluded from Amortization Base	10,930
Capitalized Interest, Excluded from Amortization Base	748
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	13,957
Prior Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	35,689
Exploration Costs, Excluded from Amortization Base	0
Capitalized Interest, Excluded from Amortization Base	360
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	36,049
More Than One Year, Less Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	2,219
Exploration Costs, Excluded from Amortization Base	0
Capitalized Interest, Excluded from Amortization Base	637
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	2,856
More Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	17,444
Exploration Costs, Excluded from Amortization Base	0
Capitalized Interest, Excluded from Amortization Base	3,177
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	20,621
Oil and Gas [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Interest Costs, Capitalized During Period	$ 1,100	$ 700	$ 900

Oil and Gas Reserves (Unaudited) Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Cash Inflows, Standardized Measure of Discounted Future Net Cash Flows	$ 602,501	$ 502,769	$ 931,637
Future Production Costs, Standardized Measure of Discounted Future Net Cash Flows	(213,578)	(186,695)	(280,910)
Future Development Costs, Standardized Measure of Discounted Future Net Cash Flows	(40,557)	(8,462)	(92,233)
Future Income Tax Expense, Standardized Measure of Discounted Future Net Cash Flows	(81,566)	(69,877)	(157,922)
Future Net Cash Flows, Standardized Measure of Discounted Future Net Cash Flows	266,800	237,735	400,572
10 Percent Annual Discount for Estimated Timing of Cash Flows, Standardized Measure of Discounted Future Net Cash Flows	(107,375)	(101,632)	(197,215)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure	$ 159,425	$ 136,103	$ 203,357

Oil and Gas Reserves (Unaudited) Change in Standard Measure of Discounted Future Cash Net Flows (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]

Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year

$ 136,103

$ 203,357

$ 168,108

Sales and Transfers of Oil and Gas Produced, Net of Production Costs

(35,932)

(48,905)

(52,914)

Net Change in Prices and Production Costs

15,126

(42,639)

57,087

Extensions, Discoveries, Additions and Improved Recovery, Less Related Costs

29,574

19,870

31,179

Changes in Estimated Future Development Costs (USD)

(12,216)

43,854

43,809

Development Costs Incurred During Period

3,554

21,931

18,940

Revisions of Previous Quantity Estimates (USD)

12,851

(86,277)

(58,211)

Accretion of Discount

15,126

25,509

19,655

Changes in Income Taxes, Estimates on Future Cash Flows, Proved Oil and Gas Reserves

(3,892)

36,578

(23,283)

Increase Due to Purchases of Reserves

Decrease Due to Sales Reserves

(869)

(37,175)

^[1]

(1,013)

Standardized Measure of Discounted Future Net Cash Flows, End of Year

$ 159,425

$ 136,103

$ 203,357

[1]	Reflects sale of Williston Basin assets in 2012.

Sale of Operating Assets and Discontinued Operations Sale of Operating Assets (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Sep. 27, 2012

Sep. 18, 2012

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Significant Acquisitions and Disposals [Line Items]

$ 1,800

$ 27,000

$ 0

$ 29,129

^[1]

$ 0

Significant Acquisitions and Disposals [Line Items]

Electric Utilities [Member] | Busch Ranch Wind Farm [Member]

$ 0

768

^[2]

Significant Acquisitions and Disposals [Line Items]

Jointly Owned Utility Plant, Proportionate Ownership Share Percentage

50.00%

Proceeds from Sale of Property, Plant, and Equipment

$ 25,000

Significant Acquisitions and Disposals [Line Items]

Oil and Gas [Member] | Williston Basin Assets [Member]

$ 0

$ 29,129

^[1]

$ 0

Significant Acquisitions and Disposals [Line Items]

Effective Date, Disposal

Jul. 01, 2012

Proceeds from Sale of Productive Assets [Abstract]

$ 29,000

Post Close Adjustment

$ 2,793

Transaction Costs

$ (1,400)

Back-in Contract Termination Fee

^[3]

16,847

Oil and Gas [Member] | Cash Proceeds Received on Date of Sale [Member] | Williston Basin Assets [Member]

Proceeds from Sale of Productive Assets [Abstract]

Proceeds from Sale of Oil and Gas Property and Equipment

243,314

Net Cash Proceeds from Sale of Oil and Gas Property and Equipment

$ 243,314

Oil and Gas [Member] | Net Cash Proceeds [Member] | Williston Basin Assets [Member]

Proceeds from Sale of Productive Assets [Abstract]

Proceeds from Sale of Oil and Gas Property and Equipment

227,860

Net Cash Proceeds from Sale of Oil and Gas Property and Equipment

$ 227,860

[1]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[2]	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.
[3]	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Sale of Operating Assets and Discontinued Operations Discontinued Operations (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Significant Acquisitions and Disposals [Line Items]

Proceeds from sale of business operations

$ 0

$ 107,511

$ 0

Income (loss) from discontinued operations, net of tax

(884)

(6,977)

9,365

Income (loss) from discontinued operations, net of tax

$ (884)

$ 0

$ (167)

$ (166)

$ (1,160)

$ (5,484)

Business Exit Costs

$ 2,500

Energy Marketing [Member]

Significant Acquisitions and Disposals [Line Items]

Disposal Date

Feb. 29, 2012

Proceeds from sale of business operations

$ 108,000

Funds Retained, Sale of Business

58,000

Disposal Group, Including Discontinued Operation, Revenue

(604)

41,101

Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax

(6,061)

14,838

Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax

(1,391)

(4,184)

Discontinued Operation, Tax Effect of Discontinued Operation

507

3,268

(5,473)

Income (loss) from discontinued operations, net of tax

(884)

(6,977)

^[1]

$ 9,365

Minimum [Member] | Energy Marketing [Member]

Significant Acquisitions and Disposals [Line Items]

Post Close Adjustment

$ 1,100

$ 1,400

[1]	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended Dec. 31, 2012.

Quarterly Historical Data (Unaudited) Quarterly Historical Data (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Nov. 19, 2013

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 31, 2012

Selected Quarterly Financial Information [Line Items]

$ 355,448

$ 259,907

$ 279,826

$ 380,671

$ 318,862

$ 246,808

$ 242,363

$ 365,851

$ 1,275,852

$ 1,173,884

$ 1,272,188

71,103

55,566

49,037

79,846

75,262

^[1]

77,810

^[1]

20,591

^[1]

70,048

255,552

243,711

186,239

Income (loss) from discontinued operations

19,007

^[2],[3]

23,124

^[3]

30,518

^[3]

43,197

^[3]

30,934

^{[1],[4],[5],[6]}

34,623

^[5],[6]

(12,323)

^[1],[5],[6]

35,271

^[5]

115,846

88,505

40,365

(884)

(167)

(166)

(1,160)

(5,484)

Income (loss) from continuing operations, Basic

$ 18,123

^[2],[3]

$ 23,124

^[3]

$ 30,518

^[3]

$ 43,197

^[3]

$ 30,767

^{[1],[4],[5],[6]}

$ 34,457

^[5],[6]

$ (13,483)

^[1],[5],[6]

$ 29,787

$ 114,962

$ 81,528

$ 49,730

$ 0.43

$ 0.52

$ 0.69

$ 0.98

$ 0.70

$ 0.79

$ (0.28)

$ 0.81

$ 2.62

$ 2.02

$ 1.01

Income (loss) from discontinued operations, Basic

(0.02)

0.00

(0.03)

(0.13)

(0.02)

(0.16)

0.24

Total income (loss) per share, Basic

0.41

0.52

0.69

0.98

0.70

0.79

(0.31)

0.68

2.60

1.86

1.25

Income (loss) from continuing operations, Diluted

0.43

0.52

0.69

0.97

0.70

0.78

(0.28)

0.80

2.61

2.01

1.01

Income (loss) from discontinued operations, Diluted

(0.02)

0.00

(0.03)

(0.12)

(0.02)

(0.16)

0.23

Total income (loss) per share, Diluted

0.41

0.52

0.69

0.97

0.70

0.78

(0.31)

0.68

2.59

1.85

1.24

Dividends paid per share

$ 0.380

$ 0.370

$ 1.52

$ 1.48

$ 1.46

Unrealized Gain (Loss) Unhedged Derivative Instrument, Net of Tax

$ 500

$ 2,000

$ 12,000

$ 4,800

$ 3,100

$ 400

$ (10,000)

$ 7,800

Impairment of Oil and Gas Properties

27,000

$ 0

$ 26,868

^[7]

$ 0

Impairment of Oil and Gas Properties After Tax

1,800

27,000

29,129

^[8]

$ 17,000

Gain (Loss) On Sale Of Oil And Gas Properties, After-Tax

1,200

$ 18,000

Selected Quarterly Financial Information [Line Items]

(1,339)

(831)

(772)

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2014 [Member]

1,000,000

550,000

1,000,000

550,000

Selected Quarterly Financial Information [Line Items]

Interest Expense, Prepayment of Debt, Net of Tax

7,600

250,000

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2013 [Member]

^[9]

250,000

Selected Quarterly Financial Information [Line Items]

Interest Expense, Prepayment of Debt, Net of Tax

4,600

$ 225,000

Selected Quarterly Financial Information [Line Items]

4,648

4,189

4,059

47,760

44,799

10,935

Power Generation [Member] | Project Financing Debt Due 2016 [Member]

$ 0

Selected Quarterly Financial Information [Line Items]

Interest Expense, Prepayment of Debt, Net of Tax

6,600

$ 87,000

Common Stock [Member] | Maximum [Member]

^[10],[11]

$ 0

$ 95,906

$ 0

$ 95,906

Selected Quarterly Financial Information [Line Items]

Share Price

$ 54.83

$ 55.09

$ 50.53

$ 44.32

$ 37.00

$ 36.28

$ 34.31

$ 35.82

Common Stock [Member] | Minimum [Member]

Selected Quarterly Financial Information [Line Items]

Share Price

$ 47.00

$ 46.62

$ 43.19

$ 36.89

$ 33.51

$ 30.29

$ 31.32

$ 32.18

[1]	Second quarter includes a pre-tax ceiling test impairment loss of $27 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27 million and $1.8 million, respectively.
[2]	Fourth quarter 2013 includes $7.6 million after-tax for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt, and a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.
[3]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million, and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.
[4]	Fourth quarter includes a $4.6 million after-tax make-whole provision for the early redemption of our $225 million notes.
[5]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.
[6]	Second quarter includes an after-tax ceiling test impairment loss of $17 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $18 million and $1.2 million, respectively.
[7]	Oil and Gas includes a ceiling test impairment (see Note 12).
[8]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[9]	For 2012, this senior unsecured note was recorded by Black Hills Utility Holdings and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets. This note was redeemed on Dec. 19, 2013 with proceeds from the issuance of the Senior unsecured notes due 2023.
[10]	This debt repaid. See Debt Transactions discussed below.
[11]	Variable interest rate.

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Statement of Income for Parent Company (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Condensed Financial Statements, Captions [Line Items]

$ 355,448

$ 259,907

$ 279,826

$ 380,671

$ 318,862

$ 246,808

$ 242,363

$ 365,851

$ 1,275,852

$ 1,173,884

$ 1,272,188

Operating expenses

1,020,300

930,173

1,085,949

Equity income (loss) in earnings of subsidiaries

$ 71,103

$ 55,566

$ 49,037

$ 79,846

$ 75,262

^[1]

$ 77,810

^[1]

$ 20,591

^[1]

$ 70,048

255,552

243,711

186,239

Other income (expense):

(86)

1,121

(111,788)

^[2]

(113,610)

^[3]

(91,383)

30,169

1,882

(42,010)

1,723

1,957

2,017

Total other income (expense)

1,798

2,965

3,726

(78,012)

(106,816)

(128,771)

(61,608)

(48,400)

(18,224)

114,962

81,528

49,730

Condensed Financial Statements, Captions [Line Items]

Operating expenses

1,339

831

772

Equity income (loss) in earnings of subsidiaries

(1,339)

(831)

(772)

Other income (expense):

100,690

93,479

87,150

(7,827)

(19,665)

(15,229)

30,169

1,882

(42,010)

Total other income (expense)

(3)

(42)

123,059

75,777

29,872

Income (loss) before income taxes

121,720

74,946

29,100

(6,758)

6,582

20,630

$ 114,962

$ 81,528

$ 49,730

[1]	Second quarter includes a pre-tax ceiling test impairment loss of $27 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27 million and $1.8 million, respectively.
[2]	Power Generation includes costs associated with interest rate swaps settled and write-off of deferred financing costs upon repayment of Black Hills Wyoming Project Financing and Corporate includes a the write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt (see Note 5).
[3]	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 5).

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Statement of OCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income (loss) available for common stock	$ 114,962	$ 81,528	$ 49,730
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Benefit plan liability adjustments - net gain (loss) (net of tax of $(3,813), $296 and $4,135, respectively)	8,237	(542)	(7,609)
Benefit plan liability adjustments - prior service (costs) (net of tax of $185, $86 and $176, respectively)	(406)	(157)	(325)
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(971))	1,820	0	0
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $88)	(165)	0	0
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(2,445), $887 and $1,708, respectively)	4,534	(1,268)	(2,831)
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $(2,016), $534 and $(709), respectively)	4,046	(643)	1,468
Other comprehensive income (loss), net of tax	18,066	(2,610)	(9,297)
Comprehensive income (loss)	133,028	78,918	40,433
Other Comprehensive Income (Loss), Tax, Parenthetical Disclosures [Abstract]
Benefit plan liability adjustments - net gain (loss) (net of tax of	(3,813)	296	4,135
Benefit plan liability adjustments - prior service (costs) (net of tax of	185	86	176
Reclassification adjustment of benefit plan liability - net gain (loss) tax	(971)	0	0
Reclassification adjustment of benefit plan liability - prior service cost, tax	88	0	0
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of	(2,445)	887	1,708
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of	$ (2,016)	$ 534	$ (709)

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Balance Sheet for Parent Company Only (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 7,841	$ 15,462
Income tax receivable, net	1,460	0
Deferred income tax assets, net, current	18,889	77,231
Other current assets	25,877	28,795
Total current assets	345,288	405,106
Property and Equipment	2,990,297	2,742,749
Other assets, non-current	27,906	19,420
Total other assets, non-current	522,896	565,214
TOTAL ASSETS	3,875,178	3,729,471
Current liabilities:
Accounts payable - affiliate, current	130,416	84,422
Derivative liabilities, current	3,474	96,541
Notes payable	82,500	277,000
Current maturities of long-term debt	0	103,973
Total current liabilities	378,394	734,889
Derivative liabilities, non-current	5,614	16,941
Long-term debt, net of current maturities	1,396,948	938,877
Total stockholders’ equity	1,307,748	1,232,509	$ 1,209,336	$ 1,100,270
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	3,875,178	3,729,471
Black Hills Corporation [Member]
Current assets:
Cash and cash equivalents	1,664	1,266	$ 3,114	$ 219
Accounts receivable — affiliates, current	1,000	2,194
Notes receivable — affiliates, current	393,586	637,586
Income tax receivable, net	14,530	5,843
Deferred income tax assets, net, current	0	29,779
Other current assets	4,705	4,887
Total current assets	415,485	681,555
Property and Equipment	6,259	1,135
Investments in subsidiaries	1,237,876	1,194,501
Notes receivable — affiliate, non-current	685,000	250,000
Deferred income tax assets, net, non-current	67,958	41,494
Other assets, non-current	9,256	4,014
Total other assets, non-current	762,214	295,508
TOTAL ASSETS	2,421,834	2,172,699
Current liabilities:
Accounts payable - affiliate, current	372	565
Derivative liabilities, current	3,474	91,617
Deferred income taxes	12,775	0
Notes payable	82,500	277,000
Notes payable — affiliate, current	0	1,032
Current maturities of long-term debt	0	100,000
Other current liabilities	9,351	9,943
Total current liabilities	108,472	480,157
Derivative liabilities, non-current	5,614	9,252
Long-term debt, net of current maturities	1,000,000	450,000
Note payable — affiliate, non-current	0	781
Total long-term debt	1,000,000	450,781
Total stockholders’ equity	1,307,748	1,232,509
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 2,421,834	$ 2,172,699

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Parent Cash Flow Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating activities:
Net income (loss) available for common stock	$ 114,962	$ 81,528	$ 49,730
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Equity in earnings of subsidiaries	86	(10)	(1,121)
Stock compensation	12,595	8,271	5,643
Unrealized gain (loss) on interest rate swaps, net	(30,169)	(1,882)	42,010
Deferred income taxes	63,784	39,716	33,600
Other adjustments, net	9,826	4,929	(5,799)
Change in certain operating assets and liabilities:
Accounts receivable and other current assets	(13,921)	13,739	22,290
Other operating activities, net	312	(6,670)	(13,721)
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	325,513	295,787	216,694
Net cash provided by (used in) operating activities of discontinued operations	(884)	21,184	7,010
Net cash provided by (used in) investing activities of continuing operations	(349,278)	(95,518)	(444,648)
Investing activities:
Property, plant and equipment additions	(354,749)	(349,129)	(440,698)
Other investing activities	5,471	(180)	(4,533)
Financing activities:
Common stock issued	4,354	4,726	123,041
Long-term debt - issuance	800,000	0	0
Long-term debt - repayments	(445,906)	(240,077)	(8,382)
Payments for Derivative Instrument, Financing Activities	(63,939)	0	0
Other financing activities	(15,394)	(2,833)	(1,666)
Net cash provided by (used in) financing activities of continuing operations	17,028	(371,446)	249,791
Net change in cash and cash equivalents	(7,621)	(43,306)	26,330
Cash and cash equivalents	7,841	15,462
Supplemental Cash Flow Information [Abstract]
Income taxes	(4,573)	(3,027)	9,854
Black Hills Corporation [Member]
Operating activities:
Net income (loss) available for common stock	114,962	81,528	49,730
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Equity in earnings of subsidiaries	(100,690)	(93,479)	(87,150)
Dividend from subsidiaries	0	0	14,500
Stock compensation	12,595	8,271	5,643
Unrealized gain (loss) on interest rate swaps, net	(30,169)	(1,882)	42,010
Deferred income taxes	10,504	(8,116)	2,599
Other adjustments, net	3,099	3,909	4,376
Change in certain operating assets and liabilities:
Accounts receivable and other current assets	(3,184)	6,541	(5,141)
Accounts payable and other current liabilities	(7,881)	(6,764)	3,550
Other operating activities, net	20,386	(7,816)	2,841
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	19,622	(17,808)	32,958
Net cash provided by (used in) investing activities of continuing operations	(138,809)	96,523	(259,252)
Investing activities:
Property, plant and equipment additions	(5,124)	0	(1,135)
Decrease (increase) in advances to affiliates	(133,685)	96,073	(258,117)
Other investing activities	0	450	0
Financing activities:
Dividends paid on common stock	(67,587)	(65,262)	(59,202)
Common stock issued	4,356	4,726	123,041
Short-term borrowings -- repayments	(532,150)	(271,753)	(821,300)
Short-term borrowings -- issuances	337,650	203,753	1,017,300
Increase (decrease) in notes payable to affiliates	(1,813)	275,806	(25,302)
Long-term debt - issuance	800,000	0	0
Long-term debt - repayments	(350,000)	(225,000)	0
Other financing activities	(6,932)	(2,833)	(5,348)
Net cash provided by (used in) financing activities of continuing operations	119,585	(80,563)	229,189
Net change in cash and cash equivalents	398	(1,848)	2,895
Cash and cash equivalents	1,664	1,266	3,114	$ 219
Supplemental Cash Flow Information [Abstract]
Non-cash adjustment to notes receivable from affiliates	57,315	40,039	0
Non-cash adjustment to notes payable to affiliates	0	(277,560)	0
Non-cash dividend, net of non-cash contributions, from affiliates	(57,315)	237,521	0
Interest	(6,638)	(18,550)	(14,667)
Income taxes	$ (4,510)	$ 3,911	$ 23,830

Schedule I Disclosures for Parent Company Only Schedule I, Schedule of Dividends Paid to Parent (Details) - Black Hills Corporation [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Dividend Paid to Parent [Line Items]
Cash Dividends Paid to Parent Company by Consolidated Subsidiaries	$ 0	$ 0	$ 14,500
Non-Cash dividend, net of non-cash contributions, distributed to Parent by subsidiaries	$ (57,315)	$ 237,521	$ 0

Schedule I Disclosures for Parent Company Only Schedule I, Long Term Debt (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Nov. 19, 2013

Jun. 21, 2013

Dec. 31, 2012

Current maturities of long-term debt

$ 0

$ 103,973

Long-term debt, excluding current maturities

1,396,948

938,877

Long-term Debt, Fiscal Year Maturity [Abstract]

Long-term Debt, Maturities, Repayments of Principal in Year Two

275,000

Long-term Debt, Maturities, Repayments of Principal in Year Three

Long-term Debt, Maturities, Repayments of Principal in Year Four

Long-term Debt, Maturities, Repayments of Principal in Year Five

Long-term Debt, Maturities, Repayments of Principal after Year Five

1,122,055

Black Hills Utility Holdings [Member]

Notes receivable — affiliates, current

410,000

Current maturities of long-term debt

1,000,000

550,000

100,000

Long-term debt, excluding current maturities

1,000,000

450,000

Notes receivable — affiliates, current

393,586

637,586

Long-term Debt, Fiscal Year Maturity [Abstract]

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

Long-term Debt, Maturities, Repayments of Principal in Year Two

275,000

Long-term Debt, Maturities, Repayments of Principal in Year Three

Long-term Debt, Maturities, Repayments of Principal in Year Four

Long-term Debt, Maturities, Repayments of Principal in Year Five

Long-term Debt, Maturities, Repayments of Principal after Year Five

$ 725,000

Senior Unsecured Notes Due 2023 [Member] [Member] | Black Hills Corporation [Member]

Nov. 30, 2023

4.25%

Senior Unsecured Notes Due 2014 [Member] | Black Hills Corporation [Member]

$ 525,000

^[1]

$ 525,000

May 15, 2014

9.00%

Senior Unsecured Notes Due 2020 [Member] | Black Hills Corporation [Member]

^[2]

$ 0

250,000

Jul. 15, 2020

5.88%

Corporate Term Loan due September 2013 [Member] | Black Hills Corporation [Member]

^[3]

$ 200,000

200,000

Sep. 30, 2013

Corporate Term Loan due June 2015 [Member] [Member] | Black Hills Corporation [Member]

^[4],[5]

$ 0

100,000

^[6],[7]

Jun. 19, 2015

Senior Unsecured Notes Due 2023 [Member] [Member] | Black Hills Corporation [Member]

$ 275,000

^{[6],[7],[8],[9]}

$ 275,000

$ 0

Nov. 30, 2023

[1]	$410 million of this senior unsecured note has been recorded at Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.
[2]	For 2012, this senior unsecured note was recorded by Black Hills Utility Holdings and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets. This note was redeemed on Dec. 19, 2013 with proceeds from the issuance of the Senior unsecured notes due 2023.
[3]	This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012 and 2013.
[4]	This debt repaid. See Debt Transactions discussed below.
[5]	This term loan was repaid on June 21, 2013, and replaced with the Long-term term loan due June 19, 2015. In 2012, this term loan was recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2013.
[6]	Variable interest rate.
[7]	Variable interest rates, based on LIBOR plus a spread.
[8]	This debt has been recorded at our Power Generation segment and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets at 2013.
[9]	Variable interest rate.

Schedule I Disclosures for Parent Company Only Schedule I, Derivative Instruments Statement of Financial Postion Location and Notional Amount (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 19, 2013

$ 3,474

$ 96,541

$ 3,474

$ 96,541

Derivative, Collateral, Right to Reclaim Cash

5,614

16,941

5,614

16,941

5,021

6,141

$ 5,021

$ 6,141

Designated as Hedging Instrument [Member]

500

$ 2,000

$ 12,000

$ 4,800

3,100

$ 400

$ (10,000)

$ 7,800

Derivative, Remaining Maturity

3 years

4 years

Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

$ 75,000

^[1]

$ 150,000

^[2]

$ 75,000

^[1]

$ 150,000

^[2]

4.97%

5.04%

4.97%

5.04%

$ 3,474

$ 7,039

$ 3,474

$ 7,039

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

5,614

16,941

5,614

16,941

3,500

Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]

$ 250,000

3,474

91,617

3,474

91,617

Black Hills Corporation [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

5,614

9,252

5,614

9,252

75,000

$ 75,000

75,000

$ 75,000

Derivative, Remaining Maturity

4.97%

4 years

$ 3,469

Pre-tax accumulated other comprehensive income (loss)

9,252

(9,088)

(12,721)

(9,088)

(12,721)

Derivative, Collateral, Right to Reclaim Cash

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

3,500

Black Hills Corporation [Member] | Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]

^[3],[4]

$ 250,000

Derivative, Remaining Maturity

5.67%

^[5]

1 year

$ 88,148

Pre-tax accumulated other comprehensive income (loss)

Derivative, Fair Value, Amount Offset Against Collateral, Net

$ 5,960

Power Generation [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

Derivatives, Carrying Amount and Fair Value [Line Items]

$ 75,000

[1]	These swaps are designated to borrowings on our Revolving Credit Facility. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps.
[2]	At Dec. 31, 2012, $75 million of these interest rate swaps were designated to borrowings on our Revolving Credit Facility and $75 million were designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps. The portion of the swaps that were designated to Black Hills Wyoming were settled upon repayment of the Black Hills Wyoming project financing. See Note 5.
[3]	Included on the Condensed Statements of Income of the Parent is the non-cash mark-to-market gains recorded on these De-designated interest rate swaps of $30 million and $1.9 million for the twelve months ended Dec. 31, 2013 and 2012, respectively.
[4]	Maximum terms in years reflect the amended early termination dates. These swaps were settled in 2013.
[5]	Maximum terms in years reflect the amended early termination dates. If the early termination dates were not extended, the swaps would have required cash settlement based on the swap value at the termination date. These swaps were settled during the fourth quarter of 2013.

Schedule I Disclosures for Parent Company Only Schedule I, Fair Value by Balance Sheet Grouping (Details) - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

$ 7,841

$ 15,462

Long-term Debt, including current maturities

82,500

277,000

1,396,948

1,042,850

Reported Value Measurement [Member]

Derivatives, Carrying Amount and Fair Value [Line Items]

7,841

15,462

Long-term Debt, including current maturities

82,500

277,000

1,396,948

1,042,850

Total Estimate of Fair Value, Fair Value Disclosure [Member]

Derivatives, Carrying Amount and Fair Value [Line Items]

Cash and cash equivalents, at fair value

^[1]

7,841

15,462

Notes payable, fair value

^[1]

82,500

277,000

Long-term debt, including current maturities, at fair value

^[2]

1,491,422

1,231,559

Derivatives, Carrying Amount and Fair Value [Line Items]

1,664

1,266

$ 3,114

$ 219

Black Hills Corporation [Member] | Reported Value Measurement [Member]

82,500

277,000

Derivatives, Carrying Amount and Fair Value [Line Items]

1,664

1,266