UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended ~~June~~September 30, 2012
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________.

	Commission File Number 001-31303



Black Hills Corporation
Incorporated in South Dakota	IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701

Registrant's telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report
NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.



	Yes x		No o

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).



	Yes x		No o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).



	Large accelerated filer x		Accelerated filer o



	Non-accelerated filer o		Smaller reporting company o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



	Yes o		No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.



Class	Outstanding at ~~July~~October 31, 2012

Common stock, $1.00 par value	~~44,188,286~~44,180,030 shares



TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3

PART I.	FINANCIAL INFORMATION	5

Item 1.	Financial Statements	5

	Condensed Consolidated Statements of Income ~~and Comprehensive Income~~ - unaudited
	Three and ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2012 and 2011	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
	Three and Nine Months Ended Sept. 30, 2012 and 2011	6

	Condensed Consolidated Balance Sheets - unaudited
	~~June~~Sept. 30, 2012, ~~December~~Dec. 31, 2011 and ~~June~~Sept. 30, 2011	67

	Condensed Consolidated Statements of Cash Flows - unaudited
	~~Six~~Nine Months Ended ~~June~~Sept. 30, 2012 and 2011	89

	Notes to Condensed Consolidated Financial Statements - unaudited	910

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	6365

Item 4.	Controls and Procedures	6769

PART II.	OTHER INFORMATION	6870

Item 1.	Legal Proceedings	6870

Item 1A.	Risk Factors	6870

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	6870

Item 4.	Mine Safety Disclosures	6870

Item 5.	Other Information	6870

Item 6.	Exhibits	6971

	Signatures	7072

	Exhibit Index	7173

GLOSSARY OF TERMS AND ABBREVIATIONS

AND ACCOUNTING STANDARDS

The following terms and abbreviations appear in the text of this report and have the definitions described below:



AFUDC	Allowance for Funds Used During Construction
AltaGas	AltaGas Renewable Energy Colorado, LLC
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation, the "Company"
BHEP	Black Hills Exploration and Production, Inc., representing our Oil and Gas segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation	Black Hills Electric Generation, LLC, representing our Power Generation segment, a direct wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business activities of Black Hills Utility Holdings
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Company
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Service Company	Black Hills Service Company, a direct wholly-owned subsidiary of the Company
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu	British thermal unit
CFTC	Commodity Futures Trading Commission
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Company
Colorado Electric	Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas	Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado IPP	Black Hills Colorado IPP, a direct wholly-owned subsidiary of Black Hills Electric Generation
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion Turbine
CVA	Credit Valuation Adjustment
CWIP	Construction Work-In-Progress
De-designated interest rate swaps	The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but were subsequently de-designated.
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
~~DRIP~~	~~Dividend Reinvestment and Stock Purchase Plan~~
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
ECA	Energy Cost Adjustment



Enserco	Enserco Energy Inc., representing our Energy Marketing segment, sold ~~February~~Feb. 29, 2012
Equity Forward Instrument	Equity Forward Agreement with J.P. Morgan connected to a public offering of 4,413,519 shares of Black Hills Corporation common stock



FASB	Financial Accounting Standards Board
FDIC	Federal Deposit Insurance Corporation
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles of the United States
Global Settlement	Settlement with the utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
IFRS	International Financial Reporting Standards
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP	Independent Power Producer
IRS	Internal Revenue Service
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	One thousand standard cubic feet
Mcfe	One thousand standard cubic feet equivalent. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying barrels by 6.
MMBtu	One million British thermal units
MSHA	Mine Safety and Health Administration
MW	Megawatt
MWh	Megawatt-hour
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NGL	Natural Gas Liquids
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
OTC	Over-the-counter
PGA	Purchase Gas Adjustment
PPA	Power Purchase Agreement
REPA	Renewable Energy Purchase Agreement
Revolving Credit Facility	Our $500 million five-year revolving credit facility which commenced on ~~February~~Feb. 1, 2012 and expires on ~~February~~Feb. 1, 2017
S&P	Standard and Poor's
SEC	United States Securities and Exchange Commission
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, representing our Coal Mining segment

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME ~~AND COMPREHENSIVE INCOME~~(LOSS)

(unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011			2012			2011			2012			2011
	(in thousands, except per share amounts)												(in thousands, except per share amounts)
Revenue:
Utilities	$	214,946		$	236,053		$	551,601		$	610,749		$	214,716		$	223,714		$	766,317		$	834,463
Non-regulated energy	27,417			24,596			56,613			50,735			32,092			25,809			88,705			76,544
Total revenue	242,363			260,649			608,214			661,484			246,808			249,523			855,022			911,007

Operating expenses:
Utilities -
Fuel, purchased power and cost of gas sold	63,452			103,827			220,635			314,338			62,582			86,127			283,217			400,465
Operations and maintenance	59,563			58,689			124,323			126,098			59,398			58,313			183,721			184,411
Non-regulated energy operations and maintenance	20,713			22,436			43,308			46,626			22,466			22,813			65,774			69,438
Gain on sale of operating assets													(27,285		)	—			(27,285		)	—
Depreciation, depletion and amortization	41,431			32,246			79,990			64,156			41,408			33,278			121,398			97,434
Taxes - property, production and severance	9,478			7,239			20,988			15,436			10,213			9,161			31,201			24,598
Impairment of long-lived assets	26,868			—			26,868			—			—			—			26,868			—
Other operating expenses	267			52			1,463			303			216			259			1,679			562
Total operating expenses	221,772			224,489			517,575			566,957			168,998			209,951			686,573			776,908

Operating income	20,591			36,160			90,639			94,527			77,810			39,572			168,449			134,099

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums, discounts and realized settlements on interest rate swaps)	(27,762		)	(28,593		)	(57,676		)	(57,796		)	(27,475		)	(29,303		)	(85,151		)	(87,099		)
Allowance for funds used during construction - borrowed	963			2,991			1,481			6,354			1,127			3,520			2,608			9,874
Capitalized interest	131			2,783			292			5,217			175			2,981			467			8,198
Unrealized gain (loss) on interest rate swaps, net	(15,552		)	(7,827		)	(3,507		)	(2,362		)	605			(38,246		)	(2,902		)	(40,608		)
Interest income	627			463			1,064			1,011			364			536			1,428			1,547
Allowance for funds used during construction - equity	195			192			472			487			196			189			668			676
Other income, net	888			504			2,360			1,235
Other income (expense), net													(287		)	528			2,073			1,763
Total other income (expense)	(40,510		)	(29,487		)	(55,514		)	(45,854		)	(25,295		)	(59,795		)	(80,809		)	(105,649		)

Income (loss) before equity in earnings (loss) of unconsolidated subsidiaries and income taxes	(19,919		)	6,673			35,125			48,673			52,515			(20,223		)	87,640			28,450
Equity in earnings (loss) of unconsolidated subsidiaries	22			40			(34		)	1,033			22			43			(12		)	1,076
Income tax benefit (expense)	7,574			(3,007		)	(12,143		)	(16,932		)	(17,914		)	9,017			(30,057		)	(7,915		)
Income (loss) from continuing operations	(12,323		)	3,706			22,948			32,774			34,623			(11,163		)	57,571			21,611
Income (loss) from discontinued operations, net of tax	(1,160		)	4,046			(6,644		)	1,888			(166		)	638			(6,810		)	2,526
Net income (loss) available for common stock	(13,483		)	7,752			16,304			34,662			$	34,457		$	(10,525	)	$	50,761		$	24,137

Other comprehensive income (loss), net of tax	(608		)	288			(774		)	(1,290		)
Comprehensive income (loss)	$	(14,091	)	$	8,040		$	15,530		$	33,372

Income (loss) per share, Basic -
Income (loss) from continuing operations, per share	$	(0.28	)	$	0.09		$	0.52		$	0.84		$	0.79		$	(0.29	)	$	1.31		$	0.55
Income (loss) from discontinued operations, per share	(0.03		)	0.11			(0.15		)	0.05			—			0.02			(0.16		)	0.07
Total income (loss) per share, Basic	$	(0.31	)	$	0.20		$	0.37		$	0.89		$	0.79		$	(0.27	)	$	1.15		$	0.62
Income (loss) per share, Diluted -
Income (loss) from continuing operations, per share	$	(0.28	)	$	0.09		$	0.52		$	0.82		$	0.78		$	(0.29	)	$	1.31		$	0.54
Income (loss) from discontinued operations, per share	(0.03		)	0.10			(0.15		)	0.05			—			0.02			(0.16		)	0.07
Total income (loss) per share, Diluted	$	(0.31	)	$	0.19		$	0.37		$	0.87		$	0.78		$	(0.27	)	$	1.15		$	0.61
Weighted average common shares outstanding:
Basic	43,799			39,109			43,765			39,084			43,847			39,145			43,792			39,105
Diluted	43,799			39,823			43,984			39,793			44,108			39,145			44,026			39,792

Dividends paid per share of common stock	$	0.370		$	0.365		$	0.740		$	0.730		$	0.370		$	0.365		$	1.110		$	1.095

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED ~~BALANCE SHEETS~~STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)

June 30,
2012 December 31,
2011 June 30,
2011
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 40,110
$ 21,628
$ 21,971
Restricted cash and equivalents 4,772
9,254
3,710
Accounts receivable, net 109,157
156,774
108,203
Materials, supplies and fuel 61,455
84,064
61,104
Derivative assets, current 16,595
18,583
9,544
Income tax receivable, net 12,141
9,344
6,661
Deferred income tax assets, net, current 30,401
37,202
20,924
Regulatory assets, current 34,781
59,955
37,584
Other current assets 26,591
21,266
17,499
Assets of discontinued operations —
340,851
358,669
Total current assets 336,003
758,921
645,869

Investments 16,208
17,261
17,302

Property, plant and equipment 3,863,380
3,724,016
3,550,783
Less accumulated depreciation and depletion (1,006,827 ) (934,441 ) (913,503 )
Total property, plant and equipment, net 2,856,553
2,789,575
2,637,280

Other assets:
Goodwill 353,396
353,396
353,396
Intangible assets, net 3,731
3,843
3,955
Derivative assets, non-current 1,770
1,971
724
Regulatory assets, non-current 186,886
182,175
139,309
Other assets, non-current 19,733
19,941
19,325
Total other assets 565,516
561,326
516,709

TOTAL ASSETS $ 3,774,280
$ 4,127,083
$ 3,817,160



	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
	(in thousands)

Net income (loss) available for common stock	$	34,457		$	(10,525	)	$	50,761		$	24,137

Other comprehensive income (loss), net of tax:
Fair value adjustment of derivatives designated as cash flow hedges (net of tax of $1,204 and $(1,215) for the three months ended 2012 and 2011 and $1,092 and $653 for the nine months ended 2012 and 2011, respectively)	(3,591		)	1,922			(3,004		)	(991		)
Reclassification adjustments of cash flow hedges settled and included in net income (loss) (net of tax of $13 and $(129) for the three months ended 2012 and 2011 and $890 and $(985) for the nine months ended 2012 and 2011, respectively)	28			285			(1,333		)	1,907
Other comprehensive income (loss), net of tax	(3,563		)	2,207			(4,337		)	916

Comprehensive income (loss)	$	30,894		$	(8,318	)	$	46,424		$	25,053

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

~~(Continued)~~

(unaudited)

June 30,
2012 December 31,
2011 June 30,
2011
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 59,739
$ 104,748
$ 84,195
Accrued liabilities 158,240
151,319
131,175
Derivative liabilities, current 85,675
84,367
65,627
Regulatory liabilities, current 16,785
16,231
17,220
Notes payable 225,000
345,000
380,000
Current maturities of long-term debt 227,590
2,473
3,613
Liabilities of discontinued operations —
173,929
182,723
Total current liabilities 773,029
878,067
864,553

Long-term debt, net of current maturities 1,044,891
1,280,409
1,183,583

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current 316,393
300,988
304,860
Derivative liabilities, non-current 42,077
49,033
17,281
Regulatory liabilities, non-current 114,593
108,217
83,643
Benefit plan liabilities 162,530
177,480
131,169
Other deferred credits and other liabilities 124,482
123,553
124,002
Total deferred credits and other liabilities 760,075
759,271
660,955

Commitments and contingencies (See Notes 6, 7, 10, 11, 13 and 16)

Stockholders' equity:
Common stockholders' —
Common stock $1 par value: 100,000,000 shares authorized: issued 44,176,520; 43,957,502 and 39,462,001 shares, respectively 44,177
43,958
39,462
Additional paid-in capital 727,613
722,623
602,961
Retained earnings 460,324
476,603
491,208
Treasury stock at cost – 69,657; 32,766 and 23,637 shares, respectively (2,177 ) (970 ) (691 )
Accumulated other comprehensive income (loss) (33,652 ) (32,878 ) (24,871 )
Total stockholders' equity 1,196,285
1,209,336
1,108,069

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 3,774,280
$ 4,127,083
$ 3,817,160



	Sept. 30, 2012			Dec. 31, 2011			Sept. 30, 2011
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	247,192		$	21,628		$	30,198
Restricted cash and equivalents	7,302			9,254			4,080
Accounts receivable, net	104,482			156,774			102,673
Materials, supplies and fuel	80,900			84,064			84,607
Derivative assets, current	16,063			18,583			12,177
Income tax receivable, net	11,869			9,344			4,728
Deferred income tax assets, net, current	33,681			37,202			37,931
Regulatory assets, current	24,606			59,955			45,713
Other current assets	44,823			21,266			25,269
Assets of discontinued operations	—			340,851			332,503
Total current assets	570,918			758,921			679,879

Investments	16,273			17,261			17,338

Property, plant and equipment	3,950,222			3,724,016			3,656,762
Less accumulated depreciation and depletion	(1,253,808		)	(934,441		)	(931,299		)
Total property, plant and equipment, net	2,696,414			2,789,575			2,725,463

Other assets:
Goodwill	353,396			353,396			353,396
Intangible assets, net	3,675			3,843			3,899
Derivative assets, non-current	1,167			1,971			3,246
Regulatory assets, non-current	191,935			182,175			142,267
Other assets, non-current	19,850			19,941			20,081
Total other assets	570,023			561,326			522,889

TOTAL ASSETS	$	3,853,628		$	4,127,083		$	3,945,569

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)

(unaudited)



	Sept. 30, 2012			December 31, 2011			Sept. 30, 2011
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	69,138		$	104,748		$	91,628
Accrued liabilities	179,284			151,319			161,650
Derivative liabilities, current	86,509			84,367			101,312
Regulatory liabilities, current	10,705			16,231			10,568
Notes payable	225,000			345,000			359,000
Current maturities of long-term debt	328,310			2,473			2,893
Liabilities of discontinued operations	—			173,929			171,685
Total current liabilities	898,946			878,067			898,736

Long-term debt, net of current maturities	942,950			1,280,409			1,282,194

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	338,194			300,988			317,864
Derivative liabilities, non-current	41,410			49,033			22,475
Regulatory liabilities, non-current	120,491			108,217			85,074
Benefit plan liabilities	167,690			177,480			124,214
Other deferred credits and other liabilities	129,630			123,553			127,007
Total deferred credits and other liabilities	797,415			759,271			676,634

Commitments and contingencies (See Notes 6, 7, 9, 11, 12 and 14)

Stockholders' equity:
Common stock —
Common stock $1 par value: 100,000,000 shares authorized: issued 44,250,588; 43,957,502 and 39,491,616 shares, respectively	44,251			43,958			39,492
Additional paid-in capital	731,176			722,623			604,945
Retained earnings	478,459			476,603			467,043
Treasury stock at cost – 75,420; 32,766 and 28,041 shares, respectively	(2,354		)	(970		)	(810		)
Accumulated other comprehensive income (loss)	(37,215		)	(32,878		)	(22,665		)
Total stockholders' equity	1,214,317			1,209,336			1,088,005

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,853,628		$	4,127,083		$	3,945,569

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

~~(unaudited)~~


	Six Months Ended June 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011
Operating activities:	(in thousands)						(unaudited, in thousands)
Net income (loss) available to common stock	$	16,304		$	34,662		$	50,761		$	24,137
(Income) loss from discontinued operations, net of tax	6,644			(1,888		)	6,810			(2,526		)
Income (loss) from continuing operations	22,948			32,774			57,571			21,611
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	79,990			64,156			121,398			97,434
Deferred financing cost amortization	4,050			3,199			5,301			5,040
Impairment of long-lived assets	26,868			—			26,868			—
Derivative fair value adjustments	(4,895		)	(3,235		)	(3,522		)	(2,305		)
Gain on sale of operating assets							(27,285		)	—
Stock compensation	3,269			3,185			5,974			4,840
Unrealized mark-to-market (gain) loss on interest rate swaps	3,507			2,362			2,902			40,608
Deferred income taxes	11,200			29,836			28,718			20,854
Equity in (earnings) loss of unconsolidated subsidiaries	34			(1,033		)
Allowance for funds used during construction - equity	(472		)	(487		)	(668		)	(676		)
Employee benefit plans	10,492			7,287			15,737			10,930
Other adjustments, net	4,258			(160		)	3,505			3,177
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	22,609			1,811			3,085			(21,692		)
Accounts receivable, unbilled revenues and other current assets	42,262			51,615			43,447			50,649
Accounts payable and other current liabilities	(55,015		)	(65,673		)	(22,042		)	(51,846		)
Regulatory assets	14,533			32,029			15,544			22,357
Regulatory liabilities	(385		)	11,573			(1,983		)	5,041
Contributions to defined benefit pension plans	(25,000		)	(550		)	(25,000		)	(11,050		)
Other operating activities, net	(4,738		)	(6,190		)	(1,067		)	(1,755		)
Net cash provided by operating activities of continuing operations	155,515			162,499			248,483			193,217
Net cash provided by (used in) operating activities of discontinued operations	21,184			19,518			21,184			13,309
Net cash provided by operating activities	176,699			182,017			269,667			206,526

Investing activities:
Property, plant and equipment additions	(148,807		)	(223,456		)	(261,414		)	(326,543		)
Proceeds from sale of assets							268,482			583
Investment in notes receivable							(21,832		)	—
Other investing activities	4,095			799			5,057			1,051
Net cash provided by (used in) investing activities of continuing operations	(144,712		)	(222,657		)	(9,707		)	(324,909		)
Proceeds from sale of business operations	108,837			—
Proceeds from sale of discontinued business operations							108,837			—
Net cash provided by (used in) investing activities of discontinued operations	(824		)	(2,407		)	(824		)	(1,953		)
Net cash provided by (used in) investing activities	(36,699		)	(225,064		)	98,306			(326,862		)

Financing activities:
Dividends paid on common stock	(32,583		)	(29,530		)	(48,904		)	(43,169		)
Common stock issued	1,510			1,437			3,835			2,199
Short-term borrowings - issuances	56,453			564,000			62,453			770,000
Short-term borrowings - repayments	(176,453		)	(433,000		)	(182,453		)	(560,000		)
Long-term debt - repayments	(10,418		)	(4,052		)	(11,647		)	(6,169		)
Other financing activities	2,833			(16		)	(2,833		)	(28		)
Net cash provided by (used in) financing activities of continuing operations	(158,658		)	98,839			(179,549		)	162,833
Net cash provided by (used in) financing activities of discontinued operations	—			(157		)	—			(157		)
Net cash provided by (used in) financing activities	(158,658		)	98,682			(179,549		)	162,676
Net change in cash and cash equivalents	(18,658		)	55,635			188,424			42,340
Cash and cash equivalents, beginning of period*	58,768			32,438			58,768			32,438
Cash and cash equivalents, end of period*	$	40,110		$	88,073		$	247,192		$	74,778

_______________________


*	~~Cash and cash equivalents include~~Includes cash of discontinued operations of $37.1 million, $~~66.1~~44.6 million and $16.0 million at ~~December~~Dec. 31, 2011, ~~June~~Sept. 30, 2011 and ~~December~~Dec. 31, 2010, respectively.

See Note 3 for supplemental disclosure of cash flow information.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company's 2011 Annual Report on Form 10-K)

(1) MANAGEMENT'S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation ~~together~~(together with our subsidiaries ~~(the~~the "Company," "us," "we," or "our"), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2011 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the ~~June~~Sept. 30, 2012, December 31, 2011 and ~~June~~Sept. 30, 2011 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and ~~six~~nine months ended ~~June~~Sept. 30, 2012 and ~~June~~Sept. 30, 2011, and our financial condition as of ~~June~~Sept. 30, 2012, December 31, 2011, and ~~June~~Sept. 30, 2011 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

On ~~February~~Feb. 29, 2012,, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. For further information see Note 1817.

Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation. Specifically, the Company has reclassified deferred financing cost amortization into a separate line on the Condensed Consolidated Statements of Cash Flows. This reclassification had no effect on total assets, net income, cash flows or earnings per share.

(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

Recently Adopted Accounting Standards and Legislation

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending ~~ASC 220,~~accounting guidance for Comprehensive Income to improve the comparability, consistency and transparency of reporting of comprehensive income. ItThe update 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 is effective for the fiscal years, and interim periods within those years beginning after ~~December~~Dec. 15, 2011. In December 2011, FASB issued ASU 2011-12, which 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.

910

At ~~December~~Dec. 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain ~~financial statements and provided additional details in the notes to the~~ financial statements, but did not have any other impact on our financial statements.

Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04

In May 2011, FASB issued an accounting standards update amending ~~ASC 820,~~accounting guidance for Fair Value Measurements and Disclosures to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity's use of a non-financial asset that is different from the asset's highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after ~~December~~Dec. 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our financial statements. Additional disclosures are included in Notes 1412 and 1513.

Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08

In September 2011, the FASB issued an amendment to ~~ASC 350,~~accounting guidance to Intangibles - Goodwill and Other to provide an option to perform a qualitative assessment to determine whether further impairment testing of goodwill is necessary. Specifically, an entity has the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. This standard is effective for annual and interim goodwill impairment testing performed for fiscal years beginning after ~~December~~Dec. 15, 2011. We perform our annual impairment testing in November of each year. The adoption of this standard will not have an impact on our financial statements.

Recently Issued Accounting Standards and Legislation

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11

In December 2011, the FASB issued revised accounting guidance to amend ~~ASC 210,~~accounting guidance for 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 is effective on a retrospective basis for interim and annual periods beginning ~~January~~Jan. 1, 2013. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.

Intangible - Goodwill and Other: Testing Indefinite Lived Intangible Assets for Impairment, ASU 2012-02

In July 2012, the FASB issued an amendment to ~~ASC 350,~~accounting guidance for Intangibles - Goodwill and Other to provide an option to perform a qualitative assessment to determine whether further impairment testing of indefinite lived intangible assets is necessary. This ASU aligns the impairment testing for intangible assets with that of goodwill as amended by ASU ~~2011-11.~~2011-08. This guidance is effective for interim and annual periods beginning after ~~September~~Sept. 15, 2012, with early adoption permitted. The adoption of this standard will not have an impact on our financial ~~statements,~~statements.

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

In August 2012, the SEC approved a final rule implementing Section 1504 of Dodd-Frank. The rule requires issuers engaged in the commercial development of oil, natural gas or minerals to disclose cash payments made to a foreign government or the United States government. We are in the process of evaluating our reporting requirements. The adoption of this rule will not have an impact on our financial statements.

Additionally, in July 2012, the CFTC and SEC published final rules that define “swap,” “security-based swap” and other key terms and concepts that are critical to the implementation of the derivatives reforms required by Dodd-Frank. We are in the process of evaluating our reporting requirements. The adoption of this rule will not have an impact on our financial position, results of operations or cash flows.

(3) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION


	Six Months Ended						Nine Months Ended
	June 30, 2012			June 30, 2011			Sept. 30, 2012			Sept. 30, 2011
	(in thousands)						(in thousands)
Non-cash investing activities from continuing operations—
Property, plant and equipment acquired with accrued liabilities	$	52,204		$	34,171
Property, plant and equipment acquired with accounts payable and accrued liabilities							$	39,303		$	49,566
Capitalized assets associated with retirement obligations	$	3,406		$	—		$	3,806		$	—
Cash (paid) refunded during the period for continuing operations—
Interest (net of amounts capitalized)	$	(55,364	)	$	(49,425	)	$	(69,901	)	$	(60,934	)
Income taxes, net	$	(383	)	$	(10,726	)	$	425		$	11,939

(4) MATERIALS, SUPPLIES AND FUEL

The amounts of ~~Materials,~~materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands) as of:


	June 30, 2012		December 31, 2011		June 30, 2011		Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
Materials and supplies	$	41,963	$	40,838	$	36,382	$	43,847	$	40,838	$	37,327
Fuel - Electric Utilities	8,089		8,201		8,808		8,289		8,201		8,639
Natural gas in storage held for distribution	11,403		35,025		15,914		28,764		35,025		38,641
Total materials, supplies and fuel	$	61,455	$	84,064	$	61,104	$	80,900	$	84,064	$	84,607

(5) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable consists primarily of customer trade accounts. The Gas Utilities' accounts receivable balance fluctuates primarily due to seasonality. We maintain an allowance for doubtful accounts that reflects our ~~best~~ estimate of ~~probable~~ uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect our ability to collect.

Following is a summary of receivables (in thousands) as of:


	Accounts		Unbilled		Less Allowance for			Accounts		Accounts		Unbilled		Less Allowance for			Accounts
June 30, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Sept. 30, 2012										Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	36,336	$	25,726	$	(620	)	$	61,442	$	46,802	$	18,441	$	(603	)	$	64,640
Gas Utilities	20,627		11,085		(950		)	30,762		18,198		9,480		(204		)	27,474
Oil and Gas	13,749		—		(105		)	13,644		10,272		—		(105		)	10,167
Coal Mining	1,982		—		—			1,982		1,540		—		—			1,540
Power Generation	197		—		—			197		4		—		—			4
Corporate	1,130		—		—			1,130		657		—		—			657
Total	$	74,021	$	36,811	$	(1,675	)	$	109,157	$	77,473	$	27,921	$	(912	)	$	104,482

1112


	Accounts		Unbilled		Less Allowance for			Accounts		Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Dec. 31, 2011										Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	42,773	$	21,151	$	(545	)	$	63,379	$	42,773	$	21,151	$	(545	)	$	63,379
Gas Utilities	39,353		38,992		(1,011		)	77,334		39,353		38,992		(1,011		)	77,334
Oil and Gas	11,282		—		(105		)	11,177		11,282		—		(105		)	11,177
Coal Mining	4,056		—		—			4,056		4,056		—		—			4,056
Power Generation	282		—		—			282		282		—		—			282
Corporate	546		—		—			546		546		—		—			546
Total	$	98,292	$	60,143	$	(1,661	)	$	156,774	$	98,292	$	60,143	$	(1,661	)	$	156,774


	Accounts		Unbilled		Less Allowance for			Accounts		Accounts		Unbilled		Less Allowance for			Accounts
June 30, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Sept. 30, 2011										Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	38,067	$	16,535	$	(685	)	$	53,917	$	41,889	$	16,401	$	(590	)	$	57,700
Gas Utilities	33,572		11,891		(1,420		)	44,043		21,168		12,518		(789		)	32,897
Oil and Gas	7,803		—		(161		)	7,642		8,820		—		(161		)	8,659
Coal Mining	1,652		—		—			1,652		1,845		—		—			1,845
Power Generation	106		—		—			106		119		—		—			119
Corporate	843		—		—			843		1,453		—		—			1,453
Total	$	82,043	$	28,426	$	(2,266	)	$	108,203	$	75,294	$	28,919	$	(1,540	)	$	102,673

(6) NOTES PAYABLE

Our credit facility and debt securities contain certain restrictive financial covenants. ~~As of~~ ~~June 30, 2012, we~~We were in compliance with all of these ~~covenants.~~covenants at Sept. 30, 2012.

We had the following short-term debt outstanding ~~as of~~at the Condensed Consolidated Balance Sheet dates (in thousands): as of:


	June 30, 2012				December 31, 2011				June 30, 2011				Sept. 30, 2012				Dec. 31, 2011				Sept. 30, 2011
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Notes Payable		Letters of Credit		Notes Payable		Letters of Credit		Notes Payable		Letters of Credit
Revolving Credit Facility	$	75,000	$	36,256	$	195,000	$	43,700	$	130,000	$	43,000	$	75,000	$	36,300	$	195,000	$	43,700	$	209,000	$	42,355
Term Loan due 2011^(a)	—		—		—		—		100,000		—
Term Loan due 2013^(b)	150,000		—		150,000		—		150,000		—
Term Loan due June 2013 ^(a)													150,000		—		150,000		—		150,000		—
Total	$	225,000	$	36,256	$	345,000	$	43,700	$	380,000	$	43,000	$	225,000	$	36,300	$	345,000	$	43,700	$	359,000	$	42,355

______________

(a) ~~The short-term loan was renegotiated to a longer term note, maturing on~~ ~~September 30, 2013~~.

~~(b)~~ In June 2012, this short-term loan was extended for one year. See discussion below.

Revolving Credit Facility

On ~~February~~Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring ~~February~~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 ~~0.50%~~0.50 percent, ~~1.50%~~1.50 percent and ~~1.50%~~1.50 percent, respectively, at ~~June~~Sept. 30, 2012. 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%~~0.25 percent.

1213

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

Term ~~Loan due 2013~~Loans

On June 24, 2012,, we extended the term of the $150 million term loan to June 24, 2013. The cost of borrowing is based on ~~1.10%~~1.10 percent over LIBOR.

Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):


	As of							As of
	June 30, 2012			Covenant Requirement				Sept. 30, 2012			Covenant Requirement
Consolidated Net Worth	$	1,196,285		Greater than	$	892,283		$	1,214,317		Greater than	$	909,511
Recourse Leverage Ratio	56.8		%	Less than	65.0		%	56.3		%	Less than	65.0		%

(7) LONG TERM DEBT

On May 15, 2012, Black Hills Power repaid its ~~4.8%~~4.8 percent Pollution Control ~~Refund~~ Revenue Bonds in full for $6.5 million principal and interest. These bonds were originally due to mature on ~~October~~Oct. 1, 2014.

(8) EARNINGS PER SHARE

Basic ~~income~~Income (loss) per share from continuing operations is computed by dividing Income (loss) from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted ~~income~~Income (loss) per share is computed by including all dilutive common shares potentially outstanding during a period.

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


	Three Months Ended June 30,					Six Months Ended June 30,				Three Months Ended Sept. 30,					Nine Months Ended Sept. 30,
	2012			2011		2012		2011		2012		2011			2012		2011

Income (loss) from continuing operations	$	(12,323	)	$	3,706	$	22,948	$	32,774	$	34,623	$	(11,163	)	$	57,571	$	21,611

Weighted average shares - basic	43,799			39,109		43,765		39,084		43,847		39,145			43,792		39,105
Dilutive effect of:
Restricted stock	—			148		150		140		175		—			159		147
Stock options	—			20		15		20		12		—			14		16
Equity forward instruments	—			533		—		496		—		—			—		473
Other dilutive effects	—			13		54		53		74		—			61		51
Weighted average shares - diluted	43,799			39,823		43,984		39,793		44,108		39,145			44,026		39,792

1314

Below is a discussion of our potentially dilutive shares that were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive.

Due to our net loss for the quarter ended ~~June~~Sept. 30, ~~2012,~~2011, potentially dilutive securities, consisting of outstanding stock options, restricted common stock, restricted stock units, non-vested performance-based share awards and warrants, were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, ~~13,081~~11,880 options to purchase shares of common stock, ~~152,318~~159,873 vested and non-vested restricted stock shares, ~~34,248~~31,408 warrants and other performance shares and 424,715 forward equity instruments were excluded from the computations for the three months ended ~~June~~Sept. 30, ~~2012.~~2011.

In addition to these potentially dilutive shares excluded due to our net loss for ~~second~~third quarter of ~~2012,~~2011, the following outstanding securities also were ~~also~~ excluded in the computation of diluted ~~income~~Income (loss) per share from continuing operations as their inclusion would have been anti-dilutive (in thousands):


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011	2012	2011	2012	2011
Stock options	99	102	113	81	77	176	101	119
Restricted stock	66	24	48	16	61	20	53	17
Other stock	42	31	29	15	—	27	19	19
Anti-dilutive shares	207	157	190	112	138	223	173	155

(9) ~~COMPREHENSIVE INCOME (LOSS)~~

~~The following table presents the components of our comprehensive income (loss) (in thousands):~~

Three Months Ended June 30, 2012 Pre-tax Amount Tax (Expense) Benefit Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges $ 178
$ (167 ) $ 11
Reclassification adjustments of cash flow hedges settled and included in net income (loss) (1,051 ) 432
(619 )
Other comprehensive income (loss) $ (873 ) $ 265
$ (608 )

Three Months Ended June 30, 2011 Pre-tax Amount Tax (Expense) Benefit Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges $ (996 ) $ 231
$ (765 )
Reclassification adjustments of cash flow hedges settled and included in net income (loss) 1,617
(564 ) 1,053
Other comprehensive income (loss) $ 621
$ (333 ) $ 288

Six Months Ended June 30, 2012 Pre-tax Amount Tax (Expense) Benefit Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges $ 699
$ (112 ) $ 587
Reclassification adjustments of cash flow hedges settled and included in net income (loss) (2,238 ) 877
(1,361 )
Other comprehensive income (loss) $ (1,539 ) $ 765
$ (774 )

Six Months Ended June 30, 2011 Pre-tax Amount Tax (Expense) Benefit Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges $ (4,781 ) $ 1,868
$ (2,913 )
Reclassification adjustments of cash flow hedges settled and included in net income (loss) 2,478
(855 ) 1,623
Other comprehensive income (loss) $ (2,303 ) $ 1,013
$ (1,290 )

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

Derivatives Designated as Cash Flow Hedges Employee Benefit Plans Total
Balance as of December 31, 2011 $ (13,802 ) $ (19,076 ) $ (32,878 )
Other comprehensive income (loss) (774 ) —
(774 )
Ending Balance June 30, 2012 $ (14,576 ) $ (19,076 ) $ (33,652 )

Derivatives Designated as Cash Flow Hedges Employee Benefit Plans Total
Balance as of December 31, 2010 $ (12,439 ) $ (11,142 ) $ (23,581 )
Other comprehensive income (loss) (1,290 ) —
(1,290 )
Ending Balance June 30, 2011 $ (13,729 ) $ (11,142 ) $ (24,871 )

(10~~) COMMON STOCK~~

~~Other than the following transactions, we had no material changes in our common stock during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2012~~ ~~from the amount reported in Note 11 of the Notes to Consolidated Financial Statements in our~~ ~~2011~~ ~~Annual Report on Form 10-K.~~

~~Equity Compensation Plans~~

~~We granted~~ ~~66,690~~ ~~target performance shares to certain officers and business unit leaders for the~~ ~~January 1, 2012 through December 31, 2014~~ ~~performance period during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2012~~. Actual shares are issued after the end of the performance period. Performance shares are awarded based on our total stockholder return over the designated performance period as measured against a selected peer group and can range from 0% to ~~200%~~ of target. 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%~~ ~~in cash and~~ ~~50%~~ ~~in shares of common stock. The grant date fair value was~~ ~~$32.26~~ ~~per share.~~

~~We granted~~ ~~145,787~~ ~~shares of restricted common stock and restricted stock units during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2012. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately~~ ~~$5.1 million~~ ~~will be recognized over the vesting period.~~

~~Stock options totaling~~ ~~41,206~~ ~~shares of common stock were exercised during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2012~~ ~~at a weighted-average exercise price of~~ ~~$28.28~~ ~~per share, providing~~ ~~$1.2 million~~ ~~of proceeds.~~

~~We issued~~ ~~3,690~~ ~~shares of common stock under our short-term incentive compensation plan during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2012. Pre-tax compensation cost related to the awards was approximately~~ ~~$0.1 million, which was expensed in~~ ~~2011~~.

~~Stock-based compensation expense for the~~ ~~three~~ ~~months ended~~ ~~June 30, 2012~~ ~~and~~ ~~2011~~ ~~was~~ ~~$1.5 million~~ ~~and~~ ~~$0.9 million, respectively, and for the~~ ~~six~~ ~~months ended~~ ~~June 30, 2012~~ ~~and~~ ~~2011~~ ~~was~~ ~~$3.3 million~~ ~~and~~ ~~$3.1 million, respectively.~~

~~As of~~ ~~June 30, 2012, total unrecognized compensation expense related to non-vested stock awards was~~ ~~$10.3 million~~ ~~and is expected to be recognized over a weighted-average period of~~ ~~2.2~~ ~~years.~~

~~Dividend Reinvestment and Stock Purchase Plan~~

~~We have a DRIP under which stockholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at~~ ~~100%~~ ~~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. We issued~~ ~~52,247~~ ~~new shares at a weighted-average price of~~ ~~$32.70~~ ~~during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2012. Unissued common stock totaling~~ ~~401,017~~ ~~shares was available for future offering under the DRIP at~~ ~~June 30, 2012~~.

~~Dividend Restrictions~~

~~Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of~~ ~~June 30, 2012, 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 stockholders 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 ~~June 30, 2012~~:

Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of ~~June 30, 2012, the restricted net assets at our Utilities Group were approximately~~ ~~$215.1 million~~.

~~As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted equity of at least~~ ~~$100.0 million~~.

(11) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans ~~(the "Pension Plans")~~(Pension Plans). One covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC and BHEP, one covers certain eligible employees of Cheyenne Light, and one covers certain eligible employees of Black Hills Energy. As of Jan. 1, 2012, all Pension Plans have been frozen to new employees and certain eligible employees who did not meet age and service based criteria at the time the Pension Plans were frozen. Additionally, effective Oct. 1, 2012, the Cheyenne Light Pension Plan was merged into the Black Hills Corporation Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.

The components of net periodic benefit cost for the Pension Plans were as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost	$	1,430		$	1,356		$	2,860		$	2,711		$	1,431		$	1,355		$	4,291		$	4,066
Interest cost	3,687			3,732			7,374			7,464			3,688			3,732			11,062			11,196
Expected return on plan assets	(4,084		)	(4,239		)	(8,168		)	(8,478		)	(4,084		)	(4,239		)	(12,252		)	(12,717		)
Prior service cost	22			25			44			50			22			25			66			75
Net loss (gain)	2,408			1,135			4,816			2,270			2,408			1,135			7,224			3,405
Net periodic benefit cost	$	3,463		$	2,009		$	6,926		$	4,017		$	3,465		$	2,008		$	10,391		$	6,025

Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor the following retiree healthcare plans ~~(the "Healthcare Plans")~~(Healthcare Plans): the Black Hills Corporation Postretirement Healthcare Plan, the Healthcare Plan for Retirees of Cheyenne Light, and the Black Hills Energy Postretirement Healthcare Plan. Employees who participate in the Healthcare Plans and who retire on or after meeting certain eligibility requirements are entitled to postretirement healthcare benefits.

1615

The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost	$	402		$	375		$	804		$	750		$	402		$	375		$	1,206		$	1,125
Interest cost	523			542			1,046			1,084			523			542			1,569			1,626
Expected return on plan assets	(19		)	(41		)	(38		)	(82		)	(19		)	(41		)	(57		)	(123		)
Prior service cost (benefit)	(125		)	(120		)	(250		)	(240		)	(125		)	(120		)	(375		)	(360		)
Net loss (gain)	222			169			444			338			222			169			666			507
Net periodic benefit cost	$	1,003		$	925		$	2,006		$	1,850		$	1,003		$	925		$	3,009		$	2,775

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives ~~(the "Supplemental Plans")~~(Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.

The components of net periodic benefit cost for the Supplemental Plans were as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011		2012		2011		2012		2011
Service cost	$	246	$	257	$	492	$	514	$	243	$	257	$	735	$	771
Interest cost	331		325		662		649		331		324		993		973
Prior service cost	1		1		2		2		1		1		3		3
Net loss (gain)	202		128		404		255		202		128		606		383
Net periodic benefit cost	$	780	$	711	$	1,560	$	1,420	$	777	$	710	$	2,337	$	2,130

Contributions

We anticipate that we will make contributions to the benefit plans during 2012 and 2013. Contributions to the Pension Plans will be made in cash, and contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):


	Contributions Made				Additional				Contributions Made				Additional
	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012		Contributions Anticipated for 2012		Contributions Anticipated for 2013		Three Months Ended Sept. 30, 2012		Nine Months Ended Sept. 30, 2012		Contributions Anticipated for 2012		Contributions Anticipated for 2013
Defined Benefit Pension Plans	$	—	$	25,000	$	—	$	4,500	$	—	$	25,000	$	—	$	4,500
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,063	$	2,126	$	2,125	$	4,380	$	1,063	$	3,189	$	1,063	$	4,380
Supplemental Non-qualified Defined Benefit Plans	$	278	$	556	$	555	$	1,090	$	278	$	834	$	278	$	1,090

(1210) BUSINESS ~~SEGMENTS~~SEGMENT 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 ~~February~~Feb. 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification 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 1817.

1716

We conduct our operations through the following five reportable segments:

Utilities Group —

Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, ~~Wyoming~~Wyo. and vicinity; and

Gas Utilities, which supplies natural gas utility service to areas in Colorado, Iowa, Kansas and Nebraska.

Non-regulated Energy Group —

Oil and Gas, which acquires, explores for, develops and produces crude oil and natural gas interests located in the Rocky Mountain region and other states;

Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming and Colorado; and

Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, ~~Wyoming.~~Wyo.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Segment information included in the accompanying Condensed Consolidated Statements of Income and ~~Comprehensive Income and~~ Condensed Consolidated Balance Sheets was as follows (in thousands):


Three Months Ended June 30, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Three Months Ended Sept. 30, 2012									External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	144,560	$	5,174		$	14,159		$	151,281	$	3,736		$	14,573
Gas	70,386		—			1,159			63,435		—			3
Non-regulated Energy:
Oil and Gas ^(a)	20,621					(19,621		)	24,728		—			17,389
Power Generation	759		17,975			3,926			1,256		19,695			5,128
Coal Mining	6,037		7,090			1,234			6,108		8,567			1,690
Corporate ^(b)	—		—			(13,180		)	—		—			(4,160		)
Intercompany eliminations	—		(30,239		)	—			—		(31,998		)	—
Total	$	242,363	$	—		$	(12,323	)	$	246,808	$	—		$	34,623


Three Months Ended June 30, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Three Months Ended Sept. 30, 2011									External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	136,131	$	3,410		$	8,614		$	151,063	$	2,653		$	15,790
Gas	99,922		—			4,440			72,651		—			572
Non-regulated Energy:
Oil and Gas	18,838		—			(79		)	19,163		—			241
Power Generation	891		6,889			548			1,011		7,089			337
Coal Mining	6,266		9,274			(381		)	9,184		8,651			555
Corporate ^(b)(c)	—		—			(9,443		)	—		—			(28,307		)
Intercompany eliminations	—		(20,972		)	7			—		(21,942		)	(351		)
Total	$	262,048	$	(1,399	)	$	3,706		$	253,072	$	(3,549	)	$	(11,163	)

1817


Six Months Ended June 30, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Nine Months Ended Sept. 30, 2012									External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	300,693	$	8,210		$	22,905		$	451,974	$	11,946		$	37,478
Gas	250,908		—			16,366			314,343		—			16,369
Non-regulated Energy:
Oil and Gas ^(a)(d)	42,266		—			(19,608		)	66,994		—			(2,219		)
Power Generation	1,937		36,424			10,840			3,193		56,119			15,968
Coal Mining	12,410		15,706			2,234			18,518		24,273			3,924
Corporate ^(c)(b)	—		—			(9,789		)	—		—			(13,949		)
Intercompany eliminations	—		(60,340		)	—			—		(92,338		)	—
Total	$	608,214	$	—		$	22,948		$	855,022	$	—		$	57,571


Six Months Ended June 30, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Nine Months Ended Sept. 30, 2011									External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	280,561	$	7,249		$	18,863		$	431,624	$	9,902		$	34,653
Gas	330,188		—			23,703			402,839		—			24,275
Non-regulated Energy:
Oil and Gas	36,744		—			(794		)	55,907		—			(553		)
Power Generation	1,578		13,822			1,734			2,589		20,911			2,071
Coal Mining	13,880		17,155			(1,679		)	23,064		25,806			(1,124		)
Corporate ^(b)(c)	—		—			(8,992		)	—		—			(37,299		)
Intercompany eliminations	—		(39,693		)	(61		)	—		(61,635		)	(412		)
Total	$	662,951	$	(1,467	)	$	32,774		$	916,023	$	(5,016	)	$	21,611

____________

Income Statement Notes:


(a)	Income (loss) from continuing operations includes a $17.7 million after-tax gain on the sale of the Williston Basin assets. See Note 15.

(b)

Income (loss) from continuing operations includes $0.4 million net after-tax non-cash mark-to-market gain and $1.9 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2012, respectively, and a $24.9 million and $26.4 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2011, respectively.


(c)	Certain indirect corporate costs and inter-segment interest expenses after-tax totaling $0.5 million for the three months ended Sept. 30, 2011 and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011 were included in the Corporate segment in continuing operations and were not reclassified as discontinued operations. See Note 17 for further information.


(d)	Income (loss) from continuing operations includes a $17.3 million non-cash after-tax ceiling test impairment ~~charge.~~expense. See Note 1716 for further information.

~~(b)~~

~~Income (loss) from continuing operations includes~~ ~~$10.1 million~~ ~~and~~ ~~$2.3 million~~ ~~net after-tax mark-to-market loss on interest rate swaps for the~~ ~~three~~ ~~and~~ ~~six~~ ~~months ended~~ ~~June 30, 2012, respectively, and a~~ ~~$5.1 million~~ ~~and~~ ~~$1.5 million~~ ~~net after-tax mark-to-market loss on interest rate swaps for the~~ ~~three~~ ~~and~~ ~~six~~ ~~months ended~~ ~~June 30, 2011, respectively.~~


~~(c)~~	Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not classified as discontinued operations but were included in the Corporate segment. See Note 18 ~~for further information.~~

1918


Total Assets (net of inter-company eliminations)	June 30, 2012		December 31, 2011			June 30, 2011
Total Assets (net of inter-company eliminations) as of:									Sept. 30, 2012		Dec. 31, 2011			Sept. 30, 2011
Utilities:
Electric^(a)	$	2,300,948	$	2,254,914		$	1,900,806		$	2,302,951	$	2,254,914		$	1,917,184
Gas	684,545		746,444			659,349			710,099		746,444			683,163
Non-regulated Energy:
Oil and Gas(b)	416,617		425,970			366,270			263,088		425,970			405,513
Power Generation^(a)	122,856		129,121			353,794			119,489		129,121			372,313
Coal Mining	90,021		88,704			89,627			90,444		88,704			94,908
Corporate	159,293		141,079		^(b)	88,645		^(b)	367,557		141,079		^(c)	139,985		^(c)
Discontinued operations	—		340,851		^(c)	358,669		^(c)	—		340,851		^(d)	332,503		^(d)
Total assets	$	3,774,280	$	4,127,083		$	3,817,160		$	3,853,628	$	4,127,083		$	3,945,569

____________

(a)

~~The PPA under which~~Upon commercial operation on Dec. 31, 2011 of the new generating facility ~~was~~ constructed by Colorado IPP at our Pueblo Airport Generation site, bythe PPA under which energy and capacity is sold to Colorado ~~IPP to support Colorado~~ Electric ~~customers~~ is accounted for as a capital lease. Therefore, commencing ~~December~~Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric as a capital lease.

~~(b) Assets of the Corporate segment were restated due to deferred taxes that were not classified as discontinued operations.~~

~~(c) See Note~~ 18


(b)	2012 includes a ceiling test impairment and the sale of the Williston Basin assets by our Oil and Gas segment. See Notes 15 and 16.


(c)	Assets of the Corporate segment were reclassified due to deferred taxes that were not classified as discontinued operations.


(d)	See Note 17 for further information relating to discontinued operations.

(1311) RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation 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 as discussed in our 2011 Annual Report on Form 10-K.

Market Risk

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

Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated ~~segment;~~and non-regulated segments; and

Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our derivative instruments.

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

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 investment grade rated companies, ~~and credit quality~~ ~~municipalities and electric cooperatives~~, 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.

2019

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 ~~June~~Sept. 30, 2012, our credit exposure (exclusive of retail customers of the regulated utilities) was concentrated primarily among investment grade rated companies, ~~municipal cooperatives~~cooperative utilities and federal agencies. ~~Credit exposure with non-investment grade or non-rated counterparties, was supported partially through letters of credit, prepayments or parental guarantees.~~

We actively manage our exposure to certain market and credit risks as described in Note 3 of the Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income ~~and Comprehensive Income~~ are detailed below and ~~within~~in Note 1412.

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.

We hold a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those OTC swaps and options. 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 are marked to fair value and are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed 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 Accumulated other comprehensive income (loss) and the ineffective portion, if any, is reported in Revenue.

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:


	June 30, 2012				December 31, 2011					June 30, 2011				Sept. 30, 2012					Dec. 31, 2011					Sept. 30, 2011
	Crude Oil Swaps/ Options		Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options		Natural Gas Swaps		Crude Oil Swaps/ Options		Natural Gas Swaps			Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options		Natural Gas Swaps
Notional ^(a)	672,000		9,020,500		528,000			5,406,250		463,500		5,969,250		537,000		7,455,250			528,000			5,406,250		414,000		4,957,250
Maximum terms in years ^(b)	1.50		1.25		1.25			1.75		1.00		0.25		1.00		1.00			1.25			1.75		1.00		0.25
Derivative assets, current	$	2,483	$	4,386	$	729		$	8,010	$	449	$	6,160	$	1,651	$	2,032		$	729		$	8,010	$	1,885	$	6,937
Derivative assets, non-current	$	1,316	$	255	$	771		$	1,148	$	214	$	456	$	494	$	39		$	771		$	1,148	$	2,529	$	717
Derivative liabilities, current	$	456	$	452	$	2,559		$	—	$	2,385	$	—	$	527	$	1,040		$	2,559		$	—	$	—	$	—
Derivative liabilities, non-current	$	981	$	331	$	811		$	7	$	1,201	$	117	$	414	$	141		$	811		$	7	$	—	$	7
Pre-tax accumulated other comprehensive income (loss)	$	1,727	$	3,305	$	(1,928	)	$	9,152	$	3,173	$	6,499	$	428	$	(344	)	$	(1,928	)	$	9,152	$	4,257	$	7,647
Cash collateral included in Derivative liabilities	$	613	$	553	$	—		$	—	$	—	$	—	$	—	$	—		$	—		$	—	$	—	$	—
Cash collateral included in Other current assets	$	267	$	51	$	—		$	—	$	—	$	—	$	1,126	$	1,288		$	—		$	—	$	—	$	—
Expense included in Revenue ^(c)	$	245	$	51	$	58		$	—	$	250	$	—	$	350	$	54		$	58		$	—	$	157	$	—

____________


(a)	Crude oil in Bbls, gas in ~~MMBtus~~MMBtus.


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


(c)	Represents the amortization of put premiums.

Based on ~~June~~Sept. 30, 2012 market prices, a $~~4.5~~1.2 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

2120

Utilities

Our utility customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into certain 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 Condensed Consolidated Balance Sheets. Gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated utility operations. Accordingly, the hedging activity is recognized in the Condensed Consolidated Statements of Income ~~and Comprehensive Income~~ when the related costs are recovered through our ~~rates.~~rates or adjustment mechanisms.

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


	June 30, 2012		December 31, 2011		June 30, 2011		Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	12,440,000	78	14,310,000	84	7,820,000	21	14,690,000	75	14,310,000	84	9,890,000	18
Natural gas options purchased	2,840,000	9	1,720,000	3	1,560,000	9	5,560,000	6	1,720,000	3	3,880,000	6
Natural gas basis swaps purchased	7,270,000	78	7,160,000	60	—	—	8,800,000	75	7,160,000	60	—	—

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


	June 30, 2012		December 31, 2011		June 30, 2011		Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
Derivative assets, current	$	9,726	$	9,844	$	2,935	$	12,380	$	9,844	$	3,355
Derivative assets, non-current	$	199	$	52	$	53	$	634	$	52	$	—
Derivative liabilities, non-current	$	6,453	$	7,156	$	175	$	4,527	$	7,156	$	1,360
Net unrealized (gain) loss included in Regulatory assets or liabilities	$	13,691	$	17,556	$	4,229
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities							$	9,318	$	17,556	$	11,813
Included in Derivatives:
Cash collateral receivable (payable)	$	15,925	$	19,416	$	6,254	$	15,740	$	19,416	$	12,058
Option premiums and commissions	$	1,238	$	880	$	760	$	2,065	$	880	$	1,750

2221

Financing Activities

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. Our interest rate swaps and related balances were as follows (dollars in thousands) as of:


	June 30, 2012						December 31, 2011						June 30, 2011						Sept. 30, 2012						Dec. 31, 2011						Sept. 30, 2011
	Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.50			1.50			5.00			2.00			5.50			0.50			4.25			1.25			5.00			2.00			5.25			0.25
Derivative liabilities, current	$	6,766		$	78,001		$	6,513		$	75,295		$	6,900		$	56,342		$	7,028		$	77,914		$	6,513		$	75,295		$	6,724		$	94,588
Derivative liabilities, non-current	$	18,976		$	15,336		$	20,363		$	20,696		$	15,788		$	—		$	18,660		$	17,668		$	20,363		$	20,696		$	21,108		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(25,742	)	$	—		$	(26,876	)	$	—		$	(22,688	)	$	—		$	(25,688	)	$	—		$	(26,876	)	$	—		$	(27,832	)	$	—
Pre-tax gain (loss)	$	—		$	(3,507	)	$	—		$	(42,010	)	$	—		$	(2,362	)
Year-to Date pre-tax gain (loss)																			$	—		$	(2,902	)	$	—		$	(42,010	)	$	—		$	(40,608	)
Cash collateral receivable (payable) included in derivative	$	—		$	6,160		$	—		$	—		$	—		$	—		$	—		$	3,310		$	—		$	—		$	—		$	—

_____________


*	Maximum terms in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. If extended, de-designated swaps totaling $100 million notional terminate in ~~6.5~~6.25 years and de-designated swaps totaling $150 million notional terminate in ~~16.5~~16.25 years.

Collateral requirements based on our corporate credit rating apply to $50 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swaps' negative mark-to-market fair value exceeds $20 million. If our senior unsecured credit rating drops to BB+ or below by S&P, or to Ba1 or below by Moody's, we would be required to post collateral for the entire amount of the swaps' negative mark-to-market fair value.

Based on ~~June~~Sept. 30, 2012 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $~~6.8~~7.0 million would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market interest rates change.

(1412) FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

~~Assets and liabilities carried at fair~~Fair value ~~are classified and disclosed~~is defined as the price that would be received to sell an asset or paid to transfer a liability in ~~one of the following categories:~~

~~Level 1~~ ~~— Unadjusted quoted prices available in active markets that are accessible~~an orderly transaction between market participants at the measurement ~~date~~date. The ASC on Fair Value Measurements and Disclosure Requirements establishes a hierarchy 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~~grouping assets and liabilities, based on significance of inputs. For additional information see Notes 3 and 4 included 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.our

~~Level 3~~2011 ~~— 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~~Annual Report on Form 10-K filed with the ~~assumptions a market participant would use in pricing the asset or liability.~~

SEC. 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

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 multiple 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.

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.

2423

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):


	As of June 30, 2012															As of Sept. 30, 2012
	Level 1		Level 2			Level 3			Counterparty Netting		Cash Collateral			Total		Level 1		Level 2			Level 3			Counterparty Netting		Cash Collateral			Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	1,014		$	—		$	—	$	—		$	1,014	$	—	$	619		$	—		$	—	$	—		$	619
Basis Swaps -- Oil	—		2,785			—			—		—			2,785		—		1,526			—			—		—			1,526
Options -- Gas	—		—			—			—		—			—		—		—			—			—		—			—
Basis Swaps -- Gas	—		4,641			—			—		—			4,641		—		2,071			—			—		—			2,071
Commodity derivatives — Utilities	—		(6,024		)	24		^(b)	—		15,925			9,925		—		(2,760		)	34		^(b)	—		15,740			13,014
Cash and cash equivalents ^(a)	44,882		—			—			—		—			44,882		247,192		—			—			—		—			247,192
Total	$	44,882	$	2,416		$	24		$	—	$	15,925		$	63,247	$	247,192	$	1,456		$	34		$	—	$	15,740		$	264,422

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	901		$	—		$	—	$	457		$	1,358	$	—	$	885		$	—		$	—	$	—		$	885
Basis Swaps -- Oil	—		(76		)	—			—		156			80		—		56			—			—		—			56
Options -- Gas	—		—			—			—		—			—		—		—			—			—		—			—
Basis Swaps -- Gas	—		230			—			—		553			783		—		1,181			—			—		—			1,181
Commodity derivatives — Utilities	—		6,453			—			—		—			6,453		—		4,527			—			—		—			4,527
Interest rate swaps	—		125,239			—			—		(6,160		)	119,079		—		124,580			—			—		(3,310		)	121,270
Total	$	—	$	132,747		$	—		$	—	$	(4,994	)	$	127,753	$	—	$	131,229		$	—		$	—	$	(3,310	)	$	127,919

______________

~~(a) Level 1 assets and liabilities are described in Note~~ 15


(a)	Level 1 assets and liabilities are described in Note 13.

(b)

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.

(b) 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.



	As of Dec. 31, 2011
	Level 1		Level 2			Level 3			Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—		$	768	^(a)	$	5	$	—	$	773
Basis Swaps -- Oil	—		727			—			—		—		727
Options -- Gas	—		—			—			—		—		—
Basis Swaps -- Gas	—		9,158			—			—		—		9,158
Commodity derivatives —Utilities	—		(9,520		)	—			—		19,416		9,896
Money market funds	6,005		—			—			—		—		6,005
Total	$	6,005	$	365		$	768	^(a)	$	5	$	19,416	$	26,559

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—		$	1,165	^(a)	$	5	$	—	$	1,170
Basis Swaps -- Oil	—		2,200			—			—		—		2,200
Options -- Gas	—		—			—			—		—		—
Basis Swaps -- Gas	—		7			—			—		—		7
Commodity derivatives — Utilities	—		7,156			—			—		—		7,156
Interest rate swaps	—		122,867			—			—		—		122,867
Total	$	—	$	132,230		$	1,165	^(a)	$	5	$	—	$	133,400

_________


(a)	Of the net balance included as Level 3, transfers out of Level 3 included settlement of losses of approximately $0.5 million within AOCI and approximately $0.9 million transferred to level 2 as inputs becoming more observable.

As of December 31, 2011
Level 1 Level 2 Level 3
Counterparty
Netting
Cash Collateral Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil $ —
$ —
$ 768
^(a)
$ 5
$ —
$ 773
Basis Swaps -- Oil —
727
—
—
—
727
Options -- Gas —
—
—
—
—
—
Basis Swaps -- Gas —
9,158
—
—
—
9,158
Commodity derivatives —Utilities —
(9,520 ) —
—
19,416
9,896
Money market funds 6,005
—
—
—
—
6,005
Total $ 6,005
$ 365
$ 768
^(a)
$ 5
$ 19,416
$ 26,559

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil $ —
$ —
$ 1,165
^(a)
$ 5
$ —
$ 1,170
Basis Swaps -- Oil —
2,200
—
—
—
2,200
Options -- Gas —
—
—
—
—
—
Basis Swaps -- Gas —
7
—
—
—
7
Commodity derivatives — Utilities —
7,156
—
—
—
7,156
Interest rate swaps —
122,867
—
—
—
122,867
Total $ —
$ 132,230
$ 1,165
^(a)
$ 5
$ —
$ 133,400

~~_________~~

~~(a) Of the net beginning balance included as Level 3 for Options - Oil, transfers out of Level 3 included approximately~~ ~~$(0.5) million~~ ~~due to gain (loss) within AOCI and approximately~~ ~~$0.9 million~~ transferred due to the related inputs becoming more observable. Previously, we utilized pricing methodologies developed by our Energy Marketing segment to value our Oil and Gas derivatives. Oil and Gas now obtains available observable inputs including quoted prices traded on active exchanges from multiple sources to value our options. Therefore, options in the Oil and Gas segment have been reclassified from Level 3 to Level 2.


	As of June 30, 2011													As of Sept. 30, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total		Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—		$	111	$	—	$	—	$	111	$	—	$	—		$	328	$	—	$	—	$	328
Basis Swaps -- Oil	—		552			—		—		—		552		—		4,086			—		—		—		4,086
Options -- Gas	—		—			—		—		—		—		—		—			—		—		—		—
Basis Swaps -- Gas	—		6,616			—		—		—		6,616		—		7,654			—		—		—		7,654
Commodity derivatives — Utilities	—		(3,266		)	—		—		6,254		2,988		—		(8,703		)	—		—		12,058		3,355
Money market funds	6,006		—			—		—		—		6,006		9,006		—			—		—		—		9,006
Total	$	6,006	$	3,902		$	111	$	—	$	6,254	$	16,273	$	9,006	$	3,037		$	328	$	—	$	12,058	$	24,429

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—		$	—	$	—	$	—	$	—	$	—	$	—		$	—	$	—	$	—	$	—
Basis Swaps -- Oil	—		3,586			—		—		—		3,586		—		—			—		—		—		—
Options -- Gas	—		—			—		—		—		—		—		—			—		—		—		—
Basis Swaps -- Gas	—		117			—		—		—		117		—		7			—		—		—		7
Commodity derivatives — Utilities	—		175			—		—		—		175		—		1,360			—		—		—		1,360
Interest rate swaps	—		79,030			—		—		—		79,030		—		122,420			—		—		—		122,420
Total	$	—	$	82,908		$	—	$	—	$	—	$	82,908	$	—	$	123,787		$	—	$	—	$	—	$	123,787

Fair Value Measures

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis and do not reflect the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements. Further, the amounts do not include net cash collateral on deposit in margin accounts at ~~June~~Sept. 30, 2012, ~~December~~Dec. 31, 2011, and ~~June~~Sept. 30, 2011, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross 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 Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 1311.

2726

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


As of June 30, 2012
As of Sept. 30, 2012							As of Sept. 30, 2012
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives			Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	6,869	$	—		Derivative assets — current	$	3,263	$	—
Commodity derivatives	Derivative assets — non-current	1,571		—			Derivative assets — non-current	533		—
Commodity derivatives	Derivative liabilities — current	—		1,304			Derivative liabilities — current	—		1,534
Commodity derivatives	Derivative liabilities — non-current	—		2,082			Derivative liabilities — non-current	—		555
Interest rate swaps	Derivative liabilities — current	—		6,766			Derivative liabilities — current	—		7,029
Interest rate swaps	Derivative liabilities — non-current	—		18,976			Derivative liabilities — non-current	—		18,661
Total derivatives designated as hedges		$	8,440	$	29,128			$	3,796	$	27,779

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	6,199		Derivative assets — current	$	421	$	3,361
Commodity derivatives	Derivative assets — non-current	—		(199		)	Derivative assets — non-current	—		(634		)
Commodity derivatives	Derivative liabilities — current	—		—			Derivative liabilities — current	—		33
Commodity derivatives	Derivative liabilities — non-current	—		6,453			Derivative liabilities — non-current	—		4,527
Interest rate swaps	Derivative liabilities — current	—		78,001			Derivative liabilities — current	—		77,913
Interest rate swaps	Derivative liabilities — non-current	—		21,496			Derivative liabilities — non-current	—		20,977
Total derivatives not designated as hedges		$	—	$	111,950			$	421	$	106,177


As of December 31, 2011
As of Dec. 31, 2011							As of Dec. 31, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives			Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,739	$	—		Derivative assets — current	$	8,739	$	—
Commodity derivatives	Derivative assets — non-current	1,919		—			Derivative assets — non-current	1,919		—
Commodity derivatives	Derivative liabilities — current	—		2,559			Derivative liabilities — current	—		2,559
Commodity derivatives	Derivative liabilities — non-current	—		818			Derivative liabilities — non-current	—		818
Interest rate swaps	Derivative liabilities — current	—		6,513			Derivative liabilities — current	—		6,513
Interest rate swaps	Derivative liabilities — non-current	—		20,363			Derivative liabilities — non-current	—		20,363
Total derivatives designated as hedges		$	10,658	$	30,253			$	10,658	$	30,253

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	9,572		Derivative assets — current	$	—	$	9,572
Commodity derivatives	Derivative assets — non-current	—		(52		)	Derivative assets — non-current	—		(52		)
Commodity derivatives	Derivative liabilities — current	—		—			Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		7,156			Derivative liabilities — non-current	—		7,156
Interest rate swaps	Derivative liabilities — current	—		75,295			Derivative liabilities — current	—		75,295
Interest rate swaps	Derivative liabilities — non-current	—		20,696			Derivative liabilities — non-current	—		20,696
Total derivatives not designated as hedges		$	—	$	112,667			$	—	$	112,667

2827


As of June 30, 2011
As of Sept. 30, 2011							As of Sept. 30, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives			Balance Sheet Location	Fair Value of Asset Derivatives			Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	6,609	$	—		Derivative assets — current	$	8,822		$	—
Commodity derivatives	Derivative assets — non-current	670		—			Derivative assets — non-current	3,246			—
Commodity derivatives	Derivative liabilities — current	—		2,385			Derivative liabilities — current	—			—
Commodity derivatives	Derivative liabilities — non-current	—		1,318			Derivative liabilities — non-current	—			7
Interest rate swaps	Derivative liabilities — current	—		6,900			Derivative liabilities — current	—			6,724
Interest rate swaps	Derivative liabilities — non-current	—		15,788			Derivative liabilities — non-current	—			21,108
Total derivatives designated as hedges		$	7,279	$	26,391			$	12,068		$	27,839

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	3,319		Derivative assets — current	$	—		$	8,703
Commodity derivatives	Derivative assets — non-current	—		(53		)	Derivative assets — non-current	—			—
Commodity derivatives	Derivative liabilities — current	—		175			Derivative liabilities — current	(2		)	(1,360		)
Commodity derivatives	Derivative liabilities — non-current	—		—			Derivative liabilities — non-current	—			—
Interest rate swaps	Derivative liabilities — current	—		56,342			Derivative liabilities — current	—			94,588
Interest rate swaps	Derivative liabilities — non-current	—		—			Derivative liabilities — non-current	—			—
Total derivatives not designated as hedges		$	—	$	59,783			$	(2	)	$	101,931

A description of our derivative activities is included in Note 1311. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of ~~Income and Comprehensive~~ Income.

Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statements of Income ~~and Comprehensive Income~~ was as follows (in thousands):


Three Months Ended June 30, 2012
Three Months Ended Sept. 30, 2012											Three Months Ended Sept. 30, 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 Reclassified Gain/(Loss) 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)			Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) 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	$	(2,251	)	Interest expense	$	(1,843	)		$	—		$	(1,684	)	Interest expense	$	(1,853	)		$	—
Commodity derivatives	2,429			Revenue	2,894				—			(3,111		)	Revenue	1,838				—
Total	$	178			$	1,051			$	—		$	(4,795	)		$	(15	)		$	—


Three Months Ended June 30, 2011
Three Months Ended Sept. 30, 2011											Three Months Ended Sept. 30, 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 Reclassified Gain/(Loss) 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)			Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) 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	$	(4,768	)	Interest expense	$	(1,919	)		$	—		$	(6,958	)	Interest expense	$	(1,930	)		$	—
Commodity derivatives	3,772			Revenue	302				—			10,095			Revenue	1,516				—
Total	$	(996	)		$	(1,617	)		$	—		$	3,137			$	(414	)		$	—

2928


Six Months Ended June 30, 2012
Nine Months Ended Sept. 30, 2012											Nine Months Ended Sept. 30, 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 Reclassified Gain/(Loss) 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)			Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) 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	$	(3,013	)	Interest expense	$	(3,665	)		$	—		$	(4,697	)	Interest expense	$	(5,518	)		$	—
Commodity derivatives	3,712			Revenue	5,903				—			601			Revenue	7,741				—
Total	$	699			$	2,238			$	—		$	(4,096	)		$	2,223			$	—


Six Months Ended June 30, 2011
Nine Months Ended Sept. 30, 2011											Nine Months Ended Sept. 30, 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 Reclassified Gain/(Loss) 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)			Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) 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	$	(4,470	)	Interest expense	$	(3,811	)		$	—		$	(11,428	)	Interest expense	$	(5,741	)		$	—
Commodity derivatives	(311		)	Revenue	1,333				—			9,784			Revenue	2,849				—
Total	$	(4,781	)		$	(2,478	)		$	—		$	(1,644	)		$	(2,892	)		$	—

Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedging instruments on our Condensed Consolidated Statements of Income ~~and Comprehensive Income~~ was as follows (in thousands):


		Three Months Ended			Six Months Ended				Three Months Ended			Nine Months Ended
		June 30, 2012			June 30, 2012				Sept. 30, 2012			Sept. 30, 2012
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			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
Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swaps, net	$	(15,552	)	$	(3,507	)	Unrealized gain (loss) on interest rate swaps, net	$	605		$	(2,902	)
Interest rate swaps - realized	Interest expense	(3,242		)	(6,447		)	Interest expense	(3,250		)	(9,697		)
Commodity derivatives								Revenue	(14		)	(14		)
		$	(18,794	)	$	(9,954	)		$	(2,659	)	$	(12,613	)


		Three Months Ended			Six Months Ended				Three Months Ended			Nine Months Ended
		June 30, 2011			June 30, 2011				Sept. 30, 2011			Sept. 30, 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			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
Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swaps, net	$	(7,827	)	$	(2,362	)	Unrealized gain (loss) on interest rate swaps, net	$	(38,246	)	$	(40,608	)
Interest rate swaps - realized	Interest expense	(3,352		)	(6,704		)	Interest expense	(3,373		)	(10,077		)
		$	(11,179	)	$	(9,066	)		$	(41,619	)	$	(50,685	)

3029

(1513) FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments are as follows (in thousands) as of:


	June 30, 2012				December 31, 2011				June 30, 2011				Sept. 30, 2012				Dec. 31, 2011				Sept. 30, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	40,110	$	40,110	$	21,628	$	21,628	$	21,971	$	21,971	$	247,192	$	247,192	$	21,628	$	21,628	$	30,198	$	30,198
Restricted cash and equivalents ^(a)	$	4,772	$	4,772	$	9,254	$	9,254	$	3,710	$	3,710	$	7,302	$	7,302	$	9,254	$	9,254	$	4,080	$	4,080
Notes payable ^(a)	$	225,000	$	225,000	$	345,000	$	345,000	$	380,000	$	380,000
Long-term debt, including current maturities ^(b)	$	1,272,481	$	1,460,723	$	1,282,882	$	1,464,289	$	1,187,196	$	1,313,052
Notes receivable ^(a)													$	21,832	$	21,832	$	—	$	—	$	—	$	—
Notes payable ^(b)													$	225,000	$	225,000	$	345,000	$	345,000	$	359,000	$	359,000
Long-term debt, including current maturities ^(c)													$	1,271,260	$	1,471,932	$	1,282,882	$	1,464,289	$	1,285,087	$	1,430,271

____________


(a)	Fair value approximates carrying value due to either the short-term ~~maturities~~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)	The carrying amounts of our notes payable approximate fair value due to their variable interest rates with short reset periods.


(c)	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.

The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

Cash and Cash Equivalents

Included in cash and cash equivalents are 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. ~~The carrying amount for cash and cash equivalents approximates fair value due to the short-term maturity of these instruments.~~

Restricted Cash and Equivalents

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

Notes Receivable

Notes receivable, included in Other current assets on the accompanying Condensed Consolidated Balance Sheet, represents cash held by a third party related to tax planning strategies for effecting like-kind exchange structuring for the purchase of additional oil and gas leases.

Notes Payable

~~The carrying amounts of~~Notes Payable represent our ~~notes payable approximate fair value due to their variable interest rates with short reset periods.~~short-term corporate term loan and borrowings under our Revolving Credit Facility.

Long-term Debt

Our debt instruments are marked to fair value using the market valuation approach. The fair value for our fixed rate debt instruments is estimated based on quoted market prices and yields for debt instruments having similar maturities and debt ratings. The carrying amounts of our variable rate debt approximate fair value due to the variable interest rates with short reset periods.

(1614) COMMITMENTS AND CONTINGENCIES

Commitments and Contingencies

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of Sept. 30, 2012, we were in compliance with these covenants.

Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of Sept. 30, 2012, the restricted net assets at our Utilities Group were approximately $227.2 million.

As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted equity of at least $100.0 million.

(15) SALE OF ASSETS

Oil and Gas

On Sept. 27, 2012, our Oil and Gas segment sold a majority of its Bakken and Three Forks shale assets in the Williston Basin of North Dakota. The sale included approximately 73 gross wells, 28,000 net lease acres and had an effective date of July 1, 2012.

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 Sept. 27, 2012 sale significantly alters the relationship and accordingly we have recorded a gain of $27.3 million with the remainder of the proceeds recorded as a reduction in the full cost pool. This reduction in the full cost pool will decrease in the depreciation, depletion and amortization rate.

Net cash proceeds were as follows (in thousands):



Cash proceeds received on date of sale	$	243,314

Adjustments to proceeds:
Post close adjustments	1,490
Transaction adviser fees	(1,400		)
Estimated payment for contractual obligation related to "back-in" fee *	(16,847		)

Net cash proceeds	$	226,557

_____________

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

Electric Utilities

On Sept. 18, 2012, Colorado Electric completed the sale of an undivided 50 percent ownership interest in the 29 megawatt Busch Ranch Wind project to AltaGas for $25.0 million. Colorado Electric retains the remaining undivided interest and will be the operator of this jointly owned facility. Commercial operation of the newly constructed wind farm was achieved on Oct. 16, 2012. Colorado Electric will purchase AltaGas's interest in the energy produced by the wind farm through a REPA expiring on Oct. 16, 2037.

(1716) 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, ~~during the second quarter of 2012,~~ we recorded a $26.9 million non-cash impairment of oil and gas assets included in our Oil and Gas ~~segment.~~segment in the second quarter of 2012. 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.

(1817) DISCONTINUED OPERATIONS

On ~~February~~Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing ~~segment, Enserco.~~segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds on the date of the sale were approximately $166.3 million, subject to final post-closing adjustments. The proceeds represent $108.8 million received from the buyer and $57.5 million cash retained from Enserco prior to closing.

Pursuant to the provisions of the ~~Stock Purchase Agreement,~~stock purchase agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $~~1.3~~1.4 million, which is accrued for in the accompanying financial ~~statements.~~statements as of Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution ~~would~~will occur through the dispute resolution provision of the ~~Stock Purchase Agreement.~~stock purchase agreement.

The accompanying Condensed Consolidated Financial Statements have been classified to reflect Enserco as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification.

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


	For the Three Months Ended						For the Six Months Ended						For the Three Months Ended						For the Nine Months Ended
	June 30, 2012			June 30, 2011			June 30, 2012			June 30, 2011			Sept. 30, 2012			Sept. 30, 2011			Sept. 30, 2012			Sept. 30, 2011

Revenue	$	—		$	12,476		$	(604	)	$	14,941		$	—		$	6,937		$	(604	)	$	21,878

Pre-tax income (loss) from discontinued operations	$	(475	)	$	6,083		$	(6,311	)	$	2,909		$	(311	)	$	1,495		$	(6,622	)	$	4,404
Pre-tax gain (loss) on sale	(1,334		)	—			(3,787		)	—			—			—			(3,787		)	—
Income tax (expense) benefit	649			(2,037		)	3,454			(1,021		)	145			(857		)	3,599			(1,878		)

Income (loss) from discontinued operations, net of tax ^(a)	$	(1,160	)	$	4,046		$	(6,644	)	$	1,888		$	(166	)	$	638		$	(6,810	)	$	2,526

_____________

~~(a) Includes transaction related costs, net of tax, of~~ ~~$0.3 million~~ ~~and~~ ~~$2.5 million~~ ~~for~~ ~~three~~ ~~and~~ ~~six~~ ~~months ended~~ ~~June~~


(a)	Includes transaction related costs, net of tax, of $0.2 million and $2.5 million for three and nine months ended Sept. 30, 2012, respectively.

Indirect corporate costs and inter-segment interest ~~expenses~~expense after-tax totaling$0 ~~and~~ $0.5 million for the three months ended ~~June~~Sept. 30, 2011, and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011, respectively, ~~and~~ ~~$1.6 million~~ ~~and~~ ~~$1.0 million~~ ~~for the six months ended~~ ~~June 30, 2012~~ ~~and~~ ~~2011, respectively, are~~were reclassified from the Energy Marketing segment to the Corporate segment in continuing operations on the accompanying Condensed Consolidated Statements of ~~Income and Comprehensive~~ Income.

Net assets of the Energy Marketing segment included in Assets/Liabilities of discontinued operations in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands) as of:


							Dec. 31, 2011			Sept. 30, 2011
	December 31, 2011			June 30, 2011
Other current assets	$	280,221		$	290,990		$	280,221		$	282,361
Derivative assets, current and non-current	52,859			57,563			52,859			50,519
Property, plant and equipment, net	5,828			6,126			5,828			5,391
Goodwill	1,435			1,435			1,435			1,435
Other non-current assets	508			2,555			508			(7,204		)
Other current liabilities	(132,951		)	(148,759		)	(132,951		)	(134,747		)
Derivative liabilities, current and non-current	(26,084		)	(28,898		)	(26,084		)	(31,978		)
Other non-current liabilities	(14,894		)	(5,066		)	(14,894		)	(4,959		)
Net assets	$	166,922		$	175,946		$	166,922		$	160,818

(18) SUBSEQUENT EVENTS

Long-term Debt

On Oct. 31, 2012, we redeemed our $225.0 million of senior unsecured 6.5 percent notes, which were originally scheduled to mature on May 15, 2013. The total payment was $238.8 million, including accrued interest expense and a make-whole provision payment of $7.1 million.


ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

We are an integrated energy company operating principally in the United States with two major business groups — Utilities and Non-regulated Energy. We report our business groups in the following financial segments:



Business Group	Financial Segment

Utilities	Electric Utilities
	Gas Utilities

Non-regulated Energy*	~~Oil and Gas~~
	Power Generation
	Coal Mining
	Oil and Gas

_______________


*	~~In February~~ On Feb. 29, 2012, we sold the stock of Enserco, our Energy Marketing segment, ~~through a stock purchase agreement~~ to a third party buyer and therefore we now classify the segment as discontinued operations.

Our Utilities Group consists of our Electric and Gas Utilities segments. Our Electric Utilities segment generates, transmits and distributes electricity to approximately 201,500 customers in South Dakota, Wyoming, Colorado and ~~Montana~~Montana; and ~~includes the operations of Cheyenne Light and its~~also distributes natural gas to approximately 34,800 ~~natural gas~~Cheyenne Light customers in Wyoming. Our Gas Utilities serve approximately 528,800 natural gas customers in Colorado, Iowa, Kansas and Nebraska. Our Non-regulated Energy Group consists of our Power Generation, Coal Mining and Oil and Gas ~~Power Generation and Coal Mining~~ segments. Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy principally to ~~other~~our utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, ~~Wyoming~~Wyo. and sells the coal primarily to on-site, mine-mouth power generation facilities. Our Oil and Gas segment principally engages in exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region.

Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August with sensitivity from the degree of humidity while the normal peak usage season for gas utilities is November through March, and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and ~~six~~nine months ended ~~June~~Sept. 30, 2012 and 2011, and our financial condition as of ~~June~~Sept. 30, 2012, ~~December~~Dec. 31, 2011, and ~~June~~Sept. 30, 2011 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other ~~period.~~period or for the entire year.

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 6264.

The following business group and segment information does not include intercompany eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated. Information has been revised to remove information related to the operations of our Energy Marketing segment, now classified as discontinued operations, as a result of the sale of Enserco on ~~February~~Feb. 29, 2012.

Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended ~~June~~Sept. 30, 2012 Compared to Three Months Ended ~~June 30, 2011~~. ~~Loss from continuing operations for the three months ended~~ ~~June 30, 2012~~ ~~was~~ ~~$12.3 million, or~~ ~~$0.28~~ ~~per share, compared to Income from continuing operations of~~ ~~$3.7 million, or~~ ~~$0.09~~ ~~per share, reported for the same period in~~ ~~2011. The~~ ~~2012~~ ~~Loss from continuing operations included a~~ ~~$10.1 million~~ ~~non-cash after-tax unrealized mark-to-market loss on certain interest rate swaps and a non-cash after-tax ceiling test impairment of~~ ~~$17.3 million~~ ~~relating to our Oil and Gas segment. The~~ ~~2011~~ ~~Income from continuing operations included a~~ ~~$5.1 million~~ ~~after-tax unrealized mark-to-market gain on the same interest rate swaps.~~

~~Net loss for the~~ ~~three months ended June 30, 2012~~ ~~was~~ ~~$13.5 million, or~~ ~~$0.31~~ ~~per share, compared to Net income of~~ ~~$7.8 million, or~~ ~~$0.19~~ ~~per share, for the same period in~~ ~~2011~~.

~~Six~~ ~~Months Ended~~ ~~June 30, 2012~~ ~~Compared to~~ ~~Six~~ ~~Months Ended~~ ~~June~~Sept. 30, 2011. Income from continuing operations for the ~~six~~three months ended ~~June~~Sept. 30, 2012 was $~~22.9~~34.6 million, or $~~0.52~~0.78 per share, compared to ~~Income~~Loss from continuing operations of $~~32.8~~11.2 million, or $~~0.82~~0.29 per share, reported for the same period in 2011. The 2012 Income from continuing operations included an after-tax gain on sale of $17.7 million relating to the sale of the Williston Basin assets of our Oil and Gas segment, an incentive accrual of $2.2 million after-tax relating to the Williston Basin asset sale and a $~~2.3~~0.4 million non-cash after-tax unrealized mark-to-market ~~loss~~gain on certain interest rate ~~swaps, a non-cash after-tax ceiling test impairment of~~ ~~$17.3 million, and an after-tax write-off of~~ ~~$1.0 million~~ ~~of deferred financing costs related to the previous Revolving Credit Facility.~~swaps. The 2011 ~~Income~~Loss from continuing operations included a $~~1.5~~24.9 million after-tax non-cash unrealized mark-to-market loss on the same interest rate swaps.

Net income for the ~~six~~three months ended ~~June~~Sept. 30, 2012 was $~~16.3~~34.5 million, or $~~0.37~~0.78 per share, compared to Net loss of $~~34.7~~10.5 million, or $~~0.87~~0.27 per share, for the same period in 2011. Net income for the three months ended Sept. 30, 2012 and 2011 include the same significant items discussed above.

Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011. Income from continuing operations for the nine months ended Sept. 30, 2012 was $57.6 million, or $1.31 per share, compared to Income from continuing operations of $21.6 million, or $0.54 per share, reported for the same period in 2011. The 2012 Income from continuing operations included an after-tax gain of $17.7 million relating to the sale of the Williston Basin assets of our Oil and Gas segment, an incentive accrual of $2.2 million after-tax relating to the Williston Basin asset sale, a non-cash after-tax ceiling test impairment of $17.3 million, a $1.9 million non-cash after-tax unrealized mark-to-market loss on certain interest rate swaps, and an after-tax write-off of $1.0 million of deferred financing costs related to our previous revolving credit facility. The 2011 Income from continuing operations included a $26.4 million after-tax unrealized non-cash mark-to-market loss on the same interest rate swaps.

Net income for the nine months ended Sept. 30, 2012 was $50.8 million, or $1.15 per share, compared to $24.1 million, or $0.61 per share, for the same period in 2011. Net income for the nine months ended Sept. 30, 2012 and 2011 include the same significant items discussed above.


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance			2012			2011			Variance			2012			2011			Variance
	(in thousands)																		(in thousands)
Revenue
Utilities	$	220,120		$	239,463		$	(19,343	)	$	559,811		$	617,998		$	(58,187	)	$	218,452		$	226,367		$	(7,915	)	$	778,263		$	844,365		$	(66,102	)
Non-regulated Energy	52,482			42,158			10,324			108,743			83,179			25,564			60,354			45,098			15,256			169,097			128,277			40,820
Intercompany eliminations	(30,239		)	(20,972		)	(9,267		)	(60,340		)	(39,693		)	(20,647		)	(31,998		)	(21,942		)	(10,056		)	(92,338		)	(61,635		)	(30,703		)
	$	242,363		$	260,649		$	(18,286	)	$	608,214		$	661,484		$	(53,270	)	$	246,808		$	249,523		$	(2,715	)	$	855,022		$	911,007		$	(55,985	)

Net income (loss)
Electric Utilities	$	14,159		$	8,614		$	5,545		$	22,905		$	18,863		$	4,042		$	14,573		$	15,790		$	(1,217	)	$	37,478		$	34,653		$	2,825
Gas Utilities	1,159			4,440			(3,281		)	16,366			23,703			(7,337		)	3			572			(569		)	16,369			24,275			(7,906		)
Utilities	15,318			13,054			2,264			39,271			42,566			(3,295		)	14,576			16,362			(1,786		)	53,847			58,928			(5,081		)

Oil and Gas ^(a)	(19,621		)	(79		)	(19,542		)	(19,608		)	(794		)	(18,814		)
Power Generation	3,926			548			3,378			10,840			1,734			9,106			5,128			337			4,791			15,968			2,071			13,897
Coal Mining	1,234			(381		)	1,615			2,234			(1,679		)	3,913			1,690			555			1,135			3,924			(1,124		)	5,048
Oil and Gas ^(a)																			17,389			241			17,148			(2,219		)	(553		)	(1,666		)
Non-regulated Energy	(14,461		)	88			(14,549		)	(6,534		)	(739		)	(5,795		)	24,207			1,133			23,074			17,673			394			17,279

Corporate and eliminations ^(b)(c)	(13,180		)	(9,436		)	(3,744		)	(9,789		)	(9,053		)	(736		)	(4,160		)	(28,658		)	24,498			(13,949		)	(37,711		)	23,762

Income from continuing operations	(12,323		)	3,706			(16,029		)	22,948			32,774			(9,826		)
Income (loss) from continuing operations																			34,623			(11,163		)	45,786			57,571			21,611			35,960

Income (loss) from discontinued operations, net of tax	(1,160		)	4,046			(5,206		)	(6,644		)	1,888			(8,532		)	(166		)	638			(804		)	(6,810		)	2,526			(9,336		)
Net income (loss)	$	(13,483	)	$	7,752		$	(21,235	)	$	16,304		$	34,662		$	(18,358	)	$	34,457		$	(10,525	)	$	44,982		$	50,761		$	24,137		$	26,624

______________

(a)

Net income (loss) for three and nine months ended Sept. 30, 2012 includes a $17.7 million after-tax gain on the sale of the Williston Basin assets and Net income (loss) for the nine months ended Sept. 30, 2012 also includes a $17.3 million non-cash after-tax ceiling test impairment. See ~~Note~~Notes 1715 and 16 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

(b)

Financial results of our Energy Marketing segment have been classified as discontinued operations. Certain indirect corporate costs and inter-segment interest expenses ~~previously charged to our Energy Marketing segment are~~totaling $0.5 million after-tax for the three months ended Sept. 30, 2011 and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011, respectively were not reclassified ~~to continuing~~as discontinued operations and are included in the Corporate ~~segment.~~segment in continuing operations. See Note 1817 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

(c)

Business Group highlights for 2012 include:

Utilities Group

On Sept. 18, 2012, Colorado Electric completed the sale of a 50 percent ownership interest in the 29 megawatt Busch Ranch Wind project for $25.0 million. The wind turbine project commenced commercial operation on Oct. 16, 2012.

On June 18, 2012, the WPSC approved a stipulation and agreement for Cheyenne Light resulting in an annual revenue increase of $2.7 million for electric customers and $1.6 million for gas customers effective July 1, 2012. The settlement also included a return on equity of ~~9.6%~~9.6 percent with a capital structure of ~~54%~~54 percent equity and ~~46%~~46 percent debt.

On June 4, 2012, Colorado Gas filed a request with the CPUC for an increase in annual gas revenues to recover capital investments and increased operation and maintenance expenses. The CPUC required this rate case filing as part of a previous settlement agreement when we purchased Colorado Gas. All parties reached a rate case settlement and the settlement hearing was held on Oct. 12, 2012. A decision is expected in the first quarter of 2013. The settlement, if approved, includes a $0.2 million revenue increase, a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.

Weather was a contributing factor for our utilities for the quarter and the year. Year-to-date utility results were unfavorably impacted by warm weather, particularly at the Gas Utilities. ~~During 2012, we experienced~~Our service territories reported warmer weather, as measured by degree days, compared to the ~~warmest March on record for our jurisdictions.~~30-year average and last year. Heating degree days year-to-date were ~~17% and 22%~~21 percent lower than weighted average norms for our ~~Electric and~~ Gas ~~Utilities, respectively.~~Utilities. When compared to colder than normal weather during the same period in 2011, heating degree days were ~~24% and 26%~~40 percent lower than the same period in 2011 for our ~~Electric Utilities and our~~ Gas ~~Utilities, respectively. The warm weather continued into the summer months, and cooling degree days quarter-to-date for~~Utilities. For our Electric Utilities, although temperatures were ~~on average 109% greater~~above normal, weather-related demand was tempered by significantly lower humidity in 2012 than ~~weighted average normal weather for the quarter ended June 30, 2012 and on average 81% higher than the same period~~2011 in ~~the prior year.~~

36our service territories.

Colorado Electric’s new $230 million, 180 MWmegawatt power plant near Pueblo, ~~Colorado~~Colo. began commercial operations and started serving utility customers on ~~January~~Jan. 1, 2012. New rates and cost adjustments were effective ~~January~~Jan. 1, 2012, providing an additional ~~$20.5~~$30.0 million in gross margins at Colorado Electric for the ~~six~~nine months ended ~~June~~Sept. 30, 2012.

~~On July 31, 2012,~~ Cheyenne Light and Black Hills Power received ~~approval from~~final approvals and permits for the Cheyenne Prairie Generating Station. The WPSC ~~for a~~approved the CPCN on July 31, 2012 authorizing the construction, operation and maintenance of a new $237 million, 132 megawatt natural gas-fired electric generating facility ~~and related gas and electric transmission~~ in Cheyenne, ~~Wyoming. On July 13,~~Wyo. The state of Wyoming issued the air permit for the project on Aug. 31, 2012 ~~a Stipulation and Agreement among the joint applicants~~ and the ~~intervenor~~U.S. Environmental Protection Agency issued the greenhouse gas air permit on Sept. 27, 2012. Upon receipt of the final permit, the major equipment for the project was ~~filed~~ordered. Commencement of construction for the new plant is expected in spring 2013. Project costs for plant construction and associated transmission are estimated at $222 million, with up to $15 million of construction financing costs, for a total of $237 million.

On Oct. 30, 2012 Cheyenne Light and Black Hills Power received approval from the WPSC ~~including provisions for~~to use a construction ~~work-in-progress rate rider. Use~~financing rider during construction of the ~~CWIP~~Cheyenne Prairie Generating Station in lieu of traditional AFUDC. The rider ~~would allow~~allows Cheyenne Light and Black Hills Power to earn a rate of return during the construction ~~eliminating~~period on the usual allowance for funds used during construction, and reducing the total construction cost from $237 million to $222 million. The WPSC noted the Stipulation and Agreement in the CPCN hearing on July 31, 2012,without approving the CWIP rider and indicating its preference to consider the rider and total construction cost in a separate proceeding.

~~Colorado Electric is progressing on construction~~approximately 60 percent of ~~a 29 MW wind turbine project as part of its plan to meet Colorado's Renewable Energy Standard. Colorado Electric's 50% share of this project will cost approximately $26.5 million and~~ the project ~~is expected~~cost related to ~~begin~~ serving ~~Colorado Electric customers no later than December 31, 2012. Our 50% share of the total expenditures on the project was $20.1 million as of June 30, 2012.~~Wyoming customers. We are evaluating filing for a similar rider in South Dakota.

On ~~April 13,~~Aug. 6, 2012 Black Hills Power and Colorado Electric announced plans to suspend plant operations at some of our older coal-fired and natural gas-fired facilities. In addition, we also identified retirement dates for the older coal-fired power plants because of federal and state environmental regulations. The affected plants are listed in the table below with their operations suspension date (if applicable) and their ultimate retirement date (if identified).



Plant	Company	Megawatts	Type of Plant	Suspend Date	Retirement Date	Age of Plant (in years)
Osage	Black Hills Power	34.5	Coal	Oct. 1, 2010	March 21, 2014	64
Ben French	Black Hills Power	25	Coal	Aug. 31, 2012	March 21, 2014	52
Neil Simpson I	Black Hills Power	21.8	Coal	NA	March 21, 2014	43
W.N. Clark	Colorado Electric	40	Coal	Dec. 31, 2012	Dec. 31, 2013	57
Pueblo Unit #5	Colorado Electric	9	Gas	Dec. 31, 2012	to be determined	71
Pueblo Unit #6	Colorado Electric	20	Gas	Dec. 31, 2012	to be determined	63

On July 30, 2012, Colorado Electric filed its Electric Resource Plan with the CPUC ~~issued its final order denying Colorado Electric's request~~seeking to develop and own replacement capacity for ~~a CPCN~~the retirement of the coal-fired W.N. Clark power plant, which must be retired pursuant to ~~construct a third utility-owned, 88 MW natural gas-fired turbine at the existing Pueblo Airport generating location. Colorado Electric retains the right under~~ the Colorado Clean Air – Clean Jobs ~~Act~~Act. The CPUC dismissed the initial filing and directed Colorado Electric to ~~own the 42 megawatts of replacement generation~~re-file an Energy Resource Plan by Jan. 18, 2013 in order to address alternatives for the replacement capacity of W.N. Clark power plant, ~~that is required to be retired on or before December 13, 2013.~~as well as the retirement of Pueblo No. 5 and No. 6. The CPUC also directed Colorado Electric ~~filed an electric resource plan on July 30, 2012 that proposed building a 40 MW, simple-cycle, gas-fired turbine as the alternative replacement resource for the W.N. Clark plant. We have not yet filed~~to request a CPCN ~~requesting approval~~for any replacement capacity that Colorado Electric seeks to ~~construct this gas-fired facility.~~develop and own.

~~Colorado Gas filed a request with the CPUC on June 4, 2012 for an increase in annual gas revenues of $1.0 million to recover capital investments made in its gas system since January 2008.~~

Non-regulated Energy Group

On Sept. 27, 2012, our Oil and Gas segment sold 85 percent of its Williston Basin assets, including approximately 73 gross wells and 28,000 net lease acres, for net cash proceeds of $226.6 million. We recognized a gain of $27.3 million on the sale. The portion of the sale amount not recognized as gain reduced the full-cost pool and will decrease our depreciation, depletion and amortization rate.

Our Coal Mining segment received all necessary permits and approval for a revised mine plan ~~which will relocate~~relocating mining operations to an area in the mine with lower overburden, reducing overall mining costs for the next several years. The new mine plan went into effect during the second quarter of 2012.

In the second quarter of 2012,, our Oil and Gas segment recorded a $26.9 million non-cash ceiling test impairment loss as a result of continued low ~~commodity~~natural gas prices.

Colorado IPP’s new $261 million, 200 MWmegawatt power plant near Pueblo, ~~Colorado~~Colo. began serving customers on ~~January~~Jan. 1, ~~2012, with its output~~2012. Output from the plant is sold under a 20-year power purchase agreement to Colorado Electric.

Corporate

On Oct. 31, 2012, we redeemed our $225.0 million of senior unsecured 6.5 percent notes, which originally were scheduled to mature on May 15, 2013.

On June 24, 2012, we extended for one year our $150 million term loan ~~under favorable terms~~at an interest rate of ~~1.10%~~1.10 percent over LIBOR.

On ~~February~~Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring ~~February~~Feb. 1, 2017 ~~at favorable terms.~~. Deferred financing costs of $1.5 million relating to the previous credit facility were written off during the first quarter of 2012.

We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $~~3.5~~2.9 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 compared to a $~~2.4~~40.6 million non-cash unrealized mark-to-market loss on these swaps for the same period in 2011.

Discontinued Operations

On ~~February~~Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing ~~segment, Enserco.~~segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds onfrom the ~~date of the sale~~transaction were approximately $166.3 million, subject to final post-closing adjustments.

Pursuant to the provisions of the ~~Stock Purchase Agreement,~~stock purchase agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $~~1.3~~1.4 million, which is accrued ~~for~~ in the accompanying financial ~~statements.~~statements as of Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution ~~would~~will occur through the dispute resolution provision of the ~~Stock Purchase Agreement.~~stock purchase agreement.

Utilities Group

We report two segments within the Utilities Group: Electric Utilities and Gas Utilities. The Electric Utilities segment includes the electric operations of Black Hills Power, Colorado Electric and the electric and natural gas operations of Cheyenne Light. The Gas Utilities segment includes the regulated natural gas utility operations of Black Hills Energy in Colorado, Iowa, Kansas and Nebraska.

Electric Utilities


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance			2012			2011			Variance			2012			2011			Variance
	(in thousands)																		(in thousands)
Revenue — electric	$	144,985		$	132,978		$	12,007		$	291,266		$	267,848		$	23,418		$	151,465		$	149,664		$	1,801		$	442,731		$	417,512		$	25,219
Revenue — Cheyenne Light gas	4,749			6,563			(1,814		)	17,637			19,962			(2,325		)
Revenue — gas																			3,552			4,052			(500		)	21,189			24,014			(2,825		)
Total revenue	149,734			139,541			10,193			308,903			287,810			21,093			155,017			153,716			1,301			463,920			441,526			22,394

Fuel, purchased power and cost of gas — electric	59,523			66,254			(6,731		)	125,121			131,932			(6,811		)	65,992			71,387			(5,395		)	191,113			203,319			(12,206		)
Purchased gas — Cheyenne Light gas	1,923			3,484			(1,561		)	10,041			11,880			(1,839		)
Purchased gas — gas																			1,046			1,703			(657		)	11,087			13,583			(2,496		)
Total fuel, purchased power and cost of gas	61,446			69,738			(8,292		)	135,162			143,812			(8,650		)	67,038			73,090			(6,052		)	202,200			216,902			(14,702		)

Gross margin — electric	85,462			66,724			18,738			166,145			135,916			30,229			85,473			78,277			7,196			251,618			214,193			37,425
Gross margin — Cheyenne Light gas	2,826			3,079			(253		)	7,596			8,082			(486		)
Gross margin — gas																			2,506			2,349			157			10,102			10,431			(329		)
Total gross margin	88,288			69,803			18,485			173,741			143,998			29,743			87,979			80,626			7,353			261,720			224,624			37,096

Operations and maintenance	36,866			34,156			2,710			76,096			71,270			4,826			34,080			34,837			(757		)	110,176			106,107			4,069
Gain on sale of operating assets																			—			(768		)	768			—			(768		)	768
Depreciation and amortization	18,695			13,006			5,689			37,627			25,830			11,797			18,821			13,221			5,600			56,448			39,051			17,397
Total operating expenses	55,561			47,162			8,399			113,723			97,100			16,623			52,901			47,290			5,611			166,624			144,390			22,234

Operating income	32,727			22,641			10,086			60,018			46,898			13,120			35,078			33,336			1,742			95,096			80,234			14,862

Interest expense, net	(12,322		)	(10,107		)	(2,215		)	(25,542		)	(20,051		)	(5,491		)	(12,527		)	(9,729		)	(2,798		)	(38,069		)	(29,780		)	(8,289		)
Other income (expense), net	291			(53		)	344			1,009			356			653			198			200			(2		)	1,207			556			651
Income tax benefit (expense)	(6,537		)	(3,867		)	(2,670		)	(12,580		)	(8,340		)	(4,240		)	(8,176		)	(8,017		)	(159		)	(20,756		)	(16,357		)	(4,399		)
Income (loss) from continuing operations	$	14,159		$	8,614		$	5,545		$	22,905		$	18,863		$	4,042		$	14,573		$	15,790		$	(1,217	)	$	37,478		$	34,653		$	2,825

3839

The following tables summarize revenue, quantities generated and purchased, quantities sold, degree days and power plant availability for our Electric Utilities:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
Revenue - Electric (in thousands)	2012		2011		2012		2011		2012		2011		2012		2011
Residential:
Black Hills Power	$	12,633	$	12,773	$	28,109	$	29,943	$	15,794	$	15,034	$	43,903	$	44,977
Cheyenne Light	7,022		7,026		15,492		15,097		8,324		7,826		23,816		22,923
Colorado Electric	21,042		19,155		43,658		39,591		26,390		24,462		70,048		64,053
Total Residential	40,697		38,954		87,259		84,631		50,508		47,322		137,767		131,953

Commercial:
Black Hills Power	18,804		17,759		35,612		35,073		20,336		19,889		55,948		54,962
Cheyenne Light	15,386		13,495		29,343		26,038		13,003		14,802		42,346		40,840
Colorado Electric	21,570		18,373		40,697		34,958		20,898		19,784		61,595		54,742
Total Commercial	55,760		49,627		105,652		96,069		54,237		54,475		159,889		150,544

Industrial:
Black Hills Power	7,063		6,464		13,083		12,228		5,846		6,716		18,929		18,944
Cheyenne Light	3,243		2,944		6,312		5,556		4,551		3,017		10,863		8,573
Colorado Electric	9,981		8,567		19,213		16,434		8,476		8,086		27,689		24,520
Total Industrial	20,287		17,975		38,608		34,218		18,873		17,819		57,481		52,037

Municipal:
Black Hills Power	887		783		1,585		1,517		930		908		2,515		2,425
Cheyenne Light	472		455		898		846		454		475		1,352		1,321
Colorado Electric	3,948		3,186		6,612		6,122		3,419		3,442		10,031		9,564
Total Municipal	5,307		4,424		9,095		8,485		4,803		4,825		13,898		13,310

Total Retail Revenue - Electric	122,051		110,980		240,614		223,403		128,421		124,441		369,035		347,844

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	4,370		4,370		9,275		8,990		5,627		4,519		14,902		13,509

Off-system Wholesale:
Black Hills Power	6,459		7,442		17,732		14,395		5,599		9,158		23,331		23,553
Cheyenne Light	1,967		2,580		4,480		5,467		1,532		1,535		6,012		7,002
Colorado Electric ^(a)	177		—		410		—		1,663		—		2,073		—
Total Off-system Wholesale ^(a)	8,603		10,022		22,622		19,862		8,794		10,693		31,416		30,555

Other Revenue:
Black Hills Power	8,156		6,507		15,246		13,146		7,002		8,716		22,248		21,862
Cheyenne Light	427		567		1,039		1,256		624		649		1,663		1,905
Colorado Electric	1,378		532		2,470		1,191		997		646		3,467		1,837
Total Other Revenue	9,961		7,606		18,755		15,593		8,623		10,011		27,378		25,604

Total Revenue - Electric	$	144,985	$	132,978	$	291,266	$	267,848	$	151,465	$	149,664	$	442,731	$	417,512

____________


(a)	Off-system sales revenue during 2010 and 2011 was deferred until a sharing mechanism was approved by the CPUC in December 2011, and recognition of ~~25%~~25 percent of the revenue commenced ~~January~~Jan. 2, 2012. As a result, Colorado Electric deferred $~~3.5~~2.0 million and $~~6.4~~8.4 million in off-system revenue during the three and ~~six~~nine months ended ~~June~~Sept. 30, 2011.

Three Months Ended
June 30, Six Months Ended
June 30,
Quantities Generated and Purchased (in MWh) 2012 2011 2012 2011
Generated —
Coal-fired:
Black Hills Power 369,049
386,006
868,841
823,844
Cheyenne Light 154,324
169,195
281,477
340,566
Colorado Electric 58,585
71,236
115,892
127,911
Total Coal-fired 581,958
626,437
1,266,210
1,292,321

Gas and Oil-fired:
Black Hills Power 6,216
1,147
6,579
2,171
Cheyenne Light —
—
—
—
Colorado Electric 19,948
30
21,580
30
Total Gas and Oil-fired 26,164
1,177
28,159
2,201

Total Generated:
Black Hills Power 375,265
387,153
875,420
826,015
Cheyenne Light 154,324
169,195
281,477
340,566
Colorado Electric 78,533
71,266
137,472
127,941
Total Generated 608,122
627,614
1,294,369
1,294,522

Purchased —
Black Hills Power 432,723
401,218
947,257
776,830
Cheyenne Light 181,408
179,079
413,027
376,248
Colorado Electric 409,242
486,052
810,369
968,837
Total Purchased 1,023,373
1,066,349
2,170,653
2,121,915

Total Generated and Purchased:
Black Hills Power 807,988
788,371
1,822,677
1,602,845
Cheyenne Light 335,732
348,274
694,504
716,814
Colorado Electric 487,775
557,318
947,841
1,096,778
Total Generated and Purchased 1,631,495
1,693,963
3,465,022
3,416,437


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
Quantity Sold (in MWh)	2012	2011	2012	2011
Residential:
Quantities Generated and Purchased (in MWh)					2012	2011	2012	2011
Generated —
Coal-fired:
Black Hills Power	106,557	107,683	256,985	282,083	475,752	463,032	1,344,593	1,286,876
Cheyenne Light	56,440	58,532	128,277	131,410	155,099	170,643	436,576	511,209
Colorado Electric	136,677	138,644	290,729	295,999	61,820	74,470	177,712	202,381
Total Residential	299,674	304,859	675,991	709,492
Total Coal-fired					692,671	708,145	1,958,881	2,000,466

Commercial:
Gas and Oil-fired:
Black Hills Power	181,281	167,649	351,374	345,886	21,543	11,424	28,122	13,595
Cheyenne Light	158,346	143,645	308,285	289,244	—	—	—	—
Colorado Electric	184,734	180,168	350,125	345,902	50,691	2,748	72,271	2,778
Total Commercial	524,361	491,462	1,009,784	981,032
Total Gas and Oil-fired					72,234	14,172	100,393	16,373

Industrial:
Total Generated:
Black Hills Power	115,024	105,861	210,759	194,610	497,295	474,456	1,372,715	1,300,471
Cheyenne Light	44,155	42,642	88,929	83,470	155,099	170,643	436,576	511,209
Colorado Electric	97,192	91,188	178,434	175,097	112,511	77,218	249,983	205,159
Total Industrial	256,371	239,691	478,122	453,177
Total Generated					764,905	722,317	2,059,274	2,016,839

Municipal:
Purchased —
Black Hills Power	8,843	7,739	16,411	16,041	280,815	409,174	1,228,072	1,186,004
Cheyenne Light	2,128	2,150	4,710	4,594	191,884	172,520	604,911	548,768
Colorado Electric	35,019	32,079	60,188	59,826	488,321	527,975	1,298,690	1,496,812
Total Municipal	45,990	41,968	81,309	80,461
Total Purchased					961,020	1,109,669	3,131,673	3,231,584

Total Retail Quantity Sold	1,126,396	1,077,980	2,245,206	2,224,162

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	72,006	82,253	161,054	172,212

Off-system Wholesale:
Total Generated and Purchased:
Black Hills Power	295,149	278,086	753,379	520,242	778,110	883,630	2,600,787	2,486,475
Cheyenne Light	53,911	79,741	120,620	163,926	346,983	343,163	1,041,487	1,059,977
Colorado Electric	6,063	94,945	8,671	173,448	600,832	605,193	1,548,673	1,701,971
Total Off-system Wholesale	355,123	452,772	882,670	857,616

Total Quantity Sold:
Black Hills Power	778,860	749,271	1,749,962	1,531,074
Cheyenne Light	314,980	326,710	650,821	672,644
Colorado Electric	459,685	537,024	888,147	1,050,272
Total Quantity Sold	1,553,525	1,613,005	3,288,930	3,253,990

Losses and Company Use:
Black Hills Power	29,128	39,100	72,715	71,771
Cheyenne Light	20,752	21,564	43,682	44,170
Colorado Electric	28,090	20,294	59,695	46,506
Total Losses and Company Use	77,970	80,958	176,092	162,447

Total Quantity Sold	1,631,495	1,693,963	3,465,022	3,416,437
Total Generated and Purchased					1,725,925	1,831,986	5,190,947	5,248,423


	Three Months Ended June 30,						Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
Degree Days	2012			2011
Heating Degree Days:	Actual	Variance from 30-Year Average		Actual	Variance from 30-Year Average
Actual —
Quantity Sold (in MWh)							2012	2011	2012	2011
Residential:
Black Hills Power	748	(27	)%	1,190	19	%	139,282	132,571	396,267	414,654
Cheyenne Light	841	(29	)%	1,354	10	%	68,816	65,643	197,093	197,053
Colorado Electric	405	(36	)%	638	(1	)%	185,696	185,775	476,425	481,774
Total Residential							393,794	383,989	1,069,785	1,093,481

Cooling Degree Days:
Actual —
Commercial:
Black Hills Power	206	108	%	56	(45	)%	202,418	198,774	553,792	544,660
Cheyenne Light	138	176	%	30	(29	)%	141,433	157,138	449,718	446,382
Colorado Electric	423	102	%	294	36	%	198,839	201,266	548,964	547,168
Total Commercial							542,690	557,178	1,552,474	1,538,210

Industrial:
Black Hills Power							93,147	106,658	303,906	301,268
Cheyenne Light							62,397	44,857	151,326	128,327
Colorado Electric							89,305	90,895	267,739	265,992
Total Industrial							244,849	242,410	722,971	695,587

Municipal:
Black Hills Power							11,154	9,917	27,565	25,958
Cheyenne Light							2,318	2,528	7,028	7,122
Colorado Electric							35,461	36,657	95,649	96,483
Total Municipal							48,933	49,102	130,242	129,563

Total Retail Quantity Sold							1,230,266	1,232,679	3,475,472	3,456,841

Contract Wholesale:
Total Contract Wholesale - Black Hills Power							88,334	84,346	249,388	256,558

Off-system Wholesale:
Black Hills Power							190,143	299,511	943,522	819,753
Cheyenne Light							46,157	47,615	166,777	211,541
Colorado Electric							52,228	48,643	60,899	222,091
Total Off-system Wholesale							288,528	395,769	1,171,198	1,253,385

Total Quantity Sold:
Black Hills Power							724,478	831,777	2,474,440	2,362,851
Cheyenne Light							321,121	317,781	971,942	990,425
Colorado Electric							561,529	563,236	1,449,676	1,613,508
Total Quantity Sold							1,607,128	1,712,794	4,896,058	4,966,784

Losses and Company Use:
Black Hills Power							53,632	51,853	126,347	123,624
Cheyenne Light							25,863	25,382	69,545	69,552
Colorado Electric							39,302	41,957	98,997	88,463
Total Losses and Company Use							118,797	119,192	294,889	281,639

Total Quantity Sold							1,725,925	1,831,986	5,190,947	5,248,423



	Three Months Ended Sept. 30,
Degree Days	2012			2011
Heating Degree Days:	Actual	Variance from 30-Year Average		Actual	Variance from 30-Year Average

Black Hills Power	99	(56	)%	153	(33	)%
Cheyenne Light	170	(40	)%	197	(40	)%
Colorado Electric	54	(45	)%	46	(50	)%

Cooling Degree Days:

Black Hills Power	731	37	%	620	26	%
Cheyenne Light	430	44	%	399	73	%
Colorado Electric	898	31	%	958	36	%


	Six Months Ended June 30,						Nine Months Ended Sept. 30,
Degree Days	2012			2011			2012			2011
							Actual	Variance from 30-Year Average		Actual	Variance from 30-Year Average
Heating Degree Days:	Actual	Variance from 30-Year Average		Actual	Variance from 30-Year Average
Black Hills Power	3,459	(18	)%	4,897	14	%	3,558	(50	)%	5,050	(30	)%
Cheyenne Light	3,602	(14	)%	4,477	2	%	3,772	(47	)%	4,674	(37	)%
Colorado Electric	2,699	(18	)%	3,419	4	%	2,753	(51	)%	3,465	(38	)%

Cooling Degree Days:
Black Hills Power	206	108	%	56	(45	)%	937	47	%	676	13	%
Cheyenne Light	138	176	%	30	(29	)%	568	63	%	429	57	%
Colorado Electric	423	102	%	294	36	%	1,321	47	%	1,252	36	%


Electric Utilities Power Plant Availability	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012			2011			2012			2011			2012		2011		2012			2011
Coal-fired plants	81.0	%	^(a)	88.6	%	^(b)	86.0	%	^(a)	89.9	%	^(b)	95.4	%	95.1	%	89.1	%	^(a)	91.6	%	^(b)
Other plants	96.4	%		89.9	%	^(c)	95.7	%		94.3	%		98.5	%	98.6	%	96.6	%		95.7	%
Total availability	88.8	%		89.0	%		90.9	%		91.5	%		97.0	%	96.4	%	93.0	%		93.1	%

_________________________


(a)	~~Three months ended June 30, 2012 reflects~~Reflects an unplanned outage due to a transformer failure and a planned outage at Neil Simpson ~~II. Six months ended June 30, 2012 also includes~~II, and a planned and extended overhaul at Wygen II.


(b)	~~2011 includes~~Reflects a major overhaul and an unplanned outage at the ~~PacifiCorp operated~~PacifiCorp-operated Wyodak plant.


~~(c)~~	~~Reflects a planned major overhaul at Neil Simpson CT.~~

4243

Cheyenne Light Natural Gas Distribution

Included in the Electric Utilities is Cheyenne Light's natural gas distribution system. The following table summarizes certain operating information for these natural gas distribution operations:


	Three Months Ended June 30,					Six Months Ended June 30,				Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011			2012		2011		2012		2011		2012		2011
Revenue - Gas (in thousands):
Residential	$	2,955	$	4,053		$	10,585	$	12,031	$	2,362	$	2,561	$	12,947	$	14,592
Commercial	1,209		1,739			5,019		5,546		770		946		5,789		6,492
Industrial	397		580			1,634		1,856		248		370		1,882		2,226
Other Sales Revenue	188		191			399		529		172		175		571		704
Total Revenue - Gas	$	4,749	$	6,563		$	17,637	$	19,962	$	3,552	$	4,052	$	21,189	$	24,014

Gross Margin (in thousands):
Residential	$	2,002	$	2,332		$	5,228	$	5,720	$	1,864	$	1,739	$	7,092	$	7,459
Commercial	551		694			1,724		1,906		417		387		2,141		2,293
Industrial	85		98			249		275		53		63		302		338
Other Gross Margin	188		(45		)	395		181		172		160		567		341
Total Gross Margin	$	2,826	$	3,079		$	7,596	$	8,082	$	2,506	$	2,349	$	10,102	$	10,431

Volumes Sold (Dth):
Residential	315,571		497,250			1,285,249		1,565,711		168,229		179,602		1,453,478		1,745,313
Commercial	217,847		302,543			798,787		926,266		119,344		122,138		918,131		1,048,404
Industrial	109,803		140,135			346,943		396,656		64,721		66,962		411,664		463,618
Total Volumes Sold	643,221		939,928			2,430,979		2,888,633		352,294		368,702		2,783,273		3,257,335

4344

Results of Operations for the Electric Utilities for the Three Months Ended ~~June~~Sept. 30, 2012 Compared to Three Months Ended ~~June~~Sept. 30, 2011: Income from continuing operations for the Electric Utilities was $~~14.2~~14.6 million for the three months ended ~~June~~Sept. 30, 2012 compared to $~~8.6~~15.8 million for the three months ended ~~June~~Sept. 30, 2011 as a result of:

Gross marginincreased primarily due to a ~~$10.9~~$9.6 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, ~~increased retail margins of $2.5~~partially offset by a $0.7 million ~~on higher quantities sold driven by warmer weather, an increase of $1.8 million from~~decrease in wholesale and transmission margins as a result of ~~increased~~decreased pricing,a decrease of $0.3 million in off-system salesand a ~~$0.5~~decrease of $0.6 million ~~increase~~ from ~~an Environmental Improvement Cost Recovery Adjustment rider at Black Hills Power.~~expiration of a reserve capacity agreement with PacifiCorp.

Operations and maintenancedecreased ~~increased~~ primarily due to a $2.1 million reduction of major maintenance accruals related to the power plants announced for retirementand cost containment efforts,partially offset by costs associated with operating the new generating facility in Pueblo, ~~Colorado and associated~~Colo.including increased corporate ~~allocations,~~allocations.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party and ~~an increase~~the gain was eliminated in ~~major maintenance costs from our generating facilities.~~the consolidation.

Depreciation and amortizationincreased primarily due to a higher asset base associated with the new 180 MWmegawatt generating facility constructed in Pueblo, ~~Colorado~~ Colo.and the capital lease assets associated with the 200 MWmegawatt generating facility providing capacity and energy from Colorado IPP.

Interest expense, netincreased ~~increased~~ primarily due to interest associated with the financing of the Pueblo generating facility completed in December 2011.Interest costs were capitalized during construction in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate in 2012 was ~~comparable to the same period in the prior year.~~impacted by a unfavorable true-up adjustment while 2011 was impacted by a favorable true-up adjustment.

Results of Operations for the Electric Utilities for the ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2011: Income from continuing operations for the Electric Utilities was $~~22.9~~37.5 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 compared to $~~18.9~~34.7 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2011 as a result of:

Gross marginincreased primarily due to a ~~$20.4~~$30.0 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, a ~~$2.7~~$1.5 million increase from wholesale and transmission margins from increased pricing, a ~~$0.6~~$0.4 million increase in off-system sales mainly from higher ~~volumes,~~quantities sold, a $1.2 million increase from an Environmental Improvement Cost Recovery Adjustment rider at Black Hills Power and increased retail margins as a result of a higher quantities sold driven by warmer ~~weather.~~weather partially offset by a decrease of $0.6 million from the expiration of a reserve capacity agreement with PacifiCorp.

Operations and maintenanceincreased primarily due to the costs associated with operating the new generating facility in Pueblo, ~~Colorado and associated~~Colo. including increased corporate ~~allocations.~~allocations partially offset by a $2.1 million reduction of major maintenance accruals related to the power plants announced for retirement and cost containment efforts.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party and the gain was eliminated in the consolidation.

Depreciation and amortizationincreased primarily due to a higher asset base associated with the new 180 MWmegawatt generating facility ~~constructed~~ in Pueblo, ~~Colorado~~Colo. and the capital lease assets associated with the 200 MWmegawatt generating facility providing capacity and energy from Colorado IPP.

Interest expense, netincreased ~~increased primarily~~primarily due to interest associated with financing of the Pueblo generating facility completed in December 2011. Interest costs were capitalized during construction in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate increased due to ~~unfavorable state income~~a favorable benefit in the prior year for a repairs deduction taken for tax ~~true-up adjustments~~purposes and the ~~impact~~flow-through treatment of ~~research and development credits not being renewed.~~such tax benefit.

4445

Gas Utilities


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance			2012			2011			Variance			2012			2011			Variance
	(in thousands)																		(in thousands)
Natural gas — regulated	$	64,033		$	93,598		$	(29,565	)	$	236,202		$	316,630		$	(80,428	)	$	56,845		$	65,887		$	(9,042	)	$	293,047		$	382,517		$	(89,470	)
Other — non-regulated services	6,353			6,324			29			14,706			13,558			1,148			6,590			6,764			(174		)	21,296			20,322			974
Total revenue	70,386			99,922			(29,536		)	250,908			330,188			(79,280		)	63,435			72,651			(9,216		)	314,343			402,839			(88,496		)

Natural gas — regulated	25,424			49,956			(24,532		)	133,540			199,459			(65,919		)	20,802			29,693			(8,891		)	154,342			229,152			(74,810		)
Other — non-regulated services	3,020			3,154			(134		)	6,889			6,780			109			3,383			3,480			(97		)	10,272			10,260			12
Total cost of sales	28,444			53,110			(24,666		)	140,429			206,239			(65,810		)	24,185			33,173			(8,988		)	164,614			239,412			(74,798		)

Gross margin	41,942			46,812			(4,870		)	110,479			123,949			(13,470		)	39,250			39,478			(228		)	149,729			163,427			(13,698		)

Operations and maintenance	28,483			28,249			234			59,782			62,809			(3,027		)	28,339			28,317			22			88,121			91,126			(3,005		)
Depreciation and amortization	6,253			5,947			306			12,410			11,968			442			6,338			6,064			274			18,748			18,032			716
Total operating expenses	34,736			34,196			540			72,192			74,777			(2,585		)	34,677			34,381			296			106,869			109,158			(2,289		)

Operating income (loss)	7,206			12,616			(5,410		)	38,287			49,172			(10,885		)	4,573			5,097			(524		)	42,860			54,269			(11,409		)

Interest expense, net	(5,749		)	(6,339		)	590			(12,289		)	(13,311		)	1,022			(5,370		)	(6,329		)	959			(17,659		)	(19,640		)	1,981
Other income (expense), net	73			124			(51		)	84			149			(65		)	(2		)	27			(29		)	82			176			(94		)
Income tax benefit (expense)	(371		)	(1,961		)	1,590			(9,716		)	(12,307		)	2,591			802			1,777			(975		)	(8,914		)	(10,530		)	1,616
Income (loss) from continuing operations	$	1,159		$	4,440		$	(3,281	)	$	16,366		$	23,703		$	(7,337	)	$	3		$	572		$	(569	)	$	16,369		$	24,275		$	(7,906	)

4546

The following tables summarize revenue, gross margin, volumes sold and degree days for our Gas Utilities:

Revenue (in thousands) Three Months Ended
June 30, Six Months Ended
June 30,
2012 2011 2012 2011
Residential:
Colorado $ 7,321
$ 10,749
$ 29,339
$ 33,735
Nebraska 13,538
20,663
54,462
79,062
Iowa 11,870
18,593
46,440
66,024
Kansas 7,762
10,568
29,183
38,521
Total Residential 40,491
60,573
159,424
217,342

Commercial:
Colorado 1,433
2,182
5,627
6,815
Nebraska 3,918
6,385
18,018
26,303
Iowa 4,734
7,802
20,507
28,685
Kansas 1,994
2,944
8,729
12,240
Total Commercial 12,079
19,313
52,881
74,043

Industrial:
Colorado 594
583
646
698
Nebraska 140
163
429
336
Iowa 449
407
1,194
1,144
Kansas 4,314
6,849
5,236
7,969
Total Industrial 5,497
8,002
7,505
10,147

Transportation:
Colorado 157
179
503
507
Nebraska 1,672
2,072
5,471
6,431
Iowa 978
827
2,228
2,152
Kansas 1,161
1,125
3,029
3,192
Total Transportation 3,968
4,203
11,231
12,282

Other Sales Revenue:
Colorado 21
25
50
56
Nebraska 517
511
1,092
1,119
Iowa 141
193
264
319
Kansas 1,319
778
3,755
1,322
Total Other Sales Revenue 1,998
1,507
5,161
2,816

Total Regulated Revenue 64,033
93,598
236,202
316,630

Non-regulated Services 6,353
6,324
14,706
13,558

Total Revenue $ 70,386
$ 99,922
$ 250,908
$ 330,188


Gross Margin (in thousands)	Three Months Ended June 30,				Six Months Ended June 30,
Revenue (in thousands)									Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011		2012		2011		2012		2011
Residential:
Colorado	$	3,141	$	3,760	$	8,827	$	9,880	$	4,498	$	5,493	$	33,837	$	39,228
Nebraska	8,997		10,464		24,588		29,381		11,370		12,736		65,832		91,798
Iowa	8,328		10,313		20,523		26,594		9,776		11,235		56,216		77,259
Kansas	5,795		6,120		14,915		16,198		7,354		7,928		36,537		46,449
Total Residential	26,261		30,657		68,853		82,053		32,998		37,392		192,422		254,734

Commercial:
Colorado	503		613		1,419		1,645		898		1,352		6,525		8,167
Nebraska	1,740		2,136		5,623		6,976		2,742		3,520		20,760		29,823
Iowa	2,036		2,433		5,833		6,596		3,988		4,397		24,495		33,082
Kansas	1,108		1,189		3,278		3,725		1,973		2,076		10,702		14,316
Total Commercial	5,387		6,371		16,153		18,942		9,601		11,345		62,482		85,388

Industrial:
Colorado	172		127		202		163		1,110		1,174		1,756		1,872
Nebraska	44		41		105		91		306		194		735		530
Iowa	45		48		116		138		357		334		1,551		1,478
Kansas	772		761		994		992		7,078		10,437		12,314		18,406
Total Industrial	1,033		977		1,417		1,384		8,851		12,139		16,356		22,286

Transportation:
Colorado	157		178		504		506		113		84		616		591
Nebraska	1,672		2,072		5,471		6,431		1,866		1,626		7,337		8,057
Iowa	978		827		2,228		2,152		816		687		3,044		2,839
Kansas	1,161		1,125		3,029		3,192		1,338		1,311		4,367		4,503
Total Transportation	3,968		4,202		11,232		12,281		4,133		3,708		15,364		15,990

Other Sales Margins:
Other Sales Revenue:
Colorado	21		25		50		56		15		22		65		78
Nebraska	518		511		1,093		1,119		469		432		1,561		1,551
Iowa	142		193		265		319		86		122		350		441
Kansas	1,279		706		3,600		1,017		692		727		4,447		2,049
Total Other Sales Margins	1,960		1,435		5,008		2,511
Total Other Sales Revenue									1,262		1,303		6,423		4,119

Total Regulated Gross Margin	38,609		43,642		102,663		117,171
Total Regulated Revenue									56,845		65,887		293,047		382,517

Non-regulated Services	3,333		3,170		7,816		6,778		6,590		6,764		21,296		20,322

Total Gross Margin	$	41,942	$	46,812	$	110,479	$	123,949
Total Revenue									$	63,435	$	72,651	$	314,343	$	402,839


Volumes Sold (in Dth)	Three Months Ended June 30,		Six Months Ended June 30,
Gross Margin (in thousands)					Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012	2011	2012	2011	2012		2011		2012		2011
Residential:
Colorado	797,696	1,127,379	3,401,097	3,847,384	$	2,548	$	2,695	$	11,375	$	12,575
Nebraska	998,527	1,772,388	5,351,344	7,842,625	8,334		8,480		32,922		37,861
Iowa	854,889	1,607,488	5,006,355	6,920,778	7,850		8,291		28,373		34,885
Kansas	498,802	818,677	3,158,476	4,249,556	5,622		5,465		20,537		21,663
Total Residential	3,149,914	5,325,932	16,917,272	22,860,343	24,354		24,931		93,207		106,984

Commercial:
Colorado	179,454	253,822	706,248	835,518	399		460		1,818		2,105
Nebraska	509,760	748,867	2,290,391	3,091,977	1,404		1,486		7,027		8,462
Iowa	669,018	1,042,988	2,896,813	3,888,734	1,890		1,862		7,723		8,458
Kansas	226,476	324,680	1,219,481	1,627,611	1,087		1,006		4,365		4,731
Total Commercial	1,584,708	2,370,357	7,112,933	9,443,840	4,780		4,814		20,933		23,756

Industrial:
Colorado	140,017	99,708	150,569	115,322	307		239		509		402
Nebraska	24,801	22,946	65,702	36,194	99		48		204		139
Iowa	93,817	68,662	222,959	178,463	56		38		172		176
Kansas	1,280,464	1,312,270	1,469,361	1,508,598	1,096		1,144		2,090		2,136
Total Industrial	1,539,099	1,503,586	1,908,591	1,838,577	1,558		1,469		2,975		2,853

Transportation:
Colorado	146,703	183,494	508,576	528,665	113		84		617		590
Nebraska	5,448,471	6,688,435	13,589,365	12,636,481	1,866		1,626		7,337		8,057
Iowa	4,492,459	4,026,034	9,679,955	9,579,099	816		687		3,044		2,839
Kansas	3,286,586	2,940,539	7,646,507	7,380,809	1,338		1,311		4,367		4,503
Total Transportation	13,374,219	13,838,502	31,424,403	30,125,054	4,133		3,708		15,365		15,989

Other Volumes:
Other Sales Margins:
Colorado	—	—	—	—	15		22		65		78
Nebraska	—	—	—	—	469		433		1,562		1,552
Iowa	—	—	—	—	86		122		351		441
Kansas	7,503	17,081	31,953	62,066	648		695		4,248		1,712
Total Other Volumes	7,503	17,081	31,953	62,066
Total Other Sales Margins					1,218		1,272		6,226		3,783

Total Volumes Sold	19,655,443	23,055,458	57,395,152	64,329,880
Total Regulated Gross Margin					36,043		36,194		138,706		153,365

Non-regulated Services					3,207		3,284		11,023		10,062

Total Gross Margin					$	39,250	$	39,478	$	149,729	$	163,427



Volumes Sold (in Dth)	Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011
Residential:
Colorado	372,722	450,778	3,773,819	4,298,162
Nebraska	681,361	764,676	6,032,705	8,607,301
Iowa	479,912	564,426	5,486,267	7,485,204
Kansas	422,708	461,169	3,581,184	4,710,725
Total Residential	1,956,703	2,241,049	18,873,975	25,101,392

Commercial:
Colorado	98,453	145,413	804,701	980,931
Nebraska	315,832	373,386	2,606,223	3,465,363
Iowa	527,923	486,758	3,424,736	4,375,492
Kansas	219,870	203,109	1,439,351	1,830,720
Total Commercial	1,162,078	1,208,666	8,275,011	10,652,506

Industrial:
Colorado	265,451	202,956	416,020	318,278
Nebraska	69,229	30,816	134,931	67,010
Iowa	74,535	56,401	297,494	234,864
Kansas	1,912,296	2,010,001	3,381,657	3,518,599
Total Industrial	2,321,511	2,300,174	4,230,102	4,138,751

Total Volumes Sold	5,440,292	5,749,889	31,379,088	39,892,649

Transportation:
Colorado	98,893	75,828	607,469	604,493
Nebraska	6,453,607	5,910,136	20,042,972	18,546,617
Iowa	4,038,804	4,068,243	13,718,759	13,647,342
Kansas	3,993,675	4,331,612	11,640,182	11,712,421
Total Transportation	14,584,979	14,385,819	46,009,382	44,510,873

Other Volumes:
Colorado	—	—	—	—
Nebraska	—	—	—	—
Iowa	—	—	—	—
Kansas ^(a)	8,427	4,086	40,380	66,152
Total Other Volumes	8,427	4,086	40,380	66,152

Total Volumes and Transportation Sold	20,033,698	20,139,794	77,428,850	84,469,674

___________

(a) Other volumes represent wholesale customers.


	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012		Three Months Ended Sept. 30, 2012		Nine Months Ended Sept. 30, 2012
Heating Degree Days:	Actual	Variance From Normal	Actual	Variance From Normal	Actual	Variance From Normal	Actual	Variance From Normal
Colorado	552	(40)%	2,902	(22)%	116	(39)%	3,018	(23)%
Nebraska	370	(36)%	2,770	(23)%	110	12%	2,880	(22)%
Iowa	614	(21)%	3,413	(20)%	216	21%	3,629	(19)%
Kansas ^(a)	291	(39)%	2,331	(21)%	42	(35)%	2,373	(21)%
Combined ^(b)	490	(31)%	2,922	(22)%	150	5%	3,176	(21)%


	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011			Three Months Ended Sept. 30, 2011			Nine Months Ended Sept. 30, 2011
Heating Degree Days:	Actual	Variance From Normal		Actual	Variance From Normal		Actual	Variance From Normal		Actual	Variance From Normal
Colorado	840	(11	)%	3,601	(6	)%	116	(38	)%	3,717	(7	)%
Nebraska	585	2	%	3,866	2	%	157	49	%	4,023	4	%
Iowa	851	7	%	4,545	1	%	235	38	%	4,780	3	%
Kansas ^(a)	406	(10	)%	3,031	1	%	54	74	%	3,085	1	%
Combined ^(b)	726	1	%	4,069	—	%	178	36	%	4,247	2	%

_______________


(a)	Our gross margin in Kansas utilizes normal degree days ~~due to~~from an approved weather normalization mechanism.


(b)	The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas which has an approved weather normalization mechanism.

Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. Over ~~70%~~70 percent of our Gas Utilities' revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for and certain expenses of these operations fluctuate significantly among quarters. Depending upon the state in which our Gas Utilities operate, the winter heating season begins around ~~November~~Nov. 1 and ends around March 31.

Results of Operations for the Gas Utilities for the Three Months Ended ~~June~~Sept. 30, 2012 Compared to Three Months Ended ~~June~~Sept. 30, 2011: Income from continuing operations for the Gas Utilities was $~~1.2~~0.0 million for the three months ended ~~June~~Sept. 30, 2012 compared to Income from continuing operations of $~~4.4~~0.6 million for the three months ended ~~June~~Sept. 30, 2011 as a result of:

Gross margin ~~decreased primarily due to a $2.0 million impact from milder weather compared~~was comparable to the same period in the prior year. ~~Heating degree days were 33% lower for the three months ended~~

~~June 30, 2012~~Operations and maintenance ~~compared~~was comparable to the same period in the prior year and 31% lower than normal. A reclassification accounting adjustment was made in the current year recording $1.3 million against gross margin that in prior year is included in operations and maintenance.

~~Operations and maintenance~~ is comparable to the prior year reflecting that the same period in the prior year included a favorable property tax true up adjustment of $0.8 million offset by a reclassification accounting adjustment that was made in the current year recording $1.3 million of operating costs in gross margin.year.

Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, netdecreased primarily due to lower interest rates.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The deviation in the effective tax rate ~~decreased as a~~from the statutory rate is the result of a favorable true-up adjustment that had a more pronounced impact in 2012 due to significantly lower pre-tax net ~~income when compared to 2011. Prior~~loss.The prior year also realized a favorable true up adjustment ~~but its impact on the effective tax rate was less pronounced due to significantly higher pre-tax net income when compared to 2012.~~for flow-through treatment of certain property-related temporary differences.

4950

Results of Operations for the Gas Utilities for the ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2011: Income from continuing operations for the Gas Utilities was $16.4 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 compared to Income from continuing operations of $~~23.7~~24.3 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2011 as a result of:

Gross margindecreased primarily due to a ~~$9.3~~$9.6 million impact from milder weather compared to the same period in the prior year. Heating degree days were ~~28%~~25 percent lower for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 compared to the same period in theprior year and ~~22%~~21 percent lower than normal. A reclassification ~~accounting~~ adjustment was made in the current year, recording ~~$4.0~~$4.9 million against gross margin ~~that~~ in prior year isthat was included in operations and maintenance.

Operations and maintenancedecreased primarily due to lower bad debt costs, ~~and~~ cost efficiencies and a reclassification accounting adjustment that was made in the current year recording ~~$4.0~~$4.9 million of operating costs in gross margin.

Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, net decreased primarily due to lower interest rates.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate increased as a result of an unfavorable state true-up adjustment. Additionally, the 2011 period was favorably impacted as a result of federal ~~income tax related~~ research and development credits and a flow-through tax adjustment ~~involving~~at Iowa Gas.

Regulatory Matters — Utilities Group

The following summarizes our recent state and federal rate case and initial surcharge orders (dollars in millions):


				Revenue		Revenue			Approved Capital Structure					Revenue		Revenue			Approved Capital Structure
	Type of Service	Date Requested	Date Effective	Amount Requested		Amount Approved		Return on Equity	Equity	Debt	Type of Service	Date Requested	Date Effective	Amount Requested		Amount Approved		Return on Equity	Equity	Debt
Nebraska Gas (1)	Gas	12/2009	9/2010	$	12.1	$	8.3	10.1%	52.0%	48.0%	Gas	12/2009	9/2010	$	12.1	$	8.3	10.1%	52.0%	48.0%
Iowa Gas ~~(4)~~(2)	Gas	6/2010	2/2011	$	4.7	$	3.4	Global Settlement	Global Settlement	Global Settlement	Gas	6/2010	2/2011	$	4.7	$	3.4	Global Settlement	Global Settlement	Global Settlement
Colorado Electric ~~(4)~~(2)	Electric	4/2011	1/2012	$	40.2	$	28.0	9.8% - 10.2%	49.1%	50.9%	Electric	4/2011	1/2012	$	40.2	$	28.0	9.8% - 10.2%	49.1%	50.9%
Cheyenne Light ~~(2)~~(3)	Electric/Gas	12/2011	7/2012	$	8.5	$	4.3	9.6%	54.0%	46.0%	Electric/Gas	12/2011	7/2012	$	8.5	$	4.3	9.6%	54.0%	46.0%
Black Hills Power ~~(4)~~(2)	Electric	1/2011	6/2011	Not Applicable		$	3.1	Not Applicable	Not Applicable	Not Applicable	Electric	1/2011	6/2011	Not Applicable		$	3.1	Not Applicable	Not Applicable	Not Applicable
Colorado Gas ~~(3)~~(4)	Gas	6/2012	Pending	$	1.0	Pending		Pending	Pending	Pending	Gas	6/2012	Pending	$	1.0	Pending		Pending	Pending	Pending

(1)

The Nebraska Public Advocate filed an appeal with the District Court related to the rate case decision which has been denied. Subsequently, the Nebraska Public Advocate filed a notice of appeal in the Court of Appeals. On March 20, 2012, the Court of Appeals affirmed the earlier decision of the District Court. The Nebraska Public Advocate petitioned the Nebraska Supreme Court to hear an appeal which was denied. Accordingly, the appeals of the rate case decision have been exhausted and the rate case decision is upheld as a final decision of the NPSC.


(2)	~~Cheyenne Light filed requests~~These rate settlements were the most recent for the jurisdiction and were previously described in our 2011 Annual Report on ~~December 1, 2011 for electric and natural gas revenue increases with the WPSC seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue.~~ Form 10-K.

(3)

On June 18, 2012, the WPSC approved a settlement agreement resulting in annual revenue increases of $2.7 million for electric customers and $1.6 million for gas customers effective July 1, 2012. The cost adjustment mechanism relating to transmission, fuel and purchased power costs was modified to eliminate the $1.0 million threshold and changed the sharing mechanism to ~~85%~~85 percent to the customer for these cost adjustment mechanisms. The agreement approved a return on equity of ~~9.6%~~9.6 percent with a capital structure of ~~54%~~54 percent equity and ~~46%~~46 percent debt.

~~(3)~~(4)

On June 4, 2012, Colorado Gas filed a request with the CPUC ~~on June 4, 2012~~ for an increase in annual gas revenues of $1.0 million to recover capital investments ~~made~~and increased operation and maintenance expenses. The CPUC required this rate case filing as part of a previous settlement agreement when we purchased Colorado Gas. All parties reached a rate case settlement, and the settlement hearing was held on Oct. 12, 2012. A decision is expected in ~~its gas system since January 2008.~~the first quarter of 2013. The settlement, if approved, includes a $0.2 million revenue increase, a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.


~~(4)~~	~~These rate settlements were the most recent for the jurisdiction and were previously described in our 2011 Annual Report on Form 10-K.~~

5051

Non-regulated Energy Group

We report three segments within our Non-regulated Energy Group: ~~Oil and Gas,~~Power Generation, Coal Mining and ~~Power Generation.~~Oil and Gas.

For more than 15 years, we also owned and operated Enserco, an energy marketing business that ~~engages~~engaged in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. We sold Enserco on ~~February~~Feb. 29, 2012, which resulted in our Energy Marketing segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations.

Power Generation


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance			2012			2011			Variance			2012			2011			Variance
	(in thousands)																		(in thousands)
Revenue	$	18,734		$	7,780		$	10,954		$	38,361		$	15,400		$	22,961		$	20,951		$	8,100		$	12,851		$	59,312		$	23,500		$	35,812

Operations and maintenance	7,566			4,091			3,475			14,698			8,279			6,419			7,788			4,602			3,186			22,486			12,881			9,605
Depreciation and amortization	1,116			1,040			76			2,230			2,104			126			1,165			1,064			101			3,395			3,168			227
Total operating expense	8,682			5,131			3,551			16,928			10,383			6,545			8,953			5,666			3,287			25,881			16,049			9,832

Operating income	10,052			2,649			7,403			21,433			5,017			16,416			11,998			2,434			9,564			33,431			7,451			25,980

Interest expense, net	(3,972		)	(1,835		)	(2,137		)	(8,715		)	(3,626		)	(5,089		)	(3,085		)	(1,835		)	(1,250		)	(11,800		)	(5,461		)	(6,339		)
Other (expense) income	9			21			(12		)	14			1,225			(1,211		)	(4		)	(5		)	1			10			1,220			(1,210		)
Income tax (expense) benefit	(2,163		)	(287		)	(1,876		)	(1,892		)	(882		)	(1,010		)	(3,781		)	(257		)	(3,524		)	(5,673		)	(1,139		)	(4,534		)

Income (loss) from continuing operations	$	3,926		$	548		$	3,378		$	10,840		$	1,734		$	9,106		$	5,128		$	337		$	4,791		$	15,968		$	2,071		$	13,897

The following table provides certain operating statistics for our plants within the Power Generation segment:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011		2012		2011		2012		2011
Contracted power plant fleet availability:
Coal-fired plant	99.2	%	99.5	%	99.6	%	99.8	%	99.4	%	97.1	%	99.5	%	98.9	%
Natural gas-fired plants	98.9	%	100.0	%	99.2	%	100.0	%	99.4	%	100.0	%	99.3	%	100.0	%
Total availability	99.0	%	99.7	%	99.3	%	99.8	%	99.4	%	98.1	%	99.4	%	99.3	%

Results of Operations for Power Generation for the Three Months Ended ~~June~~Sept. 30, 2012 Compared to Three Months Ended ~~June~~Sept. 30, 2011: Income from continuing operations for the Power Generation segment was $~~3.9~~5.1 million for the three months ended ~~June~~Sept. 30, 2012 compared to Income from continuing operations of $~~0.5~~0.3 million for the same period in 2011 as a result of:

Revenueincreased due tothe commencement of commercial operation of our new 200 MWmegawatt generating facility in Pueblo, ~~Colorado~~Colo. on ~~January~~Jan. 1, 2012.

Operations and maintenanceincreased primarily due to the costs to operate and corporate allocations relating to our new 200 megawatt generating facility in Pueblo, Colo., which began serving customers on Jan. 1, 2012.

Depreciation and amortizationwas comparable to the same period in the prior year.The new generating facility's PPA to supply capacity and energy to Colorado Electric is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, netincreased due to interest costs for financing the Pueblo generating facility.Interest costs were capitalized during construction in the prior year.

Other (expense) income, net was comparable to the same period in the prior year.

Income tax (expense) benefit: The effective tax rate was comparable to the same period in the prior year.

Results of Operations for Power Generation for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Power Generation segment was $16.0 million for the nine months ended Sept. 30, 2012 compared to Income from continuing operations of $2.1 million for the same period in 2011 as a result of:

Revenueincreased due to the commencement of commercial operation of our new 200 megawatt generating facility in Pueblo, Colo. on Jan. 1, 2012.

Operations and maintenanceincreased primarily due to the costs to operate and corporate allocations relating to our new 200 MWmegawatt generating facility in Pueblo, ~~Colorado, which began serving customers~~Colo. on ~~January~~Jan. 1, 2012.

Depreciation and amortization ~~were consistent with~~was comparable to the same period in the prior year. The new generating facility's PPA to supply capacity and energy to Colorado Electric is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, netincreased due to interest costs for financing the ~~decrease~~Pueblo generating facility. Interest costs were capitalized during construction in ~~capitalized interest as a result of completing construction on our new generating facility in Pueblo, Colorado.~~the prior year.

Other (expense) income, net ~~was comparable to the same period~~in 2011 included a gain on sale of ownership interest in the ~~prior year.~~partnership that held the Idaho generating facilities.

Income tax (expense) benefit: The effective tax rate ~~was comparable to the same period~~ in ~~the prior year.~~

~~Results of Operations for Power Generation for the~~ ~~Six~~ ~~Months Ended~~ ~~June 30,~~ 2012 ~~Compared to~~ ~~Six~~ ~~Months Ended~~ ~~June 30, 2011~~: ~~Income from continuing operations for the Power Generation segment was~~ ~~$10.8 million~~ ~~for the~~ ~~six~~ ~~months ended~~ ~~June 30, 2012~~ ~~compared to Income from continuing operations of~~ ~~$1.7 million~~ ~~for the same period in~~ ~~2011~~ ~~as a result of:~~

~~Revenue~~ ~~increased due to commencement of commercial operation of our new 200 MW generating facility in Pueblo, Colorado on January 1, 2012.~~

~~Operations and maintenance~~ ~~increased primarily due to the costs to operate and corporate allocations relating to our new 200 MW generating facility in Pueblo, Colorado on January 1, 2012.~~

~~Depreciation and amortization~~ were consistent with the same period in the prior year. The new generating facility's PPA to supply capacity and energy to Colorado Electric is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.

~~Interest expense, net~~ ~~increased due to the decrease in capitalized interest as a result of the completion of construction of our generating facility in Pueblo, Colorado.~~

~~Other (expense) income, net~~ ~~in 2011 included earnings from our partnership investment in certain Idaho generating facilities and a gain on sale of our ownership interest in the partnership which did not reoccur in 2012.~~

~~Income tax (expense) benefit: The effective tax rate~~ was impacted by a favorable state tax true-up that included certain tax credits. Such credits are the result of meeting certain applicable state requirements including the ability to utilize these tax credits. The ~~incentives~~tax credits pertain to qualified plant expenditures related to capital investment and research and development.

Coal Mining


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended Sept. 30,								Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance			2012		2011			Variance			2012			2011			Variance
	(in thousands)																		(in thousands)
Revenue	$	13,127		$	15,540		$	(2,413	)	$	28,116		$	31,035		$	(2,919	)	$	14,675	$	17,835		$	(3,160	)	$	42,791		$	48,870		$	(6,079	)

Operations and maintenance	9,883			13,011			(3,128		)	21,361			27,583			(6,222		)	10,780		14,171			(3,391		)	32,141			41,754			(9,613		)
Depreciation, depletion and amortization	2,955			4,595			(1,640		)	6,651			9,213			(2,562		)	2,922		5,151			(2,229		)	9,573			14,364			(4,791		)
Total operating expenses	12,838			17,606			(4,768		)	28,012			36,796			(8,784		)	13,702		19,322			(5,620		)	41,714			56,118			(14,404		)

Operating income (loss)	289			(2,066		)	2,355			104			(5,761		)	5,865			973		(1,487		)	2,460			1,077			(7,248		)	8,325

Interest income, net	403			936			(533		)	1,158			1,896			(738		)	1		972			(971		)	1,159			2,868			(1,709		)
Other income	646			549			97			1,527			1,118			409			525		532			(7		)	2,052			1,650			402
Income tax benefit (expense)	(104		)	200			(304		)	(555		)	1,068			(1,623		)	191		538			(347		)	(364		)	1,606			(1,970		)

Income (loss) from continuing operations	$	1,234		$	(381	)	$	1,615		$	2,234		$	(1,679	)	$	3,913		$	1,690	$	555		$	1,135		$	3,924		$	(1,124	)	$	5,048

The following table provides certain operating statistics for our Coal Mining segment (in thousands):


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011	2012	2011	2012	2011
Tons of coal sold	983	1,235	2,086	2,605	1,105	1,550	3,191	4,155
Cubic yards of overburden moved	2,280	2,933	4,922	6,388	1,827	3,873	6,749	10,261

Results of Operations for Coal Mining for the Three Months Ended ~~June~~Sept. 30, 2012 Compared to Three Months Ended ~~June~~Sept. 30, 2011: Income from continuing operations for the Coal Mining segment was $~~1.2~~1.7 million for the three months ended ~~June~~Sept. 30, 2012 compared to ~~Loss~~Income from continuing operations of $~~0.4~~0.6 million for the same period in 2011, as a result of:

Revenuedecreased primarily due to a ~~20%~~29 percent decrease in tons ~~sold. This decrease was due to~~soldas a result of the December 2011 expiration of an unprofitable ~~long-term~~ train load-out contract which represented approximately ~~29%~~29 percent of our tons sold in ~~2011. Additionally, tons sold decreased due to a planned and unplanned outage at Neil Simpson II. These decreases were~~ 2011,partially offset by ~~increased volumes sold to the Wyodak plant that experienced~~ an ~~outage~~increase in ~~2011. Approximately 50%~~average sales price as a result of price escalators and adjustments in certain of our sales contracts. Approximately 50 percent of our current coal production ~~was~~is sold under contracts that include price adjustments based on actual mining ~~cost increases.~~costs.

Operations and maintenancedecreased primarily due to ~~a 20% reduction in tons sold~~reduced overburden moved related to ~~an unprofitable train-load out contract that expired at the end of 2011 reducing overburden moved,~~lower sales volumes and mining ~~efficiencies.~~efficiencies, including decreased fuel costs and headcount reductions as a result of the revised mine plan and termination of the train load-out contract at Dec. 31, 2011.

Depreciation, depletion and amortizationdecreased primarily due to lower equipment usage and lower depreciation of mine reclamation asset retirement costs.

Interest income, netdecreased primarily due to a decrease in inter-company notes receivable upon payment of a dividend to our parent.

Other income was comparable to the same period in the prior year.

Income tax benefit (expense): The change in the effective tax rate was primarily due to the impact of percentage ~~depletion.~~depletion and a tax return true-up.

Results of Operations for Coal Mining for the ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2011: Income from continuing operations for the Coal Mining segment was $~~2.2~~3.9 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 compared to Loss from continuing operations of $~~1.7~~1.1 million for the same period in 2011, as a result of:

Revenuedecreased primarily due to a ~~20%~~23 percent decrease in tons sold. This decrease was due to the December 2011 expiration of an unprofitable ~~long-term~~ train load-out contract, ~~.which~~which represented approximately ~~29%~~29 percent of our tons sold in 2011. Additionally, tons sold decreased due to a planned and unplanned ~~outage~~outages at Neil Simpson II and a planned and extended outage at the Wygen II ~~facility. These decreases were~~facility partially offset by increased ~~volumes~~tons sold to the Wyodak plant that experienced an outage in 2011. Approximately ~~50%~~50 percent of our current coal production ~~was~~is sold under contracts that include price adjustments based on actual mining cost increases.

Operations and maintenancedecreased primarily due to ~~a 20% reduction in~~reduced overburden moved related to lower tons sold ~~related to an unprofitable train-load out contract that expired at the end of 2011, reducing overburden moved,~~ and mining ~~efficiencies.~~efficiencies, including decreased fuel costs and headcount reductions resulting from the revised mine plan and termination of the train load-out contract at Dec. 31, 2011.

Depreciation, depletion and amortizationdecreased primarily due to lower equipment usage and lower depreciation of mine reclamation asset retirement costs.

Interest income, netdecreased primarily due to a decrease in inter-company notes receivable upon payment of a dividend to our parent.

Other income was comparable to the same period in the prior year.

Income tax benefit (expense): The change in the effective tax rate was primarily due to the impact of percentage ~~depletion.~~depletion, a tax return true-up and the impact in 2011 of a favorable research and development credit.

5354

Oil and Gas


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended Sept. 30,									Nine Months Ended Sept. 30,
	2012			2011			Variance			2012			2011			Variance			2012			2011			Variance			2012			2011			Variance
	(in thousands)																		(in thousands)
Revenue	$	20,621		$	18,838		$	1,783		$	42,266		$	36,744		$	5,522		$	24,728		$	19,163		$	5,565		$	66,994		$	55,907		$	11,087

Operations and maintenance	10,338			10,187			151			21,172			20,754			418			12,118			9,573			2,545			33,290			30,327			2,963
Gain on sale of operating assets																			(27,285		)	—			(27,285		)	(27,285		)	—			(27,285		)
Depreciation, depletion and amortization	13,033			7,602			5,431			22,356			14,923			7,433			12,457			7,714			4,743			34,813			22,637			12,176
Impairment of long-lived assets	26,868			—			26,868			26,868			—			26,868			—			—			—			26,868			—			26,868
Total operating expenses	50,239			17,789			32,450			70,396			35,677			34,719			(2,710		)	17,287			(19,997		)	67,686			52,964			14,722

Operating income (loss)	(29,618		)	1,049			(30,667		)	(28,130		)	1,067			(29,197		)	27,438			1,876			25,562			(692		)	2,943			(3,635		)

Interest expense	(1,165		)	(1,389		)	224			(2,770		)	(2,772		)	2
Interest expense, net																			(1,112		)	(1,460		)	348			(3,882		)	(4,232		)	350
Other income (expense), net	87			88			(1		)	116			(97		)	213			77			54			23			193			(43		)	236
Income tax benefit (expense)	11,075			173			10,902			11,176			1,008			10,168			(9,014		)	(229		)	(8,785		)	2,162			779			1,383

Income (loss) from continuing operations	$	(19,621	)	$	(79	)	$	(19,542	)	$	(19,608	)	$	(794	)	$	(18,814	)	$	17,389		$	241		$	17,148		$	(2,219	)	$	(553	)	$	(1,666	)

The following tables provide certain operating statistics for our Oil and Gas segment:


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended Sept. 30,		Nine Months Ended Sept. 30,
	2012	2011	2012	2011	2012	2011	2012	2011
Production:
Bbls of oil sold	155,362	100,901	300,839	204,451	184,423	98,950	485,262	303,401
Mcf of natural gas sold	2,451,811	2,106,121	4,840,286	4,117,288	2,278,801	2,147,172	7,119,087	6,264,460
Gallons of NGL sold	837,626	988,819	1,652,211	1,853,259	1,099,198	993,752	2,751,409	2,847,011
Mcf equivalent sales	3,503,644	2,852,787	6,881,350	5,608,745	3,542,367	2,882,837	10,423,717	8,491,582


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
	2012		2011		2012		2011		2012		2011		2012		2011
Average price received: ^(a)
Oil/Bbl	$	76.71	$	79.53	$	77.33	$	73.10	$	88.69	$	82.76	$	81.65	$	76.25
Gas/Mcf	$	3.12	$	4.29	$	3.36	$	4.47	$	3.07	$	4.24	$	3.27	$	4.39
NGL/gallon	$	0.74	$	1.01	$	0.84	$	0.97	$	0.65	$	0.88	$	0.77	$	0.94

Depletion expense/Mcfe	$	3.47	$	2.40	$	2.98	$	2.38	$	3.26	$	2.38	$	3.07	$	2.38

____________


(a)	Net of hedge settlement gains and ~~losses~~losses.

5455

The following is a summary of certain average operating expenses per Mcfe:


	Three Months Ended June 30, 2012								Three Months Ended June 30, 2011									Three Months Ended Sept. 30, 2012								Three Months Ended Sept. 30, 2011
Producing Basin	LOE		Gathering, Compression and Processing		Production Taxes		Total		LOE		Gathering, Compression and Processing		Production Taxes			Total		LOE		Gathering, Compression and Processing		Production Taxes		Total		LOE		Gathering, Compression and Processing		Production Taxes		Total
San Juan	$	1.06	$	0.19	$	0.23	$	1.48	$	1.21	$	0.35	$	0.55		$	2.11	$	1.42	$	0.33	$	0.46	$	2.21	$	1.06	$	0.25	$	0.52	$	1.83
Piceance	0.52		0.32		0.10		0.94		0.83		0.76		(0.36		)	1.23
Piceance *																		0.13		0.35		0.14		0.62		0.80		0.63		0.28		1.71
Powder River	1.60		—		1.08		2.68		1.42		—		1.38			2.80		1.00		—		1.11		2.11		1.20		—		1.26		2.46
Williston	0.53		—		1.29		1.82		0.50		—		1.48			1.98		0.70		—		1.48		2.18		1.01		—		1.74		2.75
All other properties	1.59		—		0.18		1.77		1.23		—		0.04			1.27		1.48		—		0.25		1.73		0.62		—		0.38		1.00
Total weighted average	$	1.00	$	0.13	$	0.54	$	1.67	$	1.15	$	0.23	$	0.63		$	2.01	$	0.99	$	0.17	$	0.74	$	1.90	$	0.99	$	0.18	$	0.72	$	1.89


	Six Months Ended June 30, 2012								Six Months Ended June 30, 2011									Nine Months Ended Sept. 30, 2012								Nine Months Ended Sept. 30, 2011
Producing Basin	LOE		Gathering, Compression and Processing		Production Taxes		Total		LOE		Gathering, Compression and Processing		Production Taxes			Total		LOE		Gathering, Compression and Processing		Production Taxes		Total		LOE		Gathering, Compression and Processing		Production Taxes		Total
San Juan	$	1.02	$	0.25	$	0.29	$	1.56	$	1.23	$	0.41	$	0.55		$	2.19	$	1.14	$	0.28	$	0.34	$	1.76	$	1.17	$	0.35	$	0.54	$	2.06
Piceance	0.23		0.41		0.13		0.77		0.76		0.78		(0.06		)	1.48
Piceance *																		0.20		0.39		0.13		0.72		0.77		0.73		0.06		1.56
Powder River	1.49		—		1.20		2.69		1.36		—		1.33			2.69		1.33		—		1.17		2.50		1.31		—		1.31		2.62
Williston	0.61		—		1.27		1.88		0.38		—		1.49			1.87		0.65		—		1.35		2.00		0.59		—		1.58		2.17
All other properties	1.63		—		0.13		1.76		1.43		—		0.21			1.64		1.58		—		0.17		1.75		1.17		—		0.26		1.43
Total weighted average	$	0.94	$	0.17	$	0.57	$	1.68	$	1.17	$	0.25	$	0.68		$	2.10	$	0.96	$	0.17	$	0.63	$	1.76	$	1.11	$	0.23	$	0.70	$	2.04

___________

* Decrease in LOE is primarily due to increased volumes from two additional wells that commenced production in December 2011.

Results of Operations for Oil and Gas for the Three Months Ended ~~June~~Sept. 30, 2012 Compared to Three Months Ended ~~June~~Sept. 30, 2011: ~~Loss~~Income from continuing operations for the Oil and Gas segment was $~~19.6~~17.4 million for the three months ended ~~June~~Sept. 30, 2012 compared to ~~Loss~~Income from continuing operations of $~~0.1~~0.2 million for the same period in 2011 as a result of:

Revenueincreased primarily due to ~~increased production. A 54%~~an 86 percent increase in crude oil sales, due primarily to activities from new wells in ~~the company’s ongoing~~our drilling program in the Bakken shale formation ~~was partially offset by~~and a ~~4% decrease~~7 percent increase in the average price received for crude oil sold.A ~~14%~~6 percent increase in natural gas and NGL volumes, due primarily to the ~~completion of~~production from three Mancos formation test wells in the San Juan and Piceance Basins, was partially offset by a ~~27%~~28 percent decrease in the average price received for natural gas.

Operations and maintenance costs ~~were comparable~~increased primarily due to ~~the same period in the prior year.~~higher costs from non-operated wells and higher compensation and benefit costs.

Depreciation, depletion and amortizationincreased ~~increase~~ primarily ~~reflects a $3.4 million~~due to the year-to-date impact offrom adjusting ~~our~~ expected 2012 reserve additions due to the deferred drilling activities in the San Juan Mancos formation, as well as higher cost reserves associated with our Bakken ~~activities.~~activities and a higher depletion rate per Mcfe on higher volumes.

~~Impairment~~Gain on sale of ~~long-lived~~operating assetsrepresents ~~a write-down in~~ the ~~value~~gain on the sale of our ~~natural~~Williston Basin assets. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and ~~crude oil properties driven by low natural gas prices.~~proved reserves. The ~~write-down reflected a 12 month average NYMEX price~~remainder of ~~$3.15~~ ~~per Mcf, adjusted to~~ ~~$2.66~~ ~~per Mcf at~~ the ~~wellhead, for natural gas,~~sales amount, not recognized as gain, reduces the full-cost pool and ~~$95.67~~ ~~per barrel, adjusted to~~ ~~$85.36~~ ~~per barrel at~~should significantly decrease the ~~wellhead, for crude oil.~~future depreciation, depletion and amortization rate.

Interest expense, net was comparable to the same period in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax (expense) benefit: For 2012, the benefit generated by percentage depletion had a significantly reduced impact on the effective tax rate compared to the same period in 2011.

Results of Operations for Oil and Gas for the ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2011: Loss from continuing operations for the Oil and Gas segment was $~~19.6~~2.2 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 compared to Loss from continuing operations of $~~0.8~~0.6 million for the same period in 2011 as a result of:

Revenueincreased primarily due to a ~~47%~~60 percent increase in crude oil volume sold along with a 6%7 percent increase in the average price received for crude oil sales. Crude oil production increases reflect volumes from new wells in our ~~ongoing~~ drilling program in the Bakken shale formation. A ~~16%~~13 percent increase in natural gas and NGL volumes, due primarily to the ~~completion of~~production from three Mancos formation test wells in the San Juan and Piceance Basins, was partially offset by a ~~25%~~26 percent decrease in average price received for natural gas.

Operations and maintenance costs ~~were comparable~~increased primarily due to ~~the same period in the prior year.~~higher costs from non-operated wells and higher compensation and benefit costs.

Depreciation, depletion and amortizationincreased primarily due to the year-to-date impact from adjusting our expected 2012 reserve additions due to the deferred drilling activities in the San Juan Mancos formation, as well as higher cost reserves associated with our Bakken activities and a higher depletion rate per ~~Mcf~~Mcfe on higher volumes.

Gain on sale of operating assets represents the gain on the sale of our Williston Basin assets. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The ~~increased~~remainder of the sale amount not recognized as gain, reduced the full-cost pool and will decrease our depreciation, depletion ~~rate is primarily driven by higher capital costs per Mcfe for our Bakken oil drilling program.~~and amortization rate.

Impairment of long-lived assets represents a write-down in the value of our natural gas and crude oil properties driven by low natural gas prices. The write-down reflected a ~~12 month~~12-month average NYMEX price of $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead, for natural gas, and $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead, for crude oil.

Interest expense, net was comparable to the same period in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax (expense) benefit: The effective tax rate for the ~~six~~nine months ended ~~June~~Sept. 30, 2011 was positively impacted by a research and development credit and the benefit generated by percentage depletion had a significantly lesser impact on the effective tax rate in 2012 compared to the same period in 2011.

Corporate

Results of Operations for Corporate for the Three Months Ended ~~June~~Sept. 30, 2012 Compared to Three Months Ended ~~June~~Sept. 30, 2011: Loss from continuing operations for Corporate was $~~13.2~~4.2 million for the three months ended ~~June~~Sept. 30, 2012 compared to Loss from continuing operations of $~~9.4~~28.3 million for the three months ended ~~June~~Sept. 30, 2011. The ~~increased~~ loss for the quarter ended Sept. 30, 2012 was primarily due to an incentive compensation accrual recorded as a result of the Williston Basin asset sale offset by an unrealized, non-cash mark-to-market gain on certain interest rate swaps of approximately $0.6 million. The loss for the quarter ended Sept. 30, 2011 was primarily due to a $38.2 million unrealized, non-cash mark-to-market loss on ~~certain interest rate swaps for the quarter ended~~ ~~June 30, 2012~~ ~~of approximately~~ ~~$15.6 million~~ ~~compared to a~~ ~~$7.8 million~~ ~~unrealized, mark-to-market non-cash loss on~~ these interest rate ~~swaps in the prior year.~~swaps.

Costs of $0.5 million after-tax previously allocated to our Energy Marketing segment were reclassified to the Corporate segment consistent with accounting for discontinued operations for the three months ended Sept. 30, 2011. There were no allocated costs related to our Energy Marketing segment for the three months ended ~~June~~Sept. 30, 2012 ~~which could not be included in discontinued operations compared to after-tax costs of~~ ~~$0.5 million~~ ~~for the three months ended~~ ~~June 30, 2011~~.

Results of Operations for Corporate for the ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2011: Loss from continuing operations for Corporate was $~~9.8~~13.9 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 compared to Loss from continuing operations of $~~9.0~~37.3 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2011. The loss for the nine months ended Sept. 30, 2012 was primarily due to an incentive compensation accrual recorded as a result of the Williston Basin asset sale and an unrealized, non-cash mark-to-market loss on certain interest rate swaps ~~for the quarter ended~~ ~~June 30, 2012~~of approximately $~~3.5~~2.9 million ~~compared~~. The loss for the nine months ended Sept. 30, 2011 was primarily due to a $~~2.4~~40.6 million unrealized, non-cash mark-to-market ~~non-cash~~ loss on these interest rate ~~swaps in the prior year.~~swaps.

~~Corporate was allocated after-tax costs~~Costs of $1.6 million ~~related~~after-tax previously allocated to ~~on-going costs associated with~~ our Energy Marketing segment were reclassified to the Corporate segment consistent with accounting for discontinued operations for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 ~~which could not be included in discontinued operations~~ compared to after-tax costs of $~~1.0~~1.5 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2011.

Discontinued Operations

Results of Operations for Discontinued Operations for the Three and ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2012, Compared to Three and ~~Six~~Nine Months Ended ~~June~~Sept. 30, 2011:

~~For~~Loss from discontinued operations for the three months ended Sept. 30, 2012 was $0.2 million relating to additional operating costs to discontinue the operations and ~~six~~$6.8 million for the nine months ended ~~June~~Sept. 30, 2012, ~~we recorded~~including an after-tax loss ~~from discontinued operations~~on sale of $~~1.2~~2.4 million~~, including~~ and transaction related costs, net of tax of ~~$0.3 million~~ ~~and~~ ~~$6.6 million, including transaction related costs, net of tax~~benefit of $2.5 million~~, respectively.~~.

Pursuant to the provisions of the Stock Purchase Agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $~~1.3~~1.4 million, which is accrued ~~for~~ in the loss from discontinued operations for the ~~three~~nine months ended ~~June~~Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution ~~would~~will occur through the dispute resolution provision of the Stock Purchase Agreement.

Critical Accounting Policies

~~There~~Except as noted below, there have been no material changes in our critical accounting policies from those reported in our 2011 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting policies, see Part II, Item 7 of our 2011 Annual Report on Form 10-K.

Full-Cost Method of Accounting for Oil and Gas Activities

As previously disclosed in our 2011 Annual Report filed in Form 10-K, we utilize the full-cost method of accounting for our oil and gas activities in accordance with SEC Rule 4-10 of Regulation S-X (Rule 4-10). Under the full-cost method, sales of oil and gas properties generally are recorded as an adjustment to capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between the capitalized costs and proved oil and gas reserves. The Company's Sept. 27, 2012 sale of oil and gas properties in the Williston Basin of North Dakota was significant as defined by Rule 4-10, and accordingly a $27.3 million pre-tax gain on sale was recorded. Total net cash proceeds from the sale were approximately $227 million.

Under the guidance of Rule 4-10, if a gain or loss is recognized on such a sale, total capitalized costs shall be allocated between the reserves sold and the reserves retained on the same basis used to compute amortization, unless there are substantial economic differences between the properties sold and those retained, in which case capitalized costs shall be allocated on the basis of the relative fair value of the properties in the cost center. Because of the substantial differences between the crude oil properties we sold and those properties retained, which were predominantly natural gas, we allocated based on relative fair values.

If a different method of allocating the capitalized costs was chosen, the gain recorded on our transaction could vary substantially. For example, if the allocation was made on the same basis used to compute amortization as noted within Rule 4-10 and we utilized the ratio of proven reserve quantities from the properties sold compared to total proven reserve quantities in our cost center, we would have recorded a gain on sale of approximately $160 million. Because of the value associated with the undeveloped acreage sold, we did not believe this was an appropriate methodology for allocation.

Any change in the gain recorded would impact the amount of adjustment to our capitalized costs therefore impacting our future depletion expense recorded within our financial statements.

Liquidity and Capital Resources

All amounts are presented on a pre-tax basis unless otherwise indicated.

Cash Flow Activities

The following table summarizes our cash flows for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 and 2011 (in thousands):


Cash provided by (used in):	2012			2011			Increase (Decrease)			2012			2011			Increase (Decrease)
Operating activities	$	176,699		$	182,017		$	(5,318	)	$	269,667		$	206,526		$	63,141
Investing activities	$	(36,699	)	$	(225,064	)	$	188,365		$	98,306		$	(326,862	)	$	425,168
Financing activities	$	(158,658	)	$	98,682		$	(257,340	)	$	(179,549	)	$	162,676		$	(342,225	)

Year-to-Date 2012 Compared to Year-to-Date 2011

Operating Activities

Net cash provided by operating activities was $~~5.3~~63.1 million ~~lower~~higher for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 than for the same period in 2011 primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $~~23.4~~35.0 millionhigher for the ~~six~~nine months ended ~~June~~Sept. 30, 2012 than for the same period the prior year.

Net inflows from operating assets and liabilities were $~~24.0~~38.1 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2012, ~~a decrease~~an increase of $~~7.4~~33.5 million from the same period in the prior year. In addition to other normal working capital changes, the ~~decrease~~increase primarily related to decreased gas volumes in inventory ~~due to warmer weather~~ and to lower natural gas prices.

Cash contributions to the defined benefit pension plan were $25.0 million in 2012 compared to ~~$0.6~~$11.0 million in 2011.

Investing Activities

Net cash ~~used~~provided by investing activities was $~~188.4~~98.3 million ~~lower for the~~in ~~six months ended June 30,~~ 2012 ~~than in the same period~~compared to net cash used by investing activities of $326.9 million in 2011 ~~reflecting~~for a variance of $425.2 million. The variance was driven by cash proceeds ~~received~~from assets sold during 2012, including $243.3 million from the sale of ~~Enserco~~85 percent of ~~$108.8~~our Williston Basin assets by our Oil and Gas segment, $25 million from the sale of a 50 percent ownership interest in the Busch Ranch Wind project, and$108.8 million for the sale of Enserco. Additionally, in 2012 we had reduced capital expenditures of $~~74.6~~65.1 million due to the completion of construction of ~~180 MW of natural gas-fired electric~~our Pueblo generation ~~at Colorado Electric~~facility and ~~200 MW of natural gas-fired electric generation at Black Hills Colorado IPP in 2011.~~$21.8 million note receivable for oil and gas properties.

Financing Activities

Net cash used in financing activities in 2012was $~~257.3~~179.5 million ~~higher for the~~compared to net cash ~~six months ended June 30, 2012~~provided by ~~than in the same period~~financing activities in 2011 ~~primarily due to~~of $162.7 million for a variance of $342.2 million. The variance was driven by applying the proceeds from the sale of Enserco to pay down short-term borrowings on the Revolving Credit Facility of approximately $110 million while in the same period in the prior year we increased borrowings $210 million primarily to finance our construction program in Pueblo, ~~Colorado.~~Colo. Cash dividends on common stock of $~~32.6~~48.9 million were paid in 2012 compared to cash dividends paid of $~~29.5~~43.2 million in 2011. In addition, in May 2012 Black Hills Power repaid its Pollution Control Revenue Bonds for $6.5 million.

Dividends

Dividends paid on our common stock totaled $~~32.6~~48.9 million for the ~~six~~nine months ended ~~June~~Sept. 30, 2012, or ~~$0.74~~$1.11 per share. On ~~July 25,~~Oct. 30, 2012, our ~~Board~~board of ~~Directors~~directors declared a quarterly dividend of $0.37 per share payable ~~September~~Dec. 1, 2012, which is equivalent to an annual dividend rate of $1.48 per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our ~~credit facility~~Revolving Credit Facility and our future business prospects.

Financing Transactions and Short-Term Liquidity

Our principal sources of short-term liquidity are our Revolving Credit Facility and cash provided by operations. In addition to availability under our Revolving Credit Facility described below, as of ~~June~~Sept. 30, 2012, we had approximately $40247 million of unrestricted ~~cash. The~~cash included in Cash and cash equivalents on our Condensed Consolidated Balance Sheet resulting, in part, from the September 2012 sale of our Williston Basin assets. A portion of this cash was used on Oct. 31, 2012 to redeem our $225 million senior unsecured notes originally due in May 2013. In the first quarter of 2012, the net cash proceeds from the Enserco sale were utilized to reduce short-term debt on the Revolving Credit Facility by approximately $110 ~~million with the remainder included in our~~ ~~June 30, 2012~~ ~~cash balance.~~million.

Revolving Credit Facility

Our $500 million Revolving Credit Facility expiring ~~February~~Feb. 1, 2017 can be used for the issuance of letters of credit, to fund working capital needs and for general 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 ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were ~~0.50%~~0.50 percent, ~~1.50%~~1.50 percent and ~~1.50%~~1.50 percent, respectively. The facility contains a commitment fee that ~~will be~~is charged on the unused amount of the ~~Facility.~~facility. Based upon current credit ratings, the fee is ~~0.25%~~0.25 percent. The facility contains an accordion feature ~~which~~that allows us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million.

At ~~June~~Sept. 30, 2012, we had borrowings of $75 million and letters of credit outstanding of $36 million on our Revolving Credit Facility. Available capacity remaining was approximately $389 million at ~~June~~Sept. 30, 2012.

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions ~~maintenance of certain financial covenants~~ and a recourse leverage ratio not to exceed 0.65 to 1.00. At ~~June~~Sept. 30, 2012, our recourse leverage ratio as calculated under our Revolving Credit Facility was approximately 0.56 to 1.0. At Sept. 30, 2012, our long-term debt ratio was ~~46.6%~~46.2 percent, and our total debt leverage ratio (long-term debt and short-term debt) was ~~55.6%, and our recourse leverage ratio was approximately~~ ~~56.8%~~55.2 percent.

In addition to covenant violations, an event of default under the Revolving Credit Facility may be triggered by other events, such as a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, other debt obligations of $35 million or more. Subject to applicable cure periods (none of which apply to a failure to timely pay indebtedness), an event of default would permit the lenders to restrict our ability to further access the credit facility for loans orand new letters of credit, and could require both the immediate repayment of any outstanding principal and interest and the cash collateralization of outstanding letter of credit obligations.

We were in compliance with the covenants and ~~are~~were not in default of the terms of the Revolving Credit Facility as of ~~June~~Sept. 30, 2012.

Short-Term Corporate Term ~~Loans~~Loan

In June 2012, we extended our one-year $150 million unsecured, single draw term loan for one year. The cost of borrowing under the extended loan now due on June 24, 2013 is based on a spread of ~~1.10%~~1.10 percent over LIBOR (~~1.35%~~1.35 percent at ~~June~~Sept. 30, 2012). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of ~~June~~Sept. 30, 2012.

Long-term Corporate Term Loan

In December 2010, we entered into a one-year $100 million term loan with J.P. Morgan and Union Bank due in December 2011. On ~~September~~Sept. 30, 2011, we extended that term loan ~~for two years~~ under the existing terms to ~~September~~Sept. 30, 2013. The cost of borrowing under this term loan is based on a spread of ~~1.375%~~1.375 percent over LIBOR (~~1.62%~~1.63 percent at ~~June~~Sept. 30, 2012). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of ~~June~~Sept. 30, 2012.

Repayment of Long-term Debt

On Oct. 31, 2012, we redeemed our 6.5 percent senior unsecured notes originally due to mature on May 15, 2013 for $225.0 million plus interest and a one-time after-tax make whole-provision payment of $4.6 million.

On May 15, 2012, Black Hills Power repaid its ~~4.8%~~4.8 percent Pollution Control ~~Refund~~ Revenue Bonds in full for $6.5 million including principal and interest. These bonds were originally due to mature on ~~October~~Oct. 1, 2014.

Dividend Restrictions

Certain of our debt agreements impose restrictions on our ability to pay dividends. Any determination to pay dividends in the future will be at the discretion of our Board of Directors and will depend upon our results of operations, financial condition, restrictions imposed by applicable law and our financing agreements and other factors that our Board of Directors deems relevant.

As a result of certain statutory limitations or regulatory or financing agreements, we could have restrictions on the amount of distributions allowed to be made by our subsidiaries.

Our utility subsidiaries are generally limited by state regulatory authorities in the amount of dividends allowed ~~by state regulatory authorities~~that they can pay the utility holding company and also may have further restrictions under the Federal Power Act. As of ~~June~~Sept. 30, 2012, the restricted net assets at our Electric and Gas Utilities were approximately $~~215.1~~227.2 million.

As required by the covenants in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted equity of at least $100.0 million. In addition, Black Hills Wyoming holds $~~4.8~~7.3 million of restricted cash associated with the project financing requirements.

Future Financing Plans

We have substantial future capital expenditures planned, ~~in 2012,~~ which primarily include construction of additional utility generation to serve Black Hills Power and Cheyenne Light customers ~~wind generation to meet renewable standards in Colorado, environmental upgrades~~ and ~~replacements to existing generation to~~ meet governmental pollution control mandates and potential capital deployment in oil and gas drilling to prove-up reserves. Our capital requirements are expected to be financed through a combination of available cash, operating cash flows, borrowings on our Revolving Credit Facility, term loans and long-term financings and other debt or equity issuances.

~~We have debt due~~After the repayment of our $225 million ~~and $250 million~~senior unsecured 6.5 percent notes originally due to mature in 2013 ~~and 2014, respectively. In addition,~~discussed above, we have term loans of $250 million expiring in ~~2013.~~2013 and debt due of $250 million in 2014. With these upcoming financing requirements, we continue to evaluate various financing options that include senior unsecured notes, first mortgage bonds, term loans and project financing ~~opportunities and issuance. We anticipate executing financing transactions ahead of these maturities by late 2012 or early 2013 depending on market conditions.~~opportunities.

We intend to maintain a consolidated debt-to-capitalization level in the range of ~~50%~~50 percent to ~~55%;~~55 percent; however, due to capital projects, we may exceed this level on a temporary basis. We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and our maintenance capital requirements.

Hedges and Derivatives

Interest Rate Swaps

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations.

We have interest rate swaps with a notional amount of $250 million that are not designated as hedge instruments. Accordingly, mark-to-market changes in value on these swaps are recorded within the Condensed Consolidated Statements of ~~Income and Comprehensive~~ Income. For the three and ~~six~~nine months ended ~~June~~Sept. 30, 2012, respectively, we recorded $~~15.6 million~~ ~~and~~ ~~$3.5~~0.6 million pre-tax unrealized non-cash mark-to-market gain and $2.9 million pre-tax unrealized non-cash ~~losses~~mark-to-market loss on the swaps. The mark-to-market value on these swaps was a liability of $~~93.3~~95.6 million at ~~June~~Sept. 30, 2012. Subsequent mark-to-market adjustments could have a significant impact on our results of operations. A one basis point move in the interest rate curves over the term of the swaps would have a pre-tax impact of approximately $~~0.4~~0.3 million. These swaps are for terms of ~~6.5~~6.25 and ~~16.5~~16.25 years and have ~~amended~~ early termination dates ranging from ~~December~~Dec. 15, 2012 to ~~December~~Dec. 16, 2013. We anticipate extending these agreements upon their early termination dates and have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly as they relate to our planned capital requirements to build gas-fired power generation facilities to serve our Black Hills Power and Cheyenne Light customers, and because of our upcoming holding company debt maturities, which are $225 million and $250 million in 2013 and 2014, respectively.needs. Alternatively, we may choose to cash settle these swaps at fair value prior to the early termination dates, or unless these dates are extended we will cash settle these swaps for an amount equal to their fair values on the termination dates.

In addition, we have $150 million notional amount floating-to-fixed interest rate swaps with a maximum remaining term of ~~4.5~~4.3 years. These swaps have been designated as cash flow hedges, and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $25.7 million at ~~June~~Sept. 30, 2012.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2011 Annual Report on Form 10-K filed with the SEC.

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms including collateral requirements. As of ~~June~~Sept. 30, 2012, our senior unsecured credit ratings, as assessed by the three major credit rating agencies, were as follows:



Rating Agency	Rating	Outlook

Fitch	BBB-	Stable
Moody's^(a)	Baa3	Stable
S&P *^{(a) (b)}	BBB-	Stable

_______

*(a) In October 2012, both Moody's and S&P upgraded our outlook from Stable to Positive.

(b) In July 2012, S&P published its updated credit review, leaving ~~unchanged~~ our senior unsecured credit rating of BBB- and upgraded our risk profile from strong to ~~excellent from strong.~~excellent.

In addition, as of ~~June~~Sept. 30, 2012, Black Hills Power's first mortgage bonds were rated as follows:



Rating Agency	Rating	Outlook
Fitch	A-	Stable
Moody's^(a)	A3	Stable
S&P^(a)	BBB+	Stable

_______

(a) In October 2012, both Moody's and S&P upgraded our outlook from Stable to Positive.

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Capital Requirements

Actual and forecasted capital requirements for maintenance capital and development capital are as follows (in thousands):


	Expenditures for the		Total		Total		Total		Expenditures for the		Total		Total		Total
	Six Months Ended June 30, 2012		2012 Planned Expenditures		2013 Planned Expenditures		2014 Planned Expenditures		Nine Months Ended Sept. 30, 2012		2012 Planned Expenditures		2013 Planned Expenditures		2014 Planned Expenditures
Utilities:
Electric Utilities ⁽¹⁾	$	83,077	$	179,100	$	279,500	$	187,000
Electric Utilities ^{(1) (2)}									$	119,668	$	163,500	$	285,500	$	216,000
Gas Utilities	17,880		57,700		54,700		55,800		31,982		52,000		56,000		57,600
Non-regulated Energy:
Power Generation	5,704		7,300		4,900		6,700		5,122		7,400		4,200		6,800
Coal Mining	8,227		14,600		7,200		10,800		10,806		18,850		5,100		6,000
Oil and Gas ⁽²⁾⁽³⁾	43,031		86,300		114,600		113,100		88,223		97,200		98,300		84,300
Corporate	5,562		10,300		11,800		4,700		7,456		10,300		11,800		4,700
	$	163,481	$	355,300	$	472,700	$	378,100	$	263,257	$	349,250	$	460,900	$	375,400

____________

(1)

Planned expenditures in 2012 and 2013 of $22 million and $27 million, respectively, for the proposed 88 MW of gas-fired generation at Colorado Electric have been removed from the forecasted expenditures reported in our 2011 Annual Report on Form 10-K as a result of the denial of our request for a CPCN. Additionally, capital expenditures required to comply with environmental regulations at Neil Simpson II have been removed.

(2) Capital expenditures at our Oil and Gas Segment are driven by economics and may vary depending on the pricing environment for crude oil and natural gas. Forecasted expenditures for 2012, 2013 and 2014 shown above for the Oil and Gas segment have been decreased $25.9 million, $8.9 million and $13 million, respectively, from the amounts reported in our 2011 Annual Report on Form 10-K due to delaying our gas drilling program as a result of lower natural gas prices.


(2)	2012 forecasted capital expenditures include a reduction of $25 million for the sale of 50 percent of the Busch Ranch Wind project.

(3)

Capital expenditures at our Oil and Gas Segment are driven by economics and may vary depending on the pricing environment for crude oil and natural gas. Forecasted expenditures for 2012, 2013 and 2014 shown above for the Oil and Gas segment have been decreased from the amounts reported in our 2011 Annual Report on Form 10-K due to delaying our gas drilling program as a result of lower natural gas prices and the sale of the majority of our Williston Basin assets.

We continually evaluate all of our forecasted capital expenditures, and if determined prudent, we may defer some of these expenditures for a period of time. Future projects are dependent upon the availability of attractive economic opportunities, and as a result, actual expenditures may vary significantly from forecasted estimates.

Contractual Obligations

There have been no significant changes to contractual obligations or any off-balance sheet arrangements from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Guarantees

There have been no significant changes to guarantees from those previously disclosed in Note 20 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2011 Annual Report on Form 10-K filed with the SEC and those discussed in Note 2 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial statements.

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FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking information. All statements, other than statements of historical fact, included in this report that address activities, events, or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. The factors which may cause our results to vary significantly from our forward-looking statements include the risk factors described in Item 1A of our 2011 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q, and other reports that we file with the SEC from time to time, and the following:

~~The~~Our ability to successfully resolve the purchase price adjustments in question from the sale of Enserco.

We anticipate that our existing credit capacity, ~~and~~ available cash and operating cash flows will be sufficient to fund our working capital needs and our maintenance capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include:

Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and therefore may not have sufficient cash available for our peak winter needs and other working capital requirements, and our forecasted capital expenditure requirements.

Counterparties may default on their obligations to supply commodities, return collateral to us, or otherwise meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.

~~We expect to fund a portion of our forecasted capital requirements through a combination of long-term debt and equity issuances. However capital~~Capital market conditions and other economic or market uncertainties ~~related to interest rates~~beyond our control may affect our ability to raise capital on favorable terms.

We have term loans of $250 million expiring in 2013. In addition, we have senior unsecured bonds of $250 million due in 2014. We are evaluating financing options including senior notes, first mortgage bonds, term loans, project financing and equity issuance in the capital markets. Some important factors that could impact our ability to complete one or more of these financings include:

Our ability to access the bank loan and debt and equity capital markets depends on market conditions beyond our control. If the capital markets deteriorate, we may not be able to refinance our short-term debt and fund our capital projects on reasonable terms, if at all.

Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things. If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.

We expect to make approximately $~~355.3~~349.3 million, $~~472.7~~460.9 million and $~~378.1~~375.4 million of capital expenditures in 2012, 2013 and 2014, respectively. Some important factors that could cause actual expenditures to differ materially from those anticipated include:

The timing of planned generation, transmission or distribution projects for our Utilities Group is influenced by state and federal regulatory authorities and third parties. The occurrence of events that impact (favorably or unfavorably) our ability to make planned or unplanned capital expenditures have caused and could cause our forecasted capital expenditures to change.

Forecasted capital expenditures associated with our Oil and Gas segment are driven, in part, by current commodity prices, our ability to obtain permits, availability and costs of drilling and service equipment, and crews and other services, and our ability to negotiate agreements with property owners for land use. ~~Changes in crude oil and natural gas prices have caused and may cause us to change our planned capital expenditures related to our oil and gas operations.~~ An inability to obtain permits, equipment or land use rights could delay drilling efforts.

Our ability to complete our planned capital expenditures associated with our Oil and Gas segment may be impacted by our ability to obtain necessary drilling permits, and other necessary contract services and equipment such as drilling rigs, hydraulic fracturing services and other support services. Our plans may also be negatively impacted by weather conditions and existing or proposed regulations, including possible hydraulic fracturing regulations.

Our ability to complete the planning, permitting, construction, start-up and operation of power generation facilities in a cost-efficient and timely manner.

We expect contributions to our defined benefit pension plans to be approximately $0.0 million and $4.5 million for the remainder of 2012 and for 2013, respectively. Some important factors that could cause actual contributions to differ materially from anticipated amounts include:

The actual value of the plans' invested assets.

The discount rate used in determining the funding requirement.

We expect the goodwill related to our utility assets to fairly reflect the long-term value of stable, long-lived utility assets. Some important factors that could cause us to revisit the fair value of this goodwill include:

A significant and sustained deterioration of the market value of our common stock.

Negative regulatory orders, condemnation proceedings or other events that materially impact our Utilities Groups' ability to generate sufficient stable cash flow over an extended period of time.

The effects of changes in the market including significant changes in the risk-adjusted discount rate or growth rates.

The timing, volatility, and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets, including the possibility that we may be required to take future impairment charges under the SEC's full cost ceiling test for natural gas and crude oil reserves.

Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain or which could mandate or require closure of one or more of our generating units.

We have debt due of $225 million and $250 million in 2013 and 2014, respectively. In addition, we have term loans of $250 million expiring in 2013. We are evaluating financing options including senior notes, first mortgage bonds, term loans, project financing and debt and equity issuance in the capital markets. Some important factors that could impact our ability to complete one or more of these financings include:

6365


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Utilities

Our utility customers are exposed to the effect of volatile natural gas prices. We produce, purchase and distribute power in four states and purchase and distribute natural gas in five states, and we utilize natural gas as fuel at our Electric Utilities. All of our gas utilities have PGA provisions that allow them to pass the prudently-incurred cost of gas and services through to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to true-up billed amounts to match the actual natural gas cost we incurred. These adjustments are subject to periodic prudence reviews by the state utility commissions. We have ECA mechanisms in South Dakota, Colorado, Wyoming and Montana for our electric utilities that serve a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs and transmission costs are higher or lower than the energy cost built into our tariffs, the difference (or a portion thereof) is passed through to the customer.

As allowed or required by state utility commissions, we have entered into certain exchange-traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to the volatility of natural gas prices. These transactions are considered derivatives and are marked-to-market. Gains or losses, as well as option premiums on these transactions, are recorded in Regulatory assets or Regulatory liabilities. Once settled, the gains and losses are passed on to our customers through the PGA.

The fair value of our Utilities Group's derivative contracts is summarized below (in thousands): as of:


	June 30, 2012			December 31, 2011			June 30, 2011			Sept. 30, 2012			Dec. 31, 2011			Sept. 30, 2011
Net derivative (liabilities) assets	$	(12,453	)	$	(16,676	)	$	(3,441	)	$	(7,253	)	$	(16,676	)	$	(10,064	)
Cash collateral	15,925			19,416			6,254			15,740			19,416			12,058
	$	3,472		$	2,740		$	2,813		$	8,487		$	2,740		$	1,994

Oil and Gas Activities ~~Other Than Trading~~

We have entered into agreements to hedge a portion of our estimated 2012, 2013 and 2014 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at ~~June~~Sept. 30, 2012 were as follows:

Natural Gas


	For the Three Months Ended										For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year		March 31,		June 30,		Sept. 30,		Dec. 31,		Total Year
2012
Swaps - MMBtu					1,334,000		1,196,000		2,530,000								1,196,000		1,196,000
Weighted Average Price per MMBtu					$	3.99	$	3.74	$	3.87							$	3.74	$	3.74

2013
Swaps - MMBtu	1,220,000		1,233,000		1,246,000		1,386,500		5,085,500		1,220,000		1,233,000		1,246,000		1,155,250		4,854,250
Weighted Average Price per MMBtu	$	4.01	$	3.55	$	3.33	$	3.47	$	3.58	$	4.01	$	3.55	$	3.33	$	3.51	$	3.60

2014
Swaps - MMBtu	950,000		455,000						1,405,000		950,000		455,000						1,405,000
Weighted Average Price per MMBtu	$	3.71	$	3.45					$	3.63	$	3.71	$	3.45					$	3.63

6466

Crude Oil


	For the Three Months Ended										For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year		March 31,		June 30,		Sept. 30,		Dec. 31,		Total Year
2012
Swaps - Bbls					57,000		57,000		114,000								42,000		42,000
Weighted Average Price per Bbl					$	88.37	$	96.56	$	92.46							$	97.99	$	97.99

Puts - Bbls					21,000		21,000		42,000								21,000		21,000
Weighted Average Price per Bbl					$	76.43	$	76.43	$	76.43							$	76.43	$	76.43

Calls - Bbls					21,000		21,000		42,000								21,000		21,000
Weighted Average Price per Bbl					$	95.00	$	95.00	$	95.00							$	95.00	$	95.00

2013
Swaps - Bbls	45,000		36,000		36,000		15,000		132,000		30,000		21,000		15,000		15,000		81,000
Weighted Average Price per Bbl	$	98.93	$	102.64	$	100.49	$	101.75	$	100.69	$	101.62	$	108.96	$	110.20	$	101.75	$	105.13

Puts - Bbls	30,000		36,000		39,000		36,000		141,000		30,000		36,000		39,000		36,000		141,000
Weighted Average Price per Bbl	$	76.75	$	78.96	$	79.81	$	80.63	$	79.15	$	76.75	$	78.96	$	79.81	$	80.63	$	79.15

Calls - Bbls	30,000		36,000		39,000		36,000		141,000		30,000		36,000		39,000		36,000		141,000
Weighted Average Price per Bbl	$	96.50	$	97.17	$	97.08	$	97.25	$	97.02	$	96.50	$	97.17	$	97.08	$	97.25	$	97.02

2014
Swaps - Bbls	45,000		15,000						60,000		45,000		45,000						90,000
Weighted Average Price per Bbl	$	94.38	$	82.75					$	91.48	$	94.38	$	90.82					$	92.60

Financing Activities

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. As of ~~June~~Sept. 30, 2012, we had $150 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of ~~4.5~~4.25 years. These swaps have been designated as hedges in accordance with accounting standards for derivatives and hedges and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive income (loss) on the Condensed Consolidated Balance Sheets.

We also have interest rate swaps with a notional amount of $250 million, which were entered into for the purpose of hedging interest rate movements that would impact long-term financings that were originally expected to occur in 2008. The swaps were originally designated as cash flow hedges and the mark-to-market value was recorded in Accumulated other comprehensive income (loss) on the Condensed Consolidated Balance Sheets. Based on credit market conditions that transpired during the fourth quarter of 2008, we determined it was probable that the forecasted long-term debt financings would not occur in the time period originally specified and, as a result, the swaps were no longer effective hedges and the hedge relationships were de-designated. Mark-to-market adjustments on the swaps are now recorded within the Condensed Consolidated Statements of ~~Income and Comprehensive~~ Income. For the three months and ~~six~~nine months ended ~~June~~Sept. 30, 2012, we recorded pre-tax unrealized non-cash mark-to-market ~~losses~~gain of $~~15.6~~0.6 million and a pre-tax unrealized non-cash mark-to-market loss of $~~3.5~~2.9 million, respectively. For the three months and ~~six~~nine months ended ~~June~~Sept. 30, 2011, we recorded pre-tax unrealized non-cash mark-to-market losses of $~~7.8~~38.2 million and $~~2.4~~40.6 million, respectively. The mark-to-market value on these swaps was a liability of $95.6 million at Sept. 30, 2012. Subsequent mark-to-market adjustments could have a significant impact on our results of operations. A one basis point move in the interest rate curves over the term would have a pre-tax impact of approximately $0.3 million. These swaps are 76.25 and 1716.25 year swaps which have ~~amended~~ early termination dates ranging from ~~December~~Dec. 15, 2012 to ~~December~~Dec. 16, 2013.

We have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly our upcoming holding company debt ~~maturities, which are $225 million and $250 million in years 2013 and 2014, respectively.~~maturities. Alternatively, we may choose to cash settle these swaps at fair value prior to the early termination dates, or unless these dates are extended we will cash settle these swaps for an amount equal to their fair values on the stated termination dates.

Further details of the swap agreements are set forth in Note 1311 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

~~As of~~ ~~June 30, 2012~~, ~~December 31, 2011~~ ~~and~~ ~~June 30, 2011, our~~Our interest rate swaps and related balances were as follows (dollars in thousands): as of:


	June 30, 2012						December 31, 2011						June 30, 2011						Sept. 30, 2012						Dec. 31, 2011						Sept. 30, 2011
	Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.5			1.5			5.0			2.0			5.5			0.5			4.25			1.25			5.00			2.00			5.25			0.25
Derivative liabilities, current	$	6,766		$	78,001		$	6,513		$	75,295		$	6,900		$	56,342		$	7,028		$	77,914		$	6,513		$	75,295		$	6,724		$	94,588
Derivative liabilities, non-current	$	18,976		$	15,336		$	20,363		$	20,696		$	15,788		$	—		$	18,660		$	17,668		$	20,363		$	20,696		$	21,108		$	—
Pre-tax accumulated other comprehensive loss included in Condensed Consolidated Balance Sheets	$	(25,742	)	$	—		$	(26,876	)	$	—		$	(22,688	)	$	—		$	(25,688	)	$	—		$	(26,876	)	$	—		$	(27,832	)	$	—
Pre-tax (loss) gain included in Condensed Consolidated Statements of Income and Comprehensive Income	$	—		$	(3,507	)	$	—		$	(42,010	)	$	—		$	(2,362	)
Pre-tax (loss) gain included in Condensed Consolidated Statements of Income																			$	—		$	(2,902	)	$	—		$	(42,010	)	$	—		$	(40,608	)
Cash collateral receivable (payable) included in accounts receivable	$	—		$	6,160		$	—		$	—		$	—		$	—		$	—		$	3,310		$	—		$	—		$	—		$	—

__________

Maximum terms in years for our ~~de-designed~~de-designated interest rate swaps reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. When extended annually, de-designated swaps totaling $100 million terminate in ~~6.5~~6.25 years and de-designated swaps totaling $150 million terminate in ~~16.5~~16.25 years.

Based on ~~June~~Sept. 30, 2012 market interest rates and balances for our designated interest rate swaps, a loss of approximately $~~6.8~~7.0 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will change during the next 12 months as market interest rates change.

6668

ITEM 4. CONTROLS AND PROCEDURES

This section should be read in conjunction with Item 9A, "Controls and Procedures" included in our Annual Report on Form 10-K for the year ended ~~December~~Dec. 31, 2011.

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of ~~June~~Sept. 30, 2012 and concluded that, because of the material weakness in our internal control over financial reporting related to accounting for income taxes as previously disclosed in Item 9A, “Controls and Procedures” in our Annual Report on Form 10-K for the year ended ~~December~~Dec. 31, 2011, our disclosure controls and procedures were not effective as of ~~June~~Sept. 30, ~~2012.~~2012. Additional review, evaluation and oversight have been undertaken to ensure our unaudited Condensed Consolidated Financial Statements were prepared in accordance with generally accepted accounting principles and as a result, our management, including our Chief Executive Officer and Chief Financial Officer, have concluded that the Condensed Consolidated Financial Statements in this Form 10-Q fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in conformity with accounting principles generally accepted in the United States.

As discussed in our 2011 Annual Report on Form 10-K, management concluded that while we had appropriately designed control procedures for income tax accounting and disclosures, the existence of non-routine transactions, insufficient tax resources, and ineffective communications between the tax department and Controller organization caused us to poorly execute the controls for evaluating and recording income taxes. Management has developed and ~~is implementing~~implemented a remediation plan to address this material weakness in internal controls surrounding accounting for income taxes. Key aspects of the remediation plan include ~~enhancing~~enhanced resources and skill sets, and ~~implementing~~implementation of formal periodic meetings among the Chief Financial Officer, Controller and the tax department.

While we concluded our internal controls surrounding income taxes were not effective as of ~~June~~Sept. 30, 2012, we are remediating the material weakness and will continue to execute our remediation plan and track our performance against the plan.

During the quarter ended ~~June~~Sept. 30, 2012, there have been no other changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

6769

BLACK HILLS CORPORATION

Part II — Other Information


ITEM 1.	Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2011 Annual Report on Form 10-K and Note 1614 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 1614 is incorporated by reference into this item.


ITEM 1A.	Risk Factors

There are no material changes to the Risk Factors previously disclosed in Item 1A of Part I in our Annual Report on Form 10-K for the year ended ~~December~~Dec. 31, 2011.


ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Period
Total
Number
of
Shares
Purchased⁽¹⁾
Average
Price Paid
per Share Total Number
of Shares
Purchased as
Part of Publicly
Announced
Plans for Programs Maximum Number (or
Approximate Dollar
Value) of Shares
That May Yet Be
Purchased Under
the Plans or Programs
April 1, 2012 -
April 30, 2012 —
$ —
—
—

May 1, 2012 -
May 31, 2012 1,673
$ 32.47
—
—

June 1, 2012 -
June 30, 2012 —
$ —
—
—

Total 1,673
$ 32.47
—
—



Period	Total Number of Shares Purchased⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans for Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
July 1, 2012 -
July 31, 2012	—	$	—	—	—

Aug. 1, 2012 -
Aug. 31, 2012	262	$	31.46	—	—

Sept. 1, 2012 -
Sept. 30, 2012	—	$	—	—	—

Total	262	$	31.46	—	—

____________



(1)	Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for the payment of taxes associated with the vesting of shares of restricted stock.


ITEM 4.	Mine Safety Disclosures

~~ITEM 4.~~ ~~Mine Safety Disclosures~~

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Quarterly Report on Form 10-Q.


ITEM 5.	Other Information

None.

6870


ITEM 6.	Exhibits



	Exhibit 10 *2	~~First Amendment to the Credit~~Purchase and Sale Agreement, dated ~~June 22,~~as of August 23, 2012, by and among Black Hills ~~Corporation,~~Exploration and Production, Inc. and Other Sellers and QEP Energy Company, as ~~Borrower,~~Purchaser (excluding exhibits and certain schedules, which the ~~Bank of Nova Scotia, in its capacity as agent for the Banks and a Bank, and each of the other Banks (filed as Exhibit 10~~Registrant agrees to furnish supplementally to the ~~Registrant's Form 8-K filed on June 26, 2012)~~Securities and Exchange Commission upon request).

	Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

	Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

	Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

	Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

	Exhibit 95	Mine Safety and Health Administration Safety Data

	Exhibit 101	Financial Statements for XBRL Format

~~___________~~


*	~~Previously filed as part of the filing indicated and incorporated by reference herein.~~

6971

BLACK HILLS CORPORATION

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS CORPORATION



		/s/ David R. Emery
		David R. Emery, Chairman, President and
		Chief Executive Officer

		/s/ Anthony S. Cleberg
		Anthony S. Cleberg, Executive Vice President and
		Chief Financial Officer

Dated:	~~August 7,~~November 8, 2012

7072

EXHIBIT INDEX



Exhibit Number	Description
Exhibit 2
Exhibit 10 *	~~First Amendment to the Credit~~Purchase and Sale Agreement, dated ~~June 22,~~as of August 23, 2012, by and among Black Hills ~~Corporation,~~Exploration and Production, Inc. and Other Sellers and QEP Energy Company, as ~~Borrower,~~Purchaser (excluding exhibits and certain schedules, which the ~~Bank of Nova Scotia, in its capacity as agent for the Banks and a Bank, and each of the other Banks (filed as Exhibit 10~~Registrant agrees to furnish supplementally to the ~~Registrant's Form 8-K filed on June 26, 2012)~~Securities and Exchange Commission upon request).

Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

Exhibit 95	Mine Safety and Health Administration Safety Data

Exhibit 101	Financial Statements for XBRL Format

~~___________~~


*	~~Previously filed as part of the filing indicated and incorporated by reference herein.~~

7173



Three Months Ended June 30, 2012	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges	$	178		$	(167	)	$	11
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	(1,051		)	432			(619		)
Other comprehensive income (loss)	$	(873	)	$	265		$	(608	)