Edgar Filing: BLACK HILLS CORP /SD/

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 September 30, 2007.

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

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

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

Yes

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 October 31, 2007

Common stock, $1.00 par value	37,759,152 shares

TABLE OF CONTENTS

		Page

	Glossary of Terms	3-4

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Consolidated Statements of Income –
	Three and Nine Months Ended September 30, 2007 and 2006	5

	Condensed Consolidated Balance Sheets –
	September 30, 2007, December 31, 2006 and September 30, 2006	6

	Condensed Consolidated Statements of Cash Flows –
	Nine Months Ended September 30, 2007 and 2006	7

	Notes to Condensed Consolidated Financial Statements	8-30

Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	31-56

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	56-59

Item 4.	Controls and Procedures	59

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	60

Item 1A.	Risk Factors	60

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60

Item 6.	Exhibits	61

	Signatures	62

	Exhibit Index	63

GLOSSARY OF TERMS

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
Aquila	Aquila, Inc.
Bbl	Barrel
Bcfe	One billion cubic feet equivalent
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned
	subsidiary of Black Hills Energy, Inc.
BHER	Black Hills Energy Resources, Inc., a direct, wholly-owned subsidiary of Black
	Hills Energy, Inc.
Black Hills Energy	Black Hills Energy, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Btu	British thermal unit
Cheyenne Light	Cheyenne Light, Fuel & Power Company, a direct, wholly-owned subsidiary
	of the Company
Cheyenne Light Pension Plan	The Cheyenne Light, Fuel & Power Company Pension Plan
Dth	Dekatherm
Enserco	Enserco Energy Inc., a direct, wholly-owned subsidiary of Black Hills
	Energy, Inc.
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes –
	an Interpretation of FASB Statement 109”
GAAP	Generally Accepted Accounting Principles
GE Capital	General Electric Capital Corporation
Great Plains	Great Plains Energy Incorporated
Indeck	Indeck Capital, Inc.
IPP	Independent power production
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Las Vegas I	Las Vegas I gas-fired power plant
Las Vegas II	Las Vegas II gas-fired power plant
LVC	Las Vegas Cogeneration Limited Partnership, an indirect, wholly-owned
	subsidiary of Black Hills Energy, Inc.
Mcfe	One thousand cubic feet equivalent
MMBtu	One million British thermal units
Moody’s	Moody’s Investor Services, Inc.
Mw	Megawatt
Mwh	Megawatt-hour
Nevada Power	Nevada Power Company
PNM	PNM Resources, Inc.
SAB	SEC Staff Accounting Bulletin
SAB 108	SAB 108, “Effects of Prior Year Misstatement on Current Year Financial
	Statements”
SEC	U. S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 109	SFAS 109, “Accounting for Income Taxes”
SFAS 133	SFAS 133, “Accounting for Derivative Instruments and Hedging Activities”

SFAS 144	SFAS 144, “Accounting for the Impairment of Long-lived Assets”
SFAS 157	SFAS 157, “Fair Value Measurements”
SFAS 159	SFAS 159, “The Fair Value Option for Financial Assets and Financial
	Liabilities”
S&P	Standard & Poor’s Rating Services
Valencia	Valencia Power, LLC, an indirect, wholly-owned subsidiary of Black Hills
	Energy, Inc.
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of
	Black Hills Energy, Inc.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
	(in thousands, except per share amounts)

Operating revenues	$	162,354	$	157,608	$	512,830	$	483,312

Operating expenses:
Fuel and purchased power		42,840		47,740		130,726		151,150
Operations and maintenance		21,942		16,490		63,220		60,566
Administrative and general		27,316		19,721		79,285		64,776
Depreciation, depletion and amortization		26,630		24,141		74,712		67,407
Taxes, other than income taxes		8,347		8,570		28,337		26,667
Impairment of long-lived assets		2,721		—		2,721		—
		129,796		116,662		379,001		370,566

Operating income		32,558		40,946		133,829		112,746

Other income (expense):
Interest expense		(9,634)		(12,400)		(30,720)		(37,310)
Interest income		990		389		2,429		1,403
Allowance for funds used during
construction – equity		811		—		3,851		—
Other income, net		67		106		413		517
		(7,766)		(11,905)		(24,027)		(35,390)

Income from continuing operations
before equity in earnings of
unconsolidated subsidiaries, minority
interest and income taxes		24,792		29,041		109,802		77,356
Equity in earnings (loss) of unconsolidated
subsidiaries		574		615		2,092		(16)
Minority interest		(97)		(95)		(285)		(273)
Income tax expense		(7,627)		(7,362)		(36,235)		(23,939)

Income from continuing operations		17,642		22,199		75,374		53,128
(Loss) income from discontinued operations,
net of taxes		(178)		81		(358)		7,060

Net income	$	17,464	$	22,280	$	75,016	$	60,188

Weighted average common shares
outstanding:
Basic		37,643		33,187		36,810		33,157
Diluted		38,078		33,560		37,226		33,526

Earnings per share:
Basic–
Continuing operations	$	0.47	$	0.67	$	2.05	$	1.60
Discontinued operations		—		—		(0.01)		0.21
Total	$	0.47	$	0.67	$	2.04	$	1.81

Diluted–
Continuing operations	$	0.46	$	0.66	$	2.03	$	1.59
Discontinued operations		—		—		(0.01)		0.21
Total	$	0.46	$	0.66	$	2.02	$	1.80

Dividends paid per share of common stock	$	0.34	$	0.33	$	1.02	$	0.99

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

(unaudited)

	September 30,		December 31,		September 30,
	2007		2006		2006
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	81,201	$	36,939	$	47,716
Restricted cash		5,394		2,004		—
Receivables (net of allowance for doubtful accounts of $5,259;
$4,202 and $4,007, respectively)		238,662		263,109		195,571
Materials, supplies and fuel		92,625		92,560		91,490
Derivative assets		29,385		69,244		66,990
Income tax receivable		—		—		11,524
Other assets		11,795		9,221		7,830
Assets of discontinued operations		3,543		1,424		1,043
		462,605		474,501		422,164

Investments		23,886		23,808		23,709

Property, plant and equipment		2,430,975		2,242,396		2,180,639
Less accumulated depreciation and depletion		(652,701)		(596,029)		(574,925)
		1,778,274		1,646,367		1,605,714
Other assets:
Derivative assets		3,420		2,871		3,197
Goodwill		30,171		30,563		30,563
Intangible assets (net of accumulated amortization of
$27,363; $25,852 and $25,072, respectively)		21,777		24,429		25,209
Other		44,774		42,137		38,177
		100,142		100,000		97,146
	$	2,364,907	$	2,244,676	$	2,148,733
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	202,014	$	224,009	$	181,255
Accrued liabilities		102,019		95,020		82,098
Derivative liabilities		24,904		24,041		18,937
Deferred income taxes		—		1,215		5,001
Notes payable		96,648		145,500		147,000
Current maturities of long-term debt		143,380		17,106		17,103
Accrued income taxes		17,620		19,561		—
Liabilities of discontinued operations		694		2,526		4,131
		587,279		528,978		455,525

Long-term debt, net of current maturities		466,137		628,340		632,295

Deferred credits and other liabilities:
Deferred income taxes		191,451		174,332		170,286
Derivative liabilities		3,615		1,530		2,913
Other		143,786		116,297		101,819
		338,852		292,159		275,018

Minority interest in subsidiaries		5,075		5,158		5,198

Stockholders’ equity:
Common stock equity –
Common stock $1 par value; 100,000,000 shares authorized;
Issued 37,802,087; 33,404,902 and 33,330,841 shares,
respectively		37,802		33,405		33,331
Additional paid-in capital		558,935		409,826		407,488
Retained earnings		386,869		348,245		338,420
Treasury stock at cost – 42,935; 35,700 and 34,720
shares, respectively		(1,219)		(920)		(883)
Accumulated other comprehensive (loss) income		(14,823)		(515)		2,341
		967,564		790,041		780,697

	$	2,364,907	$	2,244,676	$	2,148,733

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)

	Nine Months Ended
	September 30,
	2007		2006
	(in thousands)
Operating activities:
Net income	$	75,016	$	60,188
Loss (income) from discontinued operations, net of taxes		358		(7,060)

Income from continuing operations		75,374		53,128
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization		74,712		67,407
Net change in derivative assets and liabilities		(4,911)		2,136
Deferred income taxes		10,008		32,042
Distributed earnings in associated companies		177		4,304
Allowance for funds used during construction – equity		(3,851)		—
Change in operating assets and liabilities:
Materials, supplies and fuel		25,011		(6,389)
Accounts receivable and other current assets		21,099		59,005
Accounts payable and other current liabilities		4,662		(61,878)
Other operating activities		6,495		26,239
Net cash provided by operating activities of continuing operations		208,776		175,994
Net cash used in operating activities of discontinued operations		(3,045)		(1,583)
Net cash provided by operating activities		205,731		174,411

Investing activities:
Property, plant and equipment additions		(159,788)		(153,820)
Proceeds from the sale of business operations		—		40,735
Payment for acquisition, net of cash acquired		—		(75,425)
Other investing activities		(3,004)		(454)
Net cash used in investing activities of continuing operations		(162,792)		(188,964)
Net cash provided by (used in) investing activities of discontinued operations		2,479		(575)
Net cash used in investing activities		(160,313)		(189,539)

Financing activities:
Dividends paid		(37,068)		(32,954)
Common stock issued		149,860		3,560
(Decrease) increase in short-term borrowings, net		(78,000)		92,000
Long-term debt – issuances		—		90,000
Long-term debt – repayments		(35,929)		(122,566)
Other financing activities		(585)		(1,171)
Net cash (used in) provided by financing activities of continuing operations		(1,722)		28,869
Net cash (used in) provided by financing activities of discontinued operations		—		—
Net cash (used in) provided by financing activities		(1,722)		28,869

Increase in cash and cash equivalents		43,696		13,741

Cash and cash equivalents:
Beginning of period		37,530^(b)		34,198^(d)
End of period	$	81,226^(a)	$	47,939^(c)

Supplemental disclosure of cash flow information:
Non-cash investing and financing activities-
Property, plant and equipment acquired with accrued liabilities or
short-term debt	$	56,274	$	31,481
Cash paid during the period for-
Interest (net of amounts capitalized)	$	30,160	$	35,317
Income taxes paid (net of amounts refunded)	$	7,627	$	12,806

_________________________

(a)	Includes insignificant September 30, 2007 cash balances included in assets of discontinued operations.

(b)	Includes approximately $0.6 million at December 31, 2006 of cash included in the assets of discontinued operations.

(c)	Includes approximately $0.2 million at September 30, 2006 of cash included in the assets of discontinued operations.

(d)	Includes approximately $2.4 million at December 31, 2005 of cash included in the assets of discontinued operations.

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 2006 Annual Report on Form 10-K)

(1)	MANAGEMENT’S STATEMENT

The financial statements included herein have been prepared by Black Hills Corporation (the Company) without audit, 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, the Company believes that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in the Company’s 2006 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 financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the September 30, 2007, December 31, 2006 and September 30, 2006 financial information and are of a normal recurring nature. Some of the Company’s operations are highly seasonal and revenues 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. The results of operations for the three and nine months ended September 30, 2007, are not necessarily indicative of the results to be expected for the full year. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

(2)	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

FIN 48

The Company adopted FIN 48 on January 1, 2007 (see Note 8). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

SAB 108

During September 2006, the staff of the SEC released SAB 108. SAB 108 provides guidance on how the effects of the carryover or reversal of prior year financial statement misstatements should be considered in quantifying a current year misstatement. Prior practice allowed the evaluation of materiality on the basis of (1) the error quantified as the amount by which the current year income statement was misstated (rollover method) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (iron curtain method). Reliance on either method in prior years could have resulted in misstatement of the financial statements. The guidance provided in SAB 108 requires both methods to be used in evaluating materiality. Immaterial prior year errors may be corrected with the first filing of prior year financial statements after adoption. The cumulative effect of the correction can either be reported in the carrying amounts of assets and liabilities as of the beginning of that fiscal year, and the offsetting adjustment made to the opening balance of retained earnings for that year, or by restating prior periods. Disclosure requirements include the nature and amount of each individual error being corrected in the cumulative adjustment, as well as a disclosure of when and how each error being corrected arose and the fact that the errors had previously been considered immaterial. SAB 108 was effective January 1, 2007. SAB 108 did not have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

(3)	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SFAS 157

During September 2006, the FASB issued SFAS 157, which applies to other accounting pronouncements that require or permit fair value measurements. This Statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. Management is currently evaluating the impact SFAS 157 will have on the Company’s consolidated financial statements.

SFAS 159

During February 2007, the FASB issued SFAS 159, which establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. Management is currently evaluating the impact SFAS 159 will have on the Company’s consolidated financial statements.

(4)	MATERIALS, SUPPLIES AND FUEL

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

	September 30,		December 31,		September 30,
Major Classification	2007		2006		2006

Materials and supplies	$	35,562	$	31,946	$	30,160
Fuel		7,401		9,663		9,387
Gas and oil held by Energy
marketing*		49,662		50,951		51,943

Total materials, supplies and fuel	$	92,625	$	92,560	$	91,490

___________________________

* As of September 30, 2007, December 31, 2006 and September 30, 2006, market adjustments related to natural gas held by Energy marketing and recorded in inventory were $(6.5) million, $(31.5) million and $(29.8) million, respectively (see Note 13 for further discussion of Energy marketing trading activities).

The inventory held by the Company’s Energy marketing subsidiary primarily consists of gas held in storage and gas imbalances held on account with pipelines. Such gas is being held in inventory to capture the price differential between the time at which it was purchased and a sales date in the future. A substantial majority of the gas was economically hedged at the time of purchase either through a fixed price physical or financial forward sale.

(5)	LONG-TERM DEBT, NOTES PAYABLE AND GUARANTEES

Note Payable

During June 2007, the Company entered into a short-term, non-interest bearing, secured promissory note payable to Public Service Company of New Mexico in connection with the purchase of certain equipment and related assets for the Company’s Valencia project in New Mexico. The secured promissory note payable is due December 2007, and is secured by the purchased equipment and related assets. The Company recorded the promissory note payable at the stated amount of the debt of $30.0 million, less interest imputed at a rate of 6 percent totaling $0.9 million, for a net amount of $29.1 million.

Long-term Debt

On April 30, 2007, the Company called its outstanding debt with GE Capital in the amount of $23.5 million. In conjunction with this, the Company expensed $0.1 million in unamortized deferred financing costs. The associated payment guarantees provided by the Company were also terminated.

The Company has classified the $128.3 million Wygen I project debt to current maturities as the debt has a maturity date of June 2008. The Company intends to refinance this debt with other long-term financing prior to its maturity.

Amendments to Revolver

On March 13, 2007, the Company entered into a second amendment to its revolving credit facility. The second amendment (i) increased the limit for borrowings or other credit accommodations for the separate credit facility for the Company’s energy marketing subsidiary from $260 million to $300 million, (ii) increased the allowed total commitments under the revolving credit facility without requiring amendment of the facility from $500 million to $600 million, (iii) effective with the acquisition of certain electric and gas utility assets from Aquila, will increase the recourse leverage ratio limit from 0.65 to 1.00 to 0.70 to 1.00 for the first year after completion of the Aquila asset acquisition, reverting to 0.65 to 1.00 thereafter, and (iv) allowed for other modifications to enable the Company to complete the Aquila asset acquisition.

Guarantees

During the nine months ended September 30, 2007, the Company had the following changes to its guarantees:

•	Extinguished two guarantees totaling $24.2 million at December 31, 2006 related to the payment and performance under the Company’s GE Capital debt obligations. The Company’s outstanding debt obligations with GE Capital were paid on April 30, 2007;

•	The $0.3 million guarantee for the payments of Black Hills Power under various transactions with Idaho Power Company expired on March 1, 2007;

•	The $3.0 million guarantee for the payments of Cheyenne Light under various transactions with Questar Energy Trading Company expired on March 31, 2007;

•	Issued a guarantee for obligations and damages, if any, due by Valencia under a power purchase agreement with Public Service Company of New Mexico for up to $12.0 million and expiring in 2028;

•	Issued a guarantee for up to $7.0 million related to the obligations of Enserco under an agency agreement whereby Enserco provides services to structure up to $100.0 million of certain transactions involving the buying, selling, transportation and storage of natural gas on behalf of another energy company and which expires in 2008; and

•	Extinguished a $10.0 million guarantee under the Las Vegas I Power Purchase and Sales Agreement on September 25, 2007.

(6)	EARNINGS PER SHARE

Basic earnings per share from continuing operations is computed by dividing income from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted earnings per share from continuing operations gives effect to all dilutive common shares potentially outstanding during a period. A reconciliation of “Income from continuing operations” and basic and diluted share amounts is as follows (in thousands):

Period ended September 30, 2007	Three Months			Nine Months
			Average			Average
	Income		Shares	Income		Shares

Income from continuing operations	$	17,642		$	75,374

Basic earnings		17,642	37,643		75,374	36,810
Dilutive effect of:
Stock options		—	111		—	108
Estimated contingent shares issuable
for prior acquisition		—	159		—	159
Others		—	165		—	149
Diluted earnings	$	17,642	38,078	$	75,374	37,226

Period ended September 30, 2006	Three Months			Nine Months
			Average			Average
	Income		Shares	Income		Shares

Income from continuing operations	$	22,199		$	53,128

Basic earnings		22,199	33,187		53,128	33,157
Dilutive effect of:
Stock options		—	91		—	85
Estimated contingent shares issuable
for prior acquisition		—	158		—	158
Others		—	124		—	126
Diluted earnings	$	22,199	33,560	$	53,128	33,526

(7)	COMPREHENSIVE INCOME

The following table presents the components of the Company’s comprehensive income

(in thousands):

	Three Months Ended
	September 30,
	2007		2006

Net income	$	17,464	$	22,280
Other comprehensive income (loss),
net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges
(net of tax of $3,558 and $(3,998),
respectively)		(6,749)		7,425
Reclassification adjustments on cash
flow hedges settled and included in
net income (net of tax of $1,296
and $132, respectively)		(2,406)		(246)

Comprehensive income	$	8,309	$	29,459

	Nine Months Ended
	September 30,
	2007		2006

Net income	$	75,016	$	60,188
Other comprehensive income (loss),
net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges
(net of tax of $3,419 and $(7,318),
respectively)		(6,521)		12,587
Reclassification adjustments on cash
flow hedges settled and included in
net income (net of tax of $4,012
and $242, respectively)		(7,787)		(416)

Comprehensive income	$	60,708	$	72,359

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

	Derivatives		Employee		Amount from
	Designated as		Benefit		Equity-method
	Cash Flow Hedges		Plans		Investees		Total

As of September 30, 2007	$	(6,248)	$	(8,404)	$	(171)	$	(14,823)

As of December 31, 2006	$	8,119	$	(8,404)	$	(230)	$	(515)

As of September 30, 2006	$	5,495	$	(2,936)	$	(218)	$	2,341

(8)	INCOME TAXES

The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized an approximate $0.7 million benefit from a decrease in the liability for unrecognized tax benefits. This benefit was accounted for as an adjustment to the January 1, 2007 balance of retained earnings.

The total gross amount of unrecognized tax benefits at January 1, 2007 was approximately $72.6 million. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $2.0 million (net of the federal benefit on state tax items and interest) at the date of adoption.

It is the Company’s continuing practice to recognize penalties and/or interest related to income tax matters in income tax expense. The Company had no penalties accrued and approximately $0.4 million for the accrual of interest income at the date of adoption of FIN 48.

The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and Canada. The Company recently received notification from the Internal Revenue Service that the 2004 and 2005 tax years will be examined. The Company continues to be under examination by a state taxing authority for tax years 2001 through 2003 and remains subject to examination by Canadian income tax authorities for tax years as early as 1999.

The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statute of limitations prior to September 30, 2008.

Effective Tax Rate

The Company’s effective tax rate differs from the federal statutory rate as follows:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2007	2006	2007	2006

	35.0%	35.0%	35.0%	35.0%
State income tax	(0.1)	0.3	0.2	0.5
Percentage depletion in excess
of cost	(1.3)	(1.5)	(0.9)	(1.3)
IRS exam tax adjustment*	—	(7.3)	—	(2.8)
Tax return true-up	(3.8)	(1.3)	(0.4)	(0.5)
Other	—	(0.3)	(1.9)	0.2
	30.0%	24.9%	32.0%	31.1%

_________________________

As a result of the settlement of an Internal Revenue Service (IRS) exam of the tax years 2001-2003 with respect to certain tax positions taken by the Company, a reduction to income tax expense of approximately $2.2 million was recorded in the third quarter of 2006.

(9)	PROCEEDS RECEIVED ON INSURANCE CLAIMS

In late 2005 and the first half of 2006, the Company’s Las Vegas II power plant experienced unplanned outages due to damage to three of its gas turbines and two of its steam turbines. The outages lasted approximately six months as repairs were made to the turbines. The Company has filed insurance claims for reimbursement of repair expenditures and business interruption losses in the amount of approximately $11.1 million. At September 30, 2006, the Company had provided for the receipt of insurance proceeds of approximately $4.3 million. Approximately $0.4 million was applied to reduce capitalized repair costs included in Property, plant and equipment on the accompanying Condensed Consolidated Balance Sheet and $2.2 million for repair costs and $1.7 million for business interruption were applied as a reduction to Operations and maintenance expense on the accompanying Condensed Consolidated Statement of Income. As of September 30, 2007, the Company continues to pursue additional reimbursement from the insurance carrier. The carrier asserts that certain deductibles, exclusions and limitations apply preventing any future claims reimbursements. There can be no assurance that the Company will obtain any additional recovery from the insurance carrier.

(10)	COMMON STOCK

Other than the following transactions, the Company had no other material changes in its common stock, as reported in Note 9 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

Private Placement of Common Stock

On February 22, 2007, the Company completed the issuance and sale of approximately 4.17 million shares of common stock at a price of $36.00 per share in a private placement offering. The Company used the approximate $145.6 million of net proceeds from this offering for debt reduction.

These shares were not initially registered under the Securities Act of 1933, therefore restricting the purchasers’ ability to offer or sell the shares. The offering agreements required the Company to register the related securities with the SEC within a specified period of time, and the Company has performed this obligation. In addition, the Company must maintain an effective shelf registration statement with the SEC, allowing resale of the restricted shares, until all related shares have been resold or cease to be restricted. If the Company fails to maintain an effective shelf registration statement in accordance with the terms of the offering agreements, it may be required to pay damages to the purchasers at a per thirty-day rate of 1.0 percent of the related share purchase price until the default is cured. The total damage payments under the agreements are limited to 10.0 percent of the related share purchase price. The Company believes the likelihood of making any payments under the damage provisions is remote and accordingly has not recognized any liability within its consolidated financial statements.

Equity Compensation Plans

•	Effective January 1, 2007, the Company granted 35,026 target performance shares to certain officers and business unit leaders of the Company for the January 1, 2007 through December 31, 2009 performance period. Performance shares are awarded based on the Company’s total shareholder return over the designated performance period as measured against a selected peer group. In addition, the Company’s stock price must also increase during the performance period.

	Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50^th percentile of the selected peer group. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50 percent in the form of cash and 50 percent in the form of common stock. The grant date fair value was $34.17 per share.

•	The Company issued 33,143 shares of common stock under the short-term incentive compensation plan during the nine months ended September 30, 2007. Pre-tax compensation cost related to the award was approximately $1.2 million, which was accrued for in 2006.

•	The Company granted 43,556 restricted common shares during the nine months ended September 30, 2007. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $1.6 million will be recognized over the three-year vesting period.

•	156,250 stock options were exercised during the nine months ended September 30, 2007, at a weighted-average exercise price of $29.76 per share providing $4.6 million of proceeds to the Company.

•	Total compensation expense recognized for all equity compensation plans for the three months ended September 30, 2007 and 2006 was $1.4 million and $0.1 million, respectively, and for the nine month periods ended September 30, 2007 and 2006 was $4.4 million and $1.8 million, respectively.

(11)	EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The Company has two non-contributory defined benefit pension plans (Plans). One Plan covers employees of the Company and the following subsidiaries who meet certain eligibility requirements: Black Hills Service Company, Black Hills Power, WRDC and BHEP. The other Plan covers employees of the Company’s subsidiary, Cheyenne Light, who meet certain eligibility requirements.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006

Service cost	$	687	$	649	$	2,061	$	1,947
Interest cost		1,129		1,041		3,387		3,123
Expected return on plan assets		(1,374)		(1,247)		(4,122)		(3,741)
Prior service cost		38		38		114		114
Net loss		127		227		381		681

Net periodic benefit cost	$	607	$	708	$	1,821	$	2,124

The Company made a $0.5 million contribution to the Cheyenne Light Pension Plan in the first quarter of 2007; no additional contributions are anticipated to be made to the Plans during the 2007 fiscal year.

Supplemental Non-qualified Defined Benefit Plans

The Company has various supplemental retirement plans for key executives of the Company (Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006

Service cost	$	103	$	87	$	309	$	261
Interest cost		289		270		867		810
Prior service cost		3		3		9		9
Net loss		178		199		534		597

Net periodic benefit cost	$	573	$	559	$	1,719	$	1,677

The Company anticipates that it will need to make contributions to the Supplemental Plans for the 2007 fiscal year of approximately $0.7 million. The contributions are expected to be made in the form of benefit payments.

Non-pension Defined Benefit Postretirement Healthcare Plans

Employees who are participants in the Company’s Postretirement Healthcare Plans (Healthcare Plans) and who meet certain eligibility requirements are entitled to postretirement healthcare benefits.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006

Service cost	$	135	$	164	$	405	$	492
Interest cost		207		203		621		609
Net transition obligation		15		38		45		114
Prior service cost		—		(6)		—		(18)
Net gain/loss		(4)		—		(12)		—

Net periodic benefit cost	$	353	$	399	$	1,059	$	1,197

The Company anticipates that it will make contributions to the Healthcare Plans for the 2007 fiscal year of approximately $0.3 million. The contributions are expected to be made in the form of benefits payments.

It has been determined that the Company’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was approximately $0.1 million for the three month periods ended September 30, 2007 and 2006 and $0.2 million for the nine month periods ended September 30, 2007 and 2006.

(12)	SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY’S
	BUSINESS

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of September 30, 2007, substantially all of the Company’s operations and assets are located within the United States.

The Company conducts its operations through the following six reporting segments:

Retail Services group –

•	Electric utility, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and

•	Electric and gas utility, which supplies electric and gas utility service to Cheyenne, Wyoming and vicinity.

Wholesale Energy group –

•	Oil and gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region, Texas, California and other states;

•	Power generation, which produces and sells power and capacity to wholesale customers with power plants concentrated in Colorado, Nevada, Wyoming and California;

•	Coal mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; and

•	Energy marketing, which markets natural gas, crude oil and related services primarily in the western and central regions of the United States and Canada.

Segment information follows the same accounting policies as described in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K. In accordance with the provisions of SFAS 71, intercompany fuel sales to the electric utility are not eliminated.

Segment information included in the accompanying Condensed Consolidated Statements of Income is as follows (in thousands):

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
September 30, 2007

Retail services:
Electric utility	$	51,129	$	645	$	5,781
Electric and gas utility		21,146		—		1,408
Wholesale energy:
Oil and gas		24,291		—		1,979
Power generation		42,235		—		5,642
Coal mining		6,818		3,628		1,358
Energy marketing		13,873		—		2,290
Corporate		—		—		(816)
Inter-segment eliminations		—		(1,411)		—

Total	$	159,492	$	2,862	$	17,642

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
September 30, 2006

Retail services:
Electric utility	$	52,467	$	723	$	5,764
Electric and gas utility		24,479		—		953
Wholesale energy:
Oil and gas		22,969		—		3,006
Power generation		42,700		—		9,839
Coal mining		6,055		3,391		1,908
Energy marketing		6,327		—		2,091
Corporate		11		—		(1,362)
Inter-segment eliminations		—		(1,514)		—

Total	$	155,008	$	2,600	$	22,199

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Nine Month Period Ended
September 30, 2007

Retail services:
Electric utility	$	142,872	$	1,641	$	17,361
Electric and gas utility		79,161		—		5,523
Wholesale energy:
Oil and gas		75,948		—		9,945
Power generation		121,763		—		16,055
Coal mining		19,458		10,734		4,353
Energy marketing		65,220		—		23,886
Corporate		—		—		(1,749)
Inter-segment eliminations		—		(3,967)		—

Total	$	504,422	$	8,408	$	75,374

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Nine Month Period Ended
September 30, 2006

Retail services:
Electric utility	$	142,676	$	1,518	$	13,099
Electric and gas utility		97,907		—		3,214
Wholesale energy:
Oil and gas		69,519		—		10,439
Power generation		114,991		—		14,310
Coal mining		15,905		9,579		4,091
Energy marketing		34,907		—		12,602
Corporate		43		—		(4,627)
Inter-segment eliminations		—		(3,733)		—

Total	$	475,948	$	7,364	$	53,128

During 2007, the Company added assets of approximately $43.7 million on the ongoing construction of the Wygen II power plant within the Electric and gas utility segment; approximately $51.8 million on maintenance capital and development drilling within the Oil and gas segment; approximately $9.6 million for development costs related to the Aquila asset acquisition; and approximately $48.6 million on assets related to the Valencia project in the Power generation segment. Other than these significant additions and changes beyond normal operating activities, the Company had no additional material changes in the assets of its reporting segments, as reported in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

(13)	RISK MANAGEMENT ACTIVITIES

The Company actively manages its exposure to certain market risks as described in Note 2 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form

10-K. Details of derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are as follows:

Trading Activities

Natural Gas and Crude Oil Marketing

The contract or notional amounts and terms of the Company’s natural gas and crude oil marketing activities and derivative commodity instruments are as follows:

	Outstanding at			Outstanding at			Outstanding at
	September 30, 2007			December 31, 2006			September 30, 2006
			Latest			Latest			Latest
	Notional		Expiration	Notional		Expiration	Notional		Expiration
	Amounts		(months)	Amounts		(months)	Amounts		(months)
(in thousands of MMBtus)
Natural gas basis
swaps purchased		150,499	27		138,111	22		146,331	16
Natural gas basis
swaps sold		158,349	27		148,720	22		153,530	18
Natural gas fixed for float
swaps purchased		51,958	25		38,239	16		44,600	18
Natural gas fixed for float
swaps sold		70,379	25		59,061	15		58,248	6
Natural gas physical
purchases		95,028	18		87,782	22		66,972	27
Natural gas physical sales		93,008	30		106,500	34		117,135	39
Natural gas options
purchased		31,973	6		22,373	15		18,447	15
Natural gas options sold		31,539	6		22,373	15		18,447	15

	Outstanding at			Outstanding at			Outstanding at
	September 30, 2007			December 31, 2006			September 30, 2006
			Latest			Latest			Latest
	Notional		Expiration	Notional		Expiration	Notional		Expiration
	Amounts		(months)	Amounts		(months)	Amounts		(months)

(in thousands of Bbls)
Crude oil physical
purchases		1,619	7		1,600	4		404^(a)	1
Crude oil physical sales		1,370	5		1,367	7		404^(a)	1
Crude oil swaps purchased		465	12		240	12		300	12
Crude oil swaps sold		465	12		240	12		300	12

(Dollars, in thousands)
Canadian dollars
purchased	$	29,000	1	$	44,000	1	$	23,000	1
Canadian dollars sold	$	—	—	$	—	—	$	1,000	2

_________________________

(a)	The Company began marketing crude oil in the Rocky Mountain region during May 2006.

Derivatives and certain natural gas and crude oil marketing activities were marked to fair value on September 30, 2007, December 31, 2006 and September 30, 2006, and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Statements of Income are as follows (in thousands):

	Current		Non-current		Current		Non-current
	Derivative		Derivative		Derivative		Derivative		Unrealized
	Assets		Assets		Liabilities		Liabilities		Gain

September 30, 2007	$	22,183	$	1,196	$	12,154	$	1,293	$	9,932

December 31, 2006	$	53,728	$	4	$	23,296	$	377	$	30,059

September 30, 2006	$	51,528	$	1,629	$	17,546	$	1,873	$	33,738

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Condensed Consolidated Balance Sheets and the related unrealized gain/loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain/loss recognized on the associated derivative asset or liability described above. As of September 30, 2007, December 31, 2006 and September 30, 2006, the market adjustments recorded in inventory were $(6.5) million, $(31.5) million and $(29.8) million, respectively.

Activities Other Than Trading

Oil and Gas Exploration and Production

On September 30, 2007, December 31, 2006 and September 30, 2006, the Company had the following derivatives and related balances (in thousands):

											Pre-tax
		Maximum			Non-				Non-		Accumulated
		Terms	Current		current		Current		current		Other		Pre-tax
		in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Income
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
September 30,
2007

Crude oil
swaps/options	465,000	1.00	$	490	$	—	$	1,995	$	688	$	(2,683)	$	490
Natural gas
swaps	11,180,500	1.60		6,712		872		494		1,035		6,403		(348)
			$	7,202	$	872	$	2,489	$	1,723	$	3,720	$	142
December 31,
2006

Crude oil
swaps/options	240,000	1.00	$	524	$	—	$	362	$	—	$	36	$	126
Natural gas
swaps	10,588,000	1.25		13,485		2,000		309		175		15,339		(338)
			$	14,009	$	2,000	$	671	$	175	$	15,375	$	(212)
September 30,
2006

Crude oil
swaps	300,000	1.00	$	456	$	—	$	1,308	$	282	$	(1,441)	$	307
Natural gas
swaps	6,765,000	1.50		13,231		1,116		—		—		14,347		—
			$	13,687	$	1,116	$	1,308	$	282	$	12,906	$	307

________________________

*crude in Bbls, gas in MMBtus

Based on September 30, 2007 market prices, a $4.1 million gain would be realized and reported in pre-tax earnings during the next twelve months related to hedges of production. Estimated and actual realized gains will likely change during the next twelve months as market prices change.

Fuel in Storage

On September 30, 2007, December 31, 2006 and September 30, 2006, the Company had the following swaps and related balances (in thousands):

											Pre-tax
					Non-				Non-		Accumulated
		Maximum	Current		current		Current		current		Other
		Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Unrealized
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		Gain
September 30,
2007

Natural gas
swaps	610,000	0.60	$	—	$	—	$	172	$	—	$	(172)	$	—

December 31,
2006

Natural gas
swaps	380,000	0.25	$	1,220	$	—	$	—	$	—	$	878	$	342

September 30,
2006

Natural gas
swaps	525,000	0.50	$	1,634	$	—	$	—	$	—	$	410	$	1,224

________________________

*gas in MMBtus

Based on September 30, 2007 market prices, a loss of $0.2 million would be realized and reported in pre-tax earnings during the next twelve months related to the cash flow hedge. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

Financing Activities

On September 30, 2007, December 31, 2006 and September 30, 2006, the Company’s interest rate swaps and related balances were as follows (in thousands):

			Weighted										Pre-tax
			Average				Non-				Non-		Accumulated
	Current		Fixed	Maximum	Current		current		Current		current		Other
	Notional		Interest	Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive
	Amount		Rate	Years	Assets		Assets		Liabilities		Liabilities		(Loss)/Income
September 30,
2007

Interest rate
swaps	$	150,000	5.04%	9.00	$	—	$	1,352	$	666	$	599	$	87

December 31,
2006

Interest rate
swaps	$	150,000	5.04%	9.75	$	287	$	867	$	74	$	978	$	102

September 30,
2006

Interest rate
swaps	$	100,000	5.09%	10.00	$	141	$	452	$	83	$	758	$	(248)

Based on September 30, 2007 market interest rates and balances, a loss of approximately $0.7 million would be realized and reported in pre-tax earnings during the next twelve months. Estimated and realized losses will likely change during the next twelve months as market interest rates change.

In addition to the interest rate swaps above, during the third quarter of 2007, the Company entered into forward starting interest rate swaps with a total notional amount of $250.0 million to hedge the risk of interest rate movement between the hedge dates and the expected pricing date for a portion of the Company’s anticipated 2008 long-term debt financings. The swaps have a mandatory early termination date of June 30, 2008. As of September 30, 2007, the mark-to-market value was $(3.8) million. These swaps are designated as cash flow hedges and accordingly, any resulting gain or loss will be recorded in “Accumulated other comprehensive loss” on the Condensed Consolidated Balance Sheet and amortized into earnings as additional interest income or expense over the life of the related long-term financing.

On July 3, 2007, Cheyenne Light entered into a $110.0 million treasury lock to hedge a $110.0 million First Mortgage Bond offering expected to be completed in November 2007. As of September 30, 2007, the mark-to-market value was $(5.6) million. The treasury lock cash settled on October 15, 2007, the pricing date of the expected offering, and resulted in a $4.3 million payment to the counterparty. The treasury lock was treated as a cash flow hedge and accordingly, the resulting loss is carried in “Accumulated other comprehensive loss” on the Condensed Consolidated Balance Sheet and will be amortized over the life of the related bonds as additional interest expense.

(14)	POWER PLANT PROJECT AND POWER PURCHASE AGEEMENT

In April 2007, the Company entered into a power purchase agreement to provide electric power to Public Service Company of New Mexico, a regulated electric and natural gas utility subsidiary of PNM.

Under the terms of the agreement, the Company will provide the capacity and energy of a 149 Mw, simple-cycle gas turbine generation facility to be located near Albuquerque, New Mexico. The project is expected to cost approximately $101 million, and has a commercial operation in-service date in June 2008. If the Company would fail to meet the June 2008 in-service date, significant penalties could be incurred under the “delay damage” provisions that are customary within agreements of this nature. The agreement is a customary tolling agreement, where the Company receives variable and fixed fees for the plant’s availability and operation, and Public Service Company of New Mexico will be responsible for providing fuel for the operation. In addition, the agreement affords the Company favorable “change of law” and “government impositions” pass-throughs to Public Service Company of New Mexico. The duration of the power purchase agreement is 20 years. During the term of the agreement, Public Service Company of New Mexico is also provided an option to acquire a 50 percent equity interest in this project for a price equal to the fair market value at the time of the option exercise, with a minimum price equal to book value.

On June 20, 2007, the Company purchased certain equipment and assets related to the Valencia project from Public Service Company of New Mexico. The assets included the power plant turbine, permits, land and other auxiliary equipment. The purchase price was approximately $40.6 million, paid through entering into a $30.0 million short-term promissory note, payable to Public Service Company of New Mexico in December 2007, and $10.6 million in cash.

(15)	LEGAL PROCEEDINGS

The Company is subject to various legal proceedings, claims and litigation as described in Note 18 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

Earn-Out Litigation

As disclosed in previous filings with the SEC, the Company has ongoing litigation with the former Indeck stockholders. On March 12, 2007, the Court granted, in part, the Company’s Motion to Dismiss the Amended Complaint. The Court dismissed Counts 1 and 5 of the Amended Complaint. Count 1 included all claims of fraud against individual defendants. Those individuals were not named in other counts of the Amended Complaint, so they were dismissed as parties to the lawsuit. Count 5 asserted a claim for breach of the covenant of good faith and fair dealing relating to the alleged destruction of evidence. The Court approved the amendment of the complaint on other theories. The Company expects to file pre-trial motions to dismiss some or all of these claims. To the extent motions to dismiss are denied, a trial of this matter is set to commence on March 31, 2008.

The parties retained an arbitrator who will direct the process and decide the Earn-Out issues presently in arbitration, according to the procedure stated in the Merger Agreement. No date for a final decision has been set by the arbitrator.

The outcome of this matter is uncertain, as is the amount of contingent merger consideration that could be awarded following arbitration and/or litigation. If any additional merger consideration is awarded, it would be recorded as additional goodwill, which would be subject to a recoverability analysis under GAAP.

Las Vegas Cogeneration/Nevada Power Company Arbitration

On March 16, 2007, Nevada Power filed a Demand for Arbitration pursuant to a Power Purchase Agreement dated May 27, 1992, (the “Agreement”) between Nevada Power and LVC. Nevada Power asserts that LVC is in breach of its obligation under the Agreement to maintain a “reliable fuel supply throughout the term of the Power Contract.” On July 5, 2007, Nevada Power served an Amended Demand for Arbitration. The relief Nevada Power requests include: (1) A determination that the Agreement requires LVC to obtain and maintain firm, long-term fuel supply and transportation agreements for the full term of the Agreement; (2) A determination that LVC failed to honor this obligation; (3) A determination that LVC’s failure to obtain and maintain firm fuel supply and transportation agreements constitutes a material breach of the Agreement; and (4) An order of specific performance requiring LVC to enter into long-term fuel supply and transportation agreements to cure the alleged breach.

LVC denies all these claims and filed its response to the Demand for Arbitration, asserting the following defenses: (1) That Nevada Power failed to honor its contractual obligation to properly negotiate in good faith before filing the Demand for Arbitration; (2) That LVC has complied with its obligations relating to fuel supply and transportation; and (3) That numerous other affirmative defenses preclude Nevada Power from receiving the relief requested.

The arbitration demand was filed with the American Arbitration Association, pursuant to its Commercial Arbitration Rules. The parties selected an arbitrator and expect resolution to the matter by the end of 2007. During October 2007, the parties initiated negotiations for the resolution of this dispute and formally agreed to suspend the arbitration proceeding pending the completion of negotiations. While the Company cannot predict the final outcome of this action, it is not expected to have a material impact on the Company’s consolidated financial position or results of operations.

California Price Reporting and Anti-Trust Litigation

As disclosed in previous filings with the SEC, the Company’s subsidiary, Enserco, has ongoing litigation in the San Diego Superior Court, in the State of California, under the heading “In re Natural Gas Anti-Trust Cases I, II, III, IV and V.” The lawsuits have been pending against other marketers, traders, transporters and sellers of natural gas since as early as 2004. The plaintiffs allege the defendants, including Enserco, used various practices to manipulate natural gas prices in California in violation of the Cartwright Act and other California state laws. Enserco had filed motions to dismiss, which were pending before the court. On June 2, 2007, Enserco reached a settlement agreement set forth in a Letter of Intent. Final documentation is expected to be completed by the end of 2007. The Company has previously made accruals sufficient to cover the agreed upon settlement payment, the amount of which is not material to the Company’s consolidated financial position, results of operations or cash flows.

FERC Compliance Investigation

Following an internal investigation of natural gas marketing activities conducted within the Wholesale energy group, the Company identified possible instances of noncompliance with regulatory requirements applicable to those activities. The Company has notified the staff of FERC of its findings. The Company has also evaluated recent public announcements of civil penalties ranging from $0.3 million to $7.0 million that have been levied against other companies for violations of FERC regulatory requirements. We believe we have adequately reserved for the estimated potential penalty that could be levied on the Company. Although the outcome of any legal or regulatory proceedings resulting from these matters cannot be predicted with any certainty, the final resolution of these matters could have a material impact on the consolidated net income of any particular period, but is not expected to have a material impact upon the Company’s overall consolidated financial position.

Except as described above, there have been no material developments in any previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first nine months of 2007.

(16)	ACQUISITIONS

Aquila

On February 7, 2007, the Company entered into a definitive agreement with Aquila for the asset acquisition of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The purchase price of the assets is $940 million, subject to closing adjustments.

The purchase is conditioned on the completion of the acquisition of the outstanding shares of Aquila by Great Plains immediately following the sale of the regulated utilities to the Company. During October 2007, shareholder approvals of the merger were completed. The purchase is also subject to regulatory approvals from the Missouri Public Service Commission, the Kansas Corporation Commission, the Colorado Public Utilities Commission, the Nebraska Public Service Commission, the Iowa Utiliti