United States
Securities and Exchange Commission 
Washington, D.C. 20549
Form 10-Q 
X 	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 	

          For the quarterly period ended September 30, 2004. 
OR 
___   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 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___ 
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). 
Yes   X                   No___ 
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 29, 2004 
                                                            Common stock, $1.00 par value                                          32,469,651 shares 

TABLE OF CONTENTS 
		Page	
PART 1. 

Item 1. 

Item 2. 

Item 3. 

Item 4. 

PART II. 

Item 1. 

Item 2. 

Item 6. 

	FINANCIAL INFORMATION

Financial Statements

Condensed Consolidated Statements of Income -
   Three and Nine Months Ended September 30, 2004 and 2003 

Condensed Consolidated Balance Sheets -
   September 30, 2004, December 31, 2003 and September 30, 2003 

Condensed Consolidated Statements of Cash Flows -
   Nine Months Ended September 30, 2004 and 2003 

Notes to Condensed Consolidated Financial Statements 

Management's Discussion and Analysis of Financial Condition and
   Results of Operations 

Quantitative and Qualitative Disclosures about Market Risk 

Controls and Procedures 

OTHER INFORMATION

Legal Proceedings 

Unregistered Sales of Equity Securities and Use of Proceeds 

Exhibits 

Signatures 

Exhibit Index 	

3

4

5

6-30

31-49

50-51

51

52

52

53

54

55 	
2 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
	Three Months Ended  
September 30  	Nine Months Ended  
September 30  	
	2004
	 	2003
	 	2004
	 	2003
	 	
	(in thousands, except per share amounts)	

Operating revenues	 	 	$	279,614	 	$	296,860	 	$	834,297	 	$	877,548	 	
Contract termination revenue	 	 	 	--	 	 	114,000	 	 	--	 	 	114,000	 	
									
 	 	 	 	279,614	 	 	410,860	 	 	834,297	 	 	991,548	 	
									
Operating expenses:	 	 		
     Fuel and purchased power	 	 	 	175,833	 	 	184,591	 	 	530,839	 	 	555,296	 	
     Operations and maintenance	 	 	 	22,773	 	 	25,887	 	 	73,037	 	 	76,659	 	
     Administrative and general	 	 	 	16,088	 	 	17,431	 	 	49,951	 	 	56,206	 	
     Depreciation, depletion and amortization	 	 	 	22,062	 	 	20,185	 	 	65,812	 	 	59,263	 	
     Taxes, other than income taxes	 	 	 	5,545	 	 	6,515	 	 	21,765	 	 	22,041	 	
     Impairment of long-lived assets	 	 	 	--	 	 	117,207	 	 	--	 	 	117,207	 	
									
 	 	 	 	242,301	 	 	371,816	 	 	741,404	 	 	886,672	 	
									
Equity in earnings (loss) of unconsolidated subsidiaries	 	 	 	285	 	 	894	 	 	(723	)	 	5,758	 	
									
Operating income	 	 	 	37,598	 	 	39,938	 	 	92,170	 	 	110,634	 	
									
Other income (expense):	 	 		
     Interest expense	 	 	 	(12,085	)	 	(13,749	)	 	(39,155	)	 	(39,313	)	
     Interest income	 	 	 	339	 	 	138	 	 	1,072	 	 	467	 	
     Other expense	 	 	 	(83	)	 	(3	)	 	(276	)	 	(262	)	
     Other income	 	 	 	196	 	 	321	 	 	792	 	 	1,010	 	
									
 	 	 	 	(11,633	)	 	(13,293	)	 	(37,567	)	 	(38,098	)	
									
Income from continuing operations before minority	 	 		
  interest, income taxes and change in accounting principle	 	 	 	25,965	 	 	26,645	 	 	54,603	 	 	72,536	 	
Minority interest	 	 	 	(48	)	 	--	 	 	(134	)	 	--	 	
Income taxes	 	 	 	(8,569	)	 	(8,972	)	 	(17,575	)	 	(25,659	)	
									
Income from continuing operations before change in accounting principles	 	 	 	17,348	 	 	17,673	 	 	36,894	 	 	46,877	 	
(Loss) income from discontinued operations, net of taxes	 	 	 	(168	)	 	4,771	 	 	1,587	 	 	9,085	 	
Change in accounting principles, net of taxes	 	 	 	--	 	 	--	 	 	--	 	 	(2,680	)	
									
         Net income	 	 	 	17,180	 	 	22,444	 	 	38,481	 	 	53,282	 	
Preferred stock dividends	 	 	 	(78	)	 	(57	)	 	(244	)	 	(172	)	
									
Net income available for common stock	 	 	$	17,102	 	$	22,387	 	$	38,237	 	$	53,110	 	
									
Weighted average common shares outstanding:	 	 		
     Basic	 	 	 	32,420	 	 	32,087	 	 	32,372	 	 	29,922	 	
									
     Diluted	 	 	 	32,913	 	 	32,754	 	 	32,885	 	 	30,457	 	
									
Earnings per share:	 	 		
Basic-	 	 		
     Continuing operations	 	 	$	0.53	 	$	0.55	 	$	1.13	 	$	1.56	 	
     Discontinued operations	 	 	 	--	 	 	0.15	 	 	0.05	 	 	0.30	 	
     Change in accounting principle	 	 	 	--	 	 	--	 	 	--	 	 	(0.09	)	
									
     Total	 	 	$	0.53	 	$	0.70	 	$	1.18	 	$	1.77	 	
									
Diluted-	 	 		
     Continuing operations	 	 	$	0.53	 	$	0.54	 	$	1.12	 	$	1.54	 	
     Discontinued operations	 	 	 	(0.01	)	 	0.15	 	 	0.05	 	 	0.30	 	
     Change in accounting principle	 	 	 	--	 	 	--	 	 	--	 	 	(0.09	)	
									
     Total	 	 	$	0.52	 	$	0.69	 	$	1.17	 	$	1.75	 	
									
Dividends paid per share of common stock	 	 	$	0.31	 	$	0.30	 	$	0.93	 	$	0.90	 	
									
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements. 
3 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
	September 30
2004	December 31
2003	September 30
2003	
	(in thousands, except share amounts)	
                                     ASSETS	 	 	 		 	 		 	 		 	
Current assets:	 	 		
     Cash and cash equivalents	 	 	$	79,942	 	$	172,759	 	$	269,669	 	
     Restricted cash	 	 	 	--	 	 	1,350	 	 	1,070	 	
     Receivables (net of allowance for doubtful accounts of $7,359; $7,345 and $4,156, respectively)	 	 	 	201,618	 	 	201,976	 	 	166,819	 	
     Materials, supplies and fuel	 	 	 	123,027	 	 	44,895	 	 	46,692	 	
     Derivative assets	 	 	 	36,271	 	 	26,804	 	 	23,781	 	
     Prepaid income taxes	 	 	 	4,241	 	 	18,940	 	 	--	 	
     Deferred income taxes	 	 	 	4,085	 	 	4,256	 	 	4,940	 	
     Other current assets	 	 	 	5,582	 	 	8,875	 	 	6,058	 	
     Assets of discontinued operations	 	 	 	3,751	 	 	4,575	 	 	6,197	 	
							
 	 	 	 	458,517	 	 	484,430	 	 	525,226	 	
							
Investments	 	 	 	23,900	 	 	26,847	 	 	24,274	 	
							
Property, plant and equipment	 	 	 	1,946,396	 	 	1,882,545	 	 	1,742,821	 	
     Less accumulated depreciation and depletion	 	 	 	(501,893	)	 	(440,274	)	 	(420,725	)	
							
 	 	 	 	1,444,503	 	 	1,442,271	 	 	1,322,096	 	
							
Other assets:	 	 		
     Derivative assets	 	 	 	625	 	 	1,002	 	 	552	 	
     Goodwill	 	 	 	30,144	 	 	30,144	 	 	24,112	 	
     Intangible assets (net of accumulated amortization of $20,910; $18,423 and $17,592, respectively)	 	 	 	37,583	 	 	40,070	 	 	40,901	 	
     Other	 	 	 	36,263	 	 	38,488	 	 	25,462	 	
							
 	 	 	 	104,615	 	 	109,704	 	 	91,027	 	
							
 	 	 	$	2,031,535	 	$	2,063,252	 	$	1,962,623	 	
							
                      LIABILITIES AND STOCKHOLDERS' EQUITY	 	 		
Current liabilities:	 	 		
     Accounts payable	 	 	$	172,958	 	$	162,706	 	$	171,149	 	
     Accrued liabilities	 	 	 	59,172	 	 	66,618	 	 	74,723	 	
     Accrued income taxes	 	 	 	6,839	 	 	5,752	 	 	73,393	 	
     Current maturities of long-term debt	 	 	 	61,016	 	 	17,659	 	 	18,075	 	
     Derivative liabilities	 	 	 	57,288	 	 	32,967	 	 	25,307	 	
     Liabilities of discontinued operations	 	 	 	589	 	 	3,444	 	 	3,800	 	
							
 	 	 	 	357,862	 	 	289,146	 	 	366,447	 	
							
Long-term debt, net of current maturities	 	 	 	736,959	 	 	868,459	 	 	747,211	 	
							
Deferred credits and other liabilities:	 	 		
     Deferred income taxes	 	 	 	145,436	 	 	125,040	 	 	87,199	 	
     Derivative liabilities	 	 	 	1,860	 	 	3,247	 	 	3,237	 	
     Other	 	 	 	63,667	 	 	62,924	 	 	59,885	 	
							
 	 	 	 	210,963	 	 	191,211	 	 	150,321	 	
							
Minority interest in subsidiaries	 	 	 	4,782	 	 	4,689	 	 	--	 	
							
Stockholders' equity:	 	 		
    Preferred stock - no par Series 2000-A; 21,500 shares authorized; Issued and	 	 		
       outstanding: 6,839; 7,771 and 5,177 shares, respectively	 	 	 	7,167	 	 	8,143	 	 	5,549	 	
							
    Common stock equity-	 	 		
      Common stock $1 par value; 100,000,000 shares authorized;	 	 		
         Issued 32,586,929; 32,447,765 and 32,293,220 shares, respectively	 	 	 	32,587	 	 	32,448	 	 	32,293	 	
      Additional paid-in capital	 	 	 	383,786	 	 	379,271	 	 	375,185	 	
      Retained earnings	 	 	 	312,661	 	 	304,567	 	 	306,392	 	
      Treasury stock at cost - 117,778; 150,048 and 159,966 shares, respectively	 	 	 	(2,842	)	 	(3,560	)	 	(3,788	)	
      Accumulated other comprehensive loss	 	 	 	(12,390	)	 	(11,122	)	 	(16,987	)	
							
 	 	 	 	713,802	 	 	701,604	 	 	693,095	 	
							
     Total stockholders' equity	 	 	 	720,969	 	 	709,747	 	 	698,644	 	
							
 	 	 	$	2,031,535	 	$	2,063,252	 	$	1,962,623	 	
							
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements. 
4

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
	Nine Months Ended
September 30	
	2004
	 	2003
	 	
	(in thousands)	
Operating activities:	 	 	 		 	 		 	
     Net income available for common	 	 	$	38,237	 	$	53,110	 	
     Adjustments to reconcile net income available for common to net cash	 	 		
       provided by operating activities:	 	 		
       Income from discontinued operations	 	 	 	(1,587	)	 	(9,085	)	
       Impairment of long-lived assets	 	 	 	--	 	 	117,207	 	
       Provision for valuation allowances	 	 	 	(70	)	 	(39	)	
       Depreciation, depletion and amortization	 	 	 	65,812	 	 	59,263	 	
       Net change in derivative assets and liabilities	 	 	 	6,491	 	 	(4,854	)	
       Deferred income taxes	 	 	 	21,144	 	 	(40,433	)	
       Net (undistributed) distributed earnings in associated companies	 	 	 	3,448	 	 	(5,758	)	
       Minority interest	 	 	 	134	 	 	--	 	
       Change in accounting principles	 	 	 	--	 	 	2,680	 	
     Change in operating assets and liabilities-	 	 		
       Accounts receivable and other current assets	 	 	 	(54,498	)	 	(19,853	)	
       Accounts payable and other current liabilities	 	 	 	2,763	 	 	81,192	 	
       Other operating activities	 	 	 	2,636	 	 	(911	)	
					
 	 	 	 	84,510	 	 	232,519	 	
					
Investing activities:	 	 		
     Property, plant and equipment additions	 	 	 	(65,572	)	 	(77,912	)	
     Payment for acquisition of minority interests	 	 	 	--	 	 	(9,000	)	
     Proceeds from sale of assets	 	 	 	--	 	 	185,926	 	
     Increase in notes receivable - Mallon Resources	 	 	 	--	 	 	(5,164	)	
     Other investing activities	 	 	 	3,144	 	 	(455	)	
					
 	 	 	 	(62,428	)	 	93,395	 	
					
Financing activities:	 	 		
     Dividends paid	 	 	 	(30,143	)	 	(27,346	)	
     Common stock issued	 	 	 	3,678	 	 	121,206	 	
     Decrease in short-term borrowings, net	 	 	 	--	 	 	(340,500	)	
     Long-term debt - issuance	 	 	 	--	 	 	252,000	 	
     Long-term debt - repayments	 	 	 	(88,143	)	 	(129,394	)	
     Other financing activities	 	 	 	(291	)	 	(7,132	)	
					
 	 	 	 	(114,899	)	 	(131,166	)	
					
         (Decrease) increase in cash and cash equivalents	 	 	 	(92,817	)	 	194,748	 	
Cash and cash equivalents:	 	 		
     Beginning of period	 	 	 	172,759	 	 	74,921	 	
					
     End of period	 	 	$	79,942	 	$	269,669	 	
					
Supplemental disclosure of cash flow information:	 	 		
     Cash paid during the period for-	 	 		
       Interest	 	 	$	35,461	 	$	47,219	 	
       Income taxes paid (refunded), net	 	 	$	(18,637	)	$	6,549	 	

Non-cash net assets acquired through issuance of common stock and	 	 		
decrease in notes receivable - Mallon Resources	 	 	$	--	 	$	51,153	 	
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements. 
5

BLACK HILLS CORPORATION 
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2003 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 Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States 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 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission. 	

  	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, 2004, December 31, 2003 and September 30, 2003, financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 30, 2004, 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) 	    RECLASSIFICATIONS	

  	Certain 2003 amounts in the financial statements have been reclassified to conform to the 2004 presentation. These reclassifications did not have an effect on the Company’s total stockholders’ equity or net income available for common stock as previously reported. 	

(3) 	    STOCK-BASED COMPENSATION 	

  	At September 30, 2004, the Company had three stock-based employee compensation plans under which it can issue stock options to its employees. The Company accounts for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations. No employee compensation cost related to stock options is reflected in net income, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. 	

6 

  	The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation” (SFAS 123), to stock-based employee compensation (in thousands, except per share amounts): 	

	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	 	2003
	 	2004
	 	2003
		
Net income available for common	 	 	 		 	 		 	 		 	 		 	
  stock, as reported	 	 	$	17,102	 	$	22,387	 	$	38,237	 	$	53,110	 	
Deduct: Total stock-based employee	 	 		
  compensation expense determined	 	 		
  under fair value based method for all	 	 		
  awards, net of related tax effects	 	 	 	(176	)	 	(282	)	 	(496	)	 	(725	)	
									
Pro forma net income	 	 	$	16,926	 	$	22,105	 	$	37,741	 	$	52,385	 	
									
Earnings per share:	 	 		
As reported--	 	 		
Basic	 	 		
     Continuing operations	 	 	$	0.53	 	$	0.55	 	$	1.13	 	$	1.56	 	
     Discontinued operations	 	 	 	--	 	 	0.15	 	 	0.05	 	 	0.30	 	
     Change in accounting principles	 	 	 	--	 	 	--	 	 	--	 	 	(0.09	)	
									
         Total	 	 	$	0.53	 	$	0.70	 	$	1.18	 	$	1.77	 	
									
Diluted	 	 		
     Continuing operations	 	 	$	0.53	 	$	0.54	 	$	1.12	 	$	1.54	 	
     Discontinued operations	 	 	 	(0.01	)	 	0.15	 	 	0.05	 	 	0.30	 	
     Change in accounting principles	 	 	 	--	 	 	--	 	 	--	 	 	(0.09	)	
									
         Total	 	 	$	0.52	 	$	0.69	 	$	1.17	 	$	1.75	 	
									
Pro forma--	 	 		
Basic	 	 		
     Continuing operations	 	 	$	0.53	 	$	0.54	 	$	1.12	 	$	1.54	 	
     Discontinued operations	 	 	 	--	 	 	0.15	 	 	0.05	 	 	0.30	 	
     Change in accounting principles	 	 	 	--	 	 	--	 	 	--	 	 	(0.09	)	
									
         Total	 	 	$	0.53	 	$	0.69	 	$	1.17	 	$	1.75	 	
									
Diluted	 	 		
     Continuing operations	 	 	$	0.52	 	$	0.53	 	$	1.11	 	$	1.52	 	
     Discontinued operations	 	 	 	(0.01	)	 	0.15	 	 	0.05	 	 	0.30	 	
     Change in accounting principles	 	 	 	--	 	 	--	 	 	--	 	 	(0.09	)	
									
         Total	 	 	$	0.51	 	$	0.68	 	$	1.16	 	$	1.73	 	
									
7

(4) 	    RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS 	

  	In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-2), which provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (2003 Medicare Act) for employers that sponsor postretirement healthcare plans that provide prescription drug benefits. FSP 106-2 supersedes FSP 106-1 that was issued in January 2004 under the same title. FSP 106-2 is effective for the first interim period beginning after June 15, 2004. The Company provides prescription drug benefits to certain eligible employees and will include the effects of the 2003 Medicare Act on its next actuarial measurement of the accumulated postretirement benefit obligation or net periodic postretirement benefit cost. The Company uses a September 30 measurement date for the Plan. 	

  	In April 2004, the FASB issued FSP FAS 141-1 and FAS 142-1, “Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-2, Whether Mineral Rights Are Tangible or Intangible Assets.” The FSP amends SFAS 141 and SFAS 142 to conform with the EITF consensus in EITF 04-2 that mineral rights, as defined by EITF 04-2, are tangible assets. When the Company adopted SFAS 142 on January 1, 2002, the amounts related to mineral rights were already classified as tangible assets and continue to be classified in “Property, plant and equipment” on the accompanying Condensed Consolidated Balance Sheets. The adoption of FSP FAS 141-1 and FAS 142-1 had no effect on the Company’s consolidated financial position, results of operations or cash flows. 	

(5) 	    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): 	

Major Classification	September 30,
2004	December 31,
2003	September 30,
2003	

Natural gas and oil held by	 	 	 		 	 		 	 		 	
  Energy Marketing	 	 	$	99,350	 	$	24,394	 	$	28,355	 	
Materials and supplies	 	 	 	22,387	 	 	18,920	 	 	17,049	 	
Fuel for generation	 	 	 	1,290	 	 	1,581	 	 	1,288	 	
							
Total materials, supplies and fuel	 	 	$	123,027	 	$	44,895	 	$	46,692	 	

  	The inventory held by our natural gas marketing company is in the form of storage agreements. The 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. Most of this natural gas is currently projected to flow out of inventory in the fourth quarter of 2004 and the first quarter of 2005. If changing market conditions make it economically advantageous to do so, the duration of holding significant amounts of natural gas in inventory could be extended. 	

8

(6) 	    ASSET RETIREMENT OBLIGATIONS 	

  	SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation have been recognized for the time period from the date the liability would have been recognized had the provisions of SFAS 143 been in effect, to the date of its adoption. 	

  	The Company has identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in our Oil and Gas segment and reclamation of our coal mining sites in our Mining segment. 	

  	The following table presents the details of the Company’s asset retirement obligations which are included on the accompanying Condensed Consolidated Balance Sheets in “Other” under “Deferred credits and other liabilities” (in thousands): 	

	Balance at
12/31/03
	Liabilities
Incurred
	Liabilities
Settled
	Accretion
	Cash Flow
Revisions
	Balance at
9/30/04

Oil and Gas	 	 	$	7,233	 	$	--	 	$	--	 	$	412	 	$	--	 	$	7,645	 	
Mining	 	 	 	15,752	 	 	485	 	 	(354	)	 	597	 	 	--	 	 	16,480	 	
													
Total	 	 	$	22,985	 	$	485	 	$	(354	)	$	1,009	 	$	--	 	$	24,125	 	

(7) 	    VARIABLE INTEREST ENTITY 	

  	In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). In December 2003, the FASB issued FIN No. 46 (Revised) (FIN 46-R) to address certain FIN 46 implementation issues. The Company’s subsidiary, Black Hills Wyoming, has an agreement with Wygen Funding, Limited Partnership, an unrelated variable interest entity (VIE) to lease the Wygen plant. Under the accounting interpretation, as amended, the Company consolidated the VIE effective December 31, 2003. The effect of consolidating the VIE into the Company’s Consolidated Balance Sheet at December 31, 2003 was an increase in total assets of $129.0 million, of which $121.5 million, net of accumulated depreciation of $3.0 million, is included in Property, plant and equipment and an increase in long-term debt in the amount of $128.3 million. 	

  	Prior to the December 31, 2003 consolidation, the Company recorded lease expense on the Wygen plant. Lease payments began upon completion of the plant in February 2003. During the three and nine months ended September 30, 2003, lease payments were $0.9 million and $3.0 million, respectively, and are included in Operations and maintenance on the accompanying 2003 Condensed Consolidated Statements of Income. The net effect on current results is to recognize depreciation and interest expense in place of recognizing lease expense. During the three and nine months ended September 30, 2004, depreciation expense was $0.8 million and $2.5 million, respectively and interest expense was $0.9 million and $2.5 million, respectively. 	

9

(8) 	    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: 	

Period ended September 30, 2004
(in thousands)	Three Months
	Nine Months
	
	Income
	Average
Shares
	Income
	Average
Shares

Income from continuing operations	 	 	$	17,348	 	 	 	 	$	36,894	 	 	 	 	
Less: preferred stock dividends	 	 	 	(78	)	 	 	 	 	(244	)	 	 	 	
							
Basic - available for common	 	 		
  shareholders	 	 	 	17,270	 	 	32,420	 	 	36,650	 	 	32,372	 	
Dilutive effect of:	 	 		
     Stock options	 	 	 	--	 	 	75	 	 	--	 	 	98	 	
     Convertible preferred stock	 	 	 	78	 	 	195	 	 	244	 	 	195	 	
     Estimated contingent shares	 	 		
       issuable for prior acquisition	 	 	 	--	 	 	158	 	 	--	 	 	158	 	
     Others	 	 	 	--	 	 	65	 	 	--	 	 	62	 	
									
Diluted - available for common shareholders	 	 	$	17,348	 	 	32,913	 	$	36,894	 	 	32,885	 	

Period ended September 30, 2003
(in thousands)	Three Months
	Nine Months
	
	Income
	Average
Shares
	Income
	Average
Shares

Income from continuing operations	 	 	$	17,673	 	 	 	 	$	46,877	 	 	 	 	
Less: preferred stock dividends	 	 	 	(57	)	 	 	 	 	(172	)	 	 	 	
							
Basic - available for common	 	 		
  shareholders	 	 	 	17,616	 	 	32,087	 	 	46,705	 	 	29,922	 	
Dilutive effect of:	 	 		
     Stock options	 	 	 	--	 	 	139	 	 	--	 	 	92	 	
     Convertible preferred stock	 	 	 	57	 	 	148	 	 	172	 	 	148	 	
     Estimated contingent shares	 	 		
       issuable for prior acquisition	 	 	 	--	 	 	335	 	 	--	 	 	257	 	
     Others	 	 	 	--	 	 	45	 	 	--	 	 	38	 	
									
Diluted - available for common shareholders	 	 	$	17,673	 	 	32,754	 	$	46,877	 	 	30,457	 	

  	On April 30, 2003, the Company completed a public offering of 4.6 million shares of common stock. Accordingly, this transaction significantly affects the weighted average number of common shares outstanding used in earnings per share calculations for the current and for future periods. 	

10

(9) 	    COMPREHENSIVE INCOME 	

  	The following table presents the components of the Company’s comprehensive (loss) income (in thousands): 	

	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003

Net income	 	 	$	17,180	 	$	22,444	 	$	38,481	 	$	53,282	 	
Other comprehensive (loss) income,	 	 		
net of tax:	 	 		
  Fair value adjustment on	 	 		
     derivatives designated as cash	 	 		
     flow hedges, (2003 is net of	 	 		
     minority interest share of $331	 	 		
     for the nine month period ended	 	 		
     September 30, 2003)	 	 	 	(1,484	)	 	2,331	 	 	(1,166	)	 	276	 	
  Unrealized loss on	 	 		
     available-for-sale securities	 	 	 	(47	)	 	--	 	 	(101	)	 	--	 	
  Reclassification adjustment for	 	 		
     interest rate swaps designated	 	 		
     as cash flow hedges settled as	 	 		
     part of the hydroelectric sale	 	 		
     and included in net income, net	 	 		
     of minority interest of $2,379	 	 		
     for the three and nine months	 	 		
     ended September 30, 2003	 	 	 	--	 	 	3,928	 	 	--	 	 	3,928	 	
									
Comprehensive income	 	 	$	15,649	 	$	28,703	 	$	37,214	 	$	57,486	 	
									
11

(10) 	    CHANGES IN COMMON STOCK 	

  	Other than the following transactions, the Company had no other material changes in its common stock, as reported in Note 8 of the Company’s 2003 Annual Report on Form 10-K. 	

  	•	  	On March 1, 2004, certain officers of the Company were named participants in a performance share award plan. Entitlement to performance shares is based on the Company’s total shareholder return over designated performance periods as measured against a selected peer group. In addition, the Company’s stock price must also increase during the performance periods. Target grants of performance shares were made for the following performance periods: 	

Grant Date	          Performance Period	Total
Target Grant of
Shares	
March 1, 2004	 	 	March 1, 2004 - December 31, 2005	 	 	 	15,458	 	
March 1, 2004	 	 	March 1, 2004 - December 31, 2006	 	 	 	31,384	 	

  		  	Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50th percentile of the selected peer group. The final value of the performance shares may vary according to the number of shares of common stock that are ultimately granted based upon the performance criteria. Compensation expense recognized for the performance share awards for the three and nine month periods ended September 30, 2004 was $0 and $0.3 million, respectively. The performance awards are paid in 50 percent cash and 50 percent common stock. 	

  	•	  	932 shares of the Preferred Stock, Series 2000-A were converted into 26,628 shares of common stock at the conversion price of $35.00 per share. 	

  	•	  	The Company granted 34,328 shares of restricted stock and 16,019 restricted stock units and issued 11,215 shares of common stock for the conversion of restricted stock units. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $1.4 million will be recognized over the vesting period as follows: $0.6 million in 2004, $0.4 million in 2005, $0.3 million in 2006 and $0.1 million in 2007. 	

  	•	  	The Company granted 103,000 stock options at a weighted average exercise price of $30.02 per share. 	

  	•	  	68,433 stock options were exercised at a weighted average price of $22.00 per share. 	

  	•	  	The Company issued 10,310 shares of common stock from treasury shares under the short-term incentive compensation plan. Compensation cost related to the award was approximately $0.3 million, which was accrued for in 2003. 	

  	•	  	The Company issued 22,934 shares of common stock under its dividend reinvestment plan at a weighted average price of $30.41 per share. 	

12

  	•	  	The Company issued 9,954 shares of common stock under its employee stock purchase plan at a price of $28.59 per share. 	

  	•	  	The Company acquired 4,005 shares of treasury stock related to a forfeiture of unvested restricted stock. 	

  	•	  	The Company acquired 7,508 shares of treasury stock related to the share withholding provisions of the restricted stock plan for the payment of taxes associated with the vesting of shares of restricted stock for certain officers and key employees. 	

(11) 	    CHANGES IN LONG-TERM DEBT AND NOTES PAYABLE 	

  	On January 30, 2004, the Company repaid $45 million of the long-term debt outstanding on the project-level debt at our Fountain Valley facility. 	

  	On May 10, 2004, the Company repurchased $25 million of its 6.5 percent senior unsecured notes due 2013. 	

  	On May 13, 2004, the Company closed on a $125 million 364-day credit facility which replaced the $200 million facility which was to expire in August 2004. The Company also amended its $225 million multi-year facility that expires in August 2006 to conform its compliance calculation to the same calculation as in the new $125 million facility. Based on the Company’s current credit ratings, the interest rate under the new $125 million facility is LIBOR plus 1.30 percent and the utilization fee rate is 0.25 percent. 	

  	On May 14, 2004, Enserco Energy Inc. amended its credit agreement increasing the facility amount by $15 million to $150 million and on September 30, 2004, the facility was renewed to September 30, 2005. 	

  	On August 31, 2004, the Company effected a call on Black Hills Power’s $5.9 million, 6.7 percent Pollution Control Revenue Bonds issued through Lawrence County, South Dakota. The bonds had a maturity date of 2010. 	

  	On September 21, 2004, the Company initiated a notice to call effective October 21, 2004, the entire $45 million Series AB 8.3 percent bonds. The bonds had a maturity date of 2024. Due to the notice to call, the bonds have been classified to current maturities of long-term debt on the September 30, 2004 Balance Sheet. 	

(12) 	  GUARANTEES 	

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

  	As prescribed in FASB Interpretation No. 45, the Company records a liability for the fair value of the obligation it has undertaken for guarantees issued after December 31, 2002. The liability recognition requirements of FASB Interpretation No. 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002, while the disclosure requirements are applied to all guarantees. 	

13

  	As of September 30, 2004, the Company had the following guarantees in place (in thousands): 	

Nature of Guarantee	Outstanding at
September 30,
2004	Year
Expiring	

Guarantee payments under the Las Vegas Cogen I Power Purchase and	 	 	 		 	 	Upon 5 days	 	
    Sales Agreement with Sempra Energy Solutions	 	 	$	10,000	 	 	written notice	 	

Guarantee payments of Las Vegas Cogen II to Nevada Power Company	 	 		
    under a power purchase agreement	 	 	 	5,000	 	 	2013	 	

Guarantee of certain obligations under Enserco's credit facility	 	 	 	3,000	 	 	2005	 	

Guarantee of obligation of Las Vegas Cogen II under an	 	 		
    interconnection and operation agreement	 	 	 	750	 	 	2005	 	

Guarantee payments of Black Hills Power under various transactions	 	 		
    with Idaho Power Company	 	 	 	500	 	 	2005	 	

Guarantee payments of Black Hills Power under various transactions	 	 		
    with Southern California Edison Company	 	 	 	750	 	 	2005	 	

Guarantee obligations under the Wygen Plant Lease	 	 	 	111,018	 	 	2008	 	

Guarantee payment and performance under credit agreements for two	 	 		
    combustion turbines	 	 	 	28,714	 	 	2010	 	

Indemnification for subsidiary reclamation/surety bonds	 	 	 	26,481	 	 	Ongoing	 	
				
 	 	 	$	186,213	 	 	 	 	

  	The Company has guaranteed up to $10.0 million of payments of its power generation subsidiary, Las Vegas Cogeneration Limited Partnership, to Sempra Energy Solutions which may arise from transactions entered into by the two parties under a Master Power Purchase and Sale Agreement. To the extent liabilities exist under this power and purchase sale agreement subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. The guarantee may be terminated for future transactions upon five days written notice. 	

  	The Company has guaranteed up to $5.0 million of payments of its power generation subsidiary, Las Vegas Cogeneration II, LLC under the Western Systems Power Pool Confirmation Agreement with Nevada Power Company. To the extent liabilities exist under the agreements subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. The guarantee expires upon payment in full of all the obligations under the contract, which expires in 2013. 	

  	The Company has guaranteed up to $3.0 million of Enserco Energy Inc.’s obligations to Fortis Capital Corp. under its credit facility. There are no liabilities on the Company’s Condensed Consolidated Balance Sheets associated with this guarantee. 	

14

  	The Company has guaranteed up to $0.8 million of the obligations of Las Vegas Cogeneration II, LLC under an interconnection and operations agreement for the LV II unit. To the extent liabilities exist under the interconnection and operations agreement, such liabilities are included in the Condensed Consolidated Balance Sheets. The obligation is due May 20, 2005. 	

  	The Company has guaranteed up to $0.5 million of the obligations of its electric utility subsidiary, Black Hills Power, Inc., under various transactions with Idaho Power Company. To the extent liabilities exist under these transactions and subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. This guarantee expires on the earlier of March 1, 2005 or 30 days after the date creditor receives written notification from guarantor. 	

  	The Company has guaranteed up to $0.8 million of the obligations of its electric utility subsidiary, Black Hills Power, Inc., under various transactions with Southern California Edison Company. To the extent liabilities exist under these transactions and subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. This guarantee expires on the earlier of April 1, 2005 or 30 days after the date creditor receives written notification from guarantor. 	

  	The Company has guaranteed the obligations of Black Hills Wyoming under the Agreement for Lease and Lease for the Wygen plant. The Company consolidates the Variable Interest Entity that owns the plant into its financial statements; therefore the obligations associated with this guarantee are included in the Condensed Consolidated Balance Sheets. If the lease was terminated and sold, the Company’s obligation is the amount of deficiency in the proceeds from the sale to repay the investors up to a maximum of 83.5 percent of the cost of the project. At September 30, 2004, the Company’s maximum obligation under the guarantee is $111.0 million (83.5 percent of $133.0 million, the cost incurred for the Wygen plant). The initial term of the lease is five years with two five-year renewal options. 	

  	The Company has guaranteed the payment of $24.6 million of debt of Black Hills Wyoming and $4.1 million of debt for another of the Company’s wholly-owned subsidiaries, Black Hills Generation. The debt is recorded on the Company’s Condensed Consolidated Balance Sheets and is due December 18, 2010. 	

  	In addition, at September 30, 2004, the Company had guarantees in place totaling approximately $26.5 million for reclamation and surety bonds for its subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in the Company’s Condensed Consolidated Balance Sheets. 	

15

(13) 	    EMPLOYEE BENEFIT PLANS 	

  	Defined Benefit Pension Plan 	

  	The Company has a noncontributory defined benefit pension plan (Plan) covering the employees of the Company and the following subsidiaries, Black Hills Power, Inc., Wyodak Resources Development Corp., Black Hills Exploration and Production and Daksoft who meet certain eligibility requirements. 	

  	The components of net periodic benefit cost for the Plan for the periods ended September 30 are as follows (in thousands): 	

	Three Months Ended	Nine Months Ended	
	2004
	2003
	2004
	2003

Service cost	 	 	$	443	 	$	323	 	$	1,329	 	$	969	 	
Interest cost	 	 	 	909	 	 	838	 	 	2,727	 	 	2,514	 	
Expected return on plan	 	 		
  assets	 	 	 	(1,129	)	 	(780	)	 	(3,387	)	 	(2,340	)	
Amortization of prior	 	 		
  service cost	 	 	 	58	 	 	58	 	 	174	 	 	174	 	
Amortization of net loss	 	 	 	375	 	 	352	 	 	1,125	 	 	1,056	 	
									
Net periodic benefit cost	 	 	$	656	 	$	791	 	$	1,968	 	$	2,373	 	

  	The Company does not anticipate that a contribution will be made to the Plan in the 2004 fiscal year. 	

  	Supplemental Nonqualified Defined Benefit Plan 	

  	The Company has various supplemental retirement plans for outside directors and key executives of the Company. The supplemental retirement plans are nonqualified defined benefit plans. 	

  	The components of net periodic benefit cost for the supplemental nonqualified plans for the periods ended September 30 are as follows (in thousands): 	

	Three Months Ended         	Nine Months Ended  	
	2004
	 	2003
	 	2004
	 	2003

Service cost	 	 	$	134	 	$	106	 	$	402	 	$	318	 	
Interest cost	 	 	 	241	 	 	190	 	 	723	 	 	570	 	
Amortization of prior	 	 		
  service cost (credit)	 	 	 	2	 	 	(1	)	 	6	 	 	(3	)	
Amortization of net loss	 	 	 	187	 	 	128	 	 	561	 	 	384	 	
									
Net periodic benefit cost	 	 	$	564	 	$	423	 	$	1,692	 	$	1,269	 	
									
16

  	The Company anticipates that contributions to the supplemental retirement plans for the 2004 fiscal year will be approximately $0.8 million; the contributions are expected to be in the form of benefit payments. 	

  	Non-pension Defined Benefit Postretirement Plan 	

  	Employees who are participants in the Company’s postretirement healthcare plan and who retire from the Company on or after attaining age 55 after completing at least five years of service to the Company are entitled to postretirement healthcare benefits. These financial statements and this Note do not reflect the effects of the 2003 Medicare Act on the postretirement benefit plan (see Note 4). 	

  	The components of net periodic benefit cost for the postretirement healthcare plan for the periods ended September 30 are as follows (in thousands): 	

	Three Months Ended	Nine Months Ended	
	2004
	2003
	2004
	2003
	
Service cost	 	 	$	140	 	$	96	 	$	420	 	$	288	 	
Interest cost	 	 	 	166	 	 	144	 	 	498	 	 	432	 	
Amortization of net	 	 		
  transition obligation	 	 	 	37	 	 	37	 	 	111	 	 	111	 	
Amortization of prior	 	 		
  service credit	 	 	 	(6	)	 	(6	)	 	(18	)	 	(18	)	
Amortization of net loss	 	 	 	47	 	 	22	 	 	141	 	 	66	 	
									
Net periodic benefit cost	 	 	$	384	 	$	293	 	$	1,152	 	$	879	 	

  	The Company anticipates that contributions to the postretirement healthcare plan for the 2004 fiscal year will be approximately $0.6 million; the contributions are expected to be in the form of benefits and administrative costs paid. 	

(14) 	     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, 2004, substantially all of the Company’s operations and assets are located within the United States. The Company’s operations are conducted through six reporting segments that include: Wholesale Energy group consisting of the following segments: Mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; Oil and Gas, which produces, explores and operates oil and gas interests located in the Rocky Mountain region, Texas, California and other states; Energy Marketing, which markets natural gas, oil and related services to customers in the Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions and transports crude oil in Texas; and Power Generation, which produces and sells generating capacity and electricity to wholesale customers; Retail Services group consisting of the following segments: Electric, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Communications, which primarily markets broadband communications services in Rapid City and the Northern Black Hills region of South Dakota. 	

17

  	Prior to 2004, the Company’s communications segment marketed campground reservation services and software development services to external parties through Daksoft, Inc. With the sale of certain assets and a change in its business strategy, Daksoft now primarily provides information technology support to the Company. With its focus now on corporate support, beginning with the first quarter 2004, Daksoft’s results of operations are included with corporate results. 	

  	Other than noted above, segment information follows the same accounting policies as described in Note 18 of the Company’s 2003 Annual Report on Form 10-K. In accordance with the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (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
Operating Revenues
	Inter-segment
Operating Revenues
	Income (loss) from
Continuing Operations

Quarter to Date	 	 	 		 	 		 	 		 	
September 30, 2004	 	 		

Energy marketing*	 	 	$	159,694	 	$	--	 	$	670	 	
Power generation	 	 	 	42,980	 	 	--	 	 	7,192	 	
Oil and gas	 	 	 	13,578	 	 	88	 	 	2,765	 	
Mining	 	 	 	3,776	 	 	3,256	 	 	2,537	 	
Electric	 	 	 	47,405	 	 	516	 	 	5,860	 	
Communications	 	 	 	9,455	 	 	--	 	 	(1,256	)	
Corporate	 	 	 	163	 	 	310	 	 	(420	)	
Intersegment eliminations	 	 	 	--	 	 	(1,607	)	 	--	 	
							
Total	 	 	$	277,051	 	$	2,563	 	$	17,348	 	
							
_________________ 
* 	  	All periods presented reflect a net presentation of revenues at the Company’s gas marketing subsidiary and a gross presentation of revenues at the Company’s crude oil marketing subsidiary in accordance with Emerging Issues Task Force (EITF) Issue 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3), and EITF Issue 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19). 	

18

	External
Operating Revenues
	Inter-segment
Operating Revenues
	Income (loss) from
Continuing Operations

Quarter to Date	 	 	 		 	 		 	 		 	
September 30, 2003	 	 		

Energy marketing*	 	 	$	168,908	 	$	--	 	$	1,324	 	
Power generation**	 	 	 	164,577	 	 	--	 	 	7,056	 	
Oil and gas	 	 	 	12,438	 	 	75	 	 	2,805	 	
Mining	 	 	 	6,011	 	 	3,166	 	 	2,234	 	
Electric	 	 	 	46,247	 	 	21	 	 	6,772	 	
Communications	 	 	 	10,136	 	 	--	 	 	(1,031	)	
Corporate	 	 	 	--	 	 	--	 	 	(1,487	)	
Intersegment eliminations	 	 	 	--	 	 	(719	)	 	--	 	
							
Total	 	 	$	408,317	 	$	2,543	 	$	17,673	 	
							
_________________ 
* 	  	All periods presented reflect a net presentation of revenues at the Company’s gas marketing subsidiary and a gross presentation of revenues at the Company’s crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19. 	

** 	  	Includes $114 million contract termination revenue as described in Note 18. 	

	External
Operating Revenues
	Inter-segment
Operating Revenues
	Income (loss) from
Continuing Operations

Year to Date	 	 	 		 	 		 	 		 	
September 30, 2004	 	 		

Energy marketing*	 	 	$	495,024	 	$	--	 	$	6,245	 	
Power generation	 	 	 	118,472	 	 	--	 	 	10,347	 	
Oil and gas**	 	 	 	40,776	 	 	260	 	 	7,215	 	
Mining	 	 	 	14,093	 	 	9,210	 	 	5,648	 	
Electric	 	 	 	128,819	 	 	558	 	 	12,712	 	
Communications	 	 	 	29,329	 	 	--	 	 	(3,209	)	
Corporate	 	 	 	630	 	 	946	 	 	(2,060	)	
Intersegment eliminations	 	 	 	--	 	 	(3,820	)	 	(4	)	
							
Total	 	 	$	827,143	 	$	7,154	 	$	36,894	 	
							
_________________ 
* 	  	All periods presented reflect a net presentation of revenues at the Company's gas marketing subsidiary and a gross presentation of revenues at the Company’s crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19. 	

** 	  	Includes a $(0.5) million revenue accrual correction. 	

19

	External
Operating Revenues
	Inter-segment
Operating Revenues
	Income (loss) from
Continuing Operations

Year to Date	 	 	 		 	 		 	 		 	
September 30, 2003	 	 		

Energy marketing*	 	 	$	523,597	 	$	--	 	$	4,079	 	
Power generation**	 	 	 	250,173	 	 	--	 	 	19,634	 	
Oil and gas	 	 	 	34,103	 	 	211	 	 	7,245	 	
Mining	 	 	 	16,552	 	 	8,954	 	 	4,722	 	
Electric	 	 	 	129,182	 	 	56	 	 	18,193	 	
Communications	 	 	 	30,595	 	 	--	 	 	(3,273	)	
Corporate	 	 	 	--	 	 	--	 	 	(3,722	)	
Intersegment eliminations	 	 	 	--	 	 	(1,875	)	 	(1	)	
							
Total	 	 	$	984,202	 	$	7,346	 	$	46,877	 	
							
_________________ 
* 	  	All periods presented reflect a net presentation of revenues at the Company’s gas marketing subsidiary and a gross presentation of revenues at the Company’s crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19. 	

** 	  	Includes $114 million contract termination revenue as described in Note 18. 	

  	The Company had no material changes in total assets of its reporting segments, as reported in Note 18 of the Company’s 2003 Annual Report on Form 10-K, beyond changes resulting from normal operating activities. 	

20

(15) 	     RISK MANAGEMENT ACTIVITIES 	

  	The Company actively manages its exposure to certain market risks as described in Note 2 of the Company’s 2003 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 Marketing 	

  	The contract or notional amounts and terms of the Company’s natural gas marketing activities and derivative commodity instruments that were marked-to-market on September 30, 2004, December 31, 2003 and September 30, 2003 are as follows: 	

	September 30, 2004	December 31, 2003	September 30, 2003	
(thousands of MMBtu's)	Notional
Amounts
	Maximum
Term in
Years
	Notional
Amounts
	Maximum Term
in Years
	Notional
Amounts
	Maximum Term
in Years

Natural gas basis swaps	 	 	 		 	 		 	 		 	 		 	 		 	 		 	
  purchased	 	 	 	28,793	 	 	1.5	 	 	13,028	 	 	1	 	 	46,026	 	 	1.25	 	
Natural gas basis swaps sold	 	 	 	30,548	 	 	1.5	 	 	12,691	 	 	1	 	 	45,589	 	 	1.25	 	
Natural gas fixed-for-float	 	 		
  swaps purchased	 	 	 	22,083	 	 	1	 	 	19,645	 	 	1.5	 	 	17,822	 	 	1	 	
Natural gas fixed-for-float	 	 		
  swaps sold	 	 	 	26,090	 	 	1.25	 	 	21,752	 	 	1.5	 	 	22,097	 	 	1.25	 	
Natural gas physical purchases	 	 	 	64,395	 	 	1.5	 	 	50,757	 	 	2.25	 	 	43,131	 	 	1.5	 	
Natural gas physical sales	 	 	 	114,031	 	 	5	 	 	44,066	 	 	2.25	 	 	49,874	 	 	1.5	 	
_________________ 
  	Derivative contracts related to the Company’s natural gas marketing activities were marked to fair value and the 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
Derivative
Assets
	Non-current
Derivative
Assets
	Current
Derivative
Liabilities
	Non-current
Derivative
Liabilities
	Unrealized
Gain (loss)

September 30, 2004	 	 	$	36,244	 	$	625	 	$	48,569	 	$	329	 	$	(12,029	)	
											
December 31, 2003	 	 	$	26,376	 	$	1,002	 	$	26,495	 	$	1,291	 	$	(408	)	
											
September 30, 2003	 	 	$	22,507	 	$	552	 	$	20,327	 	$	371	 	$	2,361	 	
											
21

  	For the nine month periods ended September 30, 2004 and 2003, contracts and other activities at the Company’s natural gas marketing operations are accounted for under the provisions of EITF 02-3 and SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). As such, all of the contracts and other activities at the Company’s natural gas marketing operations that meet the definition of a derivative under SFAS 133 are accounted for at fair value. EITF 02-3, adopted on January 1, 2003, precludes mark-to-market accounting for energy trading contracts that are not derivatives pursuant to SFAS 133. The prior authoritative accounting guidance applied was EITF Issue 98-10 “Accounting for Contracts Involving Energy Trading and Risk Management Activities” (EITF 98-10), which allowed a broad interpretation of what constituted “trading activity” and hence what would be marked-to-market. EITF 02-3 took a much narrower view of what “trading activity” should be marked-to-market, limiting mark-to-market treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. At the Company’s natural gas marketing operations, management often employs strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of the Company’s producer services, end-use origination and wholesale marketing groups. Except in very limited circumstances when the Company is able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow the Company to mark inventory, transportation or storage positions to market. The result is that while a significant majority of the Company’s natural gas marketing positions are fully economically hedged, the Company is required to mark some parts of its overall strategies (the derivatives), but are generally precluded from marking the rest of its economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements. 	

  	Non-trading Energy Activities 	

  	Crude Oil Marketing 	

  	The contract or notional amounts and terms of the Company’s crude oil contracts, are set forth below: 	

	September 30, 2004	December 31, 2003	September 30, 2003	
	Notional
Amounts
	Maximum
Term in
Years
	Notional
Amounts
	Maximum Term
in Years
	Notional
Amounts
	Maximum
Term in
Years
	
(thousands of barrels)	 	 	 		 	 		 	 		 	 		 	 		 	 		 	
Crude oil purchased	 	 	 	1,892	 	 	0.5	 	 	2,688	 	 	0.5	 	 	3,253	 	 	0.5	 	
Crude oil sold	 	 	 	1,880	 	 	0.5	 	 	2,253	 	 	0.5	 	 	3,230	 	 	0.5	 	
22

  	All of the Company’s crude oil marketing contracts are accounted for under the accrual method of accounting for all periods presented. 	

  	Oil and Gas Exploration and Production 	

  	On September 30, 2004, December 31, 2003 and September 30, 2003, the Company had the following swaps and related balances (dollars in thousands): 	

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

September 30, 2004	 	 	 		 	 		 	 		 	 		 	 		 	 		 	 		 	 		 	

Crude oil swaps	 	 	 	330,000	 	 	1.25	 	$	--	 	$	--	 	$	4,991	 	$	806	 	$	(5,748	)	$	(49	)	
Natural gas swaps	 	 	 	2,499,000	 	 	0.5	 	 	27	 	 	--	 	 	1,891	 	 	74	 	 	(1,938	)	 	--	 	
															
 	 	 	 		 	 		 	$	27	 	$	--	 	$	6,882	 	$	880	 	$	(7,686	)	$	(49	)	
															
December 31, 2003	 	 		

Crude oil swaps	 	 	 	360,000	 	 	1	 	$	--	 	$	--	 	$	1,445	 	$	--	 	$	(1,384	)	$	(61	)	
Natural gas swaps	 	 	 	4,830,000	 	 	1.25	 	 	172	 	 	--	 	 	1,611	 	 	25	 	 	(1,462	)	 	(2	)	
															
 	 	 	 		 	 		 	$	172	 	$	--	 	$	3,056	 	$	25	 	$	(2,846	)	$	(63	)	
															
September 30, 2003	 	 		

Crude oil swaps	 	 	 	270,000	 	 	1.5	 	$	--	 	$	--	 	$	676	 	$	96	 	$	(736	)	$	(36	)	
Natural gas swaps	 	 	 	945,000	 	 	0.5	 	 	1,106	 	 	--	 	 	298	 	 	--	 	 	808	 	 	--	 	
															
 	 	 	 		 	 		 	$	1,106	 	$	--	 	$	974	 	$	96	 	$	72	 	$	(36	)	
															
_________________ 
*crude in barrels, gas in MMBtu’s 
  	Based on September 30, 2004 market prices, a $6.9 million loss will be realized and reported in earnings during the next twelve months related to hedges of production. These estimated realized losses for the next twelve months were calculated using September 30, 2004 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change. 	

23

  	Financing Activities 	

  	On September 30, 2004, December 31, 2003 and September 30, 2003, the Company’s interest rate swaps and related balances were as follows (in thousands): 	

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

September 30,
2004	 	 	 		 	 		 	 		 	 		 	 		 	 		 	 		 	 		 	 		 	
 	 	 	 		 		
Swaps on	 	 		
project	 	 		
financing	 	 	$	113,000	 	 	4.22	%	 	2	 	$	--	 	$	--	 	$	1,837	 	$	651	 	$	(2,488	)	$	--	 	
																	
December 31,
2003	 	 		
 	 	 	 		 		
Swaps on	 	 		
project	 	 		
financing	 	 	$	113,000	 	 	4.48	%	 	2.75	 	$	256	 	$	--	 	$	3,247	 	$	1,931	 	$	(4,922	)	$	--	 	
Swaps on	 	 		
corporate debt	 	 	 	25,000	 	 	5.28	%	 	0.25	 	 	--	 	 	--	 	 	169	 	 	--	 	 	(169	)	 	--	 	
																	
     Total	 	 	$	138,000	 	 	 	 	 	 	 	$	256	 	$	--	 	$	3,416	 	$	1,931	 	$	(5,091	)	$	--	 	
																	
September 30,
2003	 	 		
 	 	 	 		 		
Swaps on	 	 		
project	 	 		
financing	 	 	$	113,000	 	 	4.22	%	 	3	 	$	168	 	$	--	 	$	3,574	 	$	2,770	 	$	(6,176	)	$	--	 	
Swaps on	 	 		
corporate debt	 	 	 	25,000	 	 	5.28	%	 	0.5	 	 	--	 	 	--	 	 	432	 	 	--	 	 	(430	)	 	(2	)	
																	
     Total	 	 	$	138,000	 	 	 	 	 	 	 	$	168	 	$	--	 	$	4,006	 	$	2,770	 	$	(6,606	)	$	(2	)	

  	Based on September 30, 2004 market interest rates and balances, approximately $1.8 million will be realized as additional interest expense during the next twelve months. Estimated and realized amounts will likely change during the next twelve months as market interest rates change. 	

24

(16) 	     LEGAL PROCEEDINGS 	

  	On August 13, 2004, the former shareholders of Indeck Capital, Inc. (Indeck) commenced litigation against the Company in United States District Court, Northeastern District of Illinois, Eastern Division. The lawsuit concerns the Company’s performance of its obligation under the “Earn-out” provisions of the Agreement and Plan of Merger dated July 7, 2000, related to the Company’s acquisition of Indeck. Under the “Earn-out” provisions, the former shareholders of Indeck were entitled to receive “contingent merger consideration” for a four year period beginning in 2000. The “contingent merger consideration” was not to exceed $35.0 million and was based on the acquired company’s earnings over the four year period. As of September 30, 2004, $11.3 million has been either paid or offered for payment under the “Earn-out” provisions. 	

  	The lawsuit alleges that the Company failed to meet its obligation to produce documentation for its calculation of the contingent merger consideration, and in addition, failed to issue stock compensation in the full amount due to them. The Company denies these allegations and believes that it has fully and in good faith performed all of its obligations under the Agreement and Plan of Merger. The outcome of this matter is uncertain, as is the amount of contingent merger consideration that could be awarded following arbitration or litigation. 	

  	In addition, the Company is subject to various legal proceedings, claims and litigation as described in Note 14 of the Company’s 2003 Annual Report on Form 10-K. Other than noted above, there have been no material developments in these proceedings or any new material proceedings that have developed during the first nine months of 2004. 	

(17) 	     GAIN ON SALE OF ASSETS 	

  	On March 1, 2004, the Company’s subsidiary, Daksoft, Inc., sold assets used in its campground reservation system. The Company recorded a pre-tax gain on the sale of the assets of $1.0 million, which is included as an offset to Operating expenses, Administrative and general on the Condensed Consolidated Statement of Income for the nine month period ended September 30, 2004. Prior to this sale, for segment reporting (see Note 14) results of operations for Daksoft were included in the Communications segment. As Daksoft now primarily provides information technology support to the Company, its results are included in “Corporate” for segment reporting. 	

(18) 	     CONTRACT TERMINATION REVENUE 	

  	During the third quarter of 2003, the Company completed a transaction terminating a fifteen year contract with Allegheny Energy Supply Company, LLC, a subsidiary of Allegheny Energy, Inc., for capacity and energy at the Company’s Las Vegas Cogeneration II power plant. The Company received a cash payment of $114.0 million, which is recorded as “Contract termination revenue” in the accompanying 2003 Condensed Consolidated Statements of Income. Operating results from the Las Vegas II Cogeneration power plant are included in the Power Generation segment. 	

25

(19) 	     IMPAIRMENT OF LONG-LIVED ASSETS 	

  	As a result of the contract termination discussed in Note 18, the Company assessed the recoverability of the carrying value of the Las Vegas Cogeneration II facility. The carrying value of the assets tested for impairment was $237.2 million. This assessment resulted in an impairment charge of $117.2 million to write down the related Property, plant and equipment by $83.1 million, net of accumulated depreciation of $5.1 million, and intangible assets by $34.1 million, net of accumulated amortization of $1.1 million. This charge reflects the amount by which the carrying value of the facility exceeded its estimated fair value determined by its estimated future discounted cash flows. This charge was recorded during the third quarter of 2003 and is included as a component of “Operating expenses” on the accompanying 2003 Condensed Consolidated Statements of Income. Operating results from the Las Vegas II Cogeneration power plant are included in the Power Generation segment. 	

(20)	    ACQUISITION 	

  	On March 10, 2003, the Company completed its acquisition of the Denver-based Mallon Resources Corporation as further described in Note 19 of the Company’s 2003 Annual Report on Form 10-K. On July 15, 2004, Mallon Resources Corporation changed its name to Black Hills Gas Holdings Corp. The results of operations of Black Hills Gas Holdings have been included in the accompanying Condensed Consolidated Financial Statements since the acquisition date. 	

  	The following pro forma consolidated results of operations have been prepared as if the Mallon acquisition had occurred on January 1, 2003 (in thousands): 	

	Nine Months Ended
September 30
2003

Operating revenues	 	 	$	994,489	 	
Income from continuing operations	 	 	$	46,429	 	
Net income available for common	 	 	$	52,662	 	
Earnings per share--	 	 		
  Basic:	 	 		
     Continuing operations	 	 	$	1.52	 	
     Total	 	 	$	1.73	 	
  Diluted:	 	 		
     Continuing operations	 	 	$	1.50	 	
     Total	 	 	$	1.71	 	

  	The above pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition been consummated as of that time, nor is it intended to be a projection of future results. 	

26

(21) 	     PENDING ACQUISITION 	

  	On January 13, 2004, the Company entered into a Stock Purchase Agreement to acquire from Xcel Energy Inc. all of the outstanding capital stock of its subsidiary, Cheyenne Light, Fuel & Power Company (Cheyenne), a Wyoming corporation. Cheyenne owns and operates transmission and distribution facilities to provide electricity and natural gas to consumers in Laramie County, Wyoming. The consideration for the acquisition includes a cash payment plus assumption of outstanding debt of Cheyenne. The acquisition, which has received certain state and federal regulatory approvals and remains subject to further federal approval, is expected to close on or prior to December 31, 2004. 	

(22) 	     DISCONTINUED OPERATIONS 	

  	The Company accounts for its discontinued operations under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (SFAS 144). Accordingly, results of operations and the related charges for discontinued operations have been classified as “(Loss) income from discontinued operations, net of tax”in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassifications on a consistent basis. 	

  	Sale of Landrica Development Corp. 	

  	On May 21, 2004, the Company sold its subsidiary, Landrica Development Corp. Landrica’s primary assets consisted of a coal enhancement plant and land. The purchaser made a $0.5 million cash payment to the Company and assumed a $2.9 million reclamation liability. The sale resulted in a $2.1 million after-tax gain. For segment reporting purposes, Landrica was previously included in the Coal Mining segment. 	

  	Net income from the discontinued operations is as follows (in thousands): 	

	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	 	2003
	 	2004
	 	2003
	 	
Pre-tax (loss) income	 	 	 		 	 		 	 		 	 		 	
  from discontinued	 	 		
  operations	 	 	$	--	 	$	(39	)	$	(40	)	$	639	 	
Pre-tax gain (loss) on disposal	 	 	 	(21	)	 	--	 	 	3,208	 	 	--	 	
Income tax (expense) benefit	 	 	 	7	 	 	7	 	 	(1,120	)	 	(247	)	
									
Net income (loss) from	 	 		
  discontinued operations	 	 	$	(14	)	$	(32	)	$	2,048	 	$	392	 	
									
27

  	Assets and liabilities of the discontinued operations were as follows (in thousands): 	

	December 31
2003
	September 30
2003

Current assets	 	 	$	31	 	$	833	 	
Property, plant and equipment	 	 	 	151	 	 	152	 	
Investments	 	 	 	500	 	 	500	 	
Non-current assets	 	 	 	--	 	 	44	 	
Other current liabilities	 	 	 	(118	)	 	(383	)	
Deferred reclamation	 	 	 	(2,858	)	 	(3,061	)	
Other non-current liabilities	 	 	 	(1	)	 	(1	)	
					
Net liabilities of discontinued operations	 	 	$	(2,295	)	$	(1,916	)	

  	Adoption of Plan to Sell Pepperell Plant 	

  	During the third quarter of 2003, the Company adopted a plan to sell the 40 megawatt gas-fired Pepperell plant and management continues to actively market the plant for sale. The Pepperell plant is the Company’s only remaining generation asset in the eastern market and management has determined that it is a non-strategic asset. For business segment reporting purposes, the Pepperell plant results were previously included in the Power Generation segment. 	

  	Revenues and net loss from the discontinued operations are as follows (in thousands): 	

	Three Months Ended   
September 30   	Nine Months Ended   
September 30   	
	2004
	 	2003
	 	2004
	 	2003
	 	
Operating revenues	 	 	$	10	 	$	264	 	$	10	 	$	2,131	 	
									
Pre-tax loss from	 	 		
  discontinued	 	 		
  operations	 	 	$	(248	)	$	(437	)	$	(717	)	$	(1,016	)	
Pre-tax loss on	 	 		
  disposal	 	 	 	--	 	 	(3,464	)	 	--	 	 	(3,464	)	
Income tax benefit	 	 	 	94	 	 	3,033	 	 	256	 	 	3,243	 	
									
Net loss from	 	 		
  discontinued	 	 		
  operations	 	 	$	(154	)	$	(868	)	$	(461	)	$	(1,237	)	
									
28

  	Assets and liabilities of the discontinued operations are as follows (in thousands): 	

	September 30
2004
	December 31
2003
	September 30
2003

Current assets	 	 	$	107	 	$	249	 	$	336	 	
Property, plant and equipment	 	 	 	1,064	 	 	1,064	 	 	1,064	 	
Non-current deferred tax asset	 	 	 	2,580	 	 	2,580	 	 	3,268	 	
Other current liabilities	 	 	 	(130	)	 	(86	)	 	(348	)	
Non-current liabilities	 	 	 	(459	)	 	(381	)	 	(7	)	
							
Net assets of discontinued operations	 	 	$	3,162	 	$	3,426	 	$	4,313	 	

  	Sale of Hydroelectric Assets 	

  	On September 30, 2003, the Company sold its seven hydroelectric power plants located in upstate New York. 	

  	Revenues and net income from the discontinued operations are as follows (in thousands): 	

	Three Months
Ended
September 30
2003
	Nine Months Ended
September 30
2003

Operating revenues	 	 	$	4,979	 	$	21,800	 	
					
Pre-tax income from discontinued operations	 	 	$	1,463	 	$	8,041	 	
Pre-tax gain on disposal	 	 	 	13,873	 	 	13,873	 	
Income tax expense	 	 	 	(9,665	)	 	(11,984	)	
					
Net income from discontinued operations	 	 	$	5,671	 	$	9,930	 	

(23)	    LONG-TERM TOLLING CONTRACT AND TRANSMISSION SERVICES AGREEMENT 	

  	On April 1, 2004, the Company’s long-term tolling contract to provide capacity and energy from the Las Vegas II power plant to Nevada Power Company (NPC), a subsidiary of Sierra Pacific Resources, became effective. The contract is a tolling arrangement whereby NPC is responsible for supplying natural gas. The Las Vegas II power plant, comprised of combined-cycle gas turbines, is rated at 224 megawatts. The power plant’s capacity and energy is fully dispatchable by NPC to serve its retail load. 	

29

  	The Company also has a Firm Point-to-Point Transmission Service Agreement (TSA) with NPC that expires April 30, 2008. The TSA provided transmission service in support of a Capacity and Ancillary Services Sale Agreement with Allegheny Energy Supply Company, which was terminated in September 2003. In its consideration and approval of the Nevada Power tolling contract, the Nevada Public Utilities Commission established a linkage between the TSA and the tolling contract that will result in the Company recognizing the costs of the TSA over the term of the tolling contract (10 years, $1.6 million per year) rather than the remaining term of the TSA (4 years, $3.9 million per year). 	

(24) 	     SUBSEQUENT EVENT 	

  	On October 21, 2004, the Company effected a call on its Series AB, $45 million 8.3 percent First Mortgage Bonds issued by Black Hills Power, Inc. The bonds had a maturity date of 2024. 	

30

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

We are a diversified energy holding company operating principally in the United States with two major business groups –wholesale energy and retail services. We report our business groups in the following financial segments: 
Business Group	Financial Segment	

Wholesale energy group

Retail services group 	
Power generation
Oil and gas
Coal mining
Energy marketing

Electric utility
Communications 	
Our wholesale energy group, Black Hills Energy, Inc., engages in the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing and transportation of fuel products. Our retail services group consists of our electric utility and communications segments. Our electric utility, Black Hills Power, Inc., generates, transmits and distributes electricity to an average of approximately 61,000 customers in South Dakota, Wyoming and Montana. Our communications segment provides broadband communications services to over 26,000 residential and business customers in Rapid City and the northern Black Hills region of South Dakota through Black Hills FiberCom, LLC. 
In 2003, we made the decision to divest of our non-strategic power generation assets located in the Northeastern United States. On September 30, 2003, we sold our seven hydroelectric power plants located in upstate New York. In May 2004, we sold our subsidiary, Landrica Development Corp., which held some land and coal enhancement facilities that were previously reported in our Coal Mining segment. 
The following discussion should be read in conjunction with Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – included in our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission. 
31

Results of Operations 
Consolidated Results 
Revenue and income (loss) from continuing operations provided by each business group as a percentage of our total revenue and total income (loss) from continuing operations were as follows: 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003

Revenues	 	 	 		 	 		 	 		 	 		 	

Wholesale energy	 	 	 	80	%	 	86	%	 	81	%	 	84	%	
Electric utility	 	 	 	17	 	 	11	 	 	15	 	 	13	 	
Communications	 	 	 	3	 	 	3	 	 	4	 	 	3	 	
									
 	 	 	 	100	%	 	100	%	 	100	%	 	100	%	

Income/ (Loss) from	 	 		
  Continuing Operations	 	 		

Wholesale energy	 	 	 	76	%	 	76	%	 	80	%	 	76	%	
Electric utility	 	 	 	34	 	 	38	 	 	34	 	 	39	 	
Communications	 	 	 	(7	)	 	(6	)	 	(9	)	 	(7	)	
Corporate	 	 	 	(3	)	 	(8	)	 	(5	)	 	(8	)	
									
 	 	 	 	100	%	 	100	%	 	100	%	 	100	%	
									
Discontinued operations in 2004 represent the operations of our 40 MW Pepperell power plant, our last power plant in the Eastern region, which is currently held for sale, and Landrica Development Corp., which was sold on May 21, 2004. Discontinued operations in 2003 represent the Pepperell plant as well as operations of the hydroelectric power plants located in upstate New York, which were sold on September 30, 2003, and Landrica Development Corp., which was sold on May 21, 2004. 
Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Consolidated income from continuing operations for the three-month period ended September 30, 2004 was $17.3 million or $0.53 per share compared to $17.7 million or $0.54 per share in the same period of the prior year. 
The decrease in income from continuing operations for the three-month period ended September 30, 2004 was primarily due to the following: 
  	• 	  	a $0.7 million or $0.02 per share decrease in energy marketing earnings, primarily due to a $2.1 million impact from unrealized mark-to-market adjustments, partially offset by increased realized gas marketing margins and increased earnings from crude oil pipelines; and 	

  	• 	  	a $0.9 million or $0.03 per share decrease in electric utility earnings, primarily due to lower firm system sales resulting from a 37 percent decrease in degree days, increases in purchased power expense, increased costs associated with off-system sales, higher health insurance expense and allocated corporate costs, partially offset by an increase in off-system electric sales and a decrease in fuel expense; 	

32

offset by: 
  	• 	  	a $1.1 million or $0.03 per share decrease in corporate losses due to higher allocation of corporate costs to the business segments in 2004.	

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Consolidated income from continuing operations for the nine-month period ended September 30, 2004 was $36.9 million or $1.12 per share compared to $46.9 million or $1.54 per share in the same period of the prior year. 
The decrease in income from continuing operations for the nine-month period ended September 30, 2004 was primarily due to the following: 
  	• 	  	a $9.3 million or $0.28 per share decrease in power generation earnings, primarily related to: 	

  	  	•	  	a decrease in earnings from the Las Vegas II facility, primarily related to lower revenues from the termination of the Allegheny contract and replacement with a new long-term tolling agreement at lower rates, with Nevada Power Company, that was effective April 1, 2004 and limited spot market sales in the first quarter of 2004; 	

  	  	• 	  	a $5.9 million or $0.18 per share decrease in earnings of unconsolidated subsidiaries, due to lower earnings and unrealized mark-to-market adjustments at certain power fund investments; and 	

  	  	•	  	lower earnings at the Harbor facility due to the expiration of a 2003 summer peaking agreement, 	

        partially offset by: 
  	  	• 	  	a full nine months of earnings from the Wygen Plant that went into service in February 2003, partially offset by increased depreciation expense related to the December 31, 2003 consolidation of the Wygen plant; 	

  	  	•	  	a $1.0 million, or $0.03 per share, after-tax benefit from construction related litigation settlements; 	

  	  	• 	  	a $1.9 million, or $0.06 per share, after-tax negative impact to 2003 earnings for the contract termination and asset impairment on the Las Vegas II power plant, partially offset by a $0.4 million after-tax benefit for a settlement with Enron; and	

  	•	  	a $5.5 million or $0.17 per share decrease in electric utility earnings, primarily due to lower firm system sales resulting from a 12 percent decrease in degree days, increases in purchased power expense, maintenance expense, costs associated with off-system sales, higher health insurance expense and allocated corporate costs, partially offset by increased off-system electric sales and a decrease in fuel expense; 	

33

offset by: 
  	•	  	a $2.2 million or $0.07 per share increase in energy marketing earnings, primarily due to higher earnings at our crude oil pipelines and higher margins received at our crude oil marketing operations. Earnings at our gas marketing operations were flat as a result of negative impacts from unrealized mark-to-market losses, increased payroll, incentive compensation and bank fees were offset by higher realized gas trading margins and the impact of a $3.0 million CFTC settlement on 2003 results; 	

  	•	  	a $0.9 million, or $0.03 per share increase in coal mining earnings, primarily due to a benefit from an income tax reserve adjustment, decreased production expense, administrative and interest expenses, partially offset by lower revenues and increased depreciation expense; and 	

  	•	  	a $1.7 million, or $0.05 per share decrease in corporate losses due to higher allocation of corporate costs to the business segments in 2004. 	

Net income for the nine months ended September 30, 2003, included a charge of $2.7 million or ($0.09) per share for change in accounting principles. The change in accounting principles reflects a $2.9 million charge related to the adoption of EITF 02-3 at our energy marketing segment and a $0.2 million benefit related to the adoption of SFAS 143 at our oil and gas and coal mining segments. 
Per share results in the first nine months of 2004 were also affected by an increase of 2.4 million weighted average shares outstanding, compared to the same period in 2003, due primarily to a 4.6 million share common stock offering on April 30, 2003. 
A detailed discussion of results from our operating groups and segments are included in the following pages. 
34

Wholesale Energy Group 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	 	2003
	 	2004
	 	2003
	 	
	(in thousands)	
Revenue:	 	 	 		 	 		 	 		 	 		 	
   Energy marketing*	 	 	$	159,694	 	$	168,908	 	$	495,024	 	$	523,597	 	
   Power generation**	 	 	 	42,980	 	 	164,577	 	 	118,472	 	 	250,173	 	
   Oil and gas***	 	 	 	13,666	 	 	12,513	 	 	41,036	 	 	34,314	 	
   Mining	 	 	 	7,032	 	 	9,177	 	 	23,303	 	 	25,506	 	
									
Total revenue	 	 	 	223,372	 	 	355,175	 	 	677,835	 	 	833,590	 	
Equity in earnings (losses) of	 	 		
  unconsolidated subsidiaries	 	 	 	285	 	 	894	 	 	(723	)	 	5,758	 	
Operating expenses**	 	 	 	197,614	 	 	327,703	 	 	614,022	 	 	759,826	 	
									
Operating income	 	 	$	26,043	 	$	28,366	 	$	63,090	 	$	79,522	 	
									
Income from continuing operations	 	 	$	13,164	 	$	13,419	 	$	29,455	 	$	35,680	 	
									
_________________ 
* 	  	All periods presented reflect a net presentation of revenues at our gas marketing subsidiary and a gross presentation of revenues at our crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19. 	

**	  	Power generation revenue in 2003 includes $114 million of contract termination revenue (see Note 18) and 2003 operating expenses include $117.2 million of impairment of long-lived assets (see Note 19). 	

***	  	Includes $(0.5) million revenue accrual correction for the nine month period ended September 30, 2004. 	

Discussion of results from our Wholesale Energy group’s operating segments are as follows: 
Energy Marketing 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003
	
	(in thousands)	

Revenue*	 	 	$	159,694	 	$	168,908	 	$	495,024	 	$	523,597	 	
Operating income	 	 	 	1,584	 	 	2,243	 	 	10,476	 	 	8,166	 	
Income from continuing operations	 	 	 	670	 	 	1,324	 	 	6,245	 	 	4,079	 	
_________________ 
*	  	All periods presented reflect a net presentation of revenues at our gas marketing subsidiary and a gross presentation of revenues at our crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19. 	

35

The following is a summary of average daily energy marketing volumes: 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003

Natural gas - MMBtus	 	 	 	1,749,300	 	 	1,205,900	 	 	1,635,200	 	 	1,181,800	 	
Crude oil - barrels	 	 	 	41,000	 	 	59,500	 	 	47,400	 	 	60,000	 	
Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. The decrease in revenues is a result of a 31 percent decrease in crude oil volumes marketed, partially offset by a 37 percent increase in the average price per barrel marketed. Revenue decreases from crude oil marketing were offset by a similar decrease in the cost of crude oil sold. 
Income from continuing operations decreased $0.7 million primarily due to decreased earnings at our gas marketing company as a result of increased compensation expense and a $1.9 million unrealized mark-to-market loss for 2004, compared to a $0.2 million unrealized gain in 2003 (see Note 15 and Item 3. “Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-Q, for discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our gas marketing operations). This was partially offset by increased realized gas trading margins resulting from a 45 percent increase in gas volumes marketed and increased earnings at our crude oil pipelines. 
Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. The decrease in revenues is a result of a 21 percent decrease in crude oil volumes marketed, partially offset by a 19 percent increase in the average price per barrel marketed. Revenue decreases from crude oil marketing were offset by a similar decrease in the cost of crude oil sold. 
The segment’s income from continuing operations increased $2.2 million compared to 2003 primarily due to higher earnings at our crude oil pipelines and higher margins received at our crude oil marketing operations. Income from continuing operations at our gas marketing operations was flat as a $2.1 million unrealized mark-to-market loss for 2004 compared to a $3.1 million unrealized gain in 2003, resulted in a year-over-year pre-tax decrease of $5.2 million in unrealized mark-to-market adjustments at our gas marketing operations (see Note 15 and Item 3. “Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-Q, for discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our gas marketing operations). The impacts of unrealized mark-to-market adjustments and increased payroll, incentive compensation and increased bank fees due to higher outstanding letters of credit related to increased inventory levels were offset by higher realized gas trading margins from a 38 percent increase in gas volumes marketed in 2004 and the impact of a $3.0 million CFTC settlement impacting 2003 results. 
36

Power Generation 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003
	
	(in thousands)	

Revenue*	 	 	$	42,980	 	$	164,577	 	$	118,472	 	$	250,173	 	
Equity in (losses) earnings of	 	 		
  unconsolidated subsidiaries	 	 	 	378	 	 	894	 	 	(560	)	 	5,374	 	
Operating income	 	 	 	17,729	 	 	19,485	 	 	35,164	 	 	55,438	 	
Income from continuing	 	 		
  operations	 	 	 	7,192	 	 	7,056	 	 	10,347	 	 	19,634	 	
_________________ 
* 2003 revenue includes $114 million of contract termination revenue (see Note 18). 
	September 30	
	2004
	2003
	
Independent power capacity:	 	 	 		 	 		 	
   MWs of independent power capacity in service(a)	 	 	 	1,004	 	 	1,002	 	
_________________ 
(a) Capacity in service includes 40 MW in 2004 and 2003, which are currently reported as “Discontinued operations.” 
Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Revenue for the three months ended September 30, 2003, includes $114.0 million of contract termination revenue related to the Las Vegas II Cogeneration power plant. Excluding the contract termination revenue, revenue decreased 15 percent in 2004 compared to 2003 primarily as a result of lower revenues from our Las Vegas and Harbor facilities and lower megawatt-hours being dispatched from our Gillette gas turbine. Revenues from our Las Vegas II power plant were $4.0 million lower than the prior year primarily due to the termination of the Allegheny contract and replacement with a new long-term tolling arrangement for the capacity and energy of the Las Vegas II plant at lower rates. The new contract was entered into with Nevada Power Company and became effective April 1, 2004. Capacity revenues decreased at our Harbor facility due to the expiration of a 2003 summer peaking agreement and lower merchant sales in 2004 compared to 2003. Revenues were lower from our Gillette gas turbine due to limited opportunities for economic dispatch because of prevailing regional power market conditions. Operating expenses decreased $120.4 million, primarily the result of 2003 operating expense including a $117.2 million impairment charge for the Las Vegas II power plant, the result of the termination of the Allegheny power sales contract on the Las Vegas II power plant. Excluding the impairment charge, operating expenses decreased $3.2 million, or 11 percent, primarily due to lower fuel costs from reduced dispatch at our non-tolled power plants. 
37

Income from continuing operations increased $0.1 million. Earnings results for 2004 were impacted by reduced plant revenues partially offset by lower interest expense from debt reduction from the proceeds of an asset sale and contract termination. In addition, earnings results for 2003 were negatively impacted by a $1.9 million after-tax charge for the contract termination and the asset impairment charge on the Las Vegas II power plant, partially offset by a $0.4 million after-tax benefit from a settlement with Enron. 
Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Revenue for the nine months ended September 30, 2003, includes $114.0 million of contract termination revenue related to the Las Vegas II power plant. Excluding the contract termination revenue, revenue decreased 13 percent in 2004 compared to 2003 primarily due to lower revenues from our Las Vegas and Harbor facilities. Revenues from our Las Vegas II plant were $14.3 million lower than the prior year primarily due to the termination of the Allegheny contract and replacement with a new long-term tolling arrangement for the capacity and energy of the Las Vegas II plant at lower rates. The new contract was entered into with Nevada Power Company and became effective April 1, 2004. Prior to this arrangement, the facility sold power into the market, when economic to do so, since the September 2003 termination and buyout of the long-term contract at the Las Vegas II plant. Revenues were lower from our Harbor facility due to lower merchant sales and lower capacity revenue due to the expiration of a 2003 summer peaking agreement. 
Equity in earnings of unconsolidated subsidiaries decreased $5.9 million, primarily due to the impact of mark-to-market adjustments at certain of our power fund investments that use a fair value method of accounting. 
Operating expenses decreased $117.4 million. 2003 operating expense includes a $117.2 million impairment charge for the Las Vegas II power plant, the result of the termination of the power sales contract on the Las Vegas II power plant. Excluding the impairment charge, operating expenses decreased $0.2 million due to lower maintenance expense, offset by higher fuel costs and depreciation expense. 
Income from continuing operations decreased $9.3 million. Earnings results for 2004 were impacted by reduced plant revenues, lower earnings from power fund investments, higher fuel costs and higher depreciation expense, partially offset by lower maintenance expense, lower interest expense from debt reduction from the proceeds of an asset sale and contract termination, and a $1.0 million after-tax benefit from litigation settlements. In addition, 2003 earnings results were negatively impacted by a $1.9 million after-tax charge for the contract termination and the asset impairment on the Las Vegas II plant, partially offset by a $0.4 million after-tax benefit from a settlement with Enron. 
38

Oil and Gas 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003
	
	(in thousands)	

Revenue	 	 	$	13,666	 	$	12,513	 	$	41,036	*	$	34,314	 	
Equity in (losses) earnings of	 	 		
  unconsolidated subsidiaries	 	 	 	(93	)	 	--	 	 	(163	)	 	384	 	
Operating income	 	 	 	4,325	 	 	4,129	 	 	11,513	 	 	10,960	 	
Income from continuing operations	 	 	 	2,765	 	 	2,805	 	 	7,215	 	 	7,245	 	
_________________ 
*	  	Includes $(0.5) million revenue accrual correction for the nine month period ended September 30, 2004. 	

The following is a summary of oil and natural gas production: 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003

Fuel production:	 	 	 		 	 		 	 		 	 		 	
   Barrels of oil sold	 	 	 	99,149	 	 	109,486	 	 	333,260	 	 	317,234	 	
   Mcf of natural gas sold	 	 	 	2,517,581	 	 	2,495,341	 	 	7,132,472	 	 	5,801,590	 	
   Mcf equivalent sales	 	 	 	3,112,475	 	 	3,152,257	 	 	9,132,032	 	 	7,704,994	 	
Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Revenue from our oil and gas segment increased $1.2 million for the three-month period ended September 30, 2004, compared to the same period in 2003. The increase is due to higher gas and oil prices received. Average gas and oil prices received, net of hedging activity, in 2004 were $4.43/Mcf and $27.32/bbl, respectively, compared to $3.39/Mcf and $23.48/bbl in 2003. Lease operating expenses per Mcfe sold (LOE/MCFE) were 28 percent higher than 2003. 
Income from continuing operations was flat compared to 2003. Earnings results for 2004 were affected by increased revenues from higher prices received offset by a 10 percent increase in operating expenses related to higher depletion costs and lease operating expenses. 
Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Revenues from our oil and gas segment increased $6.7 million for the nine month period ended September 30, 2004, compared to the same period in 2003. The increase in revenues is due to a 19 percent increase in volumes sold and higher gas prices received. The increase in volumes sold reflects a full nine months of production at the Mallon properties acquired in March 2003. Average gas and oil prices received, net of hedging activity, in 2004 were $4.23/Mcf and $25.13/bbl, respectively, compared to $3.94/Mcf and $25.15/bbl in 2003. 
39

Income from continuing operations was flat when compared to the same period in 2003. Earnings results were affected by higher prices and volumes sold, offset by a 24 percent, or approximately $5.6 million, increase in total operating expenses related to additional operations acquired in the Mallon transaction and higher depletion and lease operating expenses. In addition, 2004 LOE/MCFE was 8 percent higher than 2003. 
The following is a summary of our internally estimated economically recoverable oil and gas reserves. These estimates are measured using constant product prices of $47.66 per barrel of oil and $5.17 per Mcf of natural gas as of September 30, 2004, and $30.30 per barrel of oil and $4.69 per Mcf of natural gas as of September 30, 2003. The increases in reserves are primarily the result of increased product prices. Estimates of economically recoverable reserves for interim periods are based on independent year-end reserve studies updated for acquisitions, drilling activity, property sales and actual production during the interim period. These internally estimated reserves may differ from actual results. 
	September 30	
	2004
	2003

Barrels of oil (in thousands)	 	 	 	5,692	 	 	4,938	 	
Mmcf of natural gas	 	 	 	125,625	 	 	110,423	 	
Total in Mmcf equivalents	 	 	 	159,777	 	 	140,051	 	
Coal Mining 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003
	
	(in thousands)	

Revenue	 	 	$	7,032	 	$	9,177	 	$	23,303	 	$	25,506	 	
Operating income	 	 	 	2,405	 	 	2,509	 	 	5,937	 	 	4,958	 	
Income from continuing operations	 	 	 	2,537	 	 	2,234	 	 	5,648	 	 	4,722	 	

The following is a summary of coal sales volumes:	 	 		

Tons of coal sold	 	 	 	1,235,400	 	 	1,292,100	 	 	3,510,100	 	 	3,562,400	 	

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Revenue from our mining segment decreased 23 percent for the three-month period ended September 30, 2004, compared to the same period in 2003. In September 2004, the Company reached a tax settlement with the Wyoming Department of Revenue which resulted in an adjustment to coal billings for the period of fourth quarter 2001 through the year 2003. The Company recorded a $1.7 million reduction in revenues and a corresponding reduction in mineral taxes. The Company also recorded an additional $0.4 million decrease to mineral taxes and $0.5 million decrease to interest expense related to the settlement. Revenues were also impacted by a 4 percent decrease in tons of coal sold, primarily due to a reduction in train load-out sales. 
40

Operating expenses increased 2 percent, exclusive of the recording of the tax settlement, primarily due to an increase in depreciation expense, partially offset by lower overburden rates. 
Income from continuing operations increased $0.3 million primarily due to a $0.4 million benefit from an income tax reserve adjustment, a $0.6 million after-tax benefit from the Wyoming tax settlement, and lower overburden expense, partially offset by increased depreciation and a decrease in tons of coal sold. 
Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Revenue for the nine-month period ended September 30, 2004 decreased 9 percent compared to the same period in 2003. In September 2004, the Company reached a tax settlement with the Wyoming Department of Revenue, which resulted in an adjustment to coal billings for the period of fourth quarter 2001 through the year 2003. The Company recorded a $1.7 million reduction in revenues and a corresponding reduction in mineral taxes. The Company also recorded an additional $0.4 million decrease to mineral taxes and $0.5 million decrease to interest expense related to the settlement. Revenues were also impacted by a 1 percent decrease in tons of coal sold. The decrease in tons of coal sold is primarily attributable to scheduled electric plant maintenance outages and an unscheduled outage at the Wyodak plant. 
Operating expenses decreased 5 percent, exclusive of the recording of the tax settlement, primarily due to lower mining costs related to the decrease in production, lower overburden rates, lower corporate allocations and lower compensation expense, offset by increased depreciation expense. 
Income from continuing operations increased $0.9 million primarily due to a $0.4 million benefit from an income tax reserve adjustment, a $0.6 million after-tax benefit from the Wyoming tax settlement, lower production costs and general and administrative costs, partially offset by lower revenues, lower interest income and increased depreciation expense. 
Retail Services Group 
Electric Utility 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	 	2003
	 	2004
	 	2003
	 	
	(in thousands)	

Revenue	 	 	$	47,921	 	$	46,268	 	$	129,377	 	$	129,238	 	
Operating expenses	 	 	 	35,415	 	 	31,773	 	 	98,902	 	 	90,493	 	
									
Operating income	 	 	$	12,506	 	$	14,495	 	$	30,475	 	$	38,745	 	
									
Income from continuing operations	 	 	$	5,860	 	$	6,772	 	$	12,712	 	$	18,193	 	
									
41

The following table provides certain operating statistics: 
	Three Months Ended
September 30	Nine Months Ended
September 30	
	2004
	2003
	2004
	2003

Firm (system) sales - MWh	 	 	 	511,800	 	 	545,300	 	 	1,476,000	 	 	1,498,100	 	
Off-system sales - MWh	 	 	 	335,500	 	 	204,700	 	 	797,400	 	 	684,500	 	

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Electric utility revenues increased 4 percent for the three-month period ended September 30, 2004, compared to the same period in the prior year. The increase in revenue was primarily due to a 64 percent increase in off-system electric megawatt-hour sales offset by an 11 percent decrease in average prices received from off-system sales. Firm commercial and residential electricity revenues decreased 5 percent and 12 percent, respectively, and industrial revenues increased 1 percent. Degree days, which is a measure of weather trends, were 37 percent below last year. 
Electric operating expenses increased 11 percent for the three-month period ended September 30, 2004, compared to the same period in the prior year. Purchased power increased $4.3 million due to a 51 percent increase in megawatt-hours purchased, at a 5 percent decrease in the average cost per megawatt-hour. Megawatt-hours purchased increased due to uneconomic dispatch of our gas turbines and to support the increase in off-system sales. Gas costs decreased 55 percent due to a 64 percent decrease in megawatt-hours generated with our gas turbines, as prevailing prices made it more economical for us to purchase power for our peaking needs when it was available rather than generate energy from our gas turbines. The average cost per megawatt-hour of our gas generation was $67.03 for the three months ended September 30, 2004, while the average cost for purchased power was $35.25 per megawatt-hour for the same period. The decrease in fuel expense was offset by increased power marketing costs, increased health insurance costs and an increase in allocated corporate costs. 
Income from continuing operations decreased $0.9 million primarily due to increases in purchased power expense, costs associated with the increase in off-system sales, health insurance expense and allocated corporate costs, partially offset by an increase in off-system electric sales and the decrease in gas costs. 
Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Electric utility revenues were flat for the nine-month period ended September 30, 2004, compared to the same period in the prior year. Off-system electric megawatt-hour sales increased 16 percent at a 5 percent decrease in average prices received. Revenues were impacted in part by reduced Open Access Transmission Tariff rates and plant availability resulting from unscheduled and scheduled maintenance outages during the nine month period ended September 30, 2004. The increase in revenue from off-system sales was partially offset by decreased retail sales. Residential and commercial revenues decreased 3 percent and 2 percent, respectively, and industrial revenues increased 3 percent. Degree days, which is a measure of weather trends, were 12 percent below last year. 
42

Electric operating expenses increased 9 percent for the nine-month period ended September 30, 2004, compared to the same period in the prior year. Purchased power increased $9.2 million due to a 38 percent increase in megawatt-hours purchased. Megawatt-hours purchased increased primarily due to a 16 percent increase in off-system megawatt-hour sales and the uneconomic dispatch of our gas turbines. Gas costs decreased 70 percent due to an 83 percent decrease in megawatt-hours generated with our gas turbines as prevailing prices made it more economical for us to purchase power for our peaking needs when it was available rather than generate energy from our gas turbines. The average cost per megawatt-hour of our gas generation was $76.33 for the nine months ended September 30, 2004, while the average cost for purchased power was $33.38 per megawatt-hour for the same period. The decrease in fuel expense was offset by increased plant maintenance costs, power marketing costs, health insurance costs and allocated corporate costs. 
Income from continuing operations decreased $5.5 million primarily due to increases in purchased power expense, maintenance expense, costs associated with the increase in off-system sales, health insurance expense and allocated corporate costs, partially offset by an increase in off-system electric sales and the decrease in gas costs. 
Communications 
	Three Months Ended   
September 30   	Nine Months Ended   
September 30   	
	2004
	 	2003
	 	2004
	 	2003
	 	
	(in thousands)	

Revenue	 	 	$	9,455	 	$	10,136	 	$	29,329	 	$	30,595	 	
Operating expenses	 	 	 	10,449	 	 	10,810	 	 	31,458	 	 	32,797	 	
									
Operating loss	 	 	$	(994	)	$	(674	)	$	(2,129	)	$	(2,202	)	
									
Loss from continuing operations	 	 		
  and net loss	 	 	$	(1,256	)	$	(1,031	)	$	(3,209	)	$	(3,273	)	

	September 30
2004
	December 31
2003
	September 30
2003

				

Business customers	 	 	 	3,311	 	 	3,012	 	 	2,841	 	
Business access lines	 	 	 	12,949	 	 	12,023	 	 	11,518	 	
Residential customers	 	 	 	23,557	 	 	23,878	 	 	23,900	 	

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Revenues from our communications group decreased $0.7 million compared to the same period in 2003. The decrease was due to the results of operations of our information technology support subsidiary, Daksoft, Inc., being included in 2003 results. Beginning in the first quarter of 2004, Daksoft’s focus became corporate information technology support and therefore its results are included as “corporate” costs. Daksoft’s results had an insignificant impact on net earnings. Excluding Daksoft’s results, revenues were flat for the communications group as increased business customer revenues were offset by a decrease in residential customer revenues and revenues from system access billings. 
43

Loss from continuing operations increased $0.2 million compared to the same period in 2003. Earnings results for 2003 benefited from a reduction in property tax accruals. 
Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Revenue from our communications group decreased $1.3 million compared to the same period in 2003. This was due to the results of operations of our information technology support subsidiary, Daksoft, Inc., being included in 2003 results. Beginning in the first quarter of 2004, Daksoft’s focus became corporate information technology support and therefore its results are included in “corporate” costs. Daksoft’s results had an insignificant impact on net earnings. Excluding Daksoft’s results, revenue increased $0.3 million as increased business customer revenues were partially offset by a decrease in revenues from system access billings and residential customer revenues. Revenues for the nine month period ended September 30, 2004, were approximately $1.3 million lower due to sales incentive costs related to a marketing campaign responding to a local competitor’s aggressive pricing pressure, primarily in the fourth quarter of 2003, offset by revenues from additional services sold to existing customers. 
Loss from continuing operations decreased $0.1 million compared to the same period in 2003. In addition to the revenue impacts, earnings were also impacted by an increase in allocated corporate costs. 
Earnings Guidance 
Our current guidance extends through 2005 with an estimate of 2004 income from continuing operations to be between $1.70 and $1.85 per share and 2005 estimated to be $1.85 to $2.00 per share. 
Critical Accounting Policies 
There have been no material changes in our critical accounting policies from those reported in our 2003 Annual Report on Form 10-K filed with the Securities Exchange Commission. For more information on our critical accounting policies, see Part II, Item 7 in our 2003 Annual Report on Form 10-K. 
Liquidity and Capital Resources 
Cash Flow Activities 
During the nine-month period ended September 30, 2004, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay our scheduled long-term debt maturities, and to fund most of our property additions. We plan to fund future property and investment additions primarily through a combination of existing cash balances, operating cash flow, increased short-term debt, long-term debt, and long-term non-recourse project financing. 
Cash flows from operations decreased $148.0 million for the nine-month period ended September 30, 2004 compared to the same period in the prior year. The decrease is primarily due to the third quarter 2003 receipt of $114.0 million from Allegheny Energy Supply Company, LLC for the termination of a fifteen-year contract for capacity and energy at our Las Vegas II power plant, as well as decreased earnings, purchases of gas inventory held by our energy marketing operations and changes in other working capital. 
44

During the nine months ended September 30, 2004, we had cash outflows from investing activities of $62.4 million, which was primarily related to property, plant and equipment additions in the normal course of business. 
During the nine months ended September 30, 2004, we had cash outflows from financing activities of $114.9 million, primarily due to the repayment of debt and payment of quarterly cash dividends on stock. On January 30, 2004, we repaid $45 million of the project-level debt outstanding on the Fountain Valley project and on May 10, 2004, we repurchased $25 million of our 6.5 percent senior unsecured notes due 2013. On August 31, 2004, we called $5.9 million of Pollution Control Revenue Bonds, having a maturity date of 2010. 
Dividends 
Dividends paid on our common stock were $0.31 per share in each of the first, second and third quarters of 2004. As approved by our board of directors in January 2004, this reflects a 3.3 percent increase from the 2003 quarterly dividend level. 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 facilities and our future business prospects. 
Short-Term Liquidity and Financing Transactions 
Our principal sources of short-term liquidity are our revolving credit facilities and cash provided by operations. Our liquidity position remained strong during the first nine months of 2004. As of September 30, 2004, we had approximately $79.9 million of cash unrestricted for operations and $350 million of credit through revolving bank facilities. Approximately $10.0 million of the cash balance at September 30, 2004 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company. The bank facilities consisted of a $225 million facility due August 20, 2006 and a $125 million facility due May 12, 2005. The $125 million facility replaced a $200 million facility, which was due to expire on August 27, 2004. 
These bank facilities can be used to fund our working capital needs, for general corporate purposes, and to provide liquidity for a commercial paper program if implemented. At September 30, 2004, we had no bank borrowings outstanding under these facilities. After inclusion of applicable letters of credit, the remaining borrowing capacity under the bank facilities was $305.5 million at September 30, 2004. 
Additional short-term liquidity is currently expected to be provided from the proceeds of forward sales of gas inventory held by our Energy Marketing segment. At September 30, 2004, the segment had $99.4 million of oil and gas inventory, substantially all of which was economically hedged at the time of purchase through either forward physical sales or forward financial sales. Sales for a substantial majority of this inventory have been made through transactions which are scheduled to settle in the fourth quarter of 2004 and the first quarter of 2005. 
45

The above bank facilities include the following covenants that are common in such arrangements: 
  	• 	  	a consolidated net worth in an amount of not less than the sum of $550 million and 50 percent of the aggregate consolidated net income beginning April 1, 2004; 	

  	•	  	a recourse leverage ratio not to exceed 0.65 to 1.00; and 	

  	• 	  	a fixed charge coverage ratio of not less than 1.5 to 1.0. 	

If these covenants are violated, it would be considered an event of default entitling the lender to terminate the remaining commitment and accelerate all principal and interest outstanding. As of September 30, 2004, we were in compliance with the above covenants. 
Our consolidated net worth was $721.0 million at September 30, 2004, which was approximately $156.6 million in excess of the net worth we are required to maintain under the debt covenant described above. The long-term debt component of our capital structure at September 30, 2004 was 48.5 percent, our total debt leverage (long-term debt and short-term debt) was 52.5 percent, and our recourse leverage ratio was approximately 47.7 percent. 
In addition, Enserco Energy Inc., our gas marketing unit, has a $150 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. As of September 30, 2004, we had a $3.0 million guarantee to the lender under this facility. This facility was recently increased from $135 million. At September 30, 2004, there were outstanding letters of credit issued under the facility of $85.3 million, with no borrowing balances outstanding on the facility. On September 30, 2004, the facility was renewed for a one year period expiring September 30, 2005. 
Similarly, Black Hills Energy Resources, Inc. (BHER), our oil marketing unit, currently has a $25 million uncommitted, discretionary credit facility. The facility may be increased up to $40 million of available credit via notification to the bank at the beginning of each calendar quarter. This line of credit provides credit support for the purchases of crude oil by BHER. We provided no guarantee to the lender under this facility. At September 30, 2004, BHER had letters of credit outstanding of $7.3 million. 
There were no changes in our corporate credit ratings during the first nine months of 2004. 
In September 2004, the Company initiated a call notice, effective October 21, 2004, to call the entire $45 million Series AB 8.3 percent First Mortgage Bonds of Black Hills Power, Inc. The utility bonds have a maturity date of 2024. 
Our ability to obtain additional financing, if necessary, will depend upon a number of factors, including our future performance and financial results, and capital market conditions. We can provide no assurance that we will be able to raise additional capital on reasonable terms or at all. 
There have been no other material changes in our forecasted changes in liquidity requirements from those reported in Item 7 of our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission. 
46

Contractual Obligations 
The long-term debt component of our contractual obligations table disclosed in our 2003 Annual Report on Form 10-K has been reduced by the following: 
  	• 	  	$45 million of the project level debt on the Fountain Valley facility due in 2006. We repaid this portion in January 2004. 	

  	• 	  	$25 million of the 6.5 percent senior unsecured notes due in 2013. We repurchased this portion in May 2004. 	

  	•	  	$5.9 million of the 6.7 percent Pollution Control Revenue Bonds due in 2010. We called the bonds in August 2004. 	

  	• 	  	$45 million of the Series AB 8.3 percent First Mortgage Bonds due 2024. In September, we initiated a call notice to call the bonds effective October 21, 2004. 	

There were no other material changes to our contractual obligations table from those reported in Items 7 of our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission. 
Guarantees 
During the first quarter of 2004, a $5.0 million performance guarantee for Black Hills Wyoming, under a power sales agreement on the Wygen Plant expired. In addition a new $0.5 million guarantee was issued related to payments under various transactions with Idaho Power Company. 
During the second quarter of 2004, a $5.0 million guarantee related to a power pool agreement became effective and a $0.8 million guarantee was issued related to payments under various transactions with Southern California Edison Company. 
At September 30, 2004, we had guarantees totaling $186.2 million in place. 
Capital Requirements 
During the nine months ended September 30, 2004, capital expenditures were approximately $65.6 million. Due to the lack of capital deployment opportunities, in July 2004 we revised our forecasted capital requirements for maintenance capital and developmental capital as follows (in thousands): 
	2004
	2005
	2006

				
Wholesale energy	 	 	$	70,850	 	$	46,080	 	$	56,920	 	
Electric utility	 	 	 	21,180	 	 	34,370	 	 	35,630	 	
Communications	 	 	 	9,410	 	 	7,840	 	 	7,050	 	
Corporate	 	 	 	4,440	 	 	2,570	 	 	1,690	 	
Development	 	 	 	74,000	 	 	93,910	 	 	105,000	 	
							
 	 	 	$	179,880	 	$	184,770	 	$	206,290	 	
							
47

REGULATION 
On July 19, 2004, we filed an Application-Declaration on Form U-1 with the Securities and Exchange Commission (SEC) to formally request certain approvals in connection with becoming a registered holding company under the Public Utilities Holding Company Act of 1935, as amended (1935 Act). On November 1, 2004, we filed an amendment to the Application-Declaration, and the SEC issued a public notice of such filing establishing a public notice and comment period expiring November 24, 2004. 
As a registered holding company, the 1935 Act and related regulations issued by the SEC would regulate our activities and activities of our subsidiaries with respect to the acquisition and sale of securities, acquisition and sale of utility assets, transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters. 
RISK FACTORS 
There have been no material changes in our risk factors from those reported in Items 1 and 2 of our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission. 
NEW ACCOUNTING PRONOUNCEMENTS 
Other than the new pronouncements reported in our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission and those discussed in Note 4 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements issued that when implemented would require us to either retroactively restate prior period financial statements or record a cumulative catch-up adjustment. 
SAFE HARBOR FOR FORWARD LOOKING INFORMATION 
This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q 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. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described above, in Items 1 and 2 of our 2003 Annual Report on Form 10-K filed with the SEC, and the following: 
  	•	  	The amount and timing of capital deployment in new investment opportunities; 	

  	•	  	The timing of production from oil and gas development facilities, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of building, environmental and other permits, and the availability of specialized contractors, work force, equipment, and prices of and demand for our products; 	
48

  	•	  	General economic and political conditions, including tax rates or policies and inflation rates; 	

  	•	  	Our use of derivative financial instruments to hedge commodity and interest rate risks; 	

  	•	  	The creditworthiness of counterparties to trading and other transactions, and defaults on amounts due from counterparties; 	

  	• 	  	The amount of collateral required to be posted from time to time in our transactions; 	

  	• 	  	Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment; 	

  	•	  	The timing and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets; 	

  	• 	  	Weather and other natural phenomena; 	

  	•	  	The extent of success in connecting natural gas supplies to gathering and processing systems; 	

  	•	  	Industry and market changes, including the impact of consolidations and changes in competition; 	

  	•	  	The effect of accounting policies issued periodically by accounting standard-setting bodies; 	

  	•	  	The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions; 	

  	• 	  	Capital market conditions, including price risk due to marketable securities held as investments in benefit plans; and 	

  	•	  	Other factors discussed from time to time in our filings with the SEC. 	

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise. 
49

ITEM 3.	   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 	

The following table provides a reconciliation of the activity in energy trading contracts that meet the definition of a derivative under SFAS 133 and that were marked-to-market during the nine months ended September 30, 2004 (in thousands): 

		
Total fair value of natural gas marketing contract net liability at December 31, 2003	 	 	$	(408	)	
Net cash settled during the nine-month period on contracts that existed at	 	 		
  December 31, 2003	 	 	 	(2,355	)	
Change in fair value due to change in techniques and assumptions	 	 	 	--	 	
Unrealized gain (loss) on new contracts entered during the nine-month period and	 	 		
  still existing at September 30, 2004	 	 	 	(4,079	)	
Realized gain (loss) on contracts that existed at December 31, 2003 and were settled	 	 		
  during the nine-month period ended September 30, 2004	 	 	 	(2,717	)	
Unrealized gain (loss) on contracts that existed at December 31, 2003 and still exist	 	 		
  at September 30, 2004	 	 	 	(2,470	)	
			
Total fair value of natural gas marketing contract net assets at September 30, 2004	 	 	$	(12,029	)	

On January 1, 2003, the Company adopted EITF Issue No. 02-3. The adoption of EITF 02-3 resulted in certain energy trading activities no longer being accounted for at fair value, therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities and our expected cash flows from those operations. EITF 98-10 was superseded by EITF 02-3 and allowed a broad interpretation of what constituted “trading activity” and hence what would be marked-to-market. EITF 02-3 took a much narrower view of what “trading activity” should be marked-to-market, limiting mark-to-market treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. At our natural gas marketing operations, we often employ strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in very limited circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow us to mark our inventory, transportation or storage positions to market. 
The result is that while a significant majority of our natural gas marketing positions are fully economically hedged, we are required to mark some parts of our overall strategies (the derivatives), but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements. 
50

At September 30, 2004, we had a mark to fair value unrealized loss of $12.0 million for our derivative contracts related to our natural gas marketing activities, with $12.3 million of this amount current. The sources of fair value measurements were as follows (in thousands): 
	Maturities
	
Source of Fair Value	Less than 1 year	1 - 2 years	Total
Fair Value	

Actively quoted (i.e., exchange-traded) prices	 	 	$	1,181	 	$	--	 	$	1,181	 	
Prices provided by other external sources	 	 	 	(13,507	)	 	297	 	 	(13,210	)	
Modeled	 	 	 	--	 	 	--	 	 	--	 	
							
Total	 	 	$	(12,326	)	$	297	 	$	(12,029	)	

The following table (in thousands) presents a reconciliation of our net derivative assets/(liabilities) under GAAP for our gas marketing subsidiary to a non-GAAP measure of the fair value of our forward book wherein all forward trading positions are marked-to-market. The approach used in determining the non-GAAP measure is consistent with our previous accounting methods under EITF 98-10. 

		
Net derivative assets/(liabilities) (GAAP)	 	 	$	(12,029	)	
Increase/(decrease) in fair value of inventory, storage and transportation positions	 	 		
  that are related to trading, but that are not marked-to-market under GAAP	 	 	 	17,491	 	
			
Fair value of all forward positions (Non-GAAP)	 	 	$	5,462	 	

There have been no material changes in market risk faced by us from those reported in our 2003 Annual Report on Form 10-K filed with the Securities Exchange Commission. For more information on market risk, see Part II, Item 7 in our 2003 Annual Report on Form 10-K, and Note 15 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. 

ITEM 4.	   CONTROLS AND PROCEDURES 	

Evaluation of disclosure controls and procedures 
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 September 30, 2004. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods. 
Changes in internal control over financial reporting 
During the period covered by this Quarterly Report on Form 10-Q there have been no 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. 
51

BLACK HILLS CORPORATION 
Part II — Other Information 

Item 1. 	     Legal Proceedings 	

  	For information regarding legal proceedings, see Note 14 in Item 8 of the Company’s 2003 Annual Report on Form 10-K and Note 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item. 	

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

Period
	(a) Total Number
of Shares
Purchased
	(b) Average Price
Paid per Share
	(c) Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs
	(d) Maximum Number
(or Approximate
Dollar Value) of
Shares That May Yet
Be Purchased Under
the Plans or Programs

					

July 1, 2004 -	 	 	 		 	 		 	 		 	 		 	
July 31, 2004	 	 	 	--	 	$	--	 	 	--	 	 	--	 	

August 1, 2004 -	 	 		
August 31, 2004	 	 	 	4,738	(1)	$	27.40	 	 	--	 	 	--	 	

September 1, 2004 -	 	 		
September 30, 2004	 	 	 	306	(2)	$	28.42	 	 	--	 	 	--	 	

Total	 	 	 	5,044	 	$	27.46	 	 	--	 	 	--	 	

_________________ 
(1) 	  	Shares acquired from certain officers and key employees under the share withholding provisions of the Restricted Stock Plan for the payment of taxes associated with the vesting of shares of Restricted Stock. 	

(2) 	  	Shares acquired by a Rabbi Trust for the Outside Directors Stock Based Compensation Plan. 	

52

Item 6.	  Exhibits 	

Exhibit 10.1* 	  	10.1* Form of Stock Option Agreement (filed as Exhibit 10.1 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.2* 	  	Form of Restricted Stock Award Agreement (filed as Exhibit 10.2 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.3* 	  	Form of Restricted Stock Unit Award Agreement (filed as Exhibit 10.3 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.4* 	  	Form of Performance Share Award Agreement (filed as Exhibit 10.4 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.5* 	  	Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.6* 	  	Amended and Restated Credit Agreement dated as of May 14, 2004 among Enserco Energy Inc., as Borrower, and Fortis Capital Corp., as administrative agent, collateral agent, documentation agent and arranger, and BNP Paribas, and U.S. Bank National Association and Societe Generale, and each other financial institution which may become a party hereto (filed as Exhibit 10.1 to the Registrant's Form 8-K for September 30, 2004). 	

Exhibit 10.7* 	  	First Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2004, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale (filed as Exhibit 10.2 to the Registrant's Form 8-K for September 30, 2004). 	

Exhibit 31.1 	  	Certification 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 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 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 	

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

53

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, President and
  Chief Executive Officer 	

  	/s/ Mark T. Thies
Mark T. Thies, Executive Vice President and
  Chief Financial Officer 	

Dated: November 9, 2004 
54

EXHIBIT INDEX 
 	  	Exhibit
Number              Description	

Exhibit 10.1* 	  	10.1* Form of Stock Option Agreement (filed as Exhibit 10.1 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.2* 	  	Form of Restricted Stock Award Agreement (filed as Exhibit 10.2 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.3* 	  	Form of Restricted Stock Unit Award Agreement (filed as Exhibit 10.3 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.4* 	  	Form of Performance Share Award Agreement (filed as Exhibit 10.4 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.5* 	  	Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant's Form 8-K for August 30, 2004). 	

Exhibit 10.6* 	  	Amended and Restated Credit Agreement dated as of May 14, 2004 among Enserco Energy Inc., as Borrower, and Fortis Capital Corp., as administrative agent, collateral agent, documentation agent and arranger, and BNP Paribas, and U.S. Bank National Association and Societe Generale, and each other financial institution which may become a party hereto (filed as Exhibit 10.1 to the Registrant's Form 8-K for September 30, 2004). 	

Exhibit 10.7* 	  	First Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2004, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale (filed as Exhibit 10.2 to the Registrant's Form 8-K for September 30, 2004). 	

Exhibit 31.1 	  	Certification 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 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 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 	

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

55
Exhibit 31.1 
CERTIFICATION 
I, David R. Emery, certify that: 
1. 	I have reviewed this quarterly report on Form 10-Q of Black Hills Corporation; 	

2. 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 	

3. 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 	

4. 	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: 	

a) 	  	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; 	

b) 	  	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 	

c) 	  	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 	

5. 	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): 	

a) 	  	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and 	

b) 	  	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. 	

Date:  November 9, 2004
  	/s/ David R. Emery
President and
Chief Executive Officer 	

Exhibit 31.2
CERTIFICATION 
I, Mark T. Thies, certify that: 
1. 	I have reviewed this quarterly report on Form 10-Q of Black Hills Corporation; 	

2. 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 	

3. 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 	

4. 	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: 	

a) 	  	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; 	

b) 	  	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 	

c) 	  	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 	

5. 	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): 	

a) 	  	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and 	

b) 	  	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. 	

Date:  November 9, 2004
  		
  	/s/ Mark T. Thies
Executive Vice President and
Chief Financial Officer 	

Exhibit 32.1 
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 
In connection with the Quarterly Report of Black Hills Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2004 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David R. Emery, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: 
(1) 	  	The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and 	

(2) 	  	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. 	

/s/ David R. Emery
David R. Emery
President and 
Chief Executive Officer
November 9, 2004 
Exhibit 32.2 
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 
In connection with the Quarterly Report of Black Hills Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2004 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mark T. Thies, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: 
(1) 	  	The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and 	

(2) 	  	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. 	

/s/ Mark T. Thies
Mark T. Thies
Executive Vice President and
Chief Financial Officer
November 9, 2004