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EX-31.EXHIBIT 31.2 - EXHIBIT 31.2 - BLACK HILLS POWER INCexhibit312.htm
EX-32.EXHIBIT 32.1 - EXHIBIT 32.1 - BLACK HILLS POWER INCexhibit321.htm
EX-32.EXHIBIT 32.2 - EXHIBIT 32.2 - BLACK HILLS POWER INCexhibit322.htm
EX-31.EXHIBIT 31.1 - EXHIBIT 31.1 - BLACK HILLS POWER INCexhibit311.htm
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2010.
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from __________ to __________.
        
Commission File Number 1-7978
 
Black Hills Power, Inc.
Incorporated in South Dakota
 
 IRS Identification Number 46-0111677
                                                        
625 Ninth Street, Rapid City, South Dakota 57701
 
Registrant's telephone number (605) 721-1700
 
Former name, former address, and former fiscal year if changed since last report
NONE
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x
No o
 
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
Yes o
No o
 
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer
o
 
Accelerated filer
o
 
 
 
 
 
Non-accelerated filer
x
 
Smaller reporting company
o
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o 
No x
 
As of July 31, 2010, there were issued and outstanding 23,416,396 shares of the Registrant's common stock, $1.00 par value, all of which were held beneficially and of record by Black Hills Corporation.
 
Reduced Disclosure
 
The Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

 

 
Table Of Contents
 
 
 
GLOSSARY OF TERMS AND ABBREVIATIONS
 
PART 1. FINANCIAL INFORMATION
 
 
Item 1. Financial Statements
 
 
Condensed Statements of Income - unaudited
 
Three and Six Months Ended June 30, 2010 and 2009
 
 
 
 
 
Condensed Balance Sheets - unaudited
 
June 30, 2010 and December 31, 2009
 
 
 
 
 
Cash Flow Statements - unaudited
 
Six Months Ended June 30, 2010 and 2009
 
 
 
 
 
Notes to Condensed Financial Statements - unaudited
 
 
 
 
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
Item 4. Controls and Procedures
 
 
 
 
PART II. OTHER INFORMATION
 
 
 
 
Item 1. Legal Proceedings
 
Item 1A. Risk Factors
 
 
 
 
Item 6.
 
 
Exhibits
 
 
 
 
Signatures
 
 
 
 
Exhibits Index
 
 
 
 

2

 

GLOSSARY OF TERMS
 
The following terms and abbreviations appear in the text of this report and have the definitions described below:
 
AFUDC
Allowance for Funds Used During Construction
ASC 810-10-15
ASC 810-10-15, "Consolidation of Variable Interest Entities"
ASC 820
ASC 820, "Fair Value Measurements"
BHC
Black Hills Corporation, the Parent Company
Black Hills Energy
The name used to conduct the business activities of Black Hills Utility Holdings, Inc., a direct subsidiary of the Parent Company
Black Hills Wyoming
Black Hills Wyoming, LLC, an indirect subsidiary of the Parent Company
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Parent Company
DOE
Department of Energy
Enserco
Enserco Energy, Inc., an indirect subsidiary of the Parent Company
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
LIBOR
London Interbank Offered Rate
JPB
Consolidated Wyoming Municipalities Electric Power System Joint Power Board
MDU
MDU Resources Group, Inc.
MMBtu
One million British thermal units
MW
Megawatts
MWh
Megawatt-hours
Participation Agreement
Amendment and Restated Wygen III Participation Agreement dated July 14, 2010 between the Company, MDU and JPB, which includes JPB as partial owner of Wygen III
PPA
Purchase Power Agreement
SDPUC
South Dakota Public Utilities Commission
SEC
U.S. Securities and Exchange Commission
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., an indirect subsidiary of the Parent Company
 
 
 

3

 
 
 
 
 
 
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF INCOME
(unaudited)
 
 
 
 
 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2010
 
2009
 
2010
 
2009
 
(in thousands)
 
 
 
 
 
 
 
 
Operating revenue
$
56,438
 
 
$
46,836
 
 
$
110,927
 
 
$
101,294
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased power
21,616
 
 
19,753
 
 
45,852
 
 
42,515
 
Operations and maintenance
9,390
 
 
8,486
 
 
17,416
 
 
16,124
 
Administrative and general
7,441
 
 
6,972
 
 
13,633
 
 
13,243
 
Depreciation and amortization
5,684
 
 
5,006
 
 
10,418
 
 
10,052
 
Taxes, other than income taxes
1,797
 
 
1,613
 
 
3,737
 
 
3,649
 
Total operating expenses
45,928
 
 
41,830
 
 
91,056
 
 
85,583
 
 
 
 
 
 
 
 
 
Operating income
10,510
 
 
5,006
 
 
19,871
 
 
15,711
 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(5,616
)
 
(2,838
)
 
(9,482
)
 
(5,410
)
Interest income
1,029
 
 
65
 
 
1,424
 
 
164
 
AFUDC - equity
230
 
 
1,276
 
 
2,237
 
 
2,677
 
Other income, net
18
 
 
508
 
 
138
 
 
797
 
Total other income (expense)
(4,339
)
 
(989
)
 
(5,683
)
 
(1,772
)
 
 
 
 
 
 
 
 
Income before income taxes
6,171
 
 
4,017
 
 
14,188
 
 
13,939
 
Income tax expense
(2,069
)
 
(912
)
 
(4,152
)
 
(3,870
)
Net income
$
4,102
 
 
$
3,105
 
 
$
10,036
 
 
$
10,069
 
 
 
 
 
 
 
 
 
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
 

4

 

BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(unaudited)
 
June 30,
2010
 
December 31,
2009
 
(in thousands)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
2,503
 
 
$
1,709
 
Receivables - customers, net
19,000
 
 
19,991
 
Receivables - affiliates, net
4,929
 
 
4,146
 
Other receivables, net
2,428
 
 
5,293
 
Money pool notes receivable
 
 
57,737
 
Materials, supplies and fuel
19,422
 
 
18,825
 
Regulatory assets, current
6,438
 
 
7,467
 
Other current assets
2,884
 
 
1,639
 
Total current assets
57,604
 
 
116,807
 
 
 
 
 
Investments
4,337
 
 
4,197
 
 
 
 
 
Property, plant and equipment
984,695
 
 
950,577
 
Less accumulated depreciation and amortization
(298,811
)
 
(293,823
)
Total property, plant and equipment, net
685,884
 
 
656,754
 
 
 
 
 
Other assets:
 
 
 
Regulatory assets - non-current
32,227
 
 
31,305
 
Other, non-current assets
4,403
 
 
3,730
 
Total other assets
36,630
 
 
35,035
 
TOTAL ASSETS
$
784,455
 
 
$
812,793
 
 
 
 
 
LIABILITIES AND STOCKHOLDER'S EQUITY
 
 
 
Current liabilities:
 
 
 
Current maturities of long-term debt
$
75
 
 
$
32,025
 
Accounts payable
14,248
 
 
24,175
 
Accounts payable - affiliates
6,984
 
 
10,030
 
Notes Payable - affiliates
13,028
 
 
 
Accrued liabilities
16,624
 
 
17,892
 
Regulatory liabilities, current
3,138
 
 
1,238
 
Deferred income tax liabilities - current
1,781
 
 
1,853
 
Total current liabilities
55,878
 
 
87,213
 
 
 
 
 
Long-term debt, net of current maturities
276,462
 
 
297,044
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
Deferred income tax liability - non-current
107,058
 
 
96,207
 
Regulatory liabilities, non-current
16,783
 
 
14,955
 
Benefit plan liabilities
30,093
 
 
28,224
 
Other, deferred credits and other liabilities
9,720
 
 
10,952
 
Total deferred credits and other liabilities
163,654
 
 
150,338
 
 
 
 
 
Stockholder's equity:
 
 
 
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued
23,416
 
 
23,416
 
Additional paid-in capital
39,575
 
 
39,575
 
Retained earnings
226,456
 
 
216,420
 
Accumulated other comprehensive loss
(986
)
 
(1,213
)
Total stockholder's equity
288,461
 
 
278,198
 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY
$
784,455
 
 
$
812,793
 
 
 
 
 
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

5

 

 
BLACK HILLS POWER, INC.
 
CONDENSED STATEMENTS OF CASH FLOWS
 
(unaudited)
 
 
Six Months Ended June 30,
 
 
2010
 
2009
 
 
(in thousands)
 
Operating activities:
 
 
 
 
Net income
$
10,036
 
 
$
10,069
 
 
Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
 
Depreciation and amortization
10,418
 
 
10,052
 
 
Deferred income tax
11,029
 
 
3,634
 
 
Employee benefits
2,043
 
 
2,180
 
 
AFUDC - equity
(2,237
)
 
(2,677
)
 
Other non-cash adjustments
159
 
 
175
 
 
Change in operating assets and liabilities -
 
 
 
 
Accounts receivable and other current assets
(1,953
)
 
10,255
 
 
Accounts payable and other current liabilities
(10,495
)
 
11,011
 
 
Regulatory assets
(441
)
 
6
 
 
Regulatory liabilities
 
 
(142
)
 
Other operating activities
2,027
 
 
1,305
 
 
Net cash provided by operating activities
20,586
 
 
45,868
 
 
 
 
 
 
 
Investing activities:
 
 
 
 
Property, plant and equipment additions
(40,241
)
 
(76,911
)
 
Proceeds from sale of ownership interest in plant
 
 
32,321
 
 
Change in money pool note receivable from affiliate, net
57,737
 
 
 
 
Other investing activities
3,392
 
 
(4,314
)
 
Net cash provided by (used in) investing activities
20,888
 
 
(48,904
)
 
 
 
 
 
 
Financing activities:
 
 
 
 
Long-term debt - repayments
(52,532
)
 
(1,984
)
 
Change in money pool note payable to affiliates, net
13,028
 
 
5,642
 
 
Other financing activities
(1,176
)
 
 
 
Net cash (used in) provided by financing activities
(40,680
)
 
3,658
 
 
 
 
 
 
 
Increase in cash and cash equivalents
794
 
 
622
 
 
 
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Beginning of period
1,709
 
 
4
 
 
End of period
$
2,503
 
 
$
626
 
 
 
 
 
 
 
See Note 11 for supplemental cash flow information
 
 
 
 
 
 
 
 
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
 

6

 

BLACK HILLS POWER, INC.
 
Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in our 2009 Annual Report on Form 10-K)
 
(1)  MANAGEMENT'S STATEMENT
 
The condensed financial statements included herein have been prepared by Black Hills Power, Inc. (the "Company," "we," "us," or "our"), without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe 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 our 2009 Annual Report on Form 10-K filed with the SEC.
 
Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the June 30, 2010, December 31, 2009 and June 30, 2009 financial information and are of a normal recurring nature. The results of operations for the three and six months ended June 30, 2010 and our financial condition as of June 30, 2010 and December 31, 2009 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.
 
Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation. These reclassifications had no effect on total assets, net income, cash flows or earnings per share.
 
(2)  RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION
 
Recently Adopted Accounting Standards
 
Consolidation of Variable Interest Entities, ASC 810-10-15
 
In June 2009, the FASB issued a revision regarding consolidations. The amendment requires a company to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It also requires additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This standard is effective for annual periods that begin after November 15, 2009 with ongoing re-evaluation. The adoption of this standard had no impact on our financial statements.
 
Fair Value Measurements, ASC 820
 
In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3, fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements are required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. The guidance requires additional disclosures, but did not and will not impact our financial position, results of operations or cash flows.
 

7

 

Recently Issued Accounting Standards and Legislation
 
Patient Protection and Affordable Care Act (HR 3590)
 
On March 23, 2010, the President of the United States signed into law comprehensive healthcare reform legislation under the Patient Protection and Affordable Care Act, as amended by the Healthcare and Education Reconciliation Act. Included among the provisions of the law is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which would affect our Non-Pension Postretirement Benefit Plan. Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012. The application of this legislation resulted in an adjustment to Regulatory assets and is not expected to have a significant impact on our financial position, results of operations or cash flows.
 
 
(3)  ACCOUNTS RECEIVABLE
 
We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade receivables allowances by considering such factors as historical experience, credit-worthiness, the age of the receivable balances and current economic conditions that may affect the ability to pay.
 
Following is a summary of accounts receivable balances (in thousands):
 
 
June 30,
2010
 
December 31,
2009
 
 
 
 
Accounts receivable trade
$
14,003
 
 
$
14,703
 
Unbilled revenues
5,220
 
 
5,547
 
Total accounts receivable - customers
19,223
 
 
20,250
 
Allowance for doubtful accounts
(223
)
 
(259
)
Receivables - customers, net
$
19,000
 
 
$
19,991
 
 
 

8

 

(4)  REGULATORY ACCOUNTING
 
We had the following regulatory assets and liabilities (in thousands):
 
 
Recovery Period
June 30,
2010
 
December 31,
2009
 
 
 
 
 
Regulatory assets:
 
 
 
 
Unamortized loss on reacquired debt
14 years
$
3,141
 
 
$
2,207
 
AFUDC
Up to 45 years
7,106
 
 
7,579
 
Defined benefit postretirement plans
Up to 17 years
21,024
 
 
21,024
 
Deferred energy costs
Less than one year
6,438
 
 
7,467
 
Other
 
956
 
 
495
 
Total regulatory assets
 
$
38,665
 
 
$
38,772
 
 
 
 
 
 
Regulatory liabilities:
 
 
 
 
Cost of removal for utility plant
Up to 53 years
$
14,663
 
 
$
13,678
 
Other
 
5,258
 
 
2,515
 
Total regulatory liabilities
 
$
19,921
 
 
$
16,193
 
 
Regulatory assets are primarily recorded for the probable future revenue to recover the costs associated with defined benefit postretirement plans, future income taxes related to the deferred tax liability for the equity component of AFUDC of utility assets and unamortized losses on reacquired debt. To the extent that energy costs are under-recovered or over-recovered during the year, they are recorded as a regulatory asset or liability, respectively. Regulatory liabilities include the probable future decrease in rate revenues related to a decrease in deferred tax liabilities for prior reductions in statutory federal income tax rates, gains associated with regulated utilities' defined benefit postretirement plans and the cost of removal for utility plant, recovered through our electric utility rates. Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Condensed Balance Sheet. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Condensed Balance Sheet.
 
 
(5)  OTHER COMPREHENSIVE INCOME
 
The following table presents the components of Other comprehensive income (in thousands):
 
 
Three Months Ended June 30,
 
2010
 
2009
Net income
$
4,102
 
 
$
3,105
 
Other comprehensive income, net of tax:
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $4)
(6
)
 
 
Reclassification adjustments included in net income (net of tax of $(6) and $(6), respectively)
10
 
 
11
 
Comprehensive income
$
4,106
 
 
$
3,116
 
 

9

 

 
Six Months Ended June 30,
 
2010
 
2009
Net income
$
10,036
 
 
$
10,069
 
Other comprehensive income, net of tax:
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(115))
206
 
 
 
Reclassification adjustments included in net income (net of tax of $(11) and $(11), respectively)
21
 
 
21
 
Comprehensive income
$
10,263
 
 
$
10,090
 
 
Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Balance Sheets are as follows (in thousands):
 
 
June 30,
2010
 
December 31,
2009
Derivatives designated as cash flow hedges
$
(666
)
 
$
(893
)
Employee benefit plans
(320
)
 
(320
)
Total Accumulated other comprehensive loss
$
(986
)
 
$
(1,213
)
 
 
(6)  RELATED-PARTY TRANSACTIONS
 
Receivables and Payables
 
We have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $4.9 million and $4.1 million as of June 30, 2010 and December 31, 2009, respectively. We also have accounts payable balances related to transactions with other BHC subsidiaries. The balances were $7.0 million and $10.0 million as of June 30, 2010 and December 31, 2009, respectively.
 
Money Pool Notes Receivable and Notes Payable
 
We have entered into a Utility Money Pool Agreement (the "Agreement") with BHC, Cheyenne Light and Black Hills Energy. Under the Agreement, we may borrow from our Parent. The Agreement restricts us from loaning funds to our Parent or to any of our Parent's non-utility subsidiaries; the Agreement does not restrict us from making dividends to our Parent. Borrowings under the agreement bear interest at the daily cost of external funds as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one month LIBOR rate plus 100 basis points.
 
Through the Utility Money Pool, we had a net notes payable balance of $13.1 million on June 30, 2010 and a net notes receivable balance of $57.7 million as of December 31, 2009. Advances under these notes bear interest at 2.75% above the daily LIBOR rate (which equates to 0.35% at June 30, 2010). Net interest income of less than $0.1 million and $0.1 million was recorded for the three and six months ended June 30, 2010, respectively. Net interest expense was $0.7 million and $1.1 million for the three and six months ended June 30, 2009, respectively.
 

10

 

Other Balances and Transactions
 
We also received revenues of approximately $0.8 million and $0.2 million for the three months ended June 30, 2010 and 2009, respectively, and $0.9 million and $0.4 million for the six months ended June 30, 2010 and 2009, respectively from Black Hills Wyoming for the transmission of electricity.
 
We received revenues of approximately $0.3 million and $0.4 million for the three months ended June 30, 2010 and 2009, respectively, and $0.9 million and $0.7 million for the six months ended June 30, 2010 and June 30, 2009 from Cheyenne Light for the sale of electricity and dispatch services.
 
We purchase coal from WRDC. The amount purchased during the three months ended June 30, 2010 and 2009 was $3.9 million and $3.2 million, respectively; and $8.0 million and $7.1 million for the six months ended June 30, 2010 and June 30, 2009, respectively.
 
We purchase excess power generated by Cheyenne Light. The amount purchased during the three and six months ended June 30, 2010 was $2.1 million and $4.7 million and includes $1.3 million and $2.5 million for wind-generated power, respectively. The amount purchased for the three and six month periods ended June 30, 2009 was $2.0 million and $3.9 million and includes $0.5 million and $1.3 million of wind-generated power, respectively.
 
In order to fuel our combustion turbine, we purchase natural gas from Enserco. The amount purchased during the three months ended June 30, 2010 and 2009 was $0.2 million and $0.5 million, respectively; and $0.7 million and $0.6 million for the six months ended June 30, 2010 and 2009. These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.
 
In addition, we also pay our Parent for allocated corporate support service cost incurred on our behalf. Corporate costs allocated from our Parent were $4.2 million and $3.8 million for the three months ended June 30, 2010 and 2009, respectively; and $8.2 million and $7.4 million for the six months ended June 30, 2010 and 2009, respectively.
 
We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $2.0 million as of June 30, 2010 and $2.0 million as of December 31, 2009, respectively, which is included in Other, Deferred credits and other liabilities on the accompanying Condensed Balance Sheets. Interest on the funds accrues quarterly at an average quarterly prime rate (3.10% at June 30, 2010) and was less than $0.1 million for the three and six months ended June 30, 2010 and 2009, respectively.
 

11

 

(7)  EMPLOYEE BENEFIT PLANS
 
Defined Benefit Pension Plan
 
We have a noncontributory defined benefit pension plan (the "Plan") covering the employees who meet certain eligibility requirements.
 
The components of net periodic benefit cost for the Plan are as follows (in thousands):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2010
 
2009
 
2010
 
2009
Service cost
$
304
 
 
$
292
 
 
$
608
 
 
$
584
 
Interest cost
820
 
 
785
 
 
1,641
 
 
1,570
 
Expected return on plan assets
(752
)
 
(657
)
 
(1,504
)
 
(1,314
)
Prior service cost
15
 
 
28
 
 
30
 
 
56
 
Net loss
344
 
 
430
 
 
687
 
 
860
 
Net periodic benefit cost
$
731
 
 
$
878
 
 
$
1,462
 
 
$
1,756
 
 
There were no contributions made to the Plan in the first quarter of 2010. There are no further contributions expected to be made to the Plan in 2010.
 
Non-pension Defined Benefit Postretirement Plans
 
Employees who are participants in the Postretirement Healthcare Plans (the "Healthcare Plans") and who meet certain eligibility requirements are entitled to postretirement healthcare benefits.
 
The components of net periodic benefit cost for the Healthcare Plans are as follows (in thousands):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2010
 
2009
 
2010
 
2009
Service cost
$
94
 
 
$
54
 
 
$
188
 
 
$
108
 
Interest cost
149
 
 
111
 
 
298
 
 
222
 
Amortization of prior service cost
(42
)
 
 
 
(84
)
 
 
Net loss
56
 
 
 
 
112
 
 
 
Net transition obligation
 
 
13
 
 
 
 
26
 
Net periodic benefit cost
$
257
 
 
$
178
 
 
$
514
 
 
$
356
 
 
We anticipate that we will make contributions to the Healthcare Plan for the 2010 fiscal year of approximately $0.3 million. Contributions are expected to be made in the form of benefit payments.
 
It has been determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was less than $0.1 million.
 

12

 

Supplemental Nonqualified Defined Benefit Plans
 
We have various supplemental retirement plans for key executives (the "Supplemental Plans"). The Supplemental Plans are non-qualified defined benefit plans.
 
The components of net periodic benefit cost for the Supplemental Plans are as follows (in thousands):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2010
 
2009
 
2010
 
2009
Interest cost
$
25
 
 
$
25
 
 
$
50
 
 
$
50
 
Net loss
7
 
 
11
 
 
14
 
 
22
 
Net periodic benefit cost
$
32
 
 
$
36
 
 
$
64
 
 
$
72
 
 
We anticipate that we will make contributions to the Supplemental Plans for the 2010 fiscal year of approximately $0.1 million. Contributions are expected to be in the form of benefit payments.
 
 
(8)  FAIR VALUE OF FINANCIAL INSTRUMENTS
 
The estimated fair values of our financial instruments are as follows (in thousands):
 
 
June 30, 2010
 
December 31, 2009
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Cash and cash equivalents
$
2,503
 
 
$
2,503
 
 
$
1,709
 
 
$
1,709
 
Derivative financial instruments - other current assets
$
312
 
 
$
312
 
 
$
 
 
$
 
Derivative financial instruments - accrued liabilities
$
 
 
$
 
 
$
5
 
 
$
5
 
Long-term debt, including current maturities
$
276,537
 
 
$
313,767
 
 
$
329,069
 
 
$
344,942
 
 
The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.
 
Cash and Cash Equivalents
 
The carrying amount approximates fair value due to the short maturity of these instruments.
 
Derivative Financial Instruments
 
These instruments are carried at fair value. Pricing is based on quoted prices for identical or similar assets and liabilities in active and inactive markets, inputs other than quoted prices that are observable and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means.
 
Long-Term Debt
 
The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings.
 

13

 

(9)  RISK MANAGEMENT ACTIVITIES AND DERIVATIVES
 
We hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, we utilize various derivative instruments in managing these risks.
 
As of June 30, 2010 and December 31, 2009, we had the following swaps and related balances (dollars, in thousands):
 
 
Natural Gas Swaps
 
June 30, 2010
 
December 31, 2009
Notional*
232,500
 
 
232,500
 
Maximum terms in months
4
 
 
10
 
Current derivative asset
$
312
 
 
$
 
Non-current derivative asset
$
 
 
$
 
Current derivative liability
$
 
 
$
5
 
Non-current derivative liability
$
 
 
$
 
Pre-tax accumulated other comprehensive income (loss) included in the Condensed Balance Sheets
$
312
 
 
$
(5
)
Unrealized gain/(loss)
$
 
 
$
 
 
 
 
 
* Gas in MMBtus.
 
 
 
 
 
 
(10)  LONG-TERM DEBT
 
In February 2010, our Series AC bonds matured. These were paid in full for $30.0 million plus accrued interest of $1.2 million.
 
In February 2010, we provided notice to the bondholders of our intent to call the Series Y bonds in full. These bonds were originally due in 2018. A total of $2.7 million was paid on March 31, 2010, which included the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.
 
In April 2010, we provided notice to the bondholders of our intent to call the Series Z bonds in full. These bonds were originally due to mature in 2021. A total of $21.8 million was paid on June 1, 2010, which included the principal balance of $20.0 million plus accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.
 
 

14

 

(11)  SUPPLEMENTAL CASH FLOWS INFORMATION
 
 
Six Months ended
 
June 30, 2010
 
June 30, 2009
 
(in thousands)
Non-cash investing and financing activities -
 
 
 
Property, plant and equipment financed with accrued liabilities
$
5,897
 
 
$
27,782
 
 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash (paid) refunded during the period for -
 
 
 
Interest (net of amounts capitalized)
$
(10,959
)
 
$
(4,970
)
Income taxes
$
6,517
 
 
$
(621
)
 
 
(12)  COMMITMENTS AND CONTINGENCIES
 
Legal Proceedings
 
We are subject to various legal proceedings, claims and litigation as described in Note 12 of the Notes to our Financial Statements in our 2009 Annual Report on Form 10-K. There have been no material developments in any previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first six months of 2010.
 
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our financial statements are adequate in light of the probable and estimable contingencies.  However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our financial statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of June 30, 2010, cannot be reasonably determined and could have a material adverse effect on our results of operations, financial position or cash flows.
 
Purchase Power Agreement
 
In March 2010, we entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette, Wyoming effective April 2010 that replaces a previous agreement. This PPA provided the City of Gillette, through JPB, with an option to purchase a 23% ownership interest in our Wygen III facility which commenced commercial operations on April 1, 2010. The City of Gillette notified us of their intent to exercise the option to purchase the 23% ownership interest in Wygen III and the transaction closed in July 2010. The PPA terminated upon the closing of the transaction. (See Note 13)
 
(13)  SUBSEQUENT EVENT
 
Partial Sale of Wygen III
 
On July 14, 2010, we sold a 23% ownership interest in Wygen III to the JPB for $62.0 million. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The transaction entitles the JPB to approximately 25.3 MW for the life of the plant. The purchase terminates the current PPA with the City of Gillette, and the Participation Agreement provides that the City of Gillette pay us for administrative services and share in the costs of operating the plant for the life of the facility.

15

 

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2010
 
2009
 
2010
 
2009
 
(in thousands)
Revenues
$
56,438
 
 
$
46,836
 
 
$
110,927
 
 
$
101,294
 
Fuel and purchased power
21,616
 
 
19,753
 
 
45,852
 
 
42,515
 
Gross margin
34,822
 
 
27,083
 
 
65,075
 
 
58,779
 
 
 
 
 
 
 
 
 
Operating, general and administrative expenses
24,312
 
 
22,077
 
 
45,204
 
 
43,068
 
Operating income
10,510
 
 
5,006
 
 
19,871
 
 
15,711
 
 
 
 
 
 
 
 
 
Interest expense, net
(4,587
)
 
(2,773
)
 
(8,058
)
 
(5,246
)
Other income
18
 
 
508
 
 
138
 
 
797
 
AFUDC - equity
230
 
 
1,276
 
 
2,237
 
 
2,677
 
Income tax expense
(2,069
)
 
(912
)
 
(4,152
)
 
(3,870
)
Net income
$
4,102
 
 
$
3,105
 
 
$
10,036
 
 
$
10,069
 
 
 
 

16

 

The following tables provide certain operating statistics (dollars in thousands):
 
Electric Revenue
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Customer Base
2010
 
Percentage Change
 
2009
 
2010
 
Percentage Change
 
2009
Commercial
$
16,104
 
 
11
%
 
$
14,551
 
 
$
30,643
 
 
5
%
 
$
29,194
 
Residential
11,546
 
 
11
%
 
10,391
 
 
26,025
 
 
5
%
 
24,672
 
Industrial
6,204
 
 
23
%
 
5,030
 
 
10,841
 
 
11
%
 
9,780
 
Municipal Sales
748
 
 
13
%
 
660
 
 
1,401
 
 
8
%
 
1,296
 
Total retail sales
34,602
 
 
13
%
 
30,632
 
 
68,910
 
 
6
%
 
64,942
 
Contract wholesale
7,078
 
 
26
%
 
5,631
 
 
13,796
 
 
13
%
 
12,184
 
Wholesale off system
8,539
 
 
48
%
 
5,765
 
 
17,255
 
 
15
%
 
14,985
 
Total electric sale
50,219
 
 
19
%
 
42,028
 
 
99,961
 
 
9
%
 
92,111
 
Other revenues
6,219
 
 
29
%
 
4,808
 
 
10,966
 
 
19
%
 
9,183
 
Total revenues
$
56,438
 
 
21
%
 
$
46,836
 
 
$
110,927
 
 
10
%
 
$
101,294
 
 
 
 
Megawatt Hours Sold
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Customer Base
2010
 
Percentage Change
 
2009
 
2010
 
Percentage Change
 
2009
Commercial
164,863
 
 
(3
)%
 
169,955
 
 
349,301
 
 
1
%
 
345,211
 
Residential
113,903
 
 
(4
)%
 
119,123
 
 
288,438
 
 
2
%
 
282,599
 
Industrial
101,425
 
 
8
%
 
93,984
 
 
188,088
 
 
5
%
 
179,968
 
Municipal sales
7,577
 
 
0
%
 
7,567
 
 
15,803
 
 
1
%
 
15,662
 
Total retail sales
387,768
 
 
(1
)%
 
390,629
 
 
841,630
 
 
2
%
 
823,440
 
Contract wholesale
120,258
 
 
(16
)%
 
143,248
 
 
288,723
 
 
(7
)%
 
311,927
 
Wholesale off system
299,064
 
 
30
%
 
230,617
 
 
530,111
 
 
12
%
 
474,403
 
Total electric sales
807,090
 
 
6
%
 
764,494
 
 
1,660,464
 
 
3
%
 
1,609,770
 
Losses and company use
43,792
 
 
7
%
 
41,104
 
 
53,511
 
 
(20
)%
 
67,293
 
Total energy
850,882
 
 
6
%
 
805,598
 
 
1,713,975
 
 
2
%
 
1,677,063
 
 
 
 
Electric Utility Power Plant Availability
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2010
 
2009
 
2010
 
2009
Coal-fired plants *
90.9
%
 
77.4
%
 
91.4
%
 
87.0
%
Other plants
98.8
%
 
92.2
%
 
99.3
%
 
95.8
%
Total availability
93.8
%
 
83.9
%
 
94.4
%
 
90.8
%
 
*    2009 reflects major outages at Neil Simpson I and Neil Simpson II coal-fired plants. The Neil Simpson I outage was scheduled for 31 days and was subsequently extended to 39 days. The Neil Simpson II outage was scheduled for 18 days and was subsequently extended to 27 days. The outages were extended on both units for major rotor damage discovered during the overhauls.
 
 
 

17

 

 
Megawatt Hours Generated and Purchased
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Generated -
2010
 
Percentage Change
 
2009
 
2010
 
Percentage Change
 
2009
Coal-fired
559,258
 
 
60
%
 
348,657
 
 
989,831
 
 
26
%
 
786,208
 
Gas-fired
1,106
 
 
(81
)%
 
5,750
 
 
3,944
 
 
(42
)%
 
6,825
 
 
560,364
 
 
58
%
 
354,407
 
 
993,775
 
 
25
%
 
793,033
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchased
290,518
 
 
(36
)%
 
451,191
 
 
720,200
 
 
(19
)%
 
884,030
 
Total Generated and Purchased
850,882
 
 
6
%
 
805,598
 
 
1,713,975
 
 
2
%
 
1,677,063
 
 
 
 
Degree Days
Degree Days
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2010
2009
2010
2009
Heating and cooling degree days:
 
 
 
 
Actual -
 
 
 
 
Heating degree days
904
 
1,273
 
4,296
 
4,527
 
Cooling degree days
65
 
51
 
65
 
51
 
 
 
 
 
 
Variance from normal -
 
 
 
 
Heating degree days
9
%
28
%
4
%
5
%
Cooling degree days
(37
)%
(50
)%
(37
)%
(50
)%
 
Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009. Net income was $4.1 million compared to $3.1 million for the same period in the prior year primarily due to the following:
 
Gross margin: Gross margin increased $7.7 million primarily due to the impact of $5.9 million related to the outcome of the rate case where interim rates were put into effect on April 1, 2010, an increase of $0.3 million in off-system sales, a decrease in purchased power costs of $0.9 million due to the commencement of commercial operations of Wygen III, and increased intercompany revenues of $0.6 million related to a shared services agreement.
 
Operating expenses: Operating expenses increased $2.2 million primarily due to an increase of $0.9 million in depreciation expense associated with depreciation for the Wygen III plant which commenced commercial operations on April 1, 2010, an increase of $0.4 million in labor and employee benefit costs, an increase in property taxes of $0.2 million and an increase of $0.8 million in intercompany costs associated with a shared services agreement.
 
Interest expense, net: Interest expense, net increased $1.8 million primarily due to higher interest expense of $1.9 million on the bonds and a $0.6 million decrease in AFUDC associated with the borrowed funds with the completed construction at Wygen III.
 
Other income, net: Other income, net decreased $1.5 million primarily due to a decrease in AFUDC-equity.
 
Income tax, expense: Income tax expense increased $1.2 million primarily due to an increase in earnings before taxes compared to the same period in the prior year and a higher effective tax rate resulting from the lower benefit from AFUDC-equity which decreased upon commercial operations of Wygen III.
 

18

 

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009. Net income was $10.0 million compared to $10.1 million for the same period in prior year primarily due to the following:
 
Gross margin: Gross margin increased $6.3 million primarily due to the impact of $5.9 million related to the outcome of the rate case where interim rates that went into effect on April 1, 2010, an increase of $0.7 million from off-system sales, and increased intercompany revenues of $1.2 million associated with a shared services agreement, partially offset by an increase in purchased power costs of $2.1 million not recoverable through the energy cost adjustment.
 
Operating expenses: Operating expenses increased $2.1 million primarily due to an increase of $0.9 million in depreciation expense associated with depreciation for the Wygen III plant which commenced commercial operations on April 1, 2010, an increase of $0.2 million in labor and employee benefit costs and an increase of $1.2 million in intercompany costs associated with a shared services agreement.
 
Interest expense, net: Interest expense, net increased $2.8 million primarily due to a higher interest expense on the bonds offset by a $0.2 million increase in AFUDC associated with the borrowed funds from the construction at Wygen III.
 
Other income, net: Other income decreased $1.1 million primarily due to a decrease in AFUDC-equity and prior year's recognition of $0.5 million from the sale of Wygen III.
 
Income tax, expense: The effective tax rate for the six months ended June 30, 2010 was comparable to the effective tax rate for the six months ended June 30, 2009.

19

 

Significant Events
 
Sale of Partial Ownership in Wygen III
 
In March 2010, we entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette, Wyoming effective April 2010 that replaced a previous PPA entered into in 1998. This new agreement also provided the City of Gillette, through JPB, with an option to purchase a 23% ownership interest, or approximately 25.3 MW, in our Wygen III facility which commenced commercial operations on April 1, 2010. the JBP exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The City of Gillette exercised this option on July 14, 2010 and the JPB purchased the 23% ownership interest in Wygen III for $62.0 million for which we will recognize a gain on the sale of approximately $5.0 million to $6.0 million. We will continue to operate Wygen III and, through the Participation Agreement, the City of Gillette will pay us for administrative services and its share in the costs of operating the plant. The PPA dated March 2010 terminated upon the closing of the transaction.
 
Smart Grid Funding
 
In April 2010, we reached an agreement with the DOE for smart grid funding through grants totaling $9.6 million. The funds are made available through the American Recovery and Reinvestment Act of 2009 and, combined with matching investment funds from us, will enable us to install 69,000 smart meters and related communications infrastructure and information technology software and equipment. We expect to complete installation of these meters in 2011 and have spent $0.3 million of the DOE grant funds during 2010.
 
Wygen III Power Plant Project
 
Construction of our 110 MW coal-fired base load electric generation facility, Wygen III, was completed and it commenced commercial operations on April 1, 2010. The expected cost of construction is approximately $255 million, which includes estimates of AFUDC. In April 2009, we sold a 25% ownership interest to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date for the on-going construction of the facility. As described above, in July 2010, we sold an additional 23% ownership in Wygen III to the City of Gillette.
 
Rate Case Filed with the SDPUC
 
In 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years. We were seeking a $32.0 million, or 26.6%, increase in annual utility revenues. In March 2010, the SDPUC approved interim rates for a 20% increase in rates effective April 1, 2010 for South Dakota customers. On July 8, 2010, the SDPUC approved a final revenue increase of $15.2 million or 12.7%. The final settlement represented a rate base increase of $22.0 million, or 19.4%. A refund to customers will be provided and has been accrued for the difference in rates.
 
As part of the rate case settlement, we have agreed that (a) 65% of our off-system sales income will be credited to ratepayers with a minimum credit of $2.0 million per year; (b) our rates will reflect an SD Surplus Energy Credit of $2.5 million in year one (fiscal year ending March 2011), $2.25 million in year two, $2.0 million in year three and zero thereafter; and (c) a three year moratorium on any rate case filings excluding any extraordinary events as defined in the stipulation agreement.
 
Rate Case Filed with the WPSC
 
On October 19, 2009, we filed a rate case with the WPSC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. We were seeking a $3.8 million, or 38.95%, increase in annual utility revenues. On May 13, 2010, the WPSC approved an annual rate increase of $3.1 million effective June 1, 2010.

20

 

Financing Transactions and Short-Term Liquidity
 
Financing
 
In February 2010, our Series AC bonds matured. These were paid in full for $30.0 million plus accrued interest of $1.2 million.
 
In February 2010, we provided notice to the bondholders of our intent to call our Series Y bonds in full. These bonds were originally due in 2018. The balance of $2.7 million was paid on March 31, 2010, which includes the balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.
 
In April 2010, we provided notice to the bondholders of our intent to call the Series Z bonds in full. These bonds, originally due in 2021, were paid in full on June 1, 2010 with a payment of $21.8 million which included principal of $20.0 million, accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.
 
Credit Ratings
 
Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. As of June 30, 2010, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:
 
 
Rating Agency
Rating
Outlook
Moody's
A3
Stable
S&P *
BBB
Stable
Fitch
A-
Stable
 
* In July 2010, S&P upgraded our senior secured debt rating to BBB+.

21

 

SAFE HARBOR FOR FORWARD-LOOKING INFORMATION
 
This Quarterly Report on Form 10-Q includes "forward-looking statements" as defined by the 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. Forward-looking statements involve risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potentials," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurances that such indicated results will be realized. The forward-looking statements include the factors discussed above, the risk factors described in Item 1A. of our 2009 Annual Report on Form 10-K, in Item 1A. of Part II of this Quarterly Report on Form 10-Q filed with the SEC, and the following:
 
•    
Our ability to obtain adequate cost recovery for our retail utility operations through regulatory proceedings; to receive favorable rulings in the periodic applications to recover costs for fuel and purchased power; and our ability to add power generation assets into regulatory rate base;
 
•    
Our ability to access the bank loan and debt capital markets depends on market conditions beyond our control. If the credit markets remain tight and do not improve, we may not be able to permanently refinance some short-term debt and fund our power generation projects on reasonable terms, if at all;
 
•    
Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things. If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all;
 
•    
Our ability to obtain from utility commissions any requisite determination of prudency to support resource planning and development programs we propose to implement;
 
•    
The timing and extent of scheduled and unscheduled outages of power generation facilities;
 
•    
The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;
 
•    
Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 2005 and subsequent rules and regulations promulgated thereunder;
 
•    
Our ability to remedy any deficiencies that may be identified in the review of our internal controls;
 
•    
Our ability to successfully complete labor negotiations with our union;
 
•    
Our ability to recover our borrowing costs, including debt service costs, in our customer rates;
 
•    
Liabilities of environmental conditions, including remediation and reclamation obligations under environmental laws;
 
•    
Our ability to complete the permitting, construction, start-up and operations of power generating facilities in a cost-effective and timely manner;

22

 

 
•    
The timing, volatility and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost and availability 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;
 
•    
Our ability to effectively use derivative financial instruments to hedge commodity risks;
 
•    
Our ability to minimize defaults on amounts due from counterparty transactions;
 
•    
Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment and to recover those expenditures in customer rates, where applicable;
 
•    
Federal and state laws concerning climate change and air emissions, including emission reduction mandates and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain;
 
•    
Weather and other natural phenomena;
 
•    
Industry, market, political and economic 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 or events;
 
•    
The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements on our financial condition or results of operations;
 
•    
Price risk due to marketable securities held as investments in benefit plans;
 
•    
General economic and political conditions, including tax rates or policies and inflation rates; and
 
•    
Other factors discussed from time to time in our other 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.

23

 

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 June 30, 2010. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
 
There were no changes in our internal control over financial reporting during the quarter ended June 30, 2010 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
 

24

 

BLACK HILLS POWER, INC.
 
Part II - Other Information
 
Item 1. Legal Proceedings
 
For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of our 2009 Annual Report on Form 10-K and Note 8 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 8 is incorporated by reference into this item.

25

 

Item 1A. Risk Factors
 
Except to the extent updated or described below, our Risk Factors are documented in Item 1A. of  Part I in our Annual Report on Form 10-K for the year ended December 31, 2009.
 
Municipal governments within our utility service territories possess the power of condemnation, and could seek a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations, and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.
 
 

26

 

   
Item 6.    Exhibits
 
 
Exhibit 31.1  Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
Exhibit 31.2 Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
Exhibit 32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
Exhibit 32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 

27

 

BLACK HILLS POWER, INC.
 
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 POWER, INC.
 
 
 /S/ DAVID R. EMERY
 David R. Emery, Chairman
  and Chief Executive Officer 
 
 
 /S/ ANTHONY S. CLEBERG
 Anthony S. Cleberg, Executive Vice President
  and Chief Financial Officer
 
Dated: August 10, 2010
 
 
 
 
 
 

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EXHIBIT INDEX
 
Exhibit Number Description
 
Exhibit 31.1  Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
Exhibit 31.2 Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
Exhibit 32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
Exhibit 32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

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