Attached files
file | filename |
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EX-31.EXHIBIT 31.2 - EXHIBIT 31.2 - BLACK HILLS POWER INC | exhibit312.htm |
EX-32.EXHIBIT 32.1 - EXHIBIT 32.1 - BLACK HILLS POWER INC | exhibit321.htm |
EX-32.EXHIBIT 32.2 - EXHIBIT 32.2 - BLACK HILLS POWER INC | exhibit322.htm |
EX-31.EXHIBIT 31.1 - EXHIBIT 31.1 - BLACK HILLS POWER INC | exhibit311.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 |
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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. |
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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.
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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 |
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(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 |
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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.
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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.
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(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.
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(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.
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(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.
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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 |
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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.
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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.
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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.
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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.
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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.
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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
28
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.
29