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 |
OR |
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o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
| EXCHANGE ACT OF 1934 |
| For the transition period from __________ to __________. |
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| 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 | |
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Registrant’s telephone number (605) 721-1700 | |
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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 |
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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 |
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| Non-accelerated filer | x |
| Smaller reporting company | o |
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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 |
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As of October 31, 2008,April 30, 2009, 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
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| GLOSSARY OF TERMS | 3 |
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PART 1. | FINANCIAL INFORMATION |
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Item 1. | Financial Statements |
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| Condensed Statements of Income – |
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| Three | 4 |
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| Condensed Balance Sheets – |
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| 5 |
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| Condensed Statements of Cash Flows – |
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| 6 |
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| Notes to Condensed Financial Statements | 7-12 |
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Item 2. | Results of Operations |
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Item 4. | Controls and Procedures |
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PART II. | OTHER INFORMATION |
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Item 1. | Legal Proceedings | 18 |
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Item 1A. | Risk Factors |
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Item 6. | Exhibits |
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| Signatures |
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| Exhibit Index |
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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 |
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, Inc., an indirect subsidiary of the Parent Company |
Cheyenne Light | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary |
| of the Parent Company |
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CT | Combustion Turbine |
Enserco | Enserco Energy, Inc., an indirect subsidiary of the Parent Company |
FAS | Financial Accounting Standard |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
FSP | FASB Staff Position |
FSP FAS 107-1 | FSP FAS 107-1, “Interim Disclosure About Fair Value of Financial |
Instruments” | |
FSP FAS 157-2 | FSP FAS 157-2, “Effective Date of FASB Statement No. 157” |
FSP FAS | FSP FAS |
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GAAP | Generally Accepted Accounting Principles |
LIBOR | London Interbank Offered Rate |
MDU | MDU Resources Group, Inc. |
MW | Megawatts |
MWh | Megawatt-hours |
SEC | U.S. Securities and Exchange Commission |
SFAS | Statement of Financial Accounting Standards |
SFAS 157 | SFAS 157, “Fair Value Measurements” |
SFAS |
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| SFAS 161, “Disclosure about Derivative Instruments and Hedging Activities – |
| an amendment of FASB Statement No. 133” |
WRDC | Wyodak Resources Development Corp., an indirect subsidiary of the Parent |
| Company |
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF INCOME
(unaudited)
| Three Months Ended | Nine Months Ended | Three Months Ended | ||||||||||||
| September 30, | March 31, | |||||||||||||
| 2008 | 2007 | 2008 | 2007 | 2009 | 2008 | |||||||||
| (in thousands) | (in thousands) | |||||||||||||
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Operating revenue | $ | 59,358 | $ | 51,774 | $ | 174,968 | $ | 144,513 | $ | 54,458 | $ | 57,632 | |||
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Operating expenses: |
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Fuel and purchased power |
| 30,119 |
| 22,315 |
| 85,844 |
| 56,020 |
| 22,762 |
| 27,499 | |||
Operations and maintenance |
| 7,604 |
| 6,392 |
| 23,615 |
| 19,073 |
| 7,638 |
| 7,097 | |||
Administrative and general |
| 4,538 |
| 5,326 |
| 14,612 |
| 14,953 |
| 6,271 |
| 5,464 | |||
Depreciation and amortization |
| 5,275 |
| 5,197 |
| 15,805 |
| 15,535 |
| 5,047 |
| 5,252 | |||
Taxes, other than income taxes |
| 1,594 |
| 1,396 |
| 5,002 |
| 5,179 |
| 2,035 |
| 1,729 | |||
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| 49,130 |
| 40,626 |
| 144,878 |
| 110,760 |
| 43,753 |
| 47,041 | |||
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Operating income |
| 10,228 |
| 11,148 |
| 30,090 |
| 33,753 |
| 10,705 |
| 10,591 | |||
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Other income (expense): |
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Interest expense |
| (2,751) |
| (2,937) |
| (7,957) |
| (8,856) |
| (2,585) |
| (2,693) | |||
Interest income |
| 171 |
| 256 |
| 290 |
| 669 |
| 112 |
| 95 | |||
Allowance for funds used |
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during construction – equity |
| 1,183 |
| 161 |
| 2,072 |
| 402 |
| 1,401 |
| 284 | |||
Other income, net |
| 17 |
| 27 |
| 185 |
| 190 |
| 289 |
| 115 | |||
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| (1,380) |
| (2,493) |
| (5,410) |
| (7,595) |
| (783) |
| (2,199) | |||
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Income before income taxes |
| 8,848 |
| 8,655 |
| 24,680 |
| 26,158 |
| 9,922 |
| 8,392 | |||
Income taxes |
| (2,477) |
| (2,874) |
| (7,482) |
| (8,797) |
| (2,958) |
| (2,816) | |||
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Net income | $ | 6,371 | $ | 5,781 | $ | 17,198 | $ | 17,361 | $ | 6,964 | $ | 5,576 |
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(unaudited)
| September 30, | December 31, | March 31, | December 31, | ||||
| 2008 | 2007 | 2009 | 2008 | ||||
| (in thousands) | (in thousands) | ||||||
ASSETS |
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Current assets: |
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Cash and cash equivalents | $ | 1,351 | $ | 2,033 | $ | 620 | $ | 4 |
Receivables (net of allowance for doubtful accounts |
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of $560 and $388, respectively) – |
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of $371 and $370, respectively) – |
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Customers |
| 20,531 |
| 22,330 |
| 19,398 |
| 23,881 |
Affiliates |
| 3,827 |
| 8,882 |
| 2,944 |
| 12,619 |
Other |
| 1,553 |
| 2,198 |
| 902 |
| 2,111 |
Money pool note receivable – affiliates |
| — |
| 10,304 | ||||
Materials, supplies and fuel |
| 18,094 |
| 15,628 |
| 19,571 |
| 19,309 |
Other current assets |
| 6,984 |
| 3,862 |
| 6,511 |
| 5,730 |
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| 52,340 |
| 65,237 |
| 49,946 |
| 63,654 |
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Investments |
| 3,957 |
| 3,774 |
| 4,092 |
| 3,999 |
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Property, plant and equipment |
| 813,645 |
| 695,452 |
| 884,978 |
| 843,691 |
Less accumulated depreciation |
| (280,479) |
| (266,583) |
| (285,193) |
| (281,220) |
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| 533,166 |
| 428,869 |
| 599,785 |
| 562,471 |
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Other assets: |
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Regulatory assets |
| 10,562 |
| 9,899 |
| 33,748 |
| 33,818 |
Other |
| 5,483 |
| 5,901 |
| 2,231 |
| 2,842 |
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| 16,045 |
| 15,800 |
| 35,979 |
| 36,660 |
| $ | 605,508 | $ | 513,680 | $ | 689,802 | $ | 666,784 |
LIABILITIES AND STOCKHOLDER’S EQUITY |
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Current liabilities: |
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Current maturities of long-term debt | $ | 2,014 | $ | 2,009 | $ | 32,019 | $ | 2,016 |
Accounts payable |
| 24,161 |
| 12,982 |
| 28,867 |
| 26,567 |
Accounts payable – affiliates |
| 10,721 |
| 3,158 |
| 4,712 |
| 10,411 |
Notes payable – affiliates |
| 49,796 |
| — |
| 85,673 |
| 70,184 |
Accrued liabilities |
| 11,927 |
| 13,898 |
| 15,962 |
| 15,151 |
Deferred income taxes |
| 823 |
| 18 |
| 1,119 |
| 732 |
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| 99,442 |
| 32,065 |
| 168,352 |
| 125,061 |
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Long-term debt, net of current maturities |
| 149,209 |
| 151,209 |
| 119,176 |
| 149,193 |
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Deferred credits and other liabilities: |
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Deferred income taxes |
| 75,997 |
| 69,761 |
| 87,093 |
| 85,504 |
Regulatory liabilities |
| 13,312 |
| 11,085 |
| 14,026 |
| 13,573 |
Benefit plan liabilities |
| 30,926 |
| 29,904 | ||||
Other |
| 18,009 |
| 17,140 |
| 8,331 |
| 8,626 |
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| 107,318 |
| 97,986 |
| 140,376 |
| 137,607 |
Stockholder’s equity: |
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Common stock $1 par value; 50,000,000 shares authorized; |
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23,416,396 shares issued |
| 23,416 |
| 23,416 |
| 23,416 |
| 23,416 |
Additional paid-in capital |
| 39,575 |
| 39,575 |
| 39,575 |
| 39,575 |
Retained earnings |
| 187,904 |
| 170,706 |
| 200,245 |
| 193,281 |
Accumulated other comprehensive loss |
| (1,356) |
| (1,277) |
| (1,338) |
| (1,349) |
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| 249,539 |
| 232,420 |
| 261,898 |
| 254,923 |
| $ | 605,508 | $ | 513,680 | $ | 689,802 | $ | 666,784 |
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited)
| Nine Months Ended | Three Months Ended | |||||||
| September 30, | March 31, | |||||||
| 2008 | 2007 | 2009 | 2008 | |||||
| (in thousands) | (in thousands) | |||||||
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Operating activities: |
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Net income | $ | 17,198 | $ | 17,361 | $ | 6,964 | $ | 5,576 | |
Adjustments to reconcile net income to cash |
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provided by operating activities: |
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Depreciation and amortization |
| 15,805 |
| 15,535 |
| 5,047 |
| 5,252 | |
Provision for valuation allowances |
| 1 |
| 185 | |||||
Deferred income tax |
| 6,580 |
| 3,034 |
| 1,867 |
| 594 | |
Allowance for funds used during construction – |
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equity |
| (2,072) |
| (402) |
| (1,401) |
| (284) | |
Change in operating assets and liabilities – |
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Accounts receivable and other current assets |
| 4,088 |
| (5,928) |
| 14,322 |
| 10,001 | |
Accounts payable and other current liabilities |
| (1,048) |
| (4,948) |
| (9,684) |
| (740) | |
Other operating activities |
| (1,680) |
| 2,063 |
| 1,454 |
| 240 | |
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| 38,871 |
| 26,715 |
| 18,570 |
| 20,824 | |
Investing activities: |
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Property, plant and equipment additions |
| (97,475) |
| (19,726) |
| (33,336) |
| (26,388) | |
Change in affiliate money pool borrowings, net |
| 10,304 |
| (4,918) | |||||
Change in money pool notes receivable from |
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affiliate, net |
| — |
| 8,734 | |||||
Other investing activities |
| (183) |
| (177) |
| (93) |
| (115) | |
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| (87,354) |
| (24,821) |
| (33,429) |
| (17,769) | |
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Financing activities: |
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Notes payable – affiliate |
| 49,796 |
| — | |||||
Long-term debt – repayments |
| (1,995) |
| (1,989) |
| (14) |
| (14) | |
Change in money pool note payable to |
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affiliate, net |
| 15,489 |
| — | |||||
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| 47,801 |
| (1,989) |
| 15,475 |
| (14) | |
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Decrease in cash and cash equivalents |
| (682) |
| (95) | |||||
Increase in cash and cash equivalents |
| 616 |
| 3,041 | |||||
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Cash and cash equivalents: |
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Beginning of period |
| 2,033 |
| 1,223 |
| 4 |
| 2,033 | |
End of period | $ | 1,351 | $ | 1,128 | $ | 620 | $ | 5,074 | |
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Supplemental disclosure of cash flow information: |
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Non-cash investing and financing activities: |
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Property, plant and equipment acquired |
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with accrued liabilities | $ | 15,750 | $ | 764 | $ | 22,524 | $ | 5,372 | |
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Cash paid during the period for: |
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Interest (net of amounts capitalized) | $ | 9,833 | $ | 9,935 | $ | 4,017 | $ | 4,480 | |
Income taxes paid | $ | 3,396 | $ | 14,847 | |||||
Income taxes refunded | $ | (218) | $ | — |
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
BLACK HILLS POWER, INC.
Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in the Company’s 20072008 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)“Company,” “we,” “us,” “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, the Company believeswe 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 the Company’s 2007our 2008 Annual Report on Form 10-K filed with the SEC.
Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the September 30, 2008,March 31, 2009, December 31, 20072008 and September 30, 2007March 31, 2008 financial information and are of a normal recurring nature. The results of operations for the ninethree months ended September 30, 2008,March 31, 2009, are not necessarily indicative of the results to be expected for the full year.
(2) | RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS |
SFAS 157
During September 2006, the FASB issued SFAS 157. This Statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 does not expand the application of fair value accounting to any new circumstances, but applies the framework to other accounting pronouncements that require or permit fair value measurement. The Company applies fair value measurements to certain assets and liabilities, primarily commodity derivatives.
SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. As of January 1, 2008, the CompanyWe adopted the provisions of SFAS 157 on January 1, 2008 for all assets and liabilities measured at fair value exceptfor financial measurements. As permitted by FSP FAS 157-2, we deferred adoption for non-financial assets and liabilities measured at fair value on a non-recurring basis as permitted by FSP FAS 157-2.until January 1, 2009. SFAS 157 also requires new disclosures regarding the level of pricing observability associated with instruments carried at fair value. On October 10, 2008, the FASB issued FSP FAS 157-3. It was effective upon issuance including prior periods for which financial statements have not been issued. This FSP clarifies the application of FAS 157 in a market that is not active. The adoption of SFAS 157 and related FSPs did not have a material impact on the Company’sour financial position, results of operations or cash flows.
7
SFAS 159
SFAS 159 establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SFAS 159 was adopted on January 1, 2008 and did not have an impact on the Company’s financial position, results of operations or cash flows.
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SFAS 161
In March 2008, the FASB issued SFAS 161 which requires enhanced disclosures about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. This StatementSFAS 161 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption.
At March 31, 2009, we do not hold any derivative instruments. We occasionally 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 occasionally utilize various derivative instruments in managing these risks. Additionally, we engage in activities to manage risk associated with changes in interest rates. In prior years, we entered into floating-to-fixed interest rate swap agreements to minimize our exposure to interest rate fluctuations associated with our floating rate debt obligations. These swaps were designated as cash flow hedges in accordance with SFAS 133, and accordingly the resulting gain or loss is carried in Accumulated other comprehensive loss on the accompanying Condensed Balance Sheets and amortized over the life of the related debt. For the three months ended March 31, 2009 and 2008, respectively, we amortized less than $0.1 million from Accumulated other comprehensive loss to Interest expense related to a settled interest rate swap designated as a cash flow hedge.
(3) | RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS |
FSP FAS 157-4
In April 2009, the FASB approved FSP FAS 157-4 effective for interim and annual periods ending after June 15, 2009. This FSP amends FAS 157 to address inactive markets. This FSP includes a two step model with the first step determining whether factors exist that indicate a market for an asset is not active. If step one results in the conclusion that there is not an active market, step two evaluates whether the quoted price is not associated with a distressed transaction. Additional disclosures will be required. We do not anticipate that the adoption of FSP FAS 157-4 will have an impact on our operating results, financial statements issuedposition or cash flows.
FSP FAS 107-1
In April 2009, the FASB approved FSP FAS 107-1 effective for fiscal yearsinterim and interimannual periods beginningending after NovemberJune 15, 2008. The Company is2009. This FSP will require more frequent disclosures of fair value for public companies. We are currently evaluatingassessing the impact ofthat the adoption of SFAS 161.will have on our disclosures.
(4) | OTHER COMPREHENSIVE INCOME |
The following table presents the components of the Company’s Other comprehensive income (in thousands):
| Three Months Ended | Three Months Ended | ||||||
| September 30, | March 31, | ||||||
| 2008 | 2007 | 2009 | 2008 | ||||
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Net income | $ | 6,371 | $ | 5,781 | $ | 6,964 | $ | 5,576 |
Other comprehensive income, net of tax: |
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Other comprehensive income (loss), net of tax: |
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Fair value adjustment on derivatives |
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designated as cash flow hedges (net of |
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tax of $(6) and $34, respectively) |
| 10 |
| (62) | ||||
tax of $(6) and $(38), respectively) |
| 11 |
| 71 | ||||
Reclassification adjustments included |
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in net income (net of tax of $0 and $(5)) |
| — |
| 10 | ||||
in net income (net of tax of $93) |
| — |
| (171) | ||||
Total comprehensive income | $ | 6,381 | $ | 5,729 | $ | 6,975 | $ | 5,476 |
| Nine Months Ended | |||
| September 30, | |||
| 2008 | 2007 | ||
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Net income | $ | 17,198 | $ | 17,361 |
Other comprehensive income (loss), net of tax: |
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Fair value adjustment on derivatives |
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designated as cash flow hedges (net of |
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tax of $(18) and $197, respectively) |
| 30 |
| (366) |
Reclassification adjustments included |
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|
|
in net income (net of tax of $60 and $154, |
|
|
|
|
respectively) |
| (109) |
| (285) |
Total comprehensive income | $ | 17,119 | $ | 16,710 |
8
Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Balance Sheets are as follows (in thousands):
| Derivatives | Employee |
| |||
| Designated as | Benefit |
| |||
| Cash Flow Hedges | Plans | Total | |||
|
|
|
|
|
|
|
As of September 30, 2008 | $ | (940) | $ | (416) | $ | (1,356) |
|
|
|
|
|
|
|
As of December 31, 2007 | $ | (861) | $ | (416) | $ | (1,277) |
| Derivatives | Employee |
| |||
| Designated as | Benefit |
| |||
| Cash Flow Hedges | Plans | Total | |||
|
|
|
|
|
|
|
As of March 31, 2009 | $ | (921) | $ | (417) | $ | (1,338) |
|
|
|
|
|
|
|
As of December 31, 2008 | $ | (932) | $ | (417) | $ | (1,349) |
(5) | RELATED-PARTY TRANSACTIONS |
Receivables and Payables
The Company hasWe have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $3.8$2.9 million and $8.9$12.6 million as of September 30, 2008March 31, 2009 and December 31, 2007,2008, respectively. The CompanyWe also hashave accounts payable balances related to transactions with other BHC subsidiaries. The balances were $10.7$4.7 million and $3.2$10.4 million as of September 30, 2008March 31, 2009 and December 31, 2007,2008, respectively.
Money Pool Notes Receivable and Notes Payable |
The Company hasWe have entered into a Utility Money Pool Agreement with BHC, Cheyenne Light and Black Hills Energy. Under the agreement, the Companywe may borrow from the Parent. The Agreement restricts the Companyus from loaning funds to the Parent or to any of the Parent’s non-utility subsidiaries; the Agreement does not restrict the Companyus from making dividends to the 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.
The Company throughThrough the Utility Money Pool, we had net note payable balances of $49.8$85.7 million and $70.2 million as of September 30, 2008March 31, 2009 and a net note receivable of $10.3 million as of December 31, 2007.2008, respectively. Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (which equates to 4.63 percent1.2% at September 30, 2008)March 31, 2009). Net interest expense was approximatelyof $0.4 million and $0.4 million for the three months and nine months ended September 30, 2008, respectively. Net interest income of $0.3 million and $0.7 million was recorded for the three months ended March 31, 2009 and ninenet interest income of less than $0.1 million for the three months ended September 30, 2007, respectively.March 31, 2008.
Other Balances and Transactions
The CompanyWe also received revenues of approximately $0.3$0.2 million and $0.6$0.3 million for the three months ended September 30,March 31, 2009 and 2008, and 2007, respectively; and $1.0 million and $1.6 million for the nine months ended September 30, 2008 and 2007, respectively, from Black Hills Wyoming for the transmission of electricity.
The CompanyWe recorded revenues of $0.2 million and $1.3 million for the ninethree months ended September 30,March 31, 2008, and 2007, respectively, relating to payments received pursuant to a natural gas swap entered into with Enserco, with a third party transacted by Enserco on the Company’sour behalf.
9
The CompanyWe received revenues of approximately $0.4$0.3 million and $1.5$0.7 million for the three months and nine months ended September 30,March 31, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.
On July 14, 2008, BHC purchased one electric utility in Colorado and four gas utilities in Colorado, Nebraska, Iowa and Kansas from Aquila, Inc. Through this acquisition, the Company became affiliated with these utilities now known as Black Hills Energy. Under a General Dispatch and Energy Management Agreement approved by FERC, the Company commenced providing services to Colorado Electric. The Company received revenues of $0.2 million for the three and nine months ended September 30, 2008.
The Company purchasesWe purchase coal from WRDC. The amount purchased during the three months ended September 30,March 31, 2009 and 2008 and 2007 was $4.9$3.9 million and $2.9$3.1 million, respectively; and $10.8 million and $8.4 million for the nine months ended September 30, 2008 and 2007, respectively.
The Company purchasesWe purchase excess power generated by Cheyenne Light. The amount purchased during the three months ended March 31, 2009 was $2.0 million, including $0.8 million for wind-generated power, and nine$1.3 million for the three months ended September 30,March 31, 2008. On August 28, 2008, was $1.5 million and $4.6 million, respectively.we entered into a contract with Cheyenne Light placed a 95under which Cheyenne Light sells up to 20 MW base load coal-fired power plant into service on January 1, 2008.of wind-generated, renewable energy to us until 2028.
In order to fuel itsour combustion turbine, the Company purchasedwe purchase natural gas from Enserco. The amount purchased during the three months ended September 30,March 31, 2009 and 2008 and 2007 was $3.0$0.1 million and $2.7less than $0.1 million, respectively; and $6.6 million and $4.3 million for the nine months ended September 30, 2008 and 2007, respectively. These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.
In addition, the Companywe also payspay the Parent for allocated corporate support service cost incurred on itsour behalf. Corporate costs allocated from the Parent were $2.8$3.6 million and $3.0$3.1 million for the three months ended September 30,March 31, 2009 and 2008, and 2007, respectively; and $8.9 million and $8.5 million for the nine months ended September 30, 2008 and 2007, respectively.
The Company hasWe have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $1.9 million as of September 30, 2008March 31, 2009 and $1.8 million as of December 31, 2007,2008, 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 (5.3 percent(4.52% at September 30, 2008)March 31, 2009).
On August 28, 2008 the Company entered into a contract with Cheyenne Light under which Cheyenne Light will sell up to 20 MW wind-generated, renewable energy to the Company until 2028.
(6) | EMPLOYEE BENEFIT PLANS |
Defined Benefit Pension Plan
The Company hasWe have a noncontributory defined benefit pension plan (Plan) covering the employees of the Company who meet certain eligibility requirements.
The components of net periodic benefit cost for the Plan are as follows (in thousands):
| Three Months Ended | Nine Months Ended | Three Months Ended | |||||||||
| September 30, | March 31, | ||||||||||
| 2008 | 2007 | 2008 | 2007 | 2009 | 2008 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost | $ | 279 | $ | 284 | $ | 837 | $ | 852 | $ | 292 | $ | 279 |
Interest cost |
| 758 |
| 731 |
| 2,274 |
| 2,193 |
| 785 |
| 758 |
Expected return on plan assets |
| (1,094) |
| (971) |
| (3,282) |
| (2,913) |
| (657) |
| (1,094) |
Prior service cost |
| 28 |
| 26 |
| 84 |
| 78 |
| 28 |
| 28 |
Net loss |
| — |
| 102 |
| — |
| 306 |
| 430 |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost | $ | (29) | $ | 172 | $ | (87) | $ | 516 | $ | 878 | $ | (29) |
The Company does not anticipate that it will need to make aA contribution totaling less than $0.1 million was made to the Plan in the 2008 fiscal year.first quarter of 2009. There are no further contributions expected to be made to the Plan in 2009.
Supplemental Nonqualified Defined Benefit Plans
The Company hasWe have various supplemental retirement plans for key executives of the Company (Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.
The components of net periodic benefit cost for the Supplemental Plans are as follows (in thousands):
| Three Months Ended | Nine Months Ended | Three Months Ended | |||||||||
| September 30, | March 31, | ||||||||||
| 2008 | 2007 | 2008 | 2007 | 2009 | 2008 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost | $ | 30 | $ | 28 | $ | 90 | $ | 84 | $ | 25 | $ | 30 |
Net loss |
| 11 |
| 14 |
| 33 |
| 42 |
| 11 |
| 11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost | $ | 41 | $ | 42 | $ | 123 | $ | 126 | $ | 36 | $ | 41 |
The Company anticipatesWe anticipate that itwe will make contributions to the Supplemental Plans for the 20082009 fiscal year of approximately $0.1 million. Contributions are expected to be in the form of benefit payments.
Non-pension Defined Benefit Postretirement Plans
Employees who are participants in the Company’s Postretirement Healthcare Plans (Healthcare Plans) and who meet certain eligibility requirements are entitled to postretirement healthcare benefits.
The components of net periodic benefit cost for the Healthcare Plans are as follows (in thousands):
| Three Months Ended | Nine Months Ended | Three Months Ended | |||||||||
| September 30, | March 31, | ||||||||||
| 2008 | 2007 | 2008 | 2007 | 2009 | 2008 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost | $ | 52 | $ | 52 | $ | 156 | $ | 156 | $ | 54 | $ | 52 |
Interest cost |
| 104 |
| 100 |
| 312 |
| 300 |
| 111 |
| 104 |
Net transition obligation |
| 13 |
| 13 |
| 39 |
| 39 |
| 13 |
| 13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost | $ | 169 | $ | 165 | $ | 507 | $ | 495 | $ | 178 | $ | 169 |
The Company anticipatesWe anticipate that itwe will make contributions to the Healthcare Plan for the 20082009 fiscal year of approximately $0.2 million. Contributions are expected to be made in the form of benefit payments.
It has been determined that the Company’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy is not material to the Company.was $0.1 million.
(7) | LEGAL PROCEEDINGS |
The Company isWe are subject to various legal proceedings, claims and litigation as described in Note 11 of the Notes to Financial Statements in the Company’s 2007our 2008 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 ninethree months of 2008.2009.
(8) | SUBSEQUENT EVENTS |
On April 9, 2009, we sold a 25% ownership interest in our Wygen III generation facility to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. MDU will continue to reimburse us for its 25% of the total costs paid to complete the project. In conjunction with the sales transaction, we also modified a 2004 power purchase agreement under which we supplied MDU with 74 MW of capacity and energy through 2016.
Extension of Long-Term Power Sales Agreement with MEAN
12
In March 2009, our 10-year power sales contract with MEAN that originally expired in 2013 was re-negotiated and extended until 2023. Under the new contract, MEAN will purchase 20 MW of unit-contingent capacity from the Neil Simpson II and the Wygen III plants with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity from Wygen III and Neil Simpson II plants are as follows:
20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II |
15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II |
10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
ITEM 2. | RESULTS OF OPERATIONS |
| Three Months Ended | Nine Months Ended | Three Months Ended | |||||||||
| September 30, | March 31, | ||||||||||
| 2008 | 2007 | 2008 | 2007 | 2009 | 2008 | ||||||
| (in thousands) | (in thousands) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue | $ | 59,358 | $ | 51,774 | $ | 174,968 | $ | 144,513 | $ | 54,458 | $ | 57,632 |
Fuel and purchased power |
| 30,119 |
| 22,315 |
| 85,844 |
| 56,020 |
| 22,762 |
| 27,499 |
Gross margin |
| 29,239 |
| 29,459 |
| 89,124 |
| 88,493 |
| 31,696 |
| 30,133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
| 19,011 |
| 18,311 |
| 59,034 |
| 54,740 |
| 20,991 |
| 19,542 |
Operating income | $ | 10,228 | $ | 11,148 | $ | 30,090 | $ | 33,753 | $ | 10,705 | $ | 10,591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income | $ | 6,371 | $ | 5,781 | $ | 17,198 | $ | 17,361 | $ | 6,964 | $ | 5,576 |
The following tables provide certain operating statistics for the Company:statistics:
| Electric Revenue | Electric Revenue | |||||||||||||||
| (in thousands) | (in thousands) | |||||||||||||||
|
|
| |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||
|
| Percentage |
|
| Percentage |
|
| Percentage |
| ||||||||
Customer Base | 2008 | Change | 2007 | 2008 | Change | 2007 | 2009 | Change | 2008 | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Commercial | $ | 15,735 | (4)% | $ | 16,328 | $ | 42,231 | (1)% | $ | 42,502 | $ | 14,643 | 9% | $ | 13,484 | ||
Residential |
| 11,168 | (11) |
| 12,564 |
| 34,187 | (1) |
| 34,662 |
| 14,281 | 10 |
| 12,966 | ||
Industrial |
| 5,500 | (1) |
| 5,558 |
| 16,337 | 1 |
| 16,137 |
| 4,750 | (10) |
| 5,296 | ||
Municipal sales |
| 783 | (3) |
| 808 |
| 2,047 | 1 |
| 2,033 |
| 636 | 2 |
| 625 | ||
Total retail sales |
| 33,186 | (6) |
| 35,258 |
| 94,802 | (1) |
| 95,334 |
| 34,310 | 6 |
| 32,371 | ||
Contract wholesale |
| 6,862 | 5 |
| 6,566 |
| 20,064 | 7 |
| 18,855 |
| 6,553 | (5) |
| 6,931 | ||
Wholesale off system |
| 13,315 | 86 |
| 7,157 |
| 47,650 | 125 |
| 21,155 |
| 9,220 | (39) |
| 15,097 | ||
Total electric sales |
| 53,363 | 9 |
| 48,981 |
| 162,516 | 20 |
| 135,344 |
| 50,083 | (8) |
| 54,399 | ||
Other revenue |
| 5,995 | 115 |
| 2,793 |
| 12,452 | 36 |
| 9,169 |
| 4,375 | 34 |
| 3,233 | ||
Total revenue | $ | 59,358 | 15% | $ | 51,774 | $ | 174,968 | 21% | $ | 144,513 | $ | 54,458 | (6)% | $ | 57,632 |
| Megawatt Hours Sold | ||||||
|
| ||||||
| Three Months Ended March 31, | ||||||
|
| Percentage |
| ||||
Customer Base | 2009 | Change | 2008 | ||||
|
|
|
|
|
| ||
Commercial |
| 175,256 | 1% |
| 173,459 | ||
Residential |
| 163,476 | — |
| 163,034 | ||
Industrial |
| 85,984 | (16) |
| 102,669 | ||
Municipal sales |
| 8,095 | (1) |
| 8,208 | ||
Total retail sales |
| 432,811 | (3) |
| 447,370 | ||
Contract wholesale |
| 168,679 | (2) |
| 171,620 | ||
Wholesale off system |
| 243,786 | 7 |
| 227,741 | ||
Total electric sales |
| 845,276 | —% |
| 846,731 | ||
| Electric Utility Power Plant Availability | |
|
| |
| Three Months Ended March 31, | |
| 2009 | 2008 |
|
|
|
Coal-fired plants | 96.5% | 94.9% |
Other plants | 99.5% | 94.9% |
Total availability | 97.8% | 94.9% |
13
| Megawatt Hours Sold | |||||||||
|
| |||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||
|
| Percentage |
|
| Percentage |
| ||||
Customer Base | 2008 | Change | 2007 | 2008 | Change | 2007 | ||||
|
|
|
|
|
|
|
|
|
|
|
Commercial |
| 195,661 | (2)% |
| 199,239 |
| 531,433 | 1% |
| 525,815 |
Residential |
| 120,888 | (11) |
| 136,297 |
| 398,028 | 1 |
| 395,820 |
Industrial |
| 107,380 | (5) |
| 112,541 |
| 319,077 | (1) |
| 321,798 |
Municipal sales |
| 10,228 | (4) |
| 10,681 |
| 26,073 | 1 |
| 25,890 |
Total retail sales |
| 434,157 | (5) |
| 458,758 |
| 1,274,611 | — |
| 1,269,323 |
Contract wholesale |
| 165,872 | (2) |
| 169,211 |
| 494,457 | 2 |
| 486,149 |
Wholesale off system |
| 241,546 | 70 |
| 141,930 |
| 753,057 | 77 |
| 426,143 |
Total electric sales |
| 841,575 | 9% |
| 769,899 |
| 2,522,125 | 16% |
| 2,181,615 |
| Megawatt Hours Generated and Purchased | ||
|
| ||
| Three Months Ended March 31, | ||
|
| Percentage |
|
Resources | 2009 | Change | 2008 |
|
|
|
|
Coal | 437,551 | 1% | 432,882 |
Gas | 1,075 | (97) | 37,000 |
| 438,626 | (7) | 469,882 |
|
|
|
|
MWhs purchased | 432,839 | 13 | 384,581 |
Total resources | 871,465 | 2% | 854,463 |
| Electric Utility Power Plant Availability | |||
|
|
| ||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||
| 2008 | 2007 | 2008 | 2007 |
|
|
|
|
|
Coal-fired plants | 95.8% | 96.6% | 91.8%* | 95.5% |
Other plants | 98.7% | 99.8% | 90.6% | 99.6% |
Total availability | 97.1% | 98.0% | 91.3% | 97.3% |
___________________________
|
|
| Megawatt Hours Generated and Purchased | |||||
|
|
| ||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||
|
| Percentage |
|
| Percentage |
|
Resources | 2008 | Change | 2007 | 2008 | Change | 2007 |
|
|
|
|
|
|
|
Coal | 450,884 | 2% | 441,626 | 1,268,514 | (4)% | 1,316,851 |
Gas | 11,856 | (65) | 34,117 | 53,687 | (22) | 68,458 |
| 462,740 | (3)% | 475,743 | 1,322,201 | (5)% | 1,385,309 |
|
|
|
|
|
|
|
MWhs purchased | 404,148 | 26% | 321,396 | 1,256,835 | 44% | 870,447 |
Total resources | 866,888 | 9% | 797,139 | 2,579,036 | 14% | 2,255,756 |
| Heating Degree Days | |
|
| |
| Three Months Ended | |
| March 31, | |
| 2009 | 2008 |
Heating degree days: |
|
|
Actual |
|
|
Heating degree days | 3,254 | 3,361 |
|
|
|
Variance from normal |
|
|
Heating degree days | (1)% | 2% |
| Heating and Cooling Degree Days | |||
|
|
| ||
| Three Months Ended | Nine Months Ended | ||
| September 30, | September 30, | ||
| 2008 | 2007 | 2008 | 2007 |
Heating and cooling degree days: |
|
|
|
|
Actual |
|
|
|
|
Heating degree days | 223 | 171 | 4,814 | 4,083 |
Cooling degree days | 453 | 830 | 482 | 1,033 |
|
|
|
|
|
Percent of normal |
|
|
|
|
Heating degree days | 98% | 81% | 106% | 91% |
Cooling degree days | 92% | 168% | 81% | 174% |
Three Months Ended September 30, 2008March 31, 2009 Compared to Three Months Ended September 30, 2007.March 31, 2008. Net income increased $0.6$1.4 million from the prior period primarily due to the following:
• |
• Increased AFUDC of |
|
Partially offsetting the increases were the following: |
|
• |
|
|
• Increased |
15
Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007. Net income decreased $0.2 million from the prior period primarily due to the following:
|
|
|
|
|
Wygen III Power Plant Project
In March 2008, we received final regulatory approval for construction of Wygen III. Construction began immediately and the 100110 MW coal-fired base load electric generating facility is expected to take 24 to 30 months to complete.be completed in June 2010. The expected cost of construction is approximately $255 million, which includes estimates for AFUDC. A 2004 agreement with MDU included an option to purchase an ownership interest in Wygen III. In April 2009, MDU exercised this option, and we sold a 25% ownership interest in Wygen III to MDU. We expect towill retain ownership of 75 MW75% of the facility’s capacity with MDU currently being expected to take ownership ofowning the remaining 25 MW.25%. We will retain responsibility for operations of the facility with a life-of-plant site lease, and agreements with MDU for operations and coal supply agreements in place with MDU.supply.
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. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described in Item 1A of our 20072008 Annual Report on Form 10-K and 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 successfully maintain or improve our corporate credit rating; |
|
• 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; |
• Our ability to remedy any deficiencies that may be identified in the review of our internal controls; |
• 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; |
• Weather and other natural phenomena; |
• Industry and market changes, including the impact of consolidations and changes in competition; |
• The effect of accounting policies issued periodically by accounting standard-setting bodies; |
• The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions or events; |
• The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements; |
• Capital market conditions, which may affect our ability to raise capital on favorable terms; |
• Price risk due to marketable securities held as investments in benefit plans; |
|
17
• 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.
ITEM 4. | CONTROLS AND PROCEDURES |
Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of September 30, 2008.March 31, 2009. 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 September 30, 2008March 31, 2009 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
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 the Company’s 2007our 2008 Annual Report on Form 10-K and Note 7 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 7 is incorporated by reference into this item.
Item 1A. | Risk Factors |
Except as set forth below, thereThere have been no material changes in our Risk Factors from those reported in Item 1A. of Part I of our 20072008 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Recent events in the global financial crisis have made the credit markets less accessible and created a shortage of available credit. We may, therefore, be unable to obtain the financing needed to refinance debt, fund planned capital expenditures, or otherwise execute our operating strategy.
Our ability to execute our operating strategy is highly dependent on our having access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt, and fund working capital and planned capital expenditures) with operating cash flow, borrowings from BHC and proceeds from debt offerings. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in electricity prices, and general economic and market conditions.
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Recent financial distress within the global economy has caused significant disruption in the credit markets. Among other things, long-term interest rates on debt securities have increased significantly and the volume of equity and debt security issuances has decreased. Recent actions taken by the United States government, the Federal Reserve and other governmental and regulatory bodies may be insufficient to stabilize these markets. The longer such conditions persist, the more significant the implications become for the Company.
National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows.
Recent concerns over inflation, energy costs, the availability and cost of credit, and increased unemployment have contributed to an economic slowdown and fears of recession. These factors could lead to an increase in late payments from utility customers and uncollectible accounts could increase, which could materially reduce our earnings and cash flows.
Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and, therefore, recoverable.
Our regulated operations are subject to cost-of-service regulation and earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.
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Federal and state laws concerning climate change, including emission reduction mandates, and renewable energy portfolio standards may increase our electric generation costs materially and could render some of our electric generating units uneconomical to operate and maintain.
We own regulated coal-fired power plants in Wyoming. Air emissions of coal-fired power plants are subject to federal and state regulation. Recent changes in federal and state laws governing air emissions from coal-burning power plants will result in more stringent emission limitations. As the issue of climate change, particularly with respect to CO2 emissions by coal-fired power plants, receives increased attention, further emission limitations could be imposed. To the extent our coal-fired power plants are included in rate base, we will attempt to recover costs associated with complying with emission standards; however, there can be no assurance that we will be permitted to recover such compliance costs in customer rates. In addition, future changes in environmental regulations governing air pollutants could render some of our electric generating units more expensive or uneconomical to operate and maintain.
We serve electric utility customers in Montana, South Dakota, and Wyoming. Montana has adopted renewable portfolio standards that require electric utilities to source a minimum percentage of the power delivered to customers by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If Montana increases their renewable energy portfolio standards, or if similar standards are imposed by the other states in which we operate electric utilities, our power supply costs will further increase (and could increase materially). Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to fully recover such costs.
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. |
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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. |
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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. |
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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. |
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. |
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| /S/ DAVID R. EMERY |
| David R. Emery, Chairman |
| and Chief Executive Officer |
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| /S/ ANTHONY S. CLEBERG |
| Anthony S. Cleberg, Executive Vice President |
| and Chief Financial Officer |
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Dated: |
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EXHIBIT INDEX
Exhibit Number | Description |
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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. |
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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. |
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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. |
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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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