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 |
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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 April 30,July 31, 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 and Six Months Ended | 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 |
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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 |
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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, |
Cheyenne Light | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary |
| of the Parent Company |
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Enserco | Enserco Energy, Inc., an indirect subsidiary of the Parent Company |
EPA | U.S. Environmental Protection Agency |
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 | FSP FAS |
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GAAP | Generally Accepted Accounting Principles |
GHG | Greenhouse gas |
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 161 | SFAS 161, “Disclosure about Derivative Instruments and Hedging Activities – |
| an amendment of FASB Statement No. 133” |
SFAS 165 | SFAS 165, “Subsequent Events” |
SFAS 167 | SFAS 167, “Amendment to FASB Interpretation No. 46(R)” |
SFAS 168 | SFAS 168, “FASB Accounting Standards Codification and the |
Hierarchy of Generally Accepted Accounting Principles – a | |
replacement of FASB Standard No. 162” | |
WRDC | Wyodak Resources Development Corp., an indirect subsidiary of the Parent |
| Company |
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF INCOME
(unaudited)
| Three Months Ended | Three Months Ended | Six Months Ended | ||||||||||
| March 31, | June 30, | |||||||||||
| 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||
| (in thousands) | (in thousands) | |||||||||||
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Operating revenue | $ | 54,458 | $ | 57,632 | $ | 46,836 | $ | 57,978 | $ | 101,294 | $ | 115,610 | |
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Operating expenses: |
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Fuel and purchased power |
| 22,762 |
| 27,499 |
| 19,753 |
| 28,226 |
| 42,515 |
| 55,725 | |
Operations and maintenance |
| 7,638 |
| 7,097 |
| 8,486 |
| 8,914 |
| 16,124 |
| 16,011 | |
Administrative and general |
| 6,271 |
| 5,464 |
| 6,972 |
| 4,610 |
| 13,243 |
| 10,073 | |
Depreciation and amortization |
| 5,047 |
| 5,252 |
| 5,006 |
| 5,278 |
| 10,052 |
| 10,530 | |
Taxes, other than income taxes |
| 2,035 |
| 1,729 |
| 1,613 |
| 1,680 |
| 3,649 |
| 3,409 | |
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| 43,753 |
| 47,041 |
| 41,830 |
| 48,708 |
| 85,583 |
| 95,748 | |
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Operating income |
| 10,705 |
| 10,591 |
| 5,006 |
| 9,270 |
| 15,711 |
| 19,862 | |
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Other income (expense): |
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Interest expense |
| (2,585) |
| (2,693) |
| (2,838) |
| (2,513) |
| (5,410) |
| (5,206) | |
Interest income |
| 112 |
| 95 |
| 65 |
| 25 |
| 164 |
| 119 | |
Allowance for funds used |
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during construction – equity |
| 1,401 |
| 284 |
| 1,276 |
| 606 |
| 2,677 |
| 890 | |
Other income, net |
| 289 |
| 115 |
| 508 |
| 53 |
| 797 |
| 168 | |
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| (783) |
| (2,199) |
| (989) |
| (1,829) |
| (1,772) |
| (4,029) | |
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Income before income taxes |
| 9,922 |
| 8,392 |
| 4,017 |
| 7,441 |
| 13,939 |
| 15,833 | |
Income taxes |
| (2,958) |
| (2,816) |
| (912) |
| (2,190) |
| (3,870) |
| (5,006) | |
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Net income | $ | 6,964 | $ | 5,576 | $ | 3,105 | $ | 5,251 | $ | 10,069 | $ | 10,827 |
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(unaudited)
| March 31, | December 31, | June 30, | December 31, | ||||
| 2009 | 2008 | 2009 | 2008 | ||||
| (in thousands) | (in thousands) | ||||||
ASSETS |
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Current assets: |
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Cash and cash equivalents | $ | 620 | $ | 4 | $ | 626 | $ | 4 |
Receivables (net of allowance for doubtful accounts |
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of $371 and $370, respectively) – |
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of $365 and $370, respectively) – |
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Customers |
| 19,398 |
| 23,881 |
| 15,251 |
| 23,881 |
Affiliates |
| 2,944 |
| 12,619 |
| 2,707 |
| 12,619 |
Other |
| 902 |
| 2,111 |
| 6,384 |
| 2,111 |
Materials, supplies and fuel |
| 19,571 |
| 19,309 |
| 19,149 |
| 19,309 |
Other current assets |
| 6,511 |
| 5,730 |
| 7,399 |
| 5,730 |
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| 49,946 |
| 63,654 |
| 51,516 |
| 63,654 |
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Investments |
| 4,092 |
| 3,999 |
| 4,138 |
| 3,999 |
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Property, plant and equipment |
| 884,978 |
| 843,691 |
| 897,660 |
| 843,691 |
Less accumulated depreciation |
| (285,193) |
| (281,220) |
| (289,885) |
| (281,220) |
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| 599,785 |
| 562,471 |
| 607,775 |
| 562,471 |
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Other assets: |
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Regulatory assets |
| 33,748 |
| 33,818 |
| 33,732 |
| 33,818 |
Other |
| 2,231 |
| 2,842 |
| 1,601 |
| 2,842 |
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| 35,979 |
| 36,660 |
| 35,333 |
| 36,660 |
| $ | 689,802 | $ | 666,784 | $ | 698,762 | $ | 666,784 |
LIABILITIES AND STOCKHOLDER’S EQUITY |
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Current liabilities: |
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Current maturities of long-term debt | $ | 32,019 | $ | 2,016 | $ | 32,021 | $ | 2,016 |
Accounts payable |
| 28,867 |
| 26,567 |
| 38,175 |
| 26,567 |
Accounts payable – affiliates |
| 4,712 |
| 10,411 |
| 9,155 |
| 10,411 |
Notes payable – affiliates |
| 85,673 |
| 70,184 |
| 75,826 |
| 70,184 |
Accrued liabilities |
| 15,962 |
| 15,151 |
| 16,767 |
| 15,151 |
Deferred income taxes |
| 1,119 |
| 732 |
| 1,331 |
| 732 |
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| 168,352 |
| 125,061 |
| 173,275 |
| 125,061 |
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Long-term debt, net of current maturities |
| 119,176 |
| 149,193 |
| 117,204 |
| 149,193 |
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Deferred credits and other liabilities: |
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Deferred income taxes |
| 87,093 |
| 85,504 |
| 88,758 |
| 85,504 |
Regulatory liabilities |
| 14,026 |
| 13,573 |
| 14,340 |
| 13,573 |
Benefit plan liabilities |
| 30,926 |
| 29,904 |
| 31,962 |
| 29,904 |
Other |
| 8,331 |
| 8,626 |
| 8,210 |
| 8,626 |
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| 140,376 |
| 137,607 |
| 143,270 |
| 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 |
| 200,245 |
| 193,281 |
| 203,350 |
| 193,281 |
Accumulated other comprehensive loss |
| (1,338) |
| (1,349) |
| (1,328) |
| (1,349) |
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| 261,898 |
| 254,923 |
| 265,013 |
| 254,923 |
| $ | 689,802 | $ | 666,784 | $ | 698,762 | $ | 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)
| Three Months Ended | ||||||||
| March 31, | Six Months Ended | |||||||
| 2009 | 2008 | June 30, | ||||||
| (in thousands) | 2009 | 2008 | ||||||
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| (in thousands) | ||||
Operating activities: |
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Net income | $ | 6,964 | $ | 5,576 | $ | 10,069 | $ | 10,827 | |
Adjustments to reconcile net income to cash |
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provided by operating activities: |
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Depreciation and amortization |
| 5,047 |
| 5,252 |
| 10,052 |
| 10,530 | |
Provision for valuation allowances |
| 1 |
| 185 |
| (5) |
| 48 | |
Deferred income tax |
| 1,867 |
| 594 |
| 3,634 |
| 3,041 | |
Allowance for funds used during construction – |
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equity |
| (1,401) |
| (284) |
| (2,677) |
| (890) | |
Change in operating assets and liabilities – |
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Accounts receivable and other current assets |
| 14,322 |
| 10,001 |
| 10,255 |
| 8,617 | |
Accounts payable and other current liabilities |
| (9,684) |
| (740) |
| 11,011 |
| 1,859 | |
Other operating activities |
| 1,454 |
| 240 |
| 3,529 |
| 1,299 | |
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| 18,570 |
| 20,824 |
| 45,868 |
| 35,331 | |
Investing activities: |
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Property, plant and equipment additions |
| (33,336) |
| (26,388) |
| (76,911) |
| (58,841) | |
Proceeds from sale of ownership interest in plant |
| 32,321 |
| — | |||||
Change in money pool notes receivable from |
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affiliate, net |
| — |
| 8,734 |
| — |
| 10,304 | |
Other investing activities |
| (93) |
| (115) |
| (4,314) |
| (166) | |
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| (33,429) |
| (17,769) |
| (48,904) |
| (48,703) | |
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Financing activities: |
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Long-term debt – repayments |
| (14) |
| (14) |
| (1,984) |
| (1,982) | |
Change in money pool note payable to |
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affiliate, net |
| 15,489 |
| — |
| 5,642 |
| 13,325 | |
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| 15,475 |
| (14) |
| 3,658 |
| 11,343 | |
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Increase in cash and cash equivalents |
| 616 |
| 3,041 | |||||
Increase (decrease) in cash and |
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cash equivalents |
| 622 |
| (2,029) | |||||
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Cash and cash equivalents: |
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Beginning of period |
| 4 |
| 2,033 |
| 4 |
| 2,033 | |
End of period | $ | 620 | $ | 5,074 | $ | 626 | $ | 4 | |
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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 | $ | 22,524 | $ | 5,372 | $ | 27,782 | $ | 11,449 | |
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Cash paid during the period for: |
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Interest (net of amounts capitalized) | $ | 4,017 | $ | 4,480 | $ | 4,970 | $ | 5,820 | |
Income taxes refunded | $ | (218) | $ | — | |||||
Income taxes paid | $ | 621 | $ | 4,333 |
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’sour 2008 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,” “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 2008 Annual Report on Form 10-K filed with the SEC. These financial statements include consideration of events through August 14, 2009.
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 March 31,June 30, 2009, December 31, 2008 and March 31,June 30, 2008 financial information and are of a normal recurring nature. The results of operations for the three and six months ended MarchJune 30, 2009 and our financial condition as of June 30, 2009 and December 31, 2009,2008 are not necessarily indicative of the results of operations and financial condition to be expected as of or for the full year.any other period.
(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.
We adopted the provisions of SFAS 157 on January 1, 2008 for all assets and liabilities measured at fair value for 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 until January 1, 2009. SFAS 157 also requires new disclosures regarding the level of pricing observability associated with instruments carried at fair value. The adoption of SFAS 157 and related FSPs did not have a material impact on our financial position, results of operations or cash flows.
SFAS 161
In March 2008, the FASB issued SFAS 161 which requires enhanced disclosures about how derivative and hedging activities and their affect on an entity’s financial position, financial performance and cash flows. SFAS 161 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption.
7 We adopted the provisions of SFAS 161 on January 1, 2009.
At March 31,June 30, 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 threesix months ended March 31,June 30, 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.
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FSP FAS 157-4SFAS 165
In AprilMay 2009, the FASB approved FSP FAS 157-4 effectiveissued SFAS 165, which establishes general standards of accounting for interim and annual periods endingdisclosures of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. We adopted and applied the provisions of SFAS 165 for our financial statements issued 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 position or cash flows.
FSP FAS 107-1
In April 2009, the FASB approved FSP FAS 107-1 effective for interim and annual periods ending after June 15, 2009. This FSP will requirerequires public companies to provide more frequent disclosures ofabout the fair value for public companies.of their financial instruments. These disclosures are included in Note 7.
(3) | RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS |
SFAS 167
In June 2009, the FASB issued SFAS 167 which is a revision to FASB Interpretation No. 46(R). This Statement amends the analysis performed by a company in determining whether an entity that is insufficiently capitalized or is not controlled through a voting interest should be consolidated. It will require additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. We are currently assessing the impact that the adoption of this Statement will have on our disclosures.financial condition, results of operations, and cash flows.
SFAS 168
On July 1, 2009, the FASB Accounting Standards CodificationTM will become the source of authoritative GAAP recognized by the FASB to be applied by non-governmental entities. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will update GAAP references for financial statements issued after September 15, 2009.
Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Task Force Abstracts. Instead, it will issue Accounting Standards Updates. The FASB will not consider Accounting Standards Updates as authoritative in their own right. Accounting Standards Updates will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.
FSP FAS 132(R)-1
During December 2008, the FASB issued FSP FAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets in a defined benefit pension or other postretirement plan to provide users of financial statements with an understanding of:
• How investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; |
• The major categories of plan assets; |
• The input and valuation techniques used to measure the fair value of plan assets; |
• The effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and |
• Significant concentrations of risk within plan assets. |
FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009. We do not expect the adoption of FSP FAS 132(R)-1 to have a significant effect on our financial statements.
(4) | OTHER COMPREHENSIVE INCOME |
The following table presents the components of Other comprehensive income (in thousands):
| Three Months Ended | |||
| March 31, | |||
| 2009 | 2008 | ||
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Net income | $ | 6,964 | $ | 5,576 |
Other comprehensive income (loss), net of tax: |
|
|
|
|
Fair value adjustment on derivatives |
|
|
|
|
designated as cash flow hedges (net of |
|
|
|
|
tax of $(6) and $(38), respectively) |
| 11 |
| 71 |
Reclassification adjustments included |
|
|
|
|
in net income (net of tax of $93) |
| — |
| (171) |
Total comprehensive income | $ | 6,975 | $ | 5,476 |
| Three Months Ended | |||
| June 30, | |||
| 2009 | 2008 | ||
|
|
|
|
|
Net income | $ | 3,105 | $ | 5,251 |
Other comprehensive income (loss), net of tax: |
|
|
|
|
Reclassification adjustments included in |
|
|
|
|
net income (net of tax of $(6) and $(6), |
|
|
|
|
respectively) |
| 11 |
| 10 |
Total comprehensive income | $ | 3,116 | $ | 5,261 |
| Six Months Ended | |||
| June 30, | |||
| 2009 | 2008 | ||
|
|
|
|
|
Net income | $ | 10,069 | $ | 10,827 |
Other comprehensive income (loss), net of tax: |
|
|
|
|
Reclassification adjustments included |
|
|
|
|
in net income (net of tax of $(11) and $48, |
|
|
|
|
respectively) |
| 21 |
| (90) |
Total comprehensive income | $ | 10,090 | $ | 10,737 |
Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Balance Sheets are as follows (in thousands):
| Derivatives | Employee |
| Derivatives | Employee |
| ||||||
| Designated as | Benefit |
| Designated as | Benefit |
| ||||||
| Cash Flow Hedges | Plans | Total | Cash Flow Hedges | Plans | Total | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2009 | $ | (921) | $ | (417) | $ | (1,338) | ||||||
As of June 30, 2009 | $ | (911) | $ | (417) | $ | (1,328) | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008 | $ | (932) | $ | (417) | $ | (1,349) | $ | (932) | $ | (417) | $ | (1,349) |
(5) | RELATED-PARTY TRANSACTIONS |
Receivables and Payables
We have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $2.9$2.7 million and $12.6 million as of March 31,June 30, 2009 and December 31, 2008, respectively. We also have accounts payable balances related to transactions with other BHC subsidiaries. The balances were $4.7$9.2 million and $10.4 million as of March 31,June 30, 2009 and December 31, 2008, respectively.
Money Pool Notes Receivable and Notes Payable |
We have entered into a Utility Money Pool Agreement with BHC, Cheyenne Light and Black Hills Energy. Under the agreement, we may borrow from the Parent. The Agreement restricts us from loaning funds to the Parent or to any of the Parent’s non-utility subsidiaries; the Agreement does not restrict us 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.
Through the Utility Money Pool, we had net note payable balances and interest payable of $85.7$76.3 million and $70.2 million as of March 31,June 30, 2009 and December 31, 2008, respectively. Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (which equates to 1.2%1.01% at March 31,June 30, 2009). Net interest expense of $0.4$0.7 million and $1.1 million was recorded for the three months and six months ended March 31,June 30, 2009, and netrespectively. Net interest income ofexpense was less than $0.1 million for the three and six months ended March 31,June 30, 2008.
Other Balances and Transactions
We also received revenues of approximately $0.2 million and $0.3$0.4 million for the three months ended March 31,June 30, 2009 and 2008, respectively; and $0.4 million and $0.7 million for the six months ended June 30, 2009 and 2008, respectively, from Black Hills Wyoming for the transmission of electricity.
We recorded revenues of $0.2 million for the threesix months ended March 31,June 30, 2008 relating to payments received pursuant to a natural gas swap entered into with Enserco, with a third party transacted by Enserco on our behalf.
We received revenues of approximately $0.3$0.4 million and $0.7$0.4 million for the three months ended March 31,June 30, 2009 and 2008, respectively; and $0.7 million and $1.1 million for the six months ended June 30, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.
We purchase coal from WRDC. The amount purchased during the three months ended March 31,June 30, 2009 and 2008 was $3.9$3.2 million and $3.1$2.8 million, respectively.respectively; and $7.1 million and $5.9 million for the six months ended June 30, 2009 and 2008.
We purchase excess power generated by Cheyenne Light. The amount purchased during the three months and six months ended March 31,June 30, 2009 was $2.0 million including $0.8and $3.9 million, respectively and includes $0.5 million and $1.3 million for wind-generated power and $1.3 million for the three and six months ended March 31, 2008.June 30, 2009, respectively. The amount purchased for the three and six month periods ended June 30, 2008 was $1.6 million and $3.1 million, respectively. On August 28, 2008, we entered into a contract with Cheyenne Light under which Cheyenne Light sells up to 20 MW of wind-generated, renewable energy to us until 2028.
In order to fuel our combustion turbine, we purchase natural gas from Enserco. The amount purchased during the three months ended March 31,June 30, 2009 and 2008 was $0.1$0.5 million and less than $0.1$3.5 million, respectively; and $0.6 million and $3.5 million for the six months ended June 30, 2009 and 2008, respectively. These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.
In addition, we also pay the Parent for allocated corporate support service cost incurred on our behalf. Corporate costs allocated from the Parent were $3.6$3.8 million and $3.1$3.0 million for the three months ended March 31,June 30, 2009 and 2008, respectively; and $7.4 million and $6.1 million for the six months ended June 30, 2009 and 2008, respectively.
We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $1.9 million as of March 31,June 30, 2009 and December 31, 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 (4.52%(3.37% at March 31,June 30, 2009).
(6) | EMPLOYEE BENEFIT PLANS |
Defined Benefit Pension Plan
We have a noncontributory defined benefit pension plan (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 | Three Months Ended | Six Months Ended | |||||||||
| March 31, | June 30, | ||||||||||
| 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost | $ | 292 | $ | 279 | $ | 292 | $ | 279 | $ | 584 | $ | 558 |
Interest cost |
| 785 |
| 758 |
| 785 |
| 758 |
| 1,570 |
| 1,516 |
Expected return on plan assets |
| (657) |
| (1,094) |
| (657) |
| (1,094) |
| (1,314) |
| (2,188) |
Prior service cost |
| 28 |
| 28 |
| 28 |
| 28 |
| 56 |
| 56 |
Net loss |
| 430 |
| — |
| 430 |
| — |
| 860 |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost | $ | 878 | $ | (29) | $ | 878 | $ | (29) | $ | 1,756 | $ | (58) |
A contribution totaling less than $0.1 million was made to the Plan in the first quarter of 2009. There are no further contributions expected to be made to the Plan in 2009.
Supplemental Nonqualified Defined Benefit Plans
We have various supplemental retirement plans for key executives (Supplemental Plans)(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 | Three Months Ended | Six Months Ended | |||||||||
| March 31, | June 30, | ||||||||||
| 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost | $ | 25 | $ | 30 | $ | 25 | $ | 30 | $ | 50 | $ | 60 |
Net loss |
| 11 |
| 11 |
| 11 |
| 11 |
| 22 |
| 22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost | $ | 36 | $ | 41 | $ | 36 | $ | 41 | $ | 72 | $ | 82 |
We anticipate that we will make contributions to the Supplemental Plans for the 2009 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 Postretirement Healthcare Plans (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 | Three Months Ended | Six Months Ended | |||||||||
| March 31, | June 30, | ||||||||||
| 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost | $ | 54 | $ | 52 | $ | 54 | $ | 52 | $ | 108 | $ | 104 |
Interest cost |
| 111 |
| 104 |
| 111 |
| 104 |
| 222 |
| 208 |
Net transition obligation |
| 13 |
| 13 |
| 13 |
| 13 |
| 26 |
| 26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost | $ | 178 | $ | 169 | $ | 178 | $ | 169 | $ | 356 | $ | 338 |
We anticipate that we will make contributions to the Healthcare Plan for the 2009 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 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 $0.1 million.
(7) |
|
The estimated fair values of our financial instruments at June 30 are as follows (in thousands):
| 2009 | |||
| Carrying Amount | Fair Value | ||
|
|
|
|
|
Cash and cash equivalents | $ | 626 | $ | 626 |
Long-term debt | $ | 149,225 | $ | 157,081 |
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.
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.
(8) | COMMITMENTS AND CONTINGENCIES |
Legal Proceedings
We are subject to various legal proceedings, claims and litigation as described in Note 11 of the Notes to Financial Statements in our 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 threesix months of 2009.
|
|
On April 9, 2009,In the normal course of business, we sold a 25% ownership interestare subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Wygen III generation facility to MDU. At closing, MDU made a payment to us for its 25% sharefinancial 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, to dateif any, that may be incurred in excess of those amounts provided as of June 30, 2009, cannot be reasonably determined and could have a material adverse effect on the ongoing constructionour results 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.operations, financial position or cash flows.
Extension of Long-Term Power Sales Agreement with MEAN
In March 2009, our 10-year power sales contract withbetween 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 amounts from Wygen III and Neil Simpson II plants are as follows:
2009-2017 | 20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II |
2018-2019 | 15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
2020-2021 | 12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II |
2022-2023 | 10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
Sale to MDU
On April 9, 2009, we sold to MDU a 25% ownership interest in our Wygen III generation facility currently under construction. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. Proceeds of $32.8 million were received. 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 with MDU under which we supplied MDU with 74 MW of capacity and energy through 2016.
ITEM 2. | RESULTS OF OPERATIONS |
| Three Months Ended | Three Months Ended | Six Months Ended | |||||||||
| March 31, | June 30, | ||||||||||
| 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||
| (in thousands) | (in thousands) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue | $ | 54,458 | $ | 57,632 | $ | 46,836 | $ | 57,978 | $ | 101,294 | $ | 115,610 |
Fuel and purchased power |
| 22,762 |
| 27,499 |
| 19,753 |
| 28,226 |
| 42,515 |
| 55,725 |
Gross margin |
| 31,696 |
| 30,133 |
| 27,083 |
| 29,752 |
| 58,779 |
| 59,885 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
| 20,991 |
| 19,542 |
| 22,077 |
| 20,482 |
| 43,068 |
| 40,023 |
Operating income | $ | 10,705 | $ | 10,591 | $ | 5,006 | $ | 9,270 | $ | 15,711 | $ | 19,862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income | $ | 6,964 | $ | 5,576 | $ | 3,105 | $ | 5,251 | $ | 10,069 | $ | 10,827 |
The following tables provide certain operating statistics:
| Electric Revenue | ||||||
| (in thousands) | ||||||
|
| ||||||
| Three Months Ended March 31, | ||||||
|
| Percentage |
| ||||
Customer Base | 2009 | Change | 2008 | ||||
|
|
|
|
|
| ||
Commercial | $ | 14,643 | 9% | $ | 13,484 | ||
Residential |
| 14,281 | 10 |
| 12,966 | ||
Industrial |
| 4,750 | (10) |
| 5,296 | ||
Municipal sales |
| 636 | 2 |
| 625 | ||
Total retail sales |
| 34,310 | 6 |
| 32,371 | ||
Contract wholesale |
| 6,553 | (5) |
| 6,931 | ||
Wholesale off system |
| 9,220 | (39) |
| 15,097 | ||
Total electric sales |
| 50,083 | (8) |
| 54,399 | ||
Other revenue |
| 4,375 | 34 |
| 3,233 | ||
Total revenue | $ | 54,458 | (6)% | $ | 57,632 | ||
| Electric Revenue | ||||||||||||||||
| Megawatt Hours Sold | (in thousands) | |||||||||||||||
|
|
| |||||||||||||||
| Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
|
| Percentage |
|
| Percentage |
|
| Percentage |
| ||||||||
Customer Base | 2009 | Change | 2008 | 2009 | Change | 2008 | 2009 | Change | 2008 | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Commercial |
| 175,256 | 1% |
| 173,459 | $ | 14,551 | 11% | $ | 13,063 | $ | 29,194 | 10% | $ | 26,535 | ||
Residential |
| 163,476 | — |
| 163,034 |
| 10,391 | 4 |
| 10,002 |
| 24,672 | 7 |
| 22,980 | ||
Industrial |
| 85,984 | (16) |
| 102,669 |
| 5,030 | (9) |
| 5,542 |
| 9,780 | (10) |
| 10,838 | ||
Municipal sales |
| 8,095 | (1) |
| 8,208 |
| 660 | 3 |
| 639 |
| 1,296 | 3 |
| 1,264 | ||
Total retail sales |
| 432,811 | (3) |
| 447,370 |
| 30,632 | 5 |
| 29,246 |
| 64,942 | 5 |
| 61,617 | ||
Contract wholesale |
| 168,679 | (2) |
| 171,620 |
| 5,631 | (10) |
| 6,270 |
| 12,184 | (8) |
| 13,202 | ||
Wholesale off system |
| 243,786 | 7 |
| 227,741 |
| 5,765 | (70) |
| 19,238 |
| 14,985 | (56) |
| 34,335 | ||
Total electric sales |
| 845,276 | —% |
| 846,731 |
| 42,028 | (23) |
| 54,754 |
| 92,111 | (16) |
| 109,154 | ||
Other revenue |
| 4,808 | 49 |
| 3,224 |
| 9,183 | 42 |
| 6,456 | |||||||
Total revenue | $ | 46,836 | (19)% | $ | 57,978 | $ | 101,294 | (12)% | $ | 115,610 |
| 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% |
| 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 |
| Megawatt Hours Sold | |||||||||
|
| |||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||
|
| Percentage |
|
| Percentage |
| ||||
Customer Base | 2009 | Change | 2008 | 2009 | Change | 2008 | ||||
|
|
|
|
|
|
|
|
|
| |
Commercial |
| 169,955 | 5% |
| 162,313 |
| 345,211 | 3% |
| 335,772 |
Residential |
| 119,123 | 4 |
| 114,106 |
| 282,599 | 2 |
| 277,140 |
Industrial |
| 93,984 | (14) |
| 109,028 |
| 179,968 | (15) |
| 211,697 |
Municipal sales |
| 7,567 | (1) |
| 7,637 |
| 15,662 | (1) |
| 15,845 |
Total retail sales |
| 390,629 | (1) |
| 393,084 |
| 823,440 | (2) |
| 840,454 |
Contract wholesale |
| 143,248 | (9) |
| 156,965 |
| 311,927 | (5) |
| 328,585 |
Wholesale off system |
| 230,617 | (19) |
| 283,770 |
| 474,403 | (7) |
| 511,511 |
Total electric sales |
| 764,494 | (8) |
| 833,819 |
| 1,609,770 | (4) |
| 1,680,550 |
Losses and company |
|
|
|
|
|
|
|
|
|
|
use |
| 41,104 | 78 |
| 23,044 |
| 67,293 | 119 |
| 30,776 |
Total energy |
| 805,598 | (6)% |
| 856,863 |
| 1,677,063 | (2)% |
| 1,711,326 |
| 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% |
| Electric Utility Power Plant Availability | |||
|
| |||
| Three Months Ended June 30, | Six Months Ended June 30, | ||
| 2009 | 2008 | 2009 | 2008 |
|
|
|
|
|
Coal-fired plants | 77.4%* | 75.7%** | 87.0%* | 84.0%** |
Other plants | 92.2% | 85.6% | 95.8% | 91.0% |
Total availability | 83.9% | 80.6% | 90.8% | 87.5% |
___________________________
* | 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. |
** | Reflects major maintenance outages at our Ben French, Neil Simpson I and Osage coal-fired plants. The Ben French outage was scheduled for 25 days and was subsequently extended to accelerate major maintenance originally scheduled for 2009. The actual outage was 88 days and resulted in the plant’s output being restored to its full rated capacity. The Osage outage was originally scheduled for approximately 10 days and lasted 52 days as a result of additional unplanned required maintenance. All the plants were online by the end of the second quarter of 2008. |
| Megawatt Hours Generated and Purchased | |||||
|
| |||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||
|
| Percentage |
|
| Percentage |
|
Resources | 2009 | Change | 2008 | 2009 | Change | 2008 |
|
|
|
|
|
|
|
Coal | 348,657 | (9)% | 384,748 | 786,208 | (4)% | 817,630 |
Gas | 5,750 | 19 | 4,831 | 6,825 | (84) | 41,831 |
| 354,407 | (9) | 389,579 | 793,033 | (8) | 859,461 |
|
|
|
|
|
|
|
MWhs purchased | 451,191 | (3) | 467,284 | 884,030 | 4 | 851,865 |
Total resources | 805,598 | (6)% | 856,863 | 1,677,063 | (2)% | 1,711,326 |
| Heating and Cooling Degree Days | |||
|
| |||
| Three Months Ended | Six Months Ended | ||
| June 30, | June 30, | ||
| 2009 | 2008 | 2009 | 2008 |
Heating and cooling degree days: |
|
|
|
|
Actual |
|
|
|
|
Heating degree days | 1,273 | 1,230 | 4,527 | 4,591 |
Cooling degree days | 51 | 29 | 51 | 29 |
|
|
|
|
|
Variance from normal |
|
|
|
|
Heating degree days | 28% | 23% | 5% | 7% |
Cooling degree days | (50)% | (71)% | (50)% | (71)% |
Three Months Ended March 31,June 30, 2009 Compared to Three Months Ended March 31,June 30, 2008. Net income increased $1.4decreased $2.1 million from the prior period primarily due to the following:
• |
• A $1.8 million decrease in retail margins primarily due to outages at Neil Simpson I, Neil Simpson II and Wyodak, partially offset by a full quarter of operations at Ben French which had outages in the second quarter of 2008; and |
• A $1.5 million increase in employee benefit costs. |
Partially offsetting the decreases were the following: |
• Increased gross margins of $1.9 million due to an increase in transmission |
|
• Increased AFUDC of |
Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Net income decreased $0.8 million from the prior period primarily due to the following:
• A $3.8 million decrease in margins from off-system sales reflecting the lower margins available to the industry’s current low energy price environment; and |
• A $2.3 million increase in employee benefit costs. |
|
Partially offsetting the |
|
• |
|
• Increased |
Wygen III Power Plant Project and Sale to MDU
In March 2008, we received final regulatory approval for construction of Wygen III. Construction began immediately and the 110 MW coal-fired base load electric generating facility is expected to be completed inby June, 2010. The expected cost of construction is approximately $255 million, which includes estimates for AFUDC. AOur 2004 agreementPurchase Power Agreement with MDU included an option for MDU to purchase an ownership interest in Wygen III. In April 2009, MDU exercised this option, and we sold a 25% ownership interestunder an agreement entered into in Wygen III to MDU. WeApril 2009, we will retain an undivided ownership of 75% of the facility’s capacityfacility with MDU owning the remaining 25%. At closing, MDU reimbursed us for its 25%, or $32.8 million, of the total costs incurred to date on the ongoing construction of the facility. 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. In conjunction with the sales transaction, we also modified our 2004 power purchase agreement with MDU under which we supplied MDU with 74 MW of capacity and energy through 2016.
Extension of Long-Term Power Sales Agreement with MEAN
In March 2009, our 10-year power sales contract between 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 amounts from Wygen III and Neil Simpson II plants are as follows:
2009-2017 | 20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II |
2018-2019 | 15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
2020-2021 | 12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II |
2022-2023 | 10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
Purchase Power Agreement with MEAN
In July 2009, we entered into a five-year PPA with MEAN. The contract commences the month following the commercial operations of Wygen III. Under this contract, MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.
Financing Transactions and Short-Term Liquidity
Future Financing Plans
We anticipate issuing a long-term first mortgage bond of approximately $180 million. The offering is expected to be completed in the Fall of 2009; proceeds of the transaction will be used to fund capital expenditures, including construction costs related to the Wygen III facility, and to fund the approximate $30 million maturity of our Series AC, 8.06% first mortgage bonds due in February 2010.
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, 2009, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:
Rating Agency | Rating | Outlook |
Moody’s | Baa1 | Stable |
S&P | BBB | Stable |
Fitch | A- | Stable |
In August 2009, Moody’s upgraded the senior secured debt rating to A3.
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 ofForward-looking statements involve risks and uncertainties, that, amongand 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 things,similar terminology. There are various factors that could cause actual results to differ materially from those contained insuggested by the forward-looking statements; accordingly, there can be no assurances that such indicated results will be realized. The forward-looking statements includinginclude the factors discussed above, the risk factors described in Item 1A of our 2008 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; |
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• | Our ability to |
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• | 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; |
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• | The timing and extent of scheduled and unscheduled outages of power generation facilities; |
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• | 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; |
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• | Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 2005; |
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• | 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; |
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• | Our ability to effectively use derivative financial instruments to hedge commodity risks; |
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• | Our ability to minimize defaults on amounts due from counterparty transactions; |
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• | Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment; |
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• | 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; |
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• | Industry and market changes, including the impact of consolidations and changes in competition; |
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• | The effect of accounting policies issued periodically by accounting standard-setting bodies; |
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• | The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions or events; |
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• | The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements; |
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• | General economic and political conditions, including tax rates or policies and inflation rates; and |
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• | 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 March 31,June 30, 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 March 31,June 30, 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 our 2008 Annual Report on Form 10-K and Note 78 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 78 is incorporated by reference into this item.
Item 1A. | Risk Factors |
There have been no material changes inExcept to the extent updated or described below, our Risk Factors from those reportedare documented in Item 1A.IA. of Part I ofin our 2008 Annual Report on Form 10-K filed withfor the Securitiesyear ended December 31, 2008.
Federal and Exchange Commission.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.
We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. We are constructing another fossil-fuel generating plant in Wyoming. Air emissions of fossil-fuel generating plants are subject to federal, state and tribal regulation. Recent developments under federal and state laws and regulation governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations.
On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U.S. Environmental Protection Agency, holding that CO2 and other GHG emissions are pollutants subject to regulation under the motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or alternatively, to explain why GHG emissions should not be regulated. On April 17, 2008, the EPA issued its proposed endangerment finding under Section 202 of the Clean Air Act. Although this proposal does not specifically address stationary sources, such as power generation plants, the general endangerment finding relative to GHG’s could support such a proposal by the EPA for stationary sources. On March 10, 2009, the EPA released proposed rules regarding a mandatory GHG reporting regimen, the purpose of which would be to collect data to inform future policy and regulatory decisions. Finally, federal legislation is currently under consideration in the U.S. Congress, including H.R. 2454, “the American Clean Energy and Security Act of 2009”, which was approved by the U.S. House of Representatives on June 26, 2009. This legislation would affect electric generation and electric and natural gas distribution companies. H.R. 2454 would establish mandatory GHG reduction targets, utilizing a Federal emissions cap-and-trade program. H.R.2454 also proposes a national renewable electricity standard, which would implement a phased process ultimately mandating that 20% of electricity sold by retail suppliers be met by energy efficiency improvements and renewable energy resources by 2020. The Senate is expected to consider its own version of the legislation later in 2009 or in 2010.
Due to the uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation upon our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a “cap and trade” structure is implemented, the impact will also be affected by the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the affect of carbon regulation on natural gas and coal prices.
More stringent GHG emissions limitations or other energy efficiency requirements, however, could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base, we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by our non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.
We own electric utilities that serve customers in Montana, South Dakota and Wyoming. Montana has adopted mandatory renewable portfolio standards that require electric utilities to supply a minimum percentage of the power delivered to customers from renewable resources (e.g., wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If this state increases its 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. Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material negative impact on our results of operations and financial condition.
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. |