UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
x | QUARTERLY REPORT |
For the quarterly period ended March 31,June 30, 2006.
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF 1934 |
For the transition period from __________ to __________.
Commission File Number 1-7978
Black Hills Power, Inc. | |
Incorporated in South Dakota | IRS Identification Number 46-0111677 |
625 Ninth Street, Rapid City, South Dakota 57701 | |
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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 |
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer | o | Accelerated filer | o | Non-accelerated filer | x |
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
Yes | o | No | x |
As of April 30,July 31, 2006, 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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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 | 3 |
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| Condensed Balance Sheets – |
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| Condensed Statements of Cash Flows – |
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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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2
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF INCOME
(unaudited)
| Three Months Ended | Three Months Ended | Six Months Ended | |||||||||
| March 31, | June 30, | ||||||||||
| 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | ||||||
| (in thousands) | (in thousands) | ||||||||||
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Operating revenue | $ | 43,968 | $ | 43,147 | $ | 47,036 | $ | 42,261 | $ | 91,004 | $ | 85,408 |
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Operating expenses: |
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Fuel and purchased power |
| 16,048 |
| 15,729 |
| 20,588 |
| 15,587 |
| 36,636 |
| 31,316 |
Operations and maintenance |
| 5,307 |
| 4,835 |
| 8,095 |
| 6,613 |
| 13,402 |
| 11,448 |
Administrative and general |
| 5,834 |
| 5,960 |
| 4,991 |
| 5,062 |
| 10,826 |
| 11,022 |
Depreciation and amortization |
| 4,592 |
| 4,938 |
| 5,020 |
| 4,759 |
| 9,612 |
| 9,697 |
Taxes, other than income taxes |
| 2,090 |
| 2,190 |
| 1,851 |
| 2,120 |
| 3,940 |
| 4,310 |
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| 33,871 |
| 33,652 |
| 40,545 |
| 34,141 |
| 74,416 |
| 67,793 |
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Operating income |
| 10,097 |
| 9,495 |
| 6,491 |
| 8,120 |
| 16,588 |
| 17,615 |
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Other income (expense): |
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Interest expense |
| (3,243) |
| (3,215) |
| (3,367) |
| (3,146) |
| (6,610) |
| (6,361) |
Interest income |
| 286 |
| 34 |
| 465 |
| 9 |
| 751 |
| 43 |
Other income, net |
| 186 |
| 140 |
| (3) |
| 134 |
| 183 |
| 275 |
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| (2,771) |
| (3,041) |
| (2,905) |
| (3,003) |
| (5,676) |
| (6,043) |
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Income before income taxes |
| 7,326 |
| 6,454 |
| 3,586 |
| 5,117 |
| 10,912 |
| 11,572 |
Income taxes |
| (2,427) |
| (2,132) |
| (1,150) |
| (1,708) |
| (3,577) |
| (3,840) |
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Net income | $ | 4,899 | $ | 4,322 | $ | 2,436 | $ | 3,409 | $ | 7,335 | $ | 7,732 |
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
3
BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(unaudited)
| March 31, | December 31, | June 30, | December 31, | ||||
| 2006 | 2005 | 2006 | 2005 | ||||
| (in thousands) | (in thousands) | ||||||
ASSETS |
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Current assets: |
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Cash and cash equivalents | $ | 1,391 | $ | 685 | $ | 5 | $ | 685 |
Receivables (net of allowance for doubtful accounts |
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of $837 and $830, respectively) |
| 16,449 |
| 20,293 | ||||
of $262 and $830, respectively) |
| 17,764 |
| 20,293 | ||||
Receivables – affiliates |
| 1,099 |
| 1,964 |
| 1,569 |
| 1,964 |
Money Pool note receivable – affiliate |
| 4,830 |
| — | ||||
Materials, supplies and fuel |
| 14,642 |
| 14,236 |
| 16,871 |
| 14,236 |
Deferred income taxes |
| 759 |
| 835 |
| 425 |
| 835 |
Other current assets |
| 661 |
| 820 |
| 1,451 |
| 820 |
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| 39,831 |
| 38,833 |
| 38,085 |
| 38,833 |
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Investments |
| 3,478 |
| 3,340 |
| 3,492 |
| 3,340 |
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Property, plant and equipment |
| 659,034 |
| 653,679 |
| 668,331 |
| 653,679 |
Less accumulated depreciation |
| (255,061) |
| (250,583) |
| (259,024) |
| (250,583) |
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| 403,973 |
| 403,096 |
| 409,307 |
| 403,096 |
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Other assets: |
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Regulatory assets |
| 6,894 |
| 6,941 |
| 6,848 |
| 6,941 |
Other |
| 10,554 |
| 11,448 |
| 10,337 |
| 11,448 |
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| 17,448 |
| 18,389 |
| 17,185 |
| 18,389 |
| $ | 464,730 | $ | 463,658 | $ | 468,069 | $ | 463,658 |
LIABILITIES AND STOCKHOLDER’S EQUITY |
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Current liabilities: |
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Current maturities of long-term debt | $ | 1,997 | $ | 1,996 | $ | 1,999 | $ | 1,996 |
Accounts payable |
| 6,363 |
| 10,290 |
| 7,881 |
| 10,290 |
Accounts payable – affiliates |
| 1,851 |
| 1,624 |
| 3,748 |
| 1,624 |
Money Pool note payable – Parent |
| — |
| 1,842 | ||||
Money pool note payable – Parent |
| 1,023 |
| 1,842 | ||||
Accrued liabilities |
| 16,245 |
| 14,866 |
| 13,353 |
| 14,866 |
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| 26,456 |
| 30,618 |
| 28,004 |
| 30,618 |
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Long-term debt, net of current maturities |
| 155,208 |
| 155,219 |
| 153,242 |
| 155,219 |
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Deferred credits and other liabilities: |
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Deferred income taxes |
| 68,307 |
| 67,942 |
| 68,472 |
| 67,942 |
Regulatory liabilities |
| 5,668 |
| 5,740 |
| 6,402 |
| 5,740 |
Other |
| 15,541 |
| 15,460 |
| 15,925 |
| 15,460 |
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| 89,516 |
| 89,142 |
| 90,799 |
| 89,142 |
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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 |
| 39,549 |
| 39,575 |
| 39,549 |
Retained earnings |
| 131,984 |
| 127,312 |
| 134,420 |
| 127,312 |
Accumulated other comprehensive loss |
| (1,425) |
| (1,598) |
| (1,387) |
| (1,598) |
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| 193,550 |
| 188,679 |
| 196,024 |
| 188,679 |
| $ | 464,730 | $ | 463,658 | $ | 468,069 | $ | 463,658 |
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
4
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited)
| Three Months Ended | Six Months Ended | ||||||
| March 31, | June 30, | ||||||
| 2006 | 2005 | 2006 | 2005 | ||||
| (in thousands) | (in thousands) | ||||||
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Operating activities: |
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Net income | $ | 4,899 | $ | 4,322 | $ | 7,335 | $ | 7,732 |
Adjustments to reconcile net income to cash provided by |
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operating activities: |
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Adjustments to reconcile net income to cash |
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provided by operating activities: |
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Depreciation and amortization |
| 4,592 |
| 4,938 |
| 9,612 |
| 9,697 |
Deferred income tax |
| 15 |
| 22 |
| 346 |
| 230 |
Change in operating assets and liabilities - |
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Accounts receivable and other current assets |
| 3,541 |
| 4,209 |
| 113 |
| 2,406 |
Accounts payable and other current liabilities |
| (2,536) |
| (1,010) |
| (1,918) |
| (599) |
Other operating activities |
| 1,235 |
| 361 |
| 1,446 |
| 707 |
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| 11,746 |
| 12,842 |
| 16,934 |
| 20,173 |
Investing activities: |
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Property, plant and equipment additions |
| (4,220) |
| (2,782) |
| (14,669) |
| (7,249) |
Change in note receivable from affiliate, net |
| (4,830) |
| — | ||||
Other investing activities |
| (138) |
| (136) |
| (152) |
| 3,061 |
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| (9,188) |
| (2,918) |
| (14,821) |
| (4,188) |
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Financing activities: |
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Change in note payable to parent company, net |
| (1,842) |
| (9,709) |
| (819) |
| (14,350) |
Long-term debt – repayments |
| (10) |
| (9) |
| (1,974) |
| (1,973) |
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| (1,852) |
| (9,718) |
| (2,793) |
| (16,323) |
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Increase in cash and cash equivalents |
| 706 |
| 206 | ||||
Decrease in cash and cash equivalents |
| (680) |
| (338) | ||||
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Cash and cash equivalents: |
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Beginning of period |
| 685 |
| 344 |
| 685 |
| 344 |
End of period | $ | 1,391 | $ | 550 | $ | 5 | $ | 6 |
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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 with accrued liabilities | $ | 416 | $ | — | ||||
Property, plant and equipment acquired with |
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accrued liabilities | $ | 321 | $ | — | ||||
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Cash paid during the period for: |
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Interest | $ | 4,241 | $ | 3,374 | $ | 6,601 | $ | 5,996 |
Income taxes paid | $ | 1,132 | $ | 688 | $ | 4,927 | $ | 3,283 |
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
5
BLACK HILLS POWER, INC.
Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in the Company’s 2005 Annual Report on Form 10-K)
(1) | MANAGEMENT’S STATEMENT |
The financial statements included herein have been prepared by Black Hills Power, Inc. (the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in the Company’s 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the March 31,June 30, 2006, December 31, 2005 and March 31,June 30, 2005, financial information and are of a normal recurring nature. The results of operations for the three and six months ended March 31,June 30, 2006, are not necessarily indicative of the results to be expected for the full year.
(2) | RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS |
FIN 48
In June, 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109 “Accounting for Income Taxes” (FAS 109) and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006 with the impact of adoption to be reported as a cumulative effect of an accounting change. Management is currently evaluating the impact FIN 48 will have on the Company’s consolidated financial statements.
(3) | COMPREHENSIVE INCOME |
The following table presents the components of the Company’s comprehensive income (in thousands):
| Three Months Ended | |||
| March 31, | |||
| 2006 | 2005 | ||
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Net income | $ | 4,899 | $ | 4,322 |
Other comprehensive income, net of tax: |
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Fair value adjustment on derivatives designated |
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as cash flow hedges |
| 218 |
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Reclassification adjustments included |
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in net income |
| (45) |
| 11 |
Comprehensive income | $ | 5,072 | $ | 4,333 |
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| Three Months Ended | Six Months Ended | ||||||
| June 30, | June 30, | ||||||
| 2006 | 2005 | 2006 | 2005 | ||||
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Net income | $ | 2,436 | $ | 3,409 | $ | 7,335 | $ | 7,732 |
Other comprehensive income, net of tax: |
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Fair value adjustment on derivatives |
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designated as cash flow hedges |
| 27 |
| (59) |
| 245 |
| (59) |
Reclassification adjustments included |
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in net income |
| 11 |
| 11 |
| (34) |
| 22 |
Comprehensive income | $ | 2,474 | $ | 3,361 | $ | 7,546 | $ | 7,695 |
| RELATED-PARTY TRANSACTIONS |
Receivables and Payables
The Company has accounts receivable balances related to transactions with other Black Hills Corporation subsidiaries. The balances were $1.1 million and $2.0 million as of March 31, 2006 and December 31, 2005, respectively. The Company also has accounts payable balances related to transactions with other Black Hills Corporation subsidiaries. The balances were $1.9 million and $1.6 million as of March 31, 2006 and December 31, 2005, respectively.
Money Pool Notes Receivable and Notes Payable |
In August 2005, the Company entered into a Utility Money Pool Agreement with Black Hills Corporation (the Parent); and Cheyenne Light, Fuel and Power, (Cheyenne Light) an electric and gas utility subsidiary of the Parent. Under the agreement, the Company may borrow from the Parent. The Agreement restricts the Company from loaning funds to the Parent or to any of the Parent’s non-utility subsidiaries; the Agreement does not restrict the Company 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 through the Utility Money Pool has a net note receivable balance from Cheyenne Light of $4.8 million at March 31, 2006 and a net note payable balance to the Parent of $1.0 million and $1.8 million atas of June 30, 2006 and December 31, 2005.2005, respectively. Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (5.53(6.03 percent at March 31,June 30, 2006).
Other Balances and Transactions
The Company purchases coal from Wyodak Resources Development Corp., an indirect subsidiary of the Parent. The amount purchased during the three months ended March 31,June 30, 2006 and 2005 was $2.6$2.2 million and $2.4 million, respectively; and $4.8 million for each of the six month periods ended June 30, 2006 and 2005, respectively.
In addition, for the six months ended June 30, 2006 the Company recorded revenues of $0.6 million, in revenues in the three months ended March 31, 2006, relating to payments received pursuant to a fair value hedgenatural gas swap entered into with Enserco Energy, an indirect subsidiary of the Parent.
The Company also received revenues of approximately $0.2$0.6 million and $0.4 million for the three months ended March 31,June 30, 2006 and $0.12005, respectively; and $0.8 million and $0.4 million for the threesix months ended March 31,June 30, 2006 and 2005, respectively, from Black Hills Wyoming, Inc., an indirect subsidiary of Black Hills Corporation, for the transmission of electricity.
The Company also pays the Parent for allocated corporate support service cost incurred on its behalf. Corporate costs allocated from the Parent were $3.0$2.3 million and $2.2$2.4 million for the three months ended March 31,June 30, 2006 and 2005, respectively; and $5.3 million and $4.8 million for the six months ended June 30, 2006 and 2005, respectively.
Receivables and Payables
7
The Company has accounts receivable balances related to transactions with other Black Hills Corporation subsidiaries. The balances were $1.6 million and $2.0 million as of June 30, 2006 and December 31, 2005, respectively. The Company also has accounts payable balances related to transactions with other Black Hills Corporation subsidiaries. The balances were $3.7 million and $1.6 million as of June 30, 2006 and December 31, 2005, respectively.
| RISK MANAGEMENT |
On March 31,June 30, 2006 and December 31, 2005, the Company had the following swaps and related balances (in thousands):
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| Maximum | Current | current | Current | current | Other | Unrealized |
| Maximum | Current | current | Current | current | Other | Unrealized | ||||||||||||
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| Terms in | Derivative | Comprehensive | Gain |
| Terms in | Derivative | Comprehensive | Gain | ||||||||||||||||||
| Notional* | Years | Assets | Liabilities | Income (Loss) | (Loss) | Notional* | Years | Assets | Liabilities | Income (Loss) | (Loss) | ||||||||||||||||
March 31, |
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June 30, |
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2006 |
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Natural gas |
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swaps | 155,000 | 1.00 | $ | 31 | $ | — | $ | — | $ | — | $ | 31 | $ | — | 155,000 | 0.75 | $ | 73 | $ | — | $ | — | $ | — | $ | 73 | $ | — |
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December 31, |
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2005 |
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Natural gas |
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swaps | 275,000 | 0.25 | $ | 192 | $ | — | $ | 219 | $ | — | $ | (219) | $ | 192 | 275,000 | 0.25 | $ | 192 | $ | — | $ | 219 | $ | — | $ | (219) | $ | 192 |
________________________
*gas in MMbtu’s
Based on March 31,June 30, 2006 market prices, a gain of less than $0.1 million would be realized and reported in pre-tax earnings during the next twelve months related to the cash flow hedge. Estimated and actual realized gains will likely change during the next twelve months as market prices change.
In addition, certain volumes of natural gas inventory were designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Balance Sheet and the related unrealized gain/loss on the Statement of Income. As of December 31, 2005, the market adjustments recorded in inventory were $(0.2) million.
8
| EMPLOYEE BENEFIT PLANS |
Defined Benefit Pension Plan
The Company has 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 | Three Months Ended | Six Months Ended |
| ||||||||||
| March 31, | June 30, | June 30, |
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| 2006 | 2005 | 2006 | 2005 | 2006 | 2005 |
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Service cost | $ | 271 | $ | 248 | $ | 271 | $ | 248 | $ | 542 | $ | 496 | ||
Interest cost |
| 680 |
| 675 |
| 680 |
| 675 |
| 1,360 |
| 1,350 | ||
Expected return on plan assets |
| (889) |
| (870) |
| (889) |
| (870) |
| (1,778) |
| (1,740) | ||
Amortization of prior service cost |
| 26 |
| 39 |
| 26 |
| 39 |
| 52 |
| 78 | ||
Amortization of net loss |
| 166 |
| 213 |
| 166 |
| 213 |
| 332 |
| 426 | ||
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Net periodic benefit cost | $ | 254 | $ | 305 | $ | 254 | $ | 305 | $ | 508 | $ | 610 | ||
The Company does not anticipate that it will need to make a contribution to the Plan in the 2006 fiscal year.
Supplemental Nonqualified Defined Benefit Plan
The Company has various supplemental retirement plans for outside directors and key executives of the Company (Supplemental Plans). The Supplemental Plans are nonqualified 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, | ||||||||||
| 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | ||||||
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Service cost | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — |
Interest cost |
| 28 |
| 27 |
| 28 |
| 27 |
| 56 |
| 54 |
Amortization of net loss |
| 16 |
| 12 |
| 16 |
| 12 |
| 32 |
| 24 |
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Net periodic benefit cost | $ | 44 | $ | 39 | $ | 44 | $ | 39 | $ | 88 | $ | 78 |
The Company anticipates that it will make contributions to the Supplemental Plans for the 2006 fiscal year of approximately $0.1 million. The contributions are expected to be in the form of benefit payments.
9
Non-pension Defined Benefit Postretirement Plan
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 Plan are as follows (in thousands):
| Three Months Ended | Three Months Ended | Six Months Ended | |||||||||
| March 31, | June 30, | ||||||||||
| 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | ||||||
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Service cost | $ | 62 | $ | 73 | $ | 62 | $ | 73 | $ | 124 | $ | 146 |
Interest cost |
| 100 |
| 116 |
| 100 |
| 116 |
| 200 |
| 232 |
Amortization of net transition obligation |
| 29 |
| 29 |
| 29 |
| 29 |
| 58 |
| 58 |
Amortization of prior service cost |
| (5) |
| (5) |
| (5) |
| (5) |
| (10) |
| (10) |
Amortization of net loss |
| — |
| 19 |
| — |
| 19 |
| — |
| 38 |
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Net periodic benefit cost | $ | 186 | $ | 232 | $ | 186 | $ | 232 | $ | 372 | $ | 464 |
The Company anticipates that it will make contributions to the Healthcare Plan for the 2006 fiscal year of approximately $0.2 million. The contributions are expected to be 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 as follows (in thousands):
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| LEGAL PROCEEDINGS |
The Company is subject to various legal proceedings, claims and litigation as described in Note 10 of the Notes to Consolidated Financial Statements in the Company’s 2005 Annual Report on Form 10-K. There
PPM Energy, Inc. Demand for Arbitration
As disclosed in previous filings with the Securities and Exchange Commission, the Company received a Demand for Arbitration from PPM Energy, Inc. (PPM) on January 2, 2004, that alleged claims for breach of contract and requested a declaration of the parties’ rights and responsibilities under an Exchange Agreement executed in April of 2001. PPM asserted the Exchange Agreement obligated the Company to accept receipt and cause corresponding delivery of electric energy, and to grant access to transmission rights allegedly covered by the Agreement. PPM requested an award of damages in an amount not less than $20.0 million. The Company filed its Response to Demand, including a counterclaim that sought recovery of sums PPM had refused to pay pursuant to the Exchange Agreement. The dispute was presented to the arbitrator in August 2005 and the arbitrator delivered his decision on June 5, 2006.
The arbitrator concluded both parties failed to perform the Exchange Agreement, in certain respects. The Company has paid PPM a net settlement of $1.1 million in accordance with the decision. The Company does not believe that the decision will have a material impact on its ability to market surplus power in the future.
Subsequent Event - Forest Fire Claims
On August 10, 2006, the Company settled State and Federal government claims related to the Hell Canyon and Grizzly Gulch forest fires. In the settlement of governmental claims, the Company does not admit liability or responsibility for the fires, but agreed to pay $1.3 million and $5.9 million respectively to terminate the lawsuits.
Additional claims have been made for individual and business losses relating to injury to personal and real property, and lost income, as a result of the Grizzly Gulch forest fire. The Company will vigorously defend all claims brought by private parties. The settlements and additional claims are not expected to have a material adverse effect on the Company’s financial condition or results of operations.
Except as described above, there have been no material developments in theseany previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first quartersix months of 2006.
10
ITEM 2. | RESULTS OF OPERATIONS |
| Three Months Ended | Three Months Ended | Six Months Ended | ||||||||||
| March 31, | June 30, | June 30, | ||||||||||
| 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | |||||||
| (in thousands) | (in thousands) | |||||||||||
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Revenue | $ | 43,968 | $ | 43,147 | $ | 47,036 | $ | 42,261 | $ | 91,004 | $ | 85,408 | |
Operating expenses |
| 33,871 |
| 33,652 |
| 40,545 |
| 34,141 |
| 74,416 |
| 67,793 | |
Operating income | $ | 10,097 | $ | 9,495 | $ | 6,491 | $ | 8,120 | $ | 16,588 | $ | 17,615 | |
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Income from continuing operations and net income | $ | 4,899 | $ | 4,322 | |||||||||
Net income | $ | 2,436 | $ | 3,409 | $ | 7,335 | $ | 7,732 | |||||
The following tables provide certain operating statistics for the Electric Utility segment:statistics:
| Electric Revenue | Electric Revenue | |||||||||||||
| (in thousands) | (in thousands) | |||||||||||||
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| |||||||||||||
| Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
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| Percentage |
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| Percentage |
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| Percentage |
| ||||||
Customer Base | 2006 | Change | 2005 | 2006 | Change | 2005 | 2006 | Change | 2005 | ||||||
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Commercial | $ | 11,422 | —% | $ | 11,446 | $ | 11,892 | 2% | $ | 11,634 | $ | 23,290 | 1% | $ | 23,065 |
Residential |
| 10,663 | 1 |
| 10,543 |
| 8,868 | 3 |
| 8,649 |
| 19,556 | 2 |
| 19,207 |
Industrial |
| 5,011 | 3 |
| 4,854 |
| 5,187 | 6 |
| 4,910 |
| 10,198 | 4 |
| 9,764 |
Municipal sales |
| 520 | 5 |
| 493 |
| 591 | 6 |
| 555 |
| 1,111 | 6 |
| 1,048 |
Total retail sales |
| 27,616 | 1 |
| 27,336 |
| 26,538 | 3 |
| 25,748 |
| 54,155 | 2 |
| 53,084 |
Contract wholesale |
| 6,108 | 2 |
| 5,986 |
| 5,920 | 4 |
| 5,672 |
| 12,028 | 3 |
| 11,657 |
Wholesale off-system |
| 8,234 | 1 |
| 8,113 |
| 10,575 | 15 |
| 9,171 |
| 18,809 | 9 |
| 17,284 |
Total electric sales |
| 41,958 | 1 |
| 41,435 |
| 43,033 | 6 |
| 40,591 |
| 84,992 | 4 |
| 82,025 |
Other revenue |
| 2,010 | 17 |
| 1,712 |
| 4,003 | 140 |
| 1,670 |
| 6,012 | 78 |
| 3,383 |
Total revenue | $ | 43,968 | 2% | $ | 43,147 | $ | 47,036 | 11% | $ | 42,261 | $ | 91,004 | 7% | $ | 85,408 |
| Megawatt Hours | ||
|
| ||
| Three Months Ended March 31, | ||
|
| Percentage |
|
Customer Base | 2006 | Change | 2005 |
|
|
|
|
Commercial | 158,593 | 1% | 157,518 |
Residential | 141,794 | 3 | 137,947 |
Industrial | 103,027 | 5 | 98,398 |
Municipal sales | 7,059 | 9 | 6,462 |
Total retail sales | 410,473 | 3 | 400,325 |
Contract wholesale | 162,251 | 1 | 160,838 |
Wholesale off-system | 180,163 | (4) | 188,114 |
Total electric sales | 752,887 | —% | 749,277 |
11
| Megawatt Hours Sold | |||||
|
| |||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||
|
| Percentage |
|
| Percentage |
|
Customer Base | 2006 | Change | 2005 | 2006 | Change | 2005 |
|
|
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|
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Commercial | 158,046 | 4% | 152,644 | 316,639 | 2% | 310,162 |
Residential | 105,484 | 3 | 102,692 | 247,278 | 3 | 240,639 |
Industrial | 108,333 | 4 | 103,695 | 211,360 | 5 | 202,093 |
Municipal sales | 7,652 | 12 | 6,827 | 14,711 | 11 | 13,290 |
Total retail sales | 379,515 | 4 | 365,858 | 789,988 | 3 | 766,184 |
Contract wholesale | 154,694 | 3 | 150,659 | 316,945 | 2 | 311,997 |
Wholesale off-system | 268,174 | 26 | 212,460 | 448,337 | 12 | 400,074 |
Total electric sales | 802,383 | 10% | 728,977 | 1,555,270 | 5% | 1,478,255 |
| Three Months Ended | Three Months Ended | Six Months Ended | ||||||
| March 31, | June 30, | |||||||
|
| Percentage |
|
| Percentage |
|
| Percentage |
|
Resources | 2006 | Change | 2005 | 2006 | Change | 2005 | 2006 | Change | 2005 |
|
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Megawatt-hours generated: |
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|
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Coal | 454,133 | 4% | 435,935 | 366,821 | (14)% | 426,400 | 820,954 | (5)% | 862,300 |
Gas | 2,211 | 34 | 1,653 | 11,482 | 200 | 3,830 | 13,693 | 149 | 5,500 |
| 456,344 | 4 | 437,588 | 378,303 | (12) | 430,230 | 834,647 | (4) | 867,800 |
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Megawatt-hours purchased | 312,287 | (3) | 321,671 | 464,219 | 40 | 331,434 | 776,506 | 19 | 653,105 |
Total resources | 768,631 | 1% | 759,259 | 842,522 | 11 % | 761,664 | 1,611,153 | 6 % | 1,520,905 |
| Three Months Ended | Three Months Ended | Six Months Ended | |||
| March 31, | June 30, | ||||
| 2006 | 2005 | 2006 | 2005 | 2006 | 2005 |
Heating and cooling degree days |
|
| ||||
Heating and cooling degree days: |
|
|
| |||
Actual |
|
|
|
|
| |
Heating degree days | 2,946 | 2,990 | 710 | 933 | 3,656 | 3,923 |
Cooling degree days | 211 | 148 | 211 | 148 | ||
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Percent of normal |
|
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|
| |
Heating degree days | 90% | 91% | 71% | 94% | 85% | 91% |
Cooling degree days | 209% | 147% | 209% | 147% | ||
Three Months Ended March 31,June 30, 2006 Compared to Three Months Ended March 31,June 30, 2005. Income from operations decreased $1.0 million primarily due to increased operations and maintenance expense and fuel and purchased power costs, partially offset by increased revenues.
Electric utility revenues increased 11 percent for the three month period ended June 30, 2006, compared to the same period in the prior year. Total retail megawatt-hour sales increased 4 percent compared to the three months ended June 30, 2005. Heating degree days, which is a measure of weather trends, were 24 percent lower, and cooling degree days were 43 percent higher, than the same period in the prior year. Wholesale off-system sales increased 15 percent due to a 26 percent increase in megawatt-hours sold partially offset by a 9 percent decrease in average price received.
Electric operating expenses increased 19 percent for the three month period ended June 30, 2006, compared to the same period in the prior year. Fuel and purchased power costs increased 32 percent due to a 10 percent increase in megawatt-hours sold combined with increased cost per megawatt-hour primarily due to the impact of replacing low cost base load power with higher priced alternatives during the Wyodak plant outage. Operating expense for the three months ended June 30, 2006 was also affected by increased repairs and maintenance expense incurred for the Wyodak Plant and higher corporate allocations, partially offset by a decrease in power marketing legal costs relative to costs incurred in the second quarter of 2005 (See Notes to Condensed Financial Statements, Note 7 Legal Proceedings, for discussion of power marketing legal settlement).
Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005. Income from continuing operations increased $0.6 milliondecreased 5 percent primarily due to increased revenuesoperations and lower depreciationmaintenance expense and legalfuel and purchased power costs, partially offset by increased fuel costs and corporate allocations.revenues.
Electric utility revenues increased 27 percent for the threesix month period ended March 31,June 30, 2006, compared to the same period in the prior year. Total retail megawatt-hour sales increased 3 percent compared to the threesix months ended March 31,June 30, 2005. Heating degree days, which is a measure of weather trends, were 17 percent lower, and cooling degree days were 43 percent higher, than the same period in the prior year. Wholesale off-system sales increased 19 percent due to a 612 percent increase in average price received,megawatt-hours sold partially offset by a 43 percent decrease in megawatt-hours sold.average price received.
Electric operating expenses increased 110 percent for the threesix month period ended March 31,June 30, 2006, compared to the same period in the prior year. Fuel and purchased power costs increased 1217 percent due to a 45 percent increase in megawatt-hours generated at an 8 percentsold combined with increased cost per megawatt- hour primarily due to the impact of replacing low cost base load power with higher average cost. Megawatt-hours produced through coal-fired generation increased as we experienced an 18-day unscheduled plant outage atpriced alternatives during the Wyodak plant in the first quarter of 2005.outage. Operating expense for the threesix months ended March 31,June 30, 2006 was also affected by increased repairs and maintenance expense incurred for the Wyodak Plant maintenance and higher corporate allocations, which werepartially offset by a decrease in depreciation expense, due to a revision of depreciation rates resulting from an independent depreciation study commissioned by the Company, and a decrease in power marketing legal costs relative to costs incurred in 2005 (See Notes to Condensed Financial Statements, Note 7 Legal Proceedings, for discussion of power marketing legal settlement).
Request for Rate Increase. On June 30, 2006 we filed an application with the first quarterSouth Dakota Public Utilities Commission (SDPUC) for an electric rate increase to be effective January 1, 2007. The application requests a 9.5 percent rate increase for all customer classes. In addition, the application proposes annual energy cost adjustments. The proposed cost adjustments would require us to absorb a portion of 2005.power cost increases, depending in part on earnings on certain short-term wholesale sales of electricity. The current rate structure, in place since 1995, does not contain fuel or purchased power adjustment clauses and only provides the ability to request rate relief from energy costs in certain defined situations. We expect these increases, if approved by the SDPUC, would result in an annual revenue increase of approximately $9.5 million. South Dakota retail customers account for approximately 90 percent of our total retail revenues. A rate freeze has been in place since 1995.
12
SAFE HARBOR FOR FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described in Items 1 and 2Item 1A of our 2005 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:
• | Obtaining adequate cost recovery for our operations through regulatory proceedings; |
• | The amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock; |
• | Unfavorable rulings in the periodic applications to recover costs for fuel and purchased power; |
• | 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 repeal of the Public Utilities Holding Company Act of 1935 and other provisions of the recently enacted Energy Policy Act of 2005. |
• | Our ability to remedy any deficiencies that may be identified in the periodic review of our internal controls; |
• | The timing and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our |
• | The timing and extent of scheduled and unscheduled outages of power generation facilities; |
• | General economic and political conditions, including tax rates or policies and inflation rates; |
• | Our use of derivative financial instruments to hedge commodity, currency exchange rate and interest rate risks; |
• | The creditworthiness of counterparties to trading and other transactions, and defaults on amounts due from counterparties; |
• | The amount of collateral required to be posted from time to time in our transactions; |
• | Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment; |
• | 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 outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements; |
• | The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions and events; |
• | 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; and |
• |
13
|
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, 2006. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.
Internal Control Over Financial Reporting
During the period covered by this Quarterly Report on Form 10-Q, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
14
BLACK HILLS POWER, INC.
Part II – Other Information
Item 1. | Legal Proceedings |
For information regarding legal proceedings, see Note 10 of Notes to Consolidated Financial Statements in Item 8 of the Company’s 2005 Annual Report on Form 10-K and Note 67 of our Notes to Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 67 is incorporated by reference into this item.
Item 1A. | Risk Factors |
There have been no material changes in our Risk Factors from those reported in Item 1A. of Part I of our 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Item 6. | Exhibits |
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Exhibit 31.1 | Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002. |
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Exhibit 31.2 | Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002. |
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Exhibit 32.1 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002. |
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Exhibit 32.2 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002. |
15
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, President and |
| Chief Executive Officer |
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| /s/ Mark T. Thies |
| Mark T. Thies, Executive Vice President and |
| Chief Financial Officer |
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Dated: |
|
16
EXHIBIT INDEX
Exhibit Number | Description |
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Exhibit 31.1 | Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002. |
|
|
Exhibit 31.2 | Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002. |
|
|
Exhibit 32.1 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002. |
|
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Exhibit 32.2 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002. |
1719