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 September 30, 2001. OR ___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _______________. Commission File Number 333-52664 Black Hills Corporation Incorporated in South Dakota IRS Identification Number 46-0458824 625 Ninth Street Rapid City, South Dakota 57701 Registrant's telephone number (605)-721-1700 Former name, former address, and former fiscal year if changed since last report NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ---------- ---------- Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest practicable date. Class Outstanding at October 31, 2001 Common stock, $1.00 par value 26,510,053 shares 1
BLACK HILLS CORPORATION TABLE OF CONTENTS Page Number PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Statements of Income- 3 Three, Nine and Twelve Months Ended September 30, 2001 and 2000 Consolidated Balance Sheets- 4 September 30, 2001, December 31, 2000 and September 30, 2000 Consolidated Statements of Cash Flows- 5 Nine Months Ended September 30, 2001 and 2000 Notes to Consolidated Financial Statements 6-18 Item 2. Management's Discussion and Analysis of 19-28 Financial Condition and Results of Operations Item 3. Quantitative and Qualitative Disclosures about 28 Market Risk PART II. OTHER INFORMATION Item 1. Legal Proceedings 29 Item 2. Changes in Securities and Use of Proceeds 29 Item 6. Exhibits and Reports on Form 8-K 29-30 Signatures 31 Exhibit Index 32 2
PART 1 - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF INCOME (unaudited) <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands, except per share amounts) <S> <C> <C> <C> <C> <C> <C> Operating revenues $ 302,398 $ 453,231 $1,283,140 $1,038,191 $1,868,869 $1,255,890 --------- --------- ---------- ---------- ---------- ---------- Operating expenses: Fuel and purchased power 224,637 373,613 969,384 878,660 1,461,566 1,055,491 Operations and maintenance 15,252 13,859 43,051 31,483 59,538 40,221 Administrative and general 13,153 10,468 60,122 20,231 82,397 27,535 Depreciation, depletion and amortization 14,261 8,978 38,785 22,465 49,208 28,092 Taxes, other than income taxes 5,656 3,794 16,637 10,678 20,860 14,442 --------- --------- ---------- ----------- ---------- --------- 272,959 410,712 1,127,979 963,517 1,673,569 1,165,781 --------- --------- ---------- ----------- ---------- --------- Operating income 29,439 42,519 155,161 74,674 195,300 90,109 --------- --------- ---------- ----------- ---------- --------- Other income (expense): Interest expense (9,255) (9,608) (29,300) (19,886) (39,814) (23,917) Interest income 725 1,681 1,810 5,685 3,179 6,851 Other, net 5,453 578 10,026 (524) 13,397 573 --------- --------- ---------- ----------- ---------- --------- (3,077) (7,349) (17,464) (14,725) (23,238) (16,493) --------- --------- ---------- ----------- ---------- --------- Income before minority interest and income taxes 26,362 35,170 137,697 59,949 172,062 73,616 Minority interest 163 (10,276) (4,408) (10,211) (5,470) (9,255) Income taxes (10,159) (8,572) (49,978) (16,294) (64,042) (20,364) --------- ---------- ---------- --------- --------- --------- Net income 16,366 16,322 83,311 33,444 102,550 43,997 Preferred stock dividends (131) (37) (473) (37) (513) (37) --------- ---------- ---------- --------- --------- --------- Net income available for common stock $ 16,235 $ 16,285 $ 82,838 $ 33,407 $ 102,037 $ 43,960 ========= ========== ========== ========= ========= ========= Weighted average common shares outstanding: Basic 26,425 22,835 24,988 21,872 24,466 21,809 ========= ========== ========== ========= ========= ========= Diluted 26,802 23,067 25,404 21,977 24,896 21,926 ========= ========== ========== ========= ========= ========= Earnings per share of common stock: Basic $ 0.61 $ 0.71 $ 3.32 $ 1.53 $ 4.17 $ 2.02 ========== ========== =========== ========= ========= ========= Diluted $ 0.61 $ 0.71 $ 3.28 $ 1.52 $ 4.12 $ 2.01 ========== ========== =========== ========= ========= ========= Dividends paid per share of common stock $ 0.28 $ 0.27 $ 0.84 $ 0.81 $ 1.11 $ 1.07 ========== ========== =========== ========= ========= ========= </TABLE> The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. 3
BLACK HILLS CORPORATION CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> Unaudited Unaudited September 30 December 31 September 30 2001 2000 2000 ---- ---- ---- (in thousands, except share amounts) ASSETS <S> <C> <C> <C> Current assets: Cash and cash equivalents $ 51,735 $ 24,913 $ 12,102 Securities available-for-sale 3,770 2,113 3,493 Receivables (net of allowance for doubtful accounts of $5,226, $3,631 and $412, respectively) - Customers 115,981 278,436 174,167 Other 7,069 21,283 11,585 Materials, supplies and fuel 27,302 16,545 13,816 Prepaid expenses 9,848 7,428 6,570 Derivatives at market value 67,287 68,292 5,158 ------------ ----------- ----------- 282,992 419,010 226,891 ------------ ----------- ----------- Investments 73,909 63,965 114,204 ------------ ----------- ----------- Property and equipment 1,501,231 1,072,129 878,044 Less accumulated depreciation and depletion (312,178) (277,848) (265,226) ------------ ------------ ----------- 1,189,053 794,281 612,818 ------------ ------------ ----------- Other assets: Derivatives at market value 1,752 - - Other, principally goodwill and other intangibles 99,062 43,064 36,771 ------------ ------------ ----------- 100,814 43,064 36,771 ------------ ------------ ----------- $ 1,646,768 $1,320,320 $ 990,684 ============ ============ =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current maturities of long-term debt $ 20,513 $ 13,960 $ 7,052 Notes payable 320,037 211,679 170,775 Accounts payable 109,298 247,596 161,712 Accrued liabilities 55,850 49,661 29,736 Derivatives at market value 68,175 65,960 5,158 ------------- ------------ ----------- 573,873 588,856 374,433 ------------- ------------ ----------- Long-term debt, net of current maturities 434,993 307,092 214,714 ------------- ------------ ----------- Deferred credits and other liabilities: Derivatives at market value 1,636 - - Investment tax credits 2,168 2,530 2,653 Federal income taxes 64,629 62,679 56,961 Reclamation and regulatory liability 22,520 22,340 22,588 Other 15,002 16,516 12,583 ------------- ------------ ------------ 105,955 104,065 94,785 ------------- ------------ ------------ Minority interest in subsidiaries 25,940 37,961 35,463 ------------- ------------ ------------ Stockholders' equity: Preferred stock - no par Series 2000-A; 21,500 shares authorized Issued and Outstanding: 5,177; 4,000 and 4,000 shares, respectively 5,549 4,000 4,000 ------------- ------------ ------------ Common stock equity- Common stock $1 par value; 100,000,000 shares authorized; Issued: 26,830,267; 23,302,111 and 23,294,018 shares, respectively 26,830 23,302 23,294 Additional paid-in capital 238,506 73,442 73,276 Retained earnings 253,240 191,482 177,610 Treasury stock (8,841) (9,067) (7,460) Accumulated other comprehensive income (loss) (9,277) (813) 569 ------------- ------------ ----------- 500,458 278,346 267,289 ------------- ------------ ----------- Total stockholders' equity 506,007 282,346 271,289 ------------- ------------ ----------- $1,646,768 $1,320,320 $ 990,684 ============= ============ =========== </TABLE> The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. 4
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) <TABLE> <CAPTION> Nine Months Ended September 30 2001 2000 ---- ---- (in thousands) <S> <C> <C> Operating activities: Net income available for common stock $ 82,838 $ 33,407 Principal non-cash items- Depreciation, depletion and amortization 38,785 22,465 Deferred income taxes and investment tax credits 1,588 1,309 Undistributed earnings of affiliates (8,580) (4,131) Minority interest 4,408 10,211 Change in operating assets and liabilities- Accounts receivable and other current assets 161,755 (96,766) Accounts payable and other current liabilities (132,109) 79,846 Derivative fair value (10,919) - Other, net 2,896 (5,242) --------- --------- 140,662 41,099 --------- --------- Investing activities: Property additions (442,152) (95,891) (Increase) decrease in investments 374 (10,181) Payment for acquisition of net assets, net of cash acquired (10,410) - Payment for intangible assets, including goodwill (50,413) - Available-for-sale securities sold - 7,587 --------- --------- (502,601) (98,485) --------- --------- Financing activities: Dividends paid (20,752) (18,036) Treasury stock sold, net 226 570 Common stock issued 167,980 3,680 Increase in short-term borrowings 108,358 8,507 Long-term debt - issuance 145,649 61,075 Long-term debt - repayments (11,195) (1,339) Subsidiary distributions to minority interests (1,505) (1,451) --------- --------- 388,761 53,006 --------- --------- Increase (decrease) in cash and cash equivalents 26,822 (4,380) Cash and cash equivalents: Beginning of period 24,913 16,482 --------- --------- End of period $ 51,735 $ 12,102 ========= ========= Supplemental disclosure of cash flow information: Cash paid during the period for- Interest $ 28,776 $20,927 Income taxes $ 34,800 $12,118 Non-cash net assets acquired through issuance of common and preferred stock $ 3,628 $34,493 </TABLE> The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. 5
BLACK HILLS CORPORATION Notes to Consolidated Financial Statements (unaudited) (Reference is made to Notes to Consolidated Financial Statements included in the Company's 2000 Annual Report on Form 10-K) (1) MANAGEMENT'S STATEMENT The financial statements included herein have been prepared by Black Hills Corporation (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 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 2000 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 September 30, 2001, December 31, 2000 and September 30, 2000, financial information and are of a normal recurring nature. The results of operations for the three, nine and twelve months ended September 30, 2001, are not necessarily indicative of the results to be expected for the full year. (2) RECLASSIFICATIONS Certain 2000 amounts in the financial statements have been reclassified to conform to the 2001 presentation. These reclassifications did not have an effect on the Company's stockholders' equity or results of operations as previously reported. (3) NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS 141) and No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting. Under SFAS 142, goodwill and intangible assets with indefinite lives are no longer amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Intangible assets with a defined life will continue to be amortized over their useful lives (but with no maximum life). The amortization provisions of SFAS 142 apply to goodwill and intangible assets acquired after June 30, 2001. With respect to goodwill and intangible assets acquired prior to July 1, 2001, the Company is required to adopt SFAS 142 effective January 1, 2002. Management is currently evaluating the effect that adoption of the provisions of SFAS 142 that are effective January 1, 2002 will have on the Company's consolidated financial statements. 6
In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement costs being capitalized as part of the carrying amount of the long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Management expects to adopt SFAS No. 143 effective January 1, 2003 and is currently evaluating the effects adoption will have on the Company's consolidated financial statements. In August 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144 supersedes FASB Statement 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121) and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to SFAS No. 121. Management expects to adopt SFAS No. 144 effective January 1, 2002 and is currently evaluating the effects adoption will have on the Company's consolidated financial statements. (4) CHANGE IN ACCOUNTING PRINCIPLE In June 1998, the FASB issued SFAS No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities." SFAS 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS 133 allows special hedge accounting for fair value and cash flow hedges. SFAS 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS 133 requires that on date of initial adoption, an entity shall recognize all freestanding derivative instruments in the balance sheet as either assets or liabilities and measure them at fair value. The difference between a derivative's previous carrying amount and its fair value shall be reported as a transition adjustment. The transition adjustment resulting from adopting this Statement shall be reported in net income or other comprehensive income, as appropriate, as the effect of a change in accounting principle in accordance with paragraph 20 of Accounting Principles Board Opinion No. 20 (APB 20), "Accounting Changes." 7
On January 1, 2001, the Company adopted SFAS 133. The Company had certain non-trading energy contracts and interest rate swaps documented as cash flow hedges, which upon adoption resulted in a decrease to accumulated other comprehensive income of $10.1 million. Upon adoption of SFAS 133, most of the Company's energy trading activities previously accounted for under Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) fell under the purview of SFAS 133. The effect from this adoption on the energy trading companies and energy trading activities was not material because, unless otherwise noted, the trading companies do not designate their energy trading activities as hedge instruments. This "no hedge" designation results in these derivatives being measured at fair value and gains and losses recognized currently in earnings. This treatment under SFAS 133 is comparable to the accounting under EITF 98-10. (5) CHANGES IN LONG-TERM DEBT AND NOTES PAYABLE Long-term Debt In conjunction with the closing of the Fountain Valley acquisition (Note 11), the Company issued long-term non-recourse project level financing. The debt matures July 1, 2006, has a floating interest rate (4.96 percent at September 30, 2001), and is collateralized by a mortgage on the project's land and facilities, leases and rights, including rights to receive payments under long-term purchase power contracts. Notes Payable During the second quarter of 2001, the Company used net proceeds from its common stock offering (Note 10) to pay down approximately $163 million of its borrowings under short-term credit facilities. In addition, during the third quarter of 2001, the Company completed a $400 million revolving credit facility. The facility replaces the Company's previous short-term credit lines, which totaled $290 million. The credit facility was arranged by ABN Amro Bank N.V., US Bank, N.A. and Union Bank of California, N.A., with ten other banks participating. The facility consists of two $200 million tranches, one of which has a 364-day term and the other a three-year term. Outstanding borrowings under the Company's short-term credit facilities have been used primarily to fund the acquisition and construction of the Las Vegas co-generation facility (Note 11), construction costs on other power generation projects and the continued network build-out in its communications segment. Other than the above transactions, the Company had no other material changes in its consolidated indebtedness, as reported in Notes 6 and 7 of the Company's 2000 Annual Report on Form 10-K. 8
(6) COMPREHENSIVE INCOME The following table presents the components of the Company's comprehensive income: <TABLE> <CAPTION> Three Months Nine Months Twelve Months Ended Ended Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) <S> <C> <C> <C> <C> <C> <C> Net income available for common stock $16,235 $16,285 $82,838 $33,407 $102,037 $43,960 Other comprehensive income: Unrealized gain (loss) on available- for-sale securities 507 81 1,657 569 275 569 Initial impact of adoption of SFAS 133, net of minority interest - - (7,518) - (7,518) - Fair value adjustment on derivatives designated as cash flow hedges, net of minority interest (5,173) - (2,603) - (2,603) - -------- -------- -------- -------- -------- ------- Comprehensive income $11,569 $16,366 $74,374 $33,976 $92,191 $44,529 ======== ======== ======== ======== ======== ======= </TABLE> (7) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of September 30, 2001, substantially all of the Company's operations and assets are located within the United States. The Company's operations are conducted through six business segments that include: Electric group and segment, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; Independent Energy group consisting of the following segments: Mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; Oil and Gas, which produces, explores and operates oil and gas interests located in the Rocky Mountain region, Texas, California and other states; Fuel Marketing, which markets natural gas, oil, coal and related services to customers in the East Coast, Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions markets; Independent Power, which produces and sells electricity in a number of markets, with strong emphasis in the western United States; and Communications group and Others, which primarily markets communications and software development services. Segment information follows the same accounting policies as described in Note 1 of the Company's 2000 Annual Report on Form 10-K. In accordance with the provisions of SFAS No. 71, intercompany coal sales are not eliminated. Segment information included in the accompanying Consolidated Balance Sheets and Consolidated Statements of 9
Income is as follows (in thousands): <TABLE> <CAPTION> External Inter-segment Operating Revenues Operating Revenues Net Income (loss) Quarter to Date September 30, 2001 <S> <C> <C> <C> Electric $ 43,057 $ 461 $ 7,914 Mining 4,023 2,847 3,779 Oil and gas 7,750 746 2,804 Fuel marketing 216,448 3,262 3,898 Independent power 23,119 - 1,246 Communications and others 5,154 1,090 (3,275) Intersegment eliminations - (5,559) - -------- ------- ------- Total $299,551 $2,847 $16,366 ======== ====== ======= External Inter-segment Operating Revenues Operating Revenues Net Income (loss) Quarter to Date September 30, 2000 Electric $ 48,607 $ - $10,060 Mining 5,740 2,796 2,375 Oil and gas 5,259 - 1,634 Fuel marketing 361,111 - 2,319 Independent power 27,155 - 2,878 Communications and others 2,563 904 (2,944) Intersegment eliminations - (904) - -------- ------ ------- Total $450,435 $2,796 $16,322 ======== ====== ======= External Inter-segment Operating Revenues Operating Revenues Net Income (loss) Year to Date September 30, 2001 Electric $ 174,915 $ 783 $41,878 Mining 14,681 8,333 8,055 Oil and gas 24,583 1,770 8,723 Fuel marketing 980,828 16,256 31,252 Independent power 66,138 - 3,827 Communications and others 13,662 3,307 (10,424) Intersegment eliminations - (22,116) - ---------- -------- ------- Total $1,274,807 $ 8,333 $83,311 ========== ======== ======= </TABLE> 10
<TABLE> <CAPTION> External Inter-segment Operating Revenues Operating Revenues Net Income (loss) Year to Date September 30, 2000 <S> <C> <C> <C> Electric $ 117,805 $ - $24,352 Mining 14,800 7,649 6,179 Oil and gas 13,493 - 3,750 Fuel marketing 852,625 - 3,482 Independent power 27,397 - 3,008 Communications and others 4,422 2,762 (7,327) Intersegment eliminations - (2,762) - ---------- ------ ------- Total $1,030,542 $7,649 $33,444 ========== ====== ======= External Inter-segment Operating Revenues Operating Revenues Net Income (loss) 12 Months Ended September 30, 2001 Electric $ 230,419 $ 783 $ 54,593 Mining 20,761 10,334 8,579 Oil and gas 30,274 2,915 9,953 Fuel marketing 1,481,994 29,574 41,625 Independent power 78,156 329 4,062 Communications and others 16,929 4,228 (16,262) Intersegment eliminations - (37,827) - ---------- ------- -------- Total $1,858,533 $10,336 $102,550 ========== ======= ======== External Inter-segment Operating Revenues Operating Revenues Net Income (loss) 12 Months Ended September 30, 2000 Electric $ 150,796 $ - $31,651 Mining 22,706 8,006 8,145 Oil and gas 17,148 - 4,797 Fuel marketing 1,025,137 - 4,553 Independent power 27,397 - 2,992 Communications and others 4,700 3,736 (8,141) Intersegment eliminations - (3,736) - ---------- ------ ------- Total $1,247,884 $8,006 $43,997 ========== ====== ======= </TABLE> 11
Other than the following transactions the Company had no other material changes in total assets of its reporting segments, as reported in Note 13 of the Company's 2000 Annual Report on Form 10-K, beyond changes resulting from normal operating activities. o As part of the Company's reorganization plan associated with the new "holding company" structure effected in the fourth quarter of 2000, the Company transferred ownership interest in Wyodak Resources Development Corp. between its wholly-owned subsidiaries Black Hills Power and Black Hills Energy Ventures. This transaction had the effect of reducing the "Electric" reporting segment's total assets by approximately $89.6 million. Black Hills Energy Ventures is an "intermediate level" holding company and is not included in a reporting segment. o As part of the Company obtaining a new corporate revolving line-of-credit (Note 5), certain segments' total assets were realigned as a result of certain intercompany short-term borrowings previously held at the subsidiary level now being held at the "holding company" level. o The Independent Power segment had additions to its power generation assets of approximately $430 million, primarily related to the acquisition and construction of the Fountain Valley and Las Vegas Co-generation facilities, expansion of the Valmont and Arapahoe facilities and construction of the Wyoming combustion turbine. o The Oil and Gas segment had additions to its oil and gas properties of approximately $22 million related to its acquisition of Stewart Petroleum and developmental drilling. o The Communications segment had additions to its communications plant of approximately $19 million related to its continued network build-out. (8) LEGAL PROCEEDINGS On April 3, 2001, the Company reached a settlement of ongoing litigation with PacifiCorp filed in the United States District Court, District of Wyoming, (File No. 00CV-155B). The litigation concerned the parties' rights and obligations under the Further Restated and Amended Coal Supply Agreement dated May 5, 1987, under which PacifiCorp purchased coal from the Company's coal mine to meet the coal requirements of the Wyodak Power Plant. The Settlement Agreement provided for the dismissal of the litigation, with prejudice, coupled with the execution of several new coal-related agreements between the parties discussed below. The Company believes the value of the Settlement Agreements is equal to the net present value of the litigated Further Restated and Amended Coal Supply Agreement. New Restated and Amended Coal Supply Agreement: Effective January 1, 2001, the parties agreed to terminate the Further Restated and Amended Coal Supply Agreement, and replace it with the New Restated and Amended Coal Supply Agreement (New Agreement). The New Agreement begins on January 1, 2001, and extends to December 31, 2022. Under the New Agreement, the Company received an extension of sales beyond the June 8, 2013 term of the former Coal Supply Agreement. PacifiCorp will receive a price reduction for each ton of coal purchased. The minimum purchase obligation under the New Agreement increased to 1,500,000 tons of coal for each calendar year of the contract term, subject to adjustment for planned outages. The New Agreement further provides for a special one- 12
time payment by PacifiCorp in the amount of $7.3 million, which was received in August, 2001. This payment primarily relates to disputed billings under the previous agreement and a value transfer premium. Of this payment, $5.6 million was recognized currently in non-operating income, $1.0 million was previously recognized in revenues and the remaining $0.7 million is being recognized as sales are made under the New Agreement. Coal Option Agreement: The term of this agreement began October 1, 2001, and extends until December 31, 2010. The agreement provides that PacifiCorp shall purchase 1,400,000 tons of coal during the period of October 1, 2001 through December 31, 2002, and 1,000,000 tons of coal in 2003 at a fixed price. The agreement further provides the Company with a "put" option for 2002 and 2003 under which the Company may put to PacifiCorp up to 500,000 tons of coal from the Wyodak Mine at a market based price. For each calendar year from January 1, 2004 through 2010, the put option is increased to a maximum of 1,000,000 tons at a market based price. The "put" tonnages will be reduced or offset for quantities of K-Fuel purchased by PacifiCorp under the KFx Facility Output Agreement. Additionally, for each calendar year during which the Company is selling to PacifiCorp K-Fuel under the KFx Facility Output Agreement described below, and in which the Company has not exercised its "put" option, PacifiCorp may elect to purchase an equal amount of tonnage from the Company's coal reserves to use in a 50/50 blend with the K-Fuel, up to 500,000 tons per year in 2002 through 2007 at a market based price with a fixed floor. Asset Option Agreement: This agreement provides PacifiCorp an option to purchase a 10% interest in the KFx facility or the legal entity that owns the KFx facility at a market based price. The agreement also provides PacifiCorp an option to sell to the Company PacifiCorp's interest in the "In Pit" conveyor system currently owned by PacifiCorp and utilized at the Wyodak Mine at a fixed price. If PacifiCorp exercises its option to sell to the Company the "In Pit" system, the Company has a corresponding right to put to PacifiCorp the "North Conveyor System," which serves as the backup coal delivery system for the Wyodak Power Plant at a fixed price. In October 2001 both parties exercised their respective options. KFx Facility Output Agreement: The KFx plant is a coal enhancement facility the Company owns located near its Wyodak Coal Mine. The KFx plant was built to produce an enhanced coal known as "K-Fuel." Assuming the plant becomes operational, PacifiCorp agrees to purchase K-Fuel for a term beginning January 1, 2002, and extending to December 31, 2007. If the plant is not operational on or before December 31, 2003, the agreement will become void. Under this agreement, PacifiCorp agrees to purchase the output of K-Fuel from the KFx plant, up to a maximum of 500,000 tons for each calendar year from 2002 through 2007 at fixed price with market based escalation. Wyodak reserves the right to sell up to a total of 100,000 tons from the output of the KFx plant to other customers during the same time period. (9) PRICE RISK MANAGEMENT The Company is exposed to market risk stemming from changes in commodity prices. These changes could cause fluctuations in the Company's earnings and cash flows. In the normal course of business, the Company actively manages its exposure to these market risks by entering into various hedging transactions. The hedging transactions are 13
authorized under the Company's Risk Management Policies and Procedures that place clear controls on these activities. Hedging transactions involve the use of a variety of derivative financial instruments. The Company accounts for all energy trading activities at fair value as of the balance sheet date and recognizes currently the net gains or losses resulting from the revaluation of these contracts to fair value in its results of operations. As a result, substantially all of the energy trading activities of the Company's gas marketing, crude oil marketing, and coal marketing operations are accounted for under fair value accounting methodology as prescribed in SFAS 133 or EITF 98-10. Energy Trading Activities The Company, through its independent energy business group, utilizes financial instruments for its fuel marketing services. These financial instruments include fixed-for-float swap financial instruments, basis swap financial instruments and costless collars traded in the over-the-counter financial markets. These derivatives are not held for speculative purposes but rather serve to hedge the Company's exposure related to commodity purchases or sales commitments. Under SFAS 133 and EITF 98-10, these transactions qualify as derivatives or energy trading activities that must be accounted for at fair value. As such, realized and unrealized gains and losses are recorded as a component of income. Because the Company does not, as a policy, permit speculation with "open" positions, substantially all of its trading activities are back-to-back positions where a commitment to buy/(sell) a commodity is matched with a committed sale/(buy) or financial instrument. The quantities and maximum terms of derivative financial instruments held for trading purposes at September 30, 2001, December 31, 2000 and September 30, 2000 are as follows: <TABLE> <CAPTION> Max. Term September 30, 2001 Volume Covered (Years) ------------------ -------------- ------- (MMBtus) <S> <C> <C> Natural gas basis swaps purchased 17,449,482 2 Natural gas basis swaps sold 18,940,000 2 Natural gas fixed-for-float swaps purchased 13,101,810 1 Natural gas fixed-for-float swaps sold 13,278,943 1 Natural gas swing swaps purchased 2,635,000 1 Natural gas swing swaps sold 3,410,000 1 (Tons) Coal tons sold 961,046 1 Coal tons purchased 1,074,046 1 Max. Term September 30, 2000 Volume Covered (Years) ------------------ -------------- ------- (MMBtus) Natural gas basis swaps purchased 33,644,595 2 Natural gas basis swaps sold 30,954,871 2 Natural gas fixed-for-float swaps purchased 8,379,581 1 Natural gas fixed-for-float swaps sold 9,817,438 1 </TABLE> 14
<TABLE> <CAPTION> Max. Term December 31, 2000 Volume Covered (Years) ----------------- -------------- ------- (MMBtus) <S> <C> <C> Natural gas basis swaps purchased 25,577,894 2 Natural gas basis swaps sold 26,059,621 2 Natural gas fixed-for-float swaps purchased 6,476,222 1 Natural gas fixed-for-float swaps sold 7,360,560 1 (Tons) Coal tons sold 988,000 1 Coal tons purchased 896,000 1 </TABLE> As required under SFAS 133 and EITF 98-10, derivatives and energy trading activities were marked to fair value on September 30, 2001, and the gains and losses recognized in earnings. The amounts related to the accompanying consolidated balance sheet and income statement as of and for the three, nine and twelve month periods ended September 30, 2001 are as follows (in thousands): <TABLE> <CAPTION> Three Nine Twelve Month Month Month Instrument Asset Liability Gain (Loss) Gain (Loss) Gain (Loss) - ---------- ----- --------- ------------ ----------- ----------- <S> <C> <C> <C> <C> <C> Natural gas basis swaps $ 9,849 $10,283 $3,130 $10,138 $2,345 Natural gas fixed-for-float swaps 20,517 26,738 120 (3,728) (4,721) Natural gas physical 16,384 4,078 (2,854) (1,657) 5,822 Coal transactions 4,904 3,636 (587) 359 1,269 Crude oil transactions 6,148 5,393 77 232 755 -------- ------- ------ ------- ------ Totals $57,802 $50,128 $ (114) $ 5,344 $5,470 ======== ======= ====== ======= ====== </TABLE> There were no significant differences between the fair values of derivative assets and liabilities at September 30, 2000. Non-trading Energy Activities To reduce risk from fluctuations in the price of crude oil and natural gas, the Company enters into swaps and costless collar transactions. The transactions are used to hedge price risk from sales of the Company's forecasted crude oil and natural gas production. For such transactions, the Company elects hedge accounting as allowed under SFAS 133. At September 30, 2001, the Company had fixed-for-float swaps and costless collars to hedge portions of its crude oil and natural gas production. These transactions were identified as cash flow hedges, properly documented, and effectiveness testing established. At quarter-end, the hedges met the effectiveness testing criteria and retained their cash flow hedge status. The crude oil hedges recorded ineffectiveness due to basis 15
risk and time value. The effective portion of the gain or loss on these derivatives is reported in other comprehensive income and the ineffective portion is reported in earnings. At September 30, 2001, the Company had fixed-for-float swaps for 17,000 barrels of crude oil per month through December of 2001 with a net fair value of $0.1 million and 10,000 barrels of crude oil per month for January through September of 2002 with a net fair value of $0.2 million. The Company had costless collars (purchased put - sold call) for 10,000 barrels of crude oil per month for 2001 with a net fair value of $0.1 million. In addition, the Company hedged a portion of its forecasted 2001 and 2002 natural gas production with fixed-for-float swaps. At September 30, 2001, these natural gas swaps were for 1,676,000 MMBtus (4,232 MMBtus per day through October 2002) with a net fair value of $2.3 million. The effective portion of the gains and losses on these derivatives was recorded in other comprehensive income. At September 30, 2001, accumulated other comprehensive income for all non-trading energy swaps and options was $2.6 million. Derivative fair value gains and losses are recorded in other comprehensive income for the effective portion of the hedge and in earnings for the ineffective portion. The ineffective portion includes both time value and basis risk. The net gain recognized in earnings prior to actual cash settlement was immaterial. The Company acquired several fixed-for-float swaps as part of the Las Vegas Co-generation acquisition (Note 11) completed on August 31, 2001. These swaps fixed the price for an index price gas purchase agreement. The swaps hedge the natural gas purchase price for 5,000 Mmbtus per day through April 30, 2010. The fair value of these swaps at acquisition closing was $8.6 million. At acquisition closing, the swaps were designated as cash flow hedges, properly documented, and effectiveness testing established. The critical terms of the hedge match the critical terms of the hedged item so no ineffectiveness can be expected. At quarter-end, the hedges met effectiveness testing and retained their cash flow hedge status. At September 30, 2001, the change in fair value of the swaps was not significant. No adjustments were made to the fair value of the derivative instrument on the balance sheet, no adjustments were made to other comprehensive income, and no earnings impact was recorded. Financing Activities To reduce risk from fluctuations in interest rates, the Company enters into interest rate swap transactions. These transactions are used to hedge interest rate risk for variable rate debt financing. For such transactions, the Company elects hedge accounting as allowed under SFAS 133. These transactions were identified as cash flow hedges, properly documented, and effectiveness testing established. At quarter-end, these hedges met effectiveness testing criteria and retained their cash flow hedge status. At September 30, 2001, the Company had interest rate swaps with an average balance notional amount of $381.1 million, having a maximum term of ten years and a fair value of $(16.9) million. Because these hedges are fully effective (no time value or basis risk), the entire derivative fair value is recorded in 16
accumulated other comprehensive income. At September 30, 2001, the Company had $618.0 million of outstanding, floating-rate debt of which $224.0 million was not offset with interest rate swap transactions that effectively convert the debt to a fixed rate. Credit Risk In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. While the Company has not experienced significant losses due to the credit risk associated with these arrangements, the Company has off-balance sheet risk to the extent that the counterparties to these transactions may fail to perform as required by the terms of each such contract. (10) COMMON STOCK OFFERING During the first quarter of 2001, the Company announced the public offering of 3 million shares of common stock with an option for the underwriters to purchase 450,000 additional shares. Credit Suisse First Boston, Lehman Brothers, CIBC World Markets and UBS Warburg acted as the managers of the underwriting syndicate. Early in the second quarter of 2001 the Company announced the offering price was set at $52 per share and all 3 million shares were sold with the underwriters exercising their over-allotment option to purchase an additional 383,000 shares. Net proceeds were approximately $163 million after commissions and expenses. The proceeds were used to repay a portion of current indebtedness under revolving credit facilities, to fund various power plant construction costs and for general corporate purposes. (11) ACQUISITIONS In the second quarter of 2001, the Company's independent power subsidiary, Black Hills Energy Capital, closed on the purchase of the Fountain Valley facility, a 240 megawatt generation facility located near Colorado Springs, Colorado, featuring six LM-6000 simple-cycle, gas-fired turbines. The facility came on-line mid third quarter of 2001. The facility was purchased from Enron Corporation. Total cost of the project is approximately $183 million and has been financed primarily with non-recourse financing from Union Bank of California. The Company has obtained an 11-year contract with Public Service of Colorado to utilize the facility for peaking purposes. The contract is a tolling arrangement in which the Company assumes no fuel risk. On August 31, 2001, Black Hills Energy Capital closed on the purchase of a 273 MW gas-fired co-generation power plant project located in North Las Vegas, Nevada from Enron North America, a wholly-owned subsidiary of Enron Corporation. The facility currently has a 51 MW co-generation power plant in operation. Most of the power from that facility is under a long-term contract expiring in 2024. The Company has sold 50% of this power plant to another party, however, under generally accepted accounting principles the Company is required to consolidate 100% of this plant. The project also has a 222 MW combined- cycle expansion under way, which is 100%-owned by the Company. The facility is scheduled to be fully operational in the third quarter of 2002 and will utilize LM-6000 17
technology. The power of the expansion is also under a long-term contract which expires in 2017. This contract for the expansion requires the purchaser to provide fuel to the power plant when it is dispatched. The cost for the entire facility is expected to be approximately $330 million and the Company is in the process of obtaining long-term financing, which is expected to be primarily non- recourse project debt. The acquisition has been accounted for under the purchase method of accounting and, accordingly, the purchase price of approximately $205 million has been allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and the liabilities assumed as of the date of acquisition. Fair values in the allocation include assets acquired of approximately $157 million (excluding goodwill and other intangibles) and liabilities assumed of approximately $2 million. The estimated purchase price allocations are subject to adjustment, generally within one year of the date of the acquisition. Should new or additional facts about the acquisitions become available within one year of the date of acquisition, any changes to the preliminary estimates will be reflected as an adjustment to goodwill. The purchase price and related acquisition costs exceeded the fair values assigned to net tangible assets by approximately $50 million, which was recorded as long-lived intangible assets and goodwill. Operating activities of the acquired company have been included in the accompanying consolidated financial statements since the acquisition date. 18
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS We are a growth oriented, diversified energy holding company operating principally in the United States. Our regulated and unregulated businesses have expanded significantly in recent years. Our independent energy group produces and markets power and fuel. We produce and sell electricity in a number of markets, with a strong emphasis in the western United States. We also produce coal, natural gas and crude oil primarily in the Rocky Mountain region and market fuel products nationwide. We also own Black Hills Power, Inc., an electric utility serving approximately 59,400 customers in South Dakota, Wyoming and Montana. Our communications group offers state-of-the-art broadband communications services to residential and business customers in Rapid City and the northern Black Hills region of South Dakota. The following discussion should be read in conjunction with Item 7. - Management's Discussion and Analysis of Financial Condition and Results of Operations - included in our 2000 Annual Report on Form 10-K filed with the Securities and Exchange Commission. Our business and industry outlooks as disclosed in that filing continue to be consistent with management's current expectations and assessments. Unless the context otherwise requires, references in this Form 10-Q to the "Company", "we", "us" and "our" refer to Black Hills Corporation and all of its subsidiaries collectively. Results of Operations Consolidated Results Consolidated earnings for the three month period ended September 30, 2001 were $16.2 million or $0.61 per share compared to $16.3 million or $0.71 per share in the same period of the prior year. Consolidated earnings for the nine month periods ended September 30, 2001 and 2000 were $82.8 million or $3.28 per share and $33.4 million, or $1.52 per share respectively, and consolidated earnings for the twelve month period ended September 30, 2001 were $102.0 million or $4.12 per share compared to $44.0 million or $2.01 per share for the same period of the prior year. Consolidated earnings were level for the three month period ended September 30, 2001 compared to the same period in 2000. Financial results reflect the substantial price decreases and reduction in demand experienced in energy markets over the summer of 2001. The Company experienced record natural gas and oil production and strong natural gas marketing volumes sold during the third quarter of 2001. In addition, coal production increased and independent power capacity increased significantly. Earnings for the Independent Energy business group increased 29 percent over the same period in 2000 offset by a decrease in the electric utility's earnings related to a significant decrease in prices received for off-system sales and continued losses in the Communications business group. Independent Energy business group's earnings included a $3.4 million after-tax gain related to a coal contract settlement, partially offset by additional liabilities accrued for mining expenses. Increases in consolidated earnings for the nine and twelve month periods ended September 30, 2001 were primarily driven by continued strong performance in our wholesale natural gas marketing business and increased off-system wholesale electricity sales. Strong results in our independent energy business group and electric utility business group were partially offset by losses in our Communications group. 19
Unusual energy market conditions stemming primarily from gas and electricity shortages in the West contributed to our strong financial performance in the last half of 2000 and the first half of 2001. We estimated that approximately $0.40 of the reported $2.37 earnings per share in calendar year 2000 (including approximately $0.10 in the third quarter of 2000) and more than half of the reported $2.71 earnings per share for the six months ended June 30, 2001 could be attributed to high prices of natural gas and electricity and high gas trading margins. Energy prices decreased substantially beginning in June 2001, which has resulted in an earnings stream returning to a pattern which is more consistent with our longer-term baseline growth performance. Certain energy markets in which we are active have continued to experience extreme volatility. Our fuel production, fuel marketing and power sales exposure in these markets is primarily indirect through sales to credit-worthy counterparties, including neighboring utilities and gas and power marketing firms. Consolidated revenues for the three, nine and twelve month periods ended September 30, 2001 were $302.4 million, $1.3 billion and $1.9 billion, respectively. Revenues for the same periods ended September 30, 2000 were $453.2 million, $1.0 billion and $1.3 billion, respectively. The growth in revenues for the nine and twelve month periods ended September 30, 2001 was a result of high energy commodity prices through May 2001 and increased volumes of fuel marketed, primarily as a result of extreme price volatility in the western markets, acquisitions and growth in the independent energy business group and increases in off-system sales by our electric utility. The significant decrease in energy commodity prices was the primary reason for the decline in revenues for the quarter ended September 30, 2001 compared to the same quarter in 2000. Consolidated operating expenses decreased significantly during the three month period ended September 30, 2001 compared to the same quarter in 2000 due to significant decreases in purchased power costs and fuel costs related to the operation of our combustion turbines. Consolidated operating expenses have increased significantly during the nine and twelve month periods ended September 30, 2001, primarily due to significant increases in fuel costs associated with operation of our combustion turbines and purchased power costs related to excess capacity being sold to western markets. In addition, there were significant cost increases related to the operating costs of acquired and expanded businesses, increased employee costs for growing operations and higher commissions related to performance levels in our fuel marketing and wholesale energy businesses. Revenue and net income (loss) provided by each business group as a percentage of our total revenue and net income were as follows: <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- Revenues <S> <C> <C> <C> <C> <C> <C> Independent energy 84% 89% 85% 88% 87% 88% Electric utility 14 11 14 12 12 12 Communications 2 - 1 - 1 - ---- --- --- --- --- --- 100% 100% 100% 100% 100% 100% === === === === === === </TABLE> 20
<TABLE> <CAPTION> Net Income/(Loss) <S> <C> <C> <C> <C> <C> <C> Independent energy 72% 56% 62% 49% 63% 47% Electric utility 48 62 50 73 53 72 Communications and other (20) (18) (12) (22) (16) (19) --- --- --- --- --- --- 100% 100% 100% 100% 100% 100% === === === === === === </TABLE> We expect that earnings growth from the independent energy group over the next few years will be driven primarily by our continued expansion in the independent power production segment. We also believe that strength in commodity prices and increased volumes produced and marketed will provide the opportunity for strong results in our fuel marketing and oil and gas production operations. Our electric utility has continued to produce modest growth in revenue and earnings from the retail business over the past two years. We believe that this trend is stable and that, absent unplanned system outages, it will continue for the next several years due to the extension of our electric utility's rate freeze until January 1, 2005. The share of the utility's future earnings generated from wholesale off-system sales will depend on many factors, including native load growth, plant availability and commodity prices in available markets. Although our communications business continues to significantly increase residential and business customers, losses are expected to continue as the group proceeds with completing the network and increasing the customer base. Net income is expected to be achieved by 2004. We estimate net losses in 2001 of approximately $12 million. The following business group and segment information does not include intercompany eliminations: Independent Energy Group <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) <S> <C> <C> <C> <C> <C> <C> Revenue $ 258,195 $ 402,061 $1,112,589 $915,964 $1,654,337 $1,100,394 Expenses 239,972 375,323 1,018,886 878,798 1,536,752 1,059,044 --------- --------- ---------- -------- ---------- ---------- Operating income $ 18,223 $ 26,738 $ 93,703 $ 37,166 $ 117,585 $ 41,350 Net income $ 11,901 $ 9,206 $ 52,030 $ 16,419 $ 64,391 $ 20,487 EBITDA* $ 32,033 $ 20,559 $ 118,937 $ 33,843 $ 149,774 $ 40,495 </TABLE> *EBITDA represents earnings before interest, income taxes, depreciation and amortization. EBITDA is used by management and some investors as an indicator of a company's historical ability to service debt. Management believes that an increase in EBITDA is an indicator of improved ability to service existing debt, to sustain potential future increases in debt and to satisfy capital requirements. However, EBITDA is not intended to represent cash flows for the period, nor has it been presented as an alternative to either operating income, or as an indicator of operating performance or cash flows from operating, investing and financing activities, as determined by accounting principles generally accepted in the United States. EBITDA as presented may not be comparable to other similarly titled measures of other companies. 21
The following table provides a summary of certain operating statistics of our independent energy group: <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> <C> Fuel production: Tons of coal sold 872,900 838,200 2,465,700 2,216,900 3,299,000 3,015,000 Mcf equivalent sales 2,033,000 1,320,700 5,309,000 3,698,000 6,888,600 4,895,000 Average price per barrel of oil sold (including hedge transactions) $24.35 $22.53 $24.55 $21.35 $24.10 $20.17 Average price per Mcf of natural gas sold (including hedge transactions) $ 3.28 $ 2.76 $ 4.48 $ 2.44 $ 4.29 $ 2.38 Fuel marketing average daily volumes: Natural gas - MMBtus 1,062,600 903,000 947,900 787,300 981,000 763,600 Crude oil - barrels 35,100 45,000 37,000 45,000 38,400 33,300 Coal - tons 5,600 2,700 6,000 4,400 5,500 4,300 </TABLE> Earnings from the Independent Energy business group increased from 2000 amounts by $2.7 million, or $0.10 per share, and $35.6 million, or $1.40 per share, and $43.9 million, or $1.76 per share, for the three, nine and twelve month periods ended September 30, 2001, respectively. Natural gas volumes marketed increased significantly for the three, nine and twelve month periods, compared to the same periods of the previous year, while margins in the three month period returned to levels approximating historical trends. Gas and oil production had significant increases in volumes sold for the respective periods, and moderate increases in natural gas and oil prices. Coal mining results increased due to a recent coal contract settlement and increased tonnage sold, offset partially by lower average prices. Independent power operations added over 300 MW in the third quarter and has approximately 400 MW under construction. Independent power operations were affected by lower power prices in the West and lower-than-normal water flows at hydro power plants in New York. The group's non-operating income for the quarter increased over the previous year due to a portion of the coal mining subsidiaries recent coal contract settlement that was recorded in non-operating income and lower charges for minority interest in consolidated subsidiaries as a result of decreased earnings from these subsidiaries and the Company's buy-out of certain minority interest. In addition, the increase in the twelve-month period was aided by the sale of our ownership interest in a power fund management company, which resulted in a $3.7 million pre-tax gain. 22
Coal Mining Segment <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) <S> <C> <C> <C> <C> <C> <C> Revenue $6,870 $8,536 $23,014 $22,449 $31,095 $30,712 Operating income $ 830 $3,223 $ 5,664 $ 8,426 $ 6,033 $11,659 Net income $3,779 $2,375 $ 8,055 $ 6,179 $ 8,579 $ 8,145 EBITDA $7,184 $3,839 $13,891 $10,114 $14,792 $12,695 </TABLE> Earnings for the three, nine and twelve month periods increased over the prior year's periods, primarily as a result of a $3.4 million after-tax gain related to a coal contract settlement with PacifiCorp, partially offset by additional liabilities accrued for mining expenses. In addition, lower average prices received were partially offset by moderate increases in production volumes. Oil and Gas Segment <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) <S> <C> <C> <C> <C> <C> <C> Revenue $8,496 $5,259 $26,353 $13,493 $33,189 $17,148 Operating income $4,035 $2,396 $12,929 $ 5,448 $15,387 $ 7,106 Net income $2,804 $1,634 $ 8,723 $ 3,750 $ 9,953 $ 4,797 EBITDA $5,723 $3,197 $18,328 $ 7,717 $22,605 $ 9,739 </TABLE> Earnings of the oil and gas production business segment increased for the three, nine and twelve month periods due to increases in gas volumes sold of 61 percent, 50 percent and 51 percent, respectively, while average gas prices realized after hedged transactions were 19 percent, 84 percent and 80 percent higher than the same periods in the prior year, respectively. Barrels of oil sold increased 43 percent, 34 percent and 26 percent for the three, nine and twelve month periods while average prices realized after hedged transactions were 8 percent, 15 percent and 20 percent higher than the same periods in the prior year, respectively. The following is a summary of our estimated oil and gas reserves at September 30 determined using constant product prices at the end of the respective period. Estimates of economically recoverable reserves are based on a number of variables, which may differ from actual results. 2001 2000 ---- ---- Barrels of oil (in millions) 4.2 5.3 Bcf of natural gas 25.7 18.8 Total in Bcf equivalents 50.9 50.6 23
During the first quarter we announced the acquisition of operating and non-operating interests in 74 gas and oil wells from Stewart Petroleum for approximately $10 million. The acquisition was closed early in the second quarter of 2001 and increased our proved reserves by approximately 10 billion cubic feet equivalent of which approximately 86 percent are natural gas. Fuel Marketing Segment <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) <S> <C> <C> <C> <C> <C> <C> Revenue $219,710 $361,111 $997,084 $852,625 $1,511,568 $1,025,137 Operating income $ 5,606 $ 3,320 $ 49,794 $ 5,304 $ 68,378 $ 4,622 Net income $ 3,898 $ 2,319 $ 31,252 $ 3,482 $ 41,625 $ 4,553 EBITDA $ 6,146 $ 4,049 $ 51,394 $ 6,323 $ 68,874 $ 8,397 </TABLE> The significant increase in earnings for the nine and twelve month periods resulted from high margins which can, in part, be attributed to the unusual market conditions in the western markets, which primarily stem from the natural gas and electricity shortages in California and may not recur in the future. Margins in the third quarter 2001 returned to levels approximating historical trends. In addition, natural gas volumes marketed increased 18 percent, 20 percent and 28 percent for the three, nine and twelve month periods compared to the same periods of the previous year. Independent Power Production Segment <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) <S> <C> <C> <C> <C> <C> <C> Revenue $23,119 $27,155 $66,138 $27,397 $78,485 $27,397 Operating income $ 7,752 $17,799 $25,316 $17,988 $27,787 $17,963 Net income $ 1,246 $ 2,878 $ 3,827 $ 3,008 $ 4,062 $ 2,992 EBITDA $12,980 $ 9,474 $35,324 $ 9,689 $43,503 $ 9,664 </TABLE> Over 300 MW were added to operations mid third quarter 2001 and approximately 400 MW are currently under construction. Earnings from Independent power operations were affected by lower power prices in the West and lower-than-normal water flows at hydro plants in New York. 24
Electric Utility Group <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) <S> <C> <C> <C> <C> <C> <C> Revenue $43,518 $48,607 $175,698 $117,805 $231,202 $150,796 Expenses 28,272 29,994 102,477 72,567 135,011 92,289 ------- ------- -------- -------- -------- -------- Operating income $15,246 $18,613 $ 73,221 $ 45,238 $ 96,191 $ 58,507 Net income $ 7,914 $10,060 $ 41,878 $ 24,352 $ 54,593 $ 31,651 EBITDA $18,692 $22,465 $ 85,038 $ 56,867 $111,465 $ 74,098 </TABLE> Earnings from the electric utility decreased $2.2 million, or $0.08 per share and increased $17.5 million, or $0.69 per share, and $22.9 million, or $0.92 per share for the three, nine and twelve month periods ended September 30, 2001, respectively. The decrease in third quarter earnings resulted from a significant decrease in wholesale electricity prices in response to changes in western energy market conditions. Average prices received for off-system sales decreased 32 percent and increased 105 percent and 136 percent for the three, nine and twelve month periods in 2001 compared to the same periods in 2000. In addition, off-system megawatt hours sold decreased 11 percent for the three months due to changes in market conditions and increased 64 percent and 67 percent for the nine and twelve month periods ended September 30, 2001 compared to the same periods in 2000, due to higher market prices and the 40 MW generating capacity added in 2001. The Electric Utility continued to have modest gains in firm residential and commercial electric sales. These nine and twelve month period increases were partially offset by higher fuel and operating costs associated with operation of the gas turbines and other power plant operations, and higher purchased power costs. The following table provides certain operating statistics. <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> <C> Firm (system) sales - MWh 537,000 519,000 1,527,000 1,477,000 2,024,000 1,950,000 Off-system sales - MWh 211,000 237,000 761,000 465,000 980,000 588,000 </TABLE> Communications Group <TABLE> <CAPTION> Three Months Ended Nine Months Ended Twelve Months Ended September 30 September 30 September 30 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) <S> <C> <C> <C> <C> <C> <C> Revenue $ 5,154 $ 2,563 $13,717 $ 4,422 $ 16,984 $ 4,700 Expenses 8,101 5,121 23,237 11,349 32,062 13,455 ------- ------- ------- ------- -------- ------- Operating loss $(2,947) $(2,558) $(9,520) $(6,927) $(15,078) $(8,755) Net loss $(2,661) $(2,842) $(9,343) $(6,974) $(14,397) $(7,785) EBITDA $ (362) $ (949) $(2,135) $(3,503) $ (5,536) $(4,082) </TABLE> 25
Losses in Communications for the three, nine and twelve month periods ended September 30, 2001 were $(2.7) million, or $(0.10) per share, $(9.3) million, or $(0.37) per share and $(14.4) million, or $(0.58) per share, compared to $(2.8) million, or $(0.12) per share, $(7.0) million or $(0.32) per share and $(7.8) million or $(0.36) per share for the same periods in the prior year, respectively. The customer base continues to grow with an increase of 17 percent in the third quarter of 2001, compared to the second quarter of 2001. Losses for the nine and twelve month periods in 2001 increased due to increases in certain reserves for inventory and carrier billings and increased interest expense. Losses are expected to continue as the group proceeds with completing the network and increasing the customer base. Net income is expected to be achieved by 2004. The following table provides certain operating statistics: <TABLE> <CAPTION> September 30 June 30 March 31 December 31 September 30 2001 2001 2001 2000 2000 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> Business customers 1,940 1,440 980 650 490 Residential customers 13,780 12,000 10,060 8,370 6,700 </TABLE> Liquidity and Capital Resources During the three, nine and twelve month periods ended September 30, 2001, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay long-term debt maturities and substantially increase our cash position over September 30, 2000. We continue to fund property and investment additions primarily related to construction of additional electric generation facilities for our independent energy business group through a combination of operating cash flow, increased short-term debt and long-term non-recourse project financing. Investing and financing activities increased primarily due to short and long-term borrowings related to project financing. During the first quarter of 2001, the Company announced the public offering of 3 million shares of common stock with an option for the underwriters to purchase 450,000 additional shares. Credit Suisse First Boston, Lehman Brothers, CIBC World Markets and UBS Warburg acted as the managers of the underwriting syndicate. Early in the second quarter of 2001 the Company announced the offering price was set at $52 per share and all 3 million shares were sold with the underwriters exercising their over-allotment option to purchase an additional 383,000 shares. Net proceeds were approximately $163 million after commissions and expenses. The proceeds were used to repay a portion of current indebtedness under revolving credit facilities, to fund various power plant construction projects and for general corporate purposes. In addition, during the third quarter of 2001, the Company completed a $400 million revolving credit facility. The facility replaces the Company's previous short-term credit lines, which totaled $290 million. The credit facility was arranged by ABN Amro Bank N.V., US Bank, N.A. and Union Bank of California, N.A., with ten other banks participating. The facility consists of two $200 million tranches, one of which has a 364-day term and the other a three-year term. 26
Capital Requirements During the third quarter 2001, we closed on the purchase of a gas-fired generation complex in North Las Vegas, Nevada from Enron North America, a wholly-owned subsidiary of Enron Corporation. We anticipate total acquisition and construction costs for the 273 MW complex to be approximately $330 million. The project is expected to be primarily financed with project-level non-recourse debt. The capital necessary to fund this project was not included in our forecasted capital requirements reported in our 2000 Annual Report on Form 10-K filed with the Securities Exchange Commission. There have been no additional material changes in our forecasted changes in liquidity and capital requirements from those reported in Item 7 of our 2000 Annual Report on Form 10-K filed with the Securities Exchange Commission. Forward Looking Statements The above information includes "forward-looking statements" as defined by the Securities and Exchange Commission. These statements concern the Company's plans, expectations and objectives for future operations. All statements, other than statements of historical facts, included above that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, intend, anticipate, estimate, aim, project and similar expressions are also intended to identify forward-looking statements. These forward-looking statements may include, among others, such things as expansion and growth of the Company's business and operations; future financial performance; future acquisition and development of power plants; future production of coal, oil and natural gas; reserve estimates; future communications customers; and business strategy. These forward-looking statements are based on assumptions which the Company believes are reasonable based on current expectations and projections about future events and industry conditions and trends affecting the Company's business. However, whether actual results and developments will conform to the Company's expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from those contained in the forward-looking statements, including the following factors: prevailing governmental policies and regulatory actions with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition; changes in and compliance with environmental and safety laws and policies; weather conditions; population growth and demographic patterns; competition for retail and wholesale customers; pricing and transportation of commodities; market demand, including structural market changes; changes in tax rates or policies or in rates of inflation; changes in project costs; unanticipated changes in operating expenses or capital expenditures; capital market conditions; counterparty credit risk; technological advances; competition for new energy development opportunities; legal and administrative proceedings that influence the Company's business and profitability; and unanticipated developments in the western power markets, including unanticipated governmental intervention, deterioration in the financial condition of counterparties, default on amounts due, adverse changes in current or future litigation and adverse changes in the tariffs of the California Independent System Operator Corporation. Any such forward-looking statements should be considered in conjunction with Black Hills Corporation's most recent annual report on Form 10-K and its interim quarterly reports on Form 10-Q on file with the Securities and Exchange Commission. New factors that could cause actual results to differ materially from those described in forward-looking statements 27
emerge from time to time, and it is not possible for the Company to predict all such factors, or to 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. The Company assumes no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Other than changes in price risk management activities as disclosed in Note 9 to the Consolidated Financial Statements in this Form 10-Q, there have been no material changes in market risk faced by the Company from those reported in the Company's 2000 Annual Report on Form 10-K filed with the Securities Exchange Commission. For more information on market risk, see Part II, Item 7 in the Company's 2000 Annual Report on Form 10-K, and Notes to Consolidated Financial Statements in this Form 10-Q. 28
BLACK HILLS CORPORATION Part II - Other Information Item 1. Legal Proceedings For information regarding legal proceedings, see Note 7 to the Consolidated Financial Statements in this Form 10-Q, the Company's 2000 Annual Report on Form 10-K and the Company's quarterly reports on Form 10-Q for the quarters ended March 31, 2001 and June 30, 2001. Item 2. Changes In Securities and Use of Proceeds (c) On September 10, 2001, we issued the following unregistered securities pursuant to the 2000 earn-out consideration agreed to in the acquisition of Indeck Capital, Inc. on July 7, 2000. The unregistered securities were issued under Rule 506 of Regulation D of the Securities Act of 1933. Each of the stockholders is an accredited investor. <TABLE> <CAPTION> Series 2000-A Stockholder Common Shares Issued Preferred Stock Issued <S> <C> <C> Gerald R. Forsythe 7,029 178 John W. Salyer 1,360 34 Michelle R. Fawcett 736 18 Marsha Fournier 736 18 Monica Breslow 736 18 Melissa S. Forsythe 736 18 </TABLE> Item 6. Exhibits and Reports of Form 8-K (a) Exhibits The following documents are included as exhibits to this Form 10-Q: Exhibit Number Description ------ ----------- 10.1 3-Year Credit Agreement dated as of August 28, 2001 among Black Hills Corporation, as Borrower, The Financial Institutions party, hereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication Agent, U.S. Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent. 29
10.2 364-Day Credit Agreement dated as of August 28, 2001 among Black Hills Corporation, as Borrower, The Financial Institutions party, hereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication Agent, U.S. Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent. (b) Reports on Form 8-K On September 18, 2001, the Company filed a Form 8-K dated August 31, 2001 reporting "Item 5 - Other Events" related to the acquisition of a 273 MW gas-fired co-generation power plant project located northeast of Las Vegas, Nevada from Enron North America, a wholly-owned subsidiary of Enron Corporation. 30
BLACK HILLS CORPORATION 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 CORPORATION By: /s/ Roxann R. Basham --------------------------------------------- Roxann R. Basham, Vice President - Controller Principal Accounting Officer) By: /s/ Mark T. Thies --------------------------------------------- Mark T. Thies, Senior VP & CFO (Principal Financial Officer) Dated: November 14, 2001 31
EXHIBIT INDEX Exhibit Number Description 10.1 3-Year Credit Agreement dated as of August 28, 2001 among Black Hills Corporation, as Borrower, The Financial Institutions party, hereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication Agent, U.S. Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent. 10.2 364-Day Credit Agreement dated as of August 28, 2001 among Black Hills Corporation, as Borrower, The Financial Institutions party, hereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication Agent, U.S. Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent.