AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON APRIL 16, 2001 REGISTRATION NO. 333-57440 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 AMENDMENT NO. 2 TO FORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 -------------------------- BLACK HILLS CORPORATION (formerly known as Black Hills Holding Corporation) (Exact name of registrant as specified in its charter) SOUTH DAKOTA 4911 46-0458824 (State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer incorporation or organization) Classification Code Number) Identification Number) 625 NINTH STREET, P.O. BOX 1400, RAPID CITY, SOUTH DAKOTA 57709 (605) 721-1700 (Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant's Principal Executive Offices) STEVEN J. HELMERS, GENERAL COUNSEL 625 NINTH STREET P.O. BOX 1400 RAPID CITY, SOUTH DAKOTA 57709 (605) 721-1700 (Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service) -------------------------- WITH COPIES TO: ROBERT J. MELGAARD, ESQ. JOHN K. NOONEY, ESQ. VINCENT J. PISANO, ESQ. Conner & Winters, Morrill Thomas Nooney Skadden, Arps, Slate, A Professional Corporation & Braun, LLP Meagher & Flom LLP 3700 First Place Tower 625 Ninth Street Four Times Square 15 East Fifth Street P.O. Box 8108 New York, New York 10036 Tulsa, Oklahoma 74103 Rapid City, South Dakota 57709 ------------------------ APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE OF THE SECURITIES TO THE PUBLIC: AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES EFFECTIVE. -------------------------- If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, please check the following box: / / If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / / If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / / If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / / If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following box. / / -------------------------- THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE. - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------
THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.
SUBJECT TO COMPLETION, DATED APRIL 16, 2001 3,000,000 Shares [LOGO] Common Stock ----------- We are selling 3,000,000 shares of common stock. Our common stock is listed on The New York Stock Exchange under the symbol "BKH." The last reported sale price on April 12, 2001, was $52.49 per share. The underwriters have an option to purchase a maximum of 450,000 additional shares to cover over-allotments of shares. INVESTING IN THE COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE 8. Underwriting Price to Discounts and Proceeds Public Commissions to Us ------------------- ------------------- ------------------- Per Share................................ $ $ $ Total.................................... $ $ $ Delivery of the shares of common stock will be made on or about , 2001. Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. CREDIT SUISSE FIRST BOSTON LEHMAN BROTHERS CIBC WORLD MARKETS UBS WARBURG The date of this prospectus is .
[Logo] Black Hills Corporation [Map of location [Picture of hydro plant of our assets] and list of our plants] [Picture of power generation [Picture of gas-fired project under construction power plant and and list of our projects list of our plants] under construction and early development] [Picture of coal power plant and list of our coal and other power plants] [Picture of fuel [Picture of oil and [Picture of coal mine [Picture of marketing operations gas well and list of and list of our communications and list of our our operations] operations] facility and list of locations] our operations]
TABLE OF CONTENTS PAGE ---- Summary.............................. 1 Risk Factors......................... 8 Use of Proceeds...................... 16 Price Range of Common Stock and Dividends.......................... 17 Capitalization....................... 18 Selected Consolidated Financial Data............................... 19 Management's Discussion and Analysis of Financial Condition and Results of Operations...................... 21 Business............................. 36 Management........................... 62 Principal Shareholders............... 72 PAGE ---- Description of Capital Stock......... 75 United States Federal Tax Considerations for Non-U.S. Holders............................ 79 Underwriting......................... 81 Notice to Canadian Residents......... 83 Legal Opinions....................... 84 Experts.............................. 84 Where You Can Find More Information.. 84 Index to Financial Statements........ F-1 ------------------------ YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS OR TO WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH INFORMATION THAT IS DIFFERENT. THIS PROSPECTUS MAY ONLY BE USED WHERE IT IS LEGAL TO SELL THESE SECURITIES. THE INFORMATION IN THIS PROSPECTUS MAY ONLY BE ACCURATE ON THE DATE OF THIS DOCUMENT. i
FORWARD-LOOKING STATEMENTS This prospectus includes "forward-looking statements" as defined by the Securities and Exchange Commission. These statements concern our plans, expectations and objectives for future operations. All statements, other than statements of historical facts, included in this prospectus that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words "believe," "plan," "intend," "anticipate," "estimate," "goal," "aim," "project" and similar expressions are also intended to identify forward-looking statements. These forward-looking statements include, among others, such things as: - expansion and growth of our business and operations; - future financial performance; - future acquisition and development of power plants; - future production of coal, oil and natural gas; - reserve estimates; and - business strategy. 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 which could cause actual results to differ materially from those contained in the forward-looking statements, including the following factors as well as those factors discussed under the section of this prospectus entitled "Risk Factors:" - prevailing governmental polices 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; - technological advances; - competition for new energy development opportunities; and - legal and administrative proceedings that influence our business and profitability. ii
SUMMARY THIS SUMMARY HIGHLIGHTS INFORMATION CONTAINED ELSEWHERE IN THIS PROSPECTUS AND MAY NOT CONTAIN ALL OF THE INFORMATION THAT IS IMPORTANT TO YOU. YOU SHOULD CAREFULLY READ THE MORE DETAILED INFORMATION IN THE REST OF THIS PROSPECTUS ABOUT US AND THE COMMON STOCK BEING SOLD IN THIS OFFERING, INCLUDING "RISK FACTORS," AND OUR CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES. UNLESS THE CONTEXT OTHERWISE REQUIRES, REFERENCES IN THIS PROSPECTUS TO "BLACK HILLS," "WE," "US" AND "OUR" REFER TO BLACK HILLS CORPORATION AND ALL OF ITS SUBSIDIARIES COLLECTIVELY. ABOUT BLACK HILLS CORPORATION 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 58,600 customers in South Dakota, Wyoming and Montana. Our communications unit offers state-of-the-art broadband communication services to residential and business customers in Rapid City and the northern Black Hills region of South Dakota. INDEPENDENT ENERGY In recent years, the independent energy group has been our primary source of revenue and net income growth. Net income from this group is expected to exceed net income derived from our regulated utility beginning in 2001. Our independent power unit acquires, develops and operates unregulated power plants, primarily in the Rocky Mountain region of the United States. In July 2000, we expanded our presence in the independent power business by acquiring Indeck Capital, Inc. This acquisition and subsequent additions provide us with varying interests in 13 operating gas-fired and hydroelectric power plants in California, Colorado, Massachusetts and New York, of which we operate 12, as well as minority interests in several power-related funds. We have a total ownership interest of approximately 250 net megawatts. We are in the process of acquiring or constructing an additional net ownership interest of approximately 470 megawatts of generation capacity, approximately 330 megawatts of which we expect to be brought into service in 2001. As of December 31, 2000, we had 275 million tons of low-sulfur sub-bituminous coal reserves at our Wyodak mine located near Gillette, Wyoming. Substantially all of our coal production is sold under long-term contracts with our electric utility and with PacifiCorp. Our Wyodak mine will also provide coal to a 90 megawatt mine-mouth power plant which is being developed for our independent power unit and is scheduled for completion in 2003. We recently announced that we have initiated the planning and permitting process for a 500 megawatt coal-fired mine mouth power plant at the Wyodak site that may be operational by 2005. Our oil and gas exploration and production unit owns and operates 298 oil and gas wells, all in Wyoming, and owns working interests in another 341 wells operated by others located in California, Montana, North Dakota, Texas, Wyoming, Louisiana, Oklahoma and offshore in the Gulf of Mexico. As of December 31, 2000, we had proved reserves of 4.4 million barrels of oil and 18.4 billion cubic feet of natural gas, with approximately 62% of our current production consisting of natural gas. Our fuel marketing and transportation unit supplies wholesale natural gas marketing and risk management products and services primarily to customers in the Rocky Mountain and West Coast regions of the United States. In addition, this unit markets oil in the south and coal in the eastern and midwestern regions of the United States. Our customers include natural gas distribution companies, 1
municipalities, industrial users, oil and gas producers, electric utilities and coal mines. Our average daily marketing volumes for the twelve months ended December 31, 2000 were approximately 860,800 million British thermal units of natural gas, 44,300 barrels of oil and 4,400 tons of coal. Our power marketing activities involve marketing of capacity and energy from our existing power generation facilities. ELECTRIC UTILITY Our electric utility engages in the generation, transmission and distribution of electricity to approximately 58,600 customers in South Dakota, Wyoming and Montana. We control 458 megawatts of generating capacity, including 65 megawatts of capacity purchased from others under long-term power contracts at rates which currently are significantly lower than prevailing market prices. Approximately 53% of our utility's generating capacity consists of coal-fired plants and 33% is gas- or oil-fired, with the remaining 14% purchased from others. Our revenue mix for 2000 was comprised of 29% wholesale off-system, 26% commercial, 20% residential, 14% industrial, 10% contract wholesale and 1% municipal sales. In 2000, our South Dakota customers accounted for 92% of our retail electric revenues. Our retail electric rates in South Dakota are subject to a five-year freeze expiring on January 1, 2005. Because our generation capacity typically exceeds our peak load demands, we rarely purchase power on the spot market during periods of peak usage, permitting us to preserve our low-cost rate structure for our retail customers. Off-system sales offer a means to optimize the utilization of our power supply sources by permitting us to sell capacity and energy in excess of our native load requirements to wholesale customers at market prices which sometimes exceed our regulated retail rates. Wholesale off-system sales have represented an increasing percentage of our total revenues and net income. We added 40 megawatts of additional capacity to our system with the addition of the Neil Simpson combustion turbine, which we placed into operation in June 2000. Our utility operates a transmission system of 447 miles of high voltage and 541 miles of lower voltage lines. Our system has the capability of connecting to either the midwestern or western transmission grids. This provides us with an important strategic opportunity to shift off-system power to areas of higher demand and profitability as market conditions warrant. COMMUNICATIONS Our communications group, known as Black Hills FiberCom, offers a full suite of local and long distance telephone service, expanded cable television service, cable modem Internet access and high-speed data and video services to residential and business customers. We have completed a 210 mile inter- and intra-city fiber optic network and currently operate nearly 600 miles of two-way interactive hybrid fiber coaxial cable in Rapid City and the northern Black Hills region of South Dakota. The construction of our communications network is approximately 75% complete, and we expect to substantially complete construction in 2001. Since launching our services in November 1999, we have attracted over 9,000 residential and business customers. Our goal is to double the number of our customers and to attain 50% residential market penetration within our service territory while serving 35% of all broadband business customers in that territory. Our marketing strategy centers on providing bundled telecommunications services at competitive prices to commercial and residential customers. By bundling high speed Internet access with cable television and telephone service, we are able to exploit economies of scale and scope to offer customers relatively low-cost telecommunications solutions. Approximately 80% of our residential customers have opted for bundled services to date. 2
OUR BUSINESS STRATEGY Our strategy is to build long-term shareholder value by deploying our development, operating and marketing expertise in the energy industry. We plan to operate a mix of unregulated independent energy and regulated utility businesses, with emphasis on the independent power generation and fuel production segments. Our strategy includes the following key elements: - grow our independent power unit by developing and acquiring power projects primarily in the western United States; - expand the generating capacity of our existing sites through a strategy known as "brownfield development;" - sell a large percentage of the production from our independent power projects through long-term contracts in order to secure attractive investment returns; - increase our reserves of natural gas and expand our coal production; - exploit our fuel cost advantages and our operating and marketing expertise to remain a low-cost power producer; - exploit our knowledge and market expertise while managing the risks inherent in fuel marketing; - build and maintain strong relationships with wholesale energy customers; and - capitalize on our utility's established market presence, relationships and customer loyalty. For more details about our business strategy, see "Business--Strategy." RECENT DEVELOPMENTS ESTIMATED EARNINGS FOR FIRST QUARTER OF 2001 Although our results of operations for the first quarter of 2001 are not currently available, the following information reflects our expectations with respect to these results based on currently available information. We expect our earnings for the first quarter of 2001 to reach record levels of approximately $1.30 to $1.35 per share, compared to $0.42 per share reported for the same quarter of 2000. The anticipated higher earnings in the first quarter of 2001 are primarily due to the continued strong performance of our wholesale gas marketing business and increased wholesale electric sales. We also expect earnings for our independent energy business group to exceed our electric utility's earnings for the first quarter of 2001. A portion of the increased earnings is attributable to continued unusual conditions in western gas and electricity markets. We also expect that our communications business group will report continued losses in the first quarter due to capital costs and related financing costs. We expect to report our first quarter financial results on or about May 4, 2001. SETTLEMENT AGREEMENT In April 2001, we entered into a settlement agreement with PacifiCorp whereby ongoing litigation between the parties related to coal sales by our subsidiary, Wyodak Resources, for PacifiCorp's Wyodak power plant has been withdrawn. For a description of the litigation, see "Business--Legal Proceedings." A new coal supply contract for the Wyodak plant and other agreements were executed as a result of the settlement. The new coal supply contract for the Wyodak plant extends the term of the prior contract from 2013 to 2022. Wyodak Resources will receive a lump sum cash payment, while the coal sale price will be reduced and PacifiCorp's minimum annual coal purchase obligation will increase. Under the terms of a new coal sales agreement, Wyodak Resources will sell additional coal for delivery 3
to other PacifiCorp power plants from late 2001 through 2003, and Wyodak Resources will also have an option to sell additional coal to PacifiCorp through 2010. FOUNTAIN VALLEY ACQUISITION In April 2001, we purchased from Enron Corporation 100% of an independent power project under construction near Colorado Springs, Colorado known as the "Fountain Valley" project. This site will initially house 240 megawatts of gas-fired peaking facilities. Upon completion of construction, the energy and capacity generated by the Fountain Valley project will be sold to Public Service Company of Colorado under a tolling contract expiring in July 2012 pursuant to which we assume no fuel cost risk. We expect the plant to be completed in phases beginning in June 2001 and ending in July 2001 with the total cost expected to approximate $175 million. In addition to the current project, we believe that the Fountain Valley site provides us with attractive expansion and integration opportunities and is well-situated to serve other markets in the Rocky Mountain and southwest regions. We plan to further develop this site, integrating our expanding gas-fired generation resources with our nearby fuel production and marketing activities and complementing our predominantly coal-fired generation facilities in Wyoming. LONG-TERM POWER SALES CONTRACTS In February 2001, we entered into long-term power sales agreements with Cheyenne Light, Fuel and Power Company and the Municipal Electric Agency of Nebraska to sell a total of 80 megawatts of capacity from the Wygen I facility, a mine-mouth coal-fired plant with a total capacity of 90 megawatts, which is expected to be completed by spring 2003. The agreements cover a period of 10 years from the date the plant becomes operational. In March 2001, we entered into a unit contingent tolling agreement with Cheyenne Light, Fuel and Power Company for a 10-year term commencing in September 2001 for all of the energy and capacity from the Black Hills Generation Gillette CT facility, a 40 megawatt gas-fired combustine turbine facility which is scheduled to be completed in May 2001. We plan to operate this facility as a merchant plant during the summer of 2001. LANGE PROJECT In March 2001, we placed an order for a 40 megawatt gas-fired turbine that will be located either adjacent to the Wygen I and Black Hills Generation Gillette CT plants near Gillette, Wyoming, or adjacent to our transmission system in Rapid City, South Dakota. We expect to complete construction of the related power plant, known as the "Lange project," in the first quarter of 2002. PURCHASE OF OIL AND GAS PROPERTIES In March 2001, we signed a definitive agreement to purchase certain operating and non-operating interests in 74 oil and gas wells located primarily in Colorado and Wyoming for approximately $10 million from Stewart Petroleum Corporation. These properties have proved reserves of approximately 8.7 billion cubic feet of natural gas and approximately 200,000 barrels of oil, representing an increase of over 20% in our December 31, 2000 proved reserves. We expect to operate 35% of the wells representing approximately 85% of the reserves acquired. This transaction is expected to close in April 2001. HOLDING COMPANY FORMATION At our annual meeting of shareholders on June 20, 2000, our shareholders approved the formation of a holding company structure through a "plan of exchange" between Black Hills Corporation and Black Hills Holding Corporation. The formation of our holding company allows us to pursue, through separate subsidiaries, business opportunities in markets that are both regulated and unregulated. The shares offered by this prospectus are shares of common stock of the new holding company, Black Hills Corporation. 4
THE OFFERING Common stock offered by us................... 3,000,000 shares Common stock to be outstanding after the offering................................... 25,951,394 shares(1) Use of proceeds.............................. Approximately $40 million to partially fund the construction of the following independent power projects: Arapahoe CC5, Valmont Unit 8, Black Hills Generation Gillette CT and the Lange project; and approximately $108.6 million to repay a portion of indebtedness owed under our revolving credit facilities. Remaining proceeds will be used for general corporate purposes, including funding of capital expenditures and potential acquisitions, the development and construction of new facilities and additions to working capital. See "Use of Proceeds." New York Stock Exchange symbol............... "BKH" - ------------------------ (1) Based on the number of shares outstanding as of February 28, 2001. This number excludes: - 450,000 shares that may be sold upon exercise of the underwriters' over-allotment option; and - 1,048,254 shares reserved for issuance pursuant to outstanding stock options and upon conversion of our outstanding convertible preferred stock. OUR EXECUTIVE OFFICES We are incorporated in South Dakota and our headquarters and principal executive offices are located at 625 Ninth Street, P.O. Box 1400, Rapid City, South Dakota 57709. Our telephone number is (605) 721-1700. 5
SUMMARY CONSOLIDATED FINANCIAL DATA The following table presents a summary of our pro forma and historical consolidated financial data derived from our pro forma and historical consolidated financial statements. The unaudited pro forma consolidated financial data give effect to the Indeck Capital and other related acquisitions pursuant to the purchase method of accounting for business combinations and were prepared based on the assumption that the purchases had been consummated as of January 1, 2000. You should read the unaudited pro forma consolidated financial data along with our pro forma and historical consolidated financial statements and related notes, and the section of this prospectus entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations." The unaudited pro forma consolidated financial data are not necessarily indicative of the results of operations that would have occurred had the transactions described above been consummated on the date assumed, nor are they necessarily indicative of future results of operations. CONSOLIDATED INCOME STATEMENT DATA PRO FORMA HISTORICAL ------------- --------------------------------------------------------- YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, --------------------------------------------------------- 2000 2000 1999 1998 1997 1996 ------------- ---------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Electric..................... $ 173,308 $ 173,308 $133,222 $129,236 $126,497 $118,718 Coal production.............. 30,530 30,530 31,095 31,413 31,080 31,315 Fuel marketing............... 1,366,970 1,366,970 614,228 506,043 142,790 -- Oil and gas production....... 20,328 20,328 13,052 12,562 13,295 12,555 Independent power............ 84,675 39,660 -- -- -- -- Communications............... 11,371 11,371 3,423 -- -- -- Intersegment eliminations.... (18,331) (18,331) (3,145) -- -- -- ---------- ---------- -------- -------- -------- -------- Total revenues............. 1,668,851 1,623,836 791,875 679,254 313,662 162,588 Depreciation, depletion and amortization................. 35,012 32,864 25,067 24,037 22,311 22,794 Operating income............... 139,053 114,750 61,891 49,233 58,439 54,305 Other income and minority interest..................... (11,022) (8,277) 2,614 (44) 45 1,744 Interest expense............... 40,292 30,342 15,460 14,707 14,123 13,942 Income tax expense............. 34,258 30,358 15,789 11,708 14,326 13,578 Net income available for common stock........................ 57,542 52,770 37,067 25,808 32,359 30,252 Earnings per share--basic...... $ 2.47 $ 2.39 $ 1.73 $ 1.60(1) $ 1.49 $ 1.40 Earnings per share--diluted.... $ 2.45 $ 2.37 $ 1.73 $ 1.60(1) $ 1.49 $ 1.40 Weighted average shares of common stock outstanding: Basic........................ 23,293 22,118 21,445 21,623 21,692 21,660 Diluted...................... 23,543 22,281 21,482 21,665 21,706 21,660 Dividends paid per share of common stock................. $ 1.08 $ 1.08 $ 1.04 $ 1.00 $ 0.95 $ 0.92 6
CONSOLIDATED BALANCE SHEET DATA AS OF DECEMBER 31, ------------------------------------------------------ 2000 1999 1998 1997 1996 ---------- -------- -------- -------- -------- (IN THOUSANDS) Current assets........................... $ 419,010 $186,357 $140,480 $ 84,009 $ 50,997 Net property, plant and equipment........ 794,281 453,745 389,607 401,127 400,434 Total assets............................. 1,320,320 668,492 559,417 508,741 467,354 Current liabilities...................... 588,856 210,510 102,582 53,807 28,115 Deferred credits and other liabilities... 104,065 80,676 88,139 86,171 81,373 Long-term recourse debt(2)............... 158,687 160,700 162,030 163,360 164,691 Long-term non-recourse debt(2)........... 148,405 -- -- -- -- Stockholders' equity..................... 282,346 216,606 206,666 205,403 193,175 Total liabilities and capitalization..... 1,320,320 668,492 559,417 508,741 467,354 CONSOLIDATED STATEMENT OF CASH FLOWS DATA YEAR ENDED DECEMBER 31, ------------------------------------------------------ 2000 1999 1998 1997 1996 -------- -------- -------- --------- --------- (IN THOUSANDS) Cash flows from operating activities..... $ 74,470 $ 73,743 $ 54,730 $ 56,049 $ 55,397 Cash flows used by investing activities............................. (167,029) (136,057) (35,931) (30,830) (29,093) Cash flows from (used by) financing activities............................. 100,990 64,032 (20,809) (21,785) (21,143) -------- -------- -------- --------- --------- Increase (decrease) in cash and cash equivalents............................ $ 8,431 $ 1,718 $ (2,010) $ 3,434 $ 5,161 ======== ======== ======== ========= ========= OTHER FINANCIAL DATA YEAR ENDED DECEMBER 31, ----------------------------------------------------------------- 2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- (IN THOUSANDS) EBITDA(3)................................ $139,337 $89,572 $86,726 (1) $80,795 $78,843 Return on common stock equity............ 19.0% 17.1% 16.7%(1) 15.8% 15.7% - ------------------------ (1) Excludes $13.5 million pre-tax, $8.8 million after tax, or $0.41 per share, non-cash write-down of oil and gas properties due to historically low crude oil prices, lower natural gas prices and a decline in the value of unevaluated properties. (2) Excluding current maturities of long-term debt. (3) EBITDA represents earnings before interest, income taxes, depreciation and amortization and any non-recurring or non-cash items. 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, as determined by generally accepted accounting principles, or as an indicator of operating performance or cash flows from operating, investing and financing activities, as determined by generally accepted accounting principles, and is thus susceptible to varying calculations. EBITDA as presented may not be comparable to other similarly titled measures of other companies. 7
RISK FACTORS Before you invest in our common stock, you should be aware of the significant risks described below. You should carefully consider these risks, together with all of the other information included in this prospectus, before you decide whether to purchase shares of our common stock. RISKS RELATING TO OUR INDUSTRY OUR BUSINESS IS SUBJECT TO SUBSTANTIAL GOVERNMENTAL REGULATION AND PERMITTING REQUIREMENTS AND MAY BE ADVERSELY AFFECTED BY ANY FUTURE INABILITY TO COMPLY WITH EXISTING OR FUTURE REGULATIONS OR REQUIREMENTS. IN GENERAL. Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. We may incur significant additional costs because of our compliance with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulation may have a detrimental effect on our business. Furthermore, with the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the assets we operate, we expect our environmental expenditures to be substantial in the future. ENERGY REGULATION. The Public Utility Holding Company Act of 1935, or PUHCA, and the Federal Power Act regulate public utility holding companies and their subsidiaries and place certain constraints on the conduct of their business. The Energy Policy Act of 1992 provides relief from regulation under PUHCA to exempt wholesale generators. Maintaining the status of our facilities as exempt wholesale generators is conditioned on their continuing to meet statutory criteria and could be jeopardized, for example, by the making of retail sales by an exempt wholesale generator in violation of the requirements of the Energy Policy Act. We are continually in the process of obtaining or renewing federal, state and local approvals required to operate our facilities. Additional regulatory approvals may be required in the future due to a change in laws or regulations, or interpretations of existing laws and regulations, a change in our customers or other reasons. We may not always be able to obtain all required regulatory approvals, and we may not be able to obtain any necessary modifications to existing regulatory approvals or maintain all required regulatory approvals. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain and comply with any required regulatory approvals, the operation of our facilities or the sale of electricity to third parties could be prevented or subject to additional costs. ENVIRONMENTAL REGULATION. In July 1999, the United States Environmental Protection Agency finalized rules designed to protect and improve visibility impairment resulting from air emissions. Among other things, the regulations required states to identify sources of emissions (including specified coal-fired generating units built between 1962 and 1977) by 2004 that would be subject to "best available retrofit technology," or BART. These sources will be required to implement BART within five years after the EPA approves state plans adopted to combat visibility impairment (the submission of these plans is due between 2004 and 2008). In January 2001, the EPA proposed guidance to assist states in determining which sources should be subject to the BART requirement, but the proposed guidance has not been published pending a review by the newly appointed administrator of the EPA. Currently, the best available technology consists of "scrubbers," which are devices that trap pollutants in power-plant stacks. While we have installed scrubbers in our Wyodak and Neil Simpson II plants, we have not done so at the remainder of our coal-fired plants. If the proposed guidance is adopted in its current form, management believes that the only existing plant where additional capital investment may 8
be required in order to comply with Clean Air Act requirements is our Neil Simpson I plant. Any capital expenditures associated with bringing the plant into compliance are not expected to have a material adverse effect on our financial condition or results of operations. In acquiring some of our facilities, we assumed on-site liabilities associated with the environmental condition of those facilities, regardless of when such liabilities arose and whether known or unknown, and in some cases agreed to indemnify the former owners of those facilities for on-site environmental liabilities. We strive at all times to be in compliance with all applicable environmental laws and regulations. However, steps to bring our facilities into compliance could be expensive, and thus could adversely affect our financial condition. Environmental and other governmental laws have also increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells and related facilities. Moreover, environmental laws and regulations can change. See "Business--Regulation." WE FACE ONGOING CHANGES IN THE UNITED STATES UTILITY INDUSTRY THAT COULD AFFECT OUR COMPETITIVENESS. The United States electric utility industry is currently experiencing increasing competitive pressures, primarily in wholesale markets, as a result of consumer demands, technological advances, deregulation, greater availability of natural gas-fired generation and other factors. The Federal Energy Regulatory Commission, or FERC, has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses and deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry. Proposals have been introduced in Congress to repeal PUHCA, and FERC has publicly indicated support for the PUHCA repeal effort. To the extent competitive pressures increase and the pricing and sale of electricity assumes more characteristics of a commodity business, the economics of domestic independent power generation projects may come under increasing pressure. In addition, the independent system operators who oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of our generation facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we can offer no assurance that we will be able to operate profitably in all wholesale power markets. WE HAVE SOME EXPOSURE TO MARKET DISRUPTIONS IN CALIFORNIA. In 1996, California enacted legislation restructuring the state's investor-owned utilities. The legislation instituted a freeze on retail rates that investor-owned utilities could charge their customers for the duration of a transition period established by the legislation. The legislation did not make any provision for a California utility to recover costs of purchased electricity that exceeded the rates that could be charged under the rate freeze. Due to inadequate supplies of power and an unanticipated surge in demand, the California market has experienced rapid increases in electric power and natural gas prices. As a result, the state's two largest investor-owned utilities, Pacific Gas & Electric Company ("PG&E") and Southern California Edison ("SCE"), have incurred costs of procuring power significantly in excess of their ability to recover those costs through authorized retail rates and have 9
indicated that, unless the rate freeze is eliminated or other proposed relief is provided, they are, or shortly will become, insolvent. In April 2001, PG&E filed a voluntary petition for Chapter 11 bankruptcy protection. We may experience losses related to the potential insolvency of the California utilities in the event that a utility defaults on its obligations: - under its agreements with us; - to the California Independent System Operator, or CAISO, which administers the real-time markets for energy and ancillary services, resulting in non-payment to us under our capacity sales agreement with the CAISO; or - to other energy companies, causing those energy companies to default on their obligations to us. We have two agreements with SCE involving our California independent power plants. - In 1999, we entered into a settlement agreement with SCE involving the Harbor Cogeneration plant located in Wilmington, California, in which we own a 31.8% interest. The settlement agreement provides for the termination of a 30-year power purchase agreement, in exchange for which we are entitled to receive payments of approximately $4 million per year through October 2008 for our interest in the plant. - The cogeneration plant located in Ontario, California is entitled to receive energy and capacity payments from SCE of approximately $1.7 million per year, under a long-term contract expiring in 2010. As of March 1, 2001, SCE owed us past due payments of approximately $1.5 million, with delinquencies ranging from 15 to 75 days in duration. We have no other material contractual relationships with SCE and no material agreements with PG&E. The Harbor Cogeneration plant has sold the peaking capacity from its expansion to the CAISO for the peak summer periods of 2001 through 2003 under an agreement that provides for payments to us of $1 million per year for each of 2001, 2002 and 2003. We have no other agreements with the CAISO and do not otherwise sell capacity and energy directly into the California market either through long-term contracts or on a merchant basis. All other merchant sales are made to power marketers who in turn sell into the California market. In addition, our fuel production and fuel marketing exposure to the California market is primarily indirect through sales to creditworthy counterparties, including neighboring utilities and gas and power marketing firms. In recent months, the Governor of the State of California, representatives of the state legislature and numerous industry participants have undertaken several initiatives designed to address market disruptions in California. In April 2001, SCE, its parent, Edison International, and the California Department of Water Resources signed a "Memorandum of Understanding" under which the state would pay $2.76 billion to purchase SCE's high voltage transmission system and SCE would withdraw a federal lawsuit in which it has sought authority to bill its customers for past unrecovered costs. Prior to its implementation, this agreement must be approved by the California state legislature, the California Public Utilities Commission and FERC. There is no assurance that any legislation will be enacted or that, if enacted, the sale of transmission assets will provide SCE with sufficient funds to pay any current or future obligations to us. In addition, there is no assurance that any current or future defaults by California utilities on obligations owed to others will not result in defaults by our counterparties. However, we believe that our direct exposure to potential defaults in the California market is largely limited to the agreements with SCE and the CAISO described above and that our indirect exposure is minimal. 10
RISKS RELATED TO OUR BUSINESS COMPETITION IS INCREASING IN ALL OF OUR BUSINESSES. In particular, the independent power industry is characterized by numerous strong and capable competitors, some of which have more extensive experience in the operation, acquisition and development of power generation facilities, larger staffs or greater financial resources than we do. Many of our competitors are also seeking favorable power generation opportunities. This competition may adversely affect our ability to make investments or acquisitions on attractive terms. There also exists strong competition in all aspects of the oil and gas industry, including exploration, production and fuel marketing. We must compete with a substantial number of other energy companies, many of which have substantially greater financial, managerial, technical and other resources than we possess. OUR BROADBAND COMMUNICATIONS BUSINESS IS SUBJECT TO SIGNIFICANT COMPETITION FOR ITS SERVICES AND TO RAPID TECHNOLOGICAL CHANGE. Although our communications unit has achieved rapid penetration of our existing market, Black Hills FiberCom faces strong competition for its services from the incumbent local exchange carrier, which has dominated the local communications markets, as well as from long distance providers, Internet service providers, the incumbent cable television provider and others. The area's incumbent local exchange carrier has responded to our presence by offering an extended area service plan matching our market area. Internet service provider competition is currently limited primarily to dial-up services. Broadband services competing with our cable modem service are not widely available in our market, except for the small number of digital subscriber lines provided by the area's incumbent local exchange carrier. The incumbent cable television provider has upgraded its system, but not to the extent necessary to provide bundled services through its own facilities, and it must resell telephony services to compete with our bundled products. However, the incumbent cable television provider may respond with more competitive services as our market penetration increases. The communications industry is subject to rapid and significant changes in technology. There can be no assurance that future technological developments will not have a material adverse effect on Black Hills FiberCom's competitive position. We do, however, expect that future technological developments will be based on fiber optic technology, and that we will be in an advantageous position to be the first in our market to deploy those technological advancements on a cost-effective basis. Our ability to recover our capital investment and achieve operating profits is dependent on our ability to attract additional customers and is subject to the risk that technological advances may render our network obsolete. No assurance can be given that we will be successful in meeting our goals. If we determine that we will be unable to recover our investment, we would be required to take a non-cash charge to earnings in an amount that could be material in order to write down a portion of our investment in Black Hills FiberCom. OUR RATE FREEZE AGREEMENT WITH THE SOUTH DAKOTA PUBLIC UTILITIES COMMISSION PREVENTS US FROM PASSING ON TO OUR SOUTH DAKOTA RETAIL UTILITY CUSTOMERS COST INCREASES THAT MAY BE INCURRED DURING THE RATE FREEZE PERIOD, ABSENT EXTRAORDINARY CIRCUMSTANCES. Our utility's rate freeze agreement with the South Dakota Public Utilities Commission provides that, during the period ending January 1, 2005, Black Hills Power may not apply to the Commission for any increase in rates, except upon the occurrence of certain extraordinary events. Although most of our utility's costs are fixed under long-term fuel and power supply agreements, our utility's historically stable returns could be threatened by plant outages, machinery failure, increases in purchased power costs over which our utility has no control, acts of nature or other unexpected events that could cause operating costs to increase. Since, however, we own or control generating 11
capacity in excess of our historical peak demands, we do not anticipate that our utility will be required to purchase replacement power in wholesale power markets, except in the event of unexpected plant outages. BECAUSE WHOLESALE POWER, FUEL PRICES AND OTHER COSTS ARE SUBJECT TO VOLATILITY, OUR REVENUES MAY FLUCTUATE. A substantial portion of our growth in net income in recent years is attributable to increasing wholesale sales by our utility and our independent energy unit into a robust wholesale market. The prices of energy products in the wholesale power markets are influenced by many factors outside our control, including fuel prices, transmission constraints, supply and demand, weather, economic conditions, and the rules, regulations and actions of the system operators in those markets. Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable. The success of our oil and gas operations will depend substantially upon the prevailing market prices of oil and natural gas. Historically, oil and natural gas prices and markets have also been volatile, and they are likely to continue to be volatile in the future. A decrease in oil or natural gas prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. A decline in fuel price volatility could also affect our revenues and returns from oil and gas marketing, which tend to increase when markets are volatile. ESTIMATES OF OUR PROVED RESERVES MAY MATERIALLY CHANGE DUE TO NUMEROUS UNCERTAINTIES INHERENT IN ESTIMATING OIL AND NATURAL GAS RESERVES. There are many uncertainties inherent in estimating quantities of proved reserves and their values. The process of estimating oil and natural gas reserves requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretations and judgment, and the assumptions used regarding quantities of recoverable oil and natural gas reserves and prices for oil and natural gas. Actual prices, production, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates, and these variances may be significant. Any significant variance from the assumptions used could result in the actual quantity of our reserves and future net cash flow being materially different from the estimates in our reported reserves. In addition, results of drilling, testing and production and changes in oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions. WE HAVE A LIMITED HISTORY OF SELLING AND MARKETING PRODUCTS IN THE WHOLESALE POWER MARKETS AND MAY NOT BE ABLE TO SUCCESSFULLY MANAGE THE RISKS ASSOCIATED WITH THIS ASPECT OF OUR BUSINESS. We sell our energy, capacity and other energy products that are not otherwise committed under long-term contracts into wholesale power markets, either directly or through power marketers. We operate within strict limits, typically selling only our available capacity and not engaging in power marketing for others or in any speculative activity by selling in excess of what we reasonably believe our facilities are capable of producing or will produce. The overall objective of our power marketing activities is to optimize the utilization of our facilities to achieve an appropriate rate of return on our generation asset portfolio and our utility's off-system sales without taking any undue risks. Nevertheless, we have been managing risks associated with price volatility in this manner for only a limited amount 12
of time. We and any power marketing company we hire may not be able to effectively manage this price volatility, and may not be able to successfully manage the other risks associated with trading in energy markets, including the risk that counterparties may not perform, especially if the current disruptions in the western markets worsen. WE HAVE SUBSTANTIAL INDEBTEDNESS AND WILL REQUIRE SIGNIFICANT ADDITIONAL AMOUNTS OF DEBT AND EQUITY CAPITAL TO GROW OUR BUSINESSES. OUR FUTURE ACCESS TO SUCH FUNDS IS NOT CERTAIN. As of December 31, 2000, we had short-term debt of $226 million, long-term recourse debt of $159 million and long-term non-recourse debt of $148 million. Our substantial debt presents the risk that we might not generate sufficient cash to maintain our credit facilities or service our indebtedness. In addition, our leveraged capital structure could limit our ability to finance the acquisition and development of additional projects, to compete effectively, to operate successfully under adverse economic conditions and to fully implement our strategy. The terms of our debt may also restrict our flexibility in operating our projects. In order to access capital on a substantially non-recourse basis in the future, we may have to make larger equity investments in, or provide more financial support for, our project subsidiaries. We also may not be successful in structuring future financing for our projects on a substantially non-recourse basis. The South Dakota Constitution requires shareholder approval of corporate indebtedness and prohibits South Dakota corporations, such as us, from incurring recourse debt in excess of levels previously approved by shareholders. At our next annual shareholders meeting in May 2001, we intend to ask our shareholders to approve an increase in the level of authorized borrowings from $500 million to $2 billion in order to support the future growth of our independent energy business. No assurance can be given, however, that our shareholders will approve this additional borrowing authority. Any failure to obtain additional borrowing authority could inhibit our ability to pursue our growth plan. We estimate that our communications unit will require approximately $25 million of additional financing to substantially complete the construction of its network in 2001. To date, we have generated capital for our independent energy investments and our communications network principally through internally-generated cash flow and through borrowings. We cannot assure you that we will continue to generate sufficient cash flow or that we will be able to raise additional debt or equity capital from others in the future. OUR POWER PROJECT DEVELOPMENT, EXPANSION AND ACQUISITION ACTIVITIES, OUR OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES AND THE CONSTRUCTION OF OUR COMMUNICATIONS NETWORK MAY NOT BE SUCCESSFUL, WHICH WOULD IMPAIR OUR ABILITY TO EXECUTE OUR GROWTH STRATEGY. The growth of our independent power business through development, expansion and acquisition activities is critical to our future growth. While we are currently developing new facilities and expanding existing projects, with a significant development backlog, we may not be able to continue to develop attractive opportunities or to complete acquisitions or development projects that we undertake. Factors that could cause our activities to be unsuccessful include competition, our inability to obtain required governmental permits and approvals, and our inability to negotiate acceptable acquisition, construction, fuel supply or other material agreements. Similarly, we expect to continue to evaluate and pursue oil and gas acquisition opportunities on terms which management considers favorable. Our operations may be materially curtailed, delayed or canceled as a result of numerous factors, including accidents, title problems, weather conditions, shortages or delays in delivery of equipment or compliance with governmental requirements. There are relatively few manufacturers of the hybrid fiber coaxial cable equipment we are using to build our broadband communications network. Although construction is approximately 75% complete, 13
any difficulties we experience in identifying satisfactory suppliers or alternative sources of equipment could delay the completion of our network, impede our ability to connect new customers and cause our communications unit to experience operating losses for a longer period than currently expected. CONSTRUCTION, EXPANSION, REFURBISHMENT AND OPERATION OF POWER GENERATION FACILITIES INVOLVE SIGNIFICANT RISKS THAT CANNOT ALWAYS BE COVERED BY INSURANCE OR CONTRACTUAL PROTECTIONS. The construction, expansion and refurbishment of power generation and transmission and resource recovery facilities involve many risks, including: - inability to obtain required governmental permits and approvals; - unavailability of equipment; - supply interruptions; - work stoppages; - labor disputes; - social unrest; - weather interferences; - unforeseen engineering, environmental and geological problems; and - unanticipated cost overruns. The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover lost revenues, increased expenses or liquidated damages payments. Any of these risks could cause us to operate below expected capacity levels, which in turn could result in lost revenues, increased expenses, higher maintenance costs and penalties. As a result, a project may operate at a loss or be unable to fund principal and interest payments under its project financing agreements, which may result in a default under that project's indebtedness. RISKS RELATING TO OUR CORPORATE STRUCTURE PROVISIONS OF SOUTH DAKOTA LAW AND OUR ARTICLES OF INCORPORATION AND BYLAWS, AND SEVERAL OTHER FACTORS, COULD LIMIT ANOTHER PARTY'S ABILITY TO ACQUIRE US AND COULD DEPRIVE YOU OF THE OPPORTUNITY TO OBTAIN A TAKEOVER PREMIUM FOR YOUR SHARES OF COMMON STOCK. A number of provisions under South Dakota law and that are contained in our articles of incorporation and bylaws could make it more difficult for another company to acquire us and for you to receive any related takeover premium for your shares. These provisions, among other things: - provide for a classified board of directors, which allows only one-third of our directors to be elected each year; - restrict the ability of shareholders to take action by written consent and to call a special meeting; - authorize the board of directors to designate the terms of and issue new series of preferred stock; and - impose restrictions on business combinations with certain interested parties. 14
In addition, the South Dakota Public Utility Commission may assert jurisdiction to review and authorize certain business combinations or other acquisitions of our capital stock. Any attempt to obtain control of us by means of a tender offer, merger or otherwise could be discouraged, delayed or prevented if the South Dakota Public Utility Commission determined that it has the authority or the obligation to review the transaction. LIQUIDITY RISKS WE CANNOT ASSURE YOU THAT A HIGHLY ACTIVE TRADING MARKET FOR OUR COMMON STOCK WILL DEVELOP. We have not offered common stock in the public market since 1993 and our common stock currently lacks the level of liquidity or high trading volume enjoyed by some of our competitors. The continued absence of a highly active trading market for our common stock could cause our stock price to fluctuate significantly. 15
USE OF PROCEEDS We expect that the net proceeds from this offering of common stock will be approximately $148.6 million at an assumed public offering price of $52.49 per share, after deducting discounts to the underwriters and estimated expenses of this offering that we will pay. Approximately $40 million of the net proceeds will be used to partially fund the Arapahoe CC5 and Valmont Unit 8 plant expansions and the construction of the Black Hills Generation Gillette CT and Lange projects. An additional $108.6 million will be used to repay a portion of current indebtedness under our revolving credit facilities with ABN AMRO Bank N.V., as agent. Borrowings under our $115 million revolving credit facility bear interest at a floating rate, which at March 31, 2001 was 6.46%. Borrowings under our $50 million credit facility also bear interest at a floating rate, which at March 31, 2001 was 5.71%. During the last year, we have used borrowings under these credit facilities to expand our independent energy business, including approximately $36 million to fund our equity contribution in the Fountain Valley project. We expect to borrow an additional $10 million under these facilities to fund the purchase of 74 oil and gas wells from Stewart Petroleum Corporation in April 2001. Any remaining net proceeds will be used for general corporate purposes, which may include funding of capital expenditures and potential acquisitions, the development and construction of new facilities and additions to working capital. 16
PRICE RANGE OF COMMON STOCK AND DIVIDENDS Our common stock trades on the New York Stock Exchange under the symbol "BKH." The following table sets forth the high and low sale prices per share of our common stock, as reported in the New York Stock Exchange composite transactions, and the cash dividends paid per share of common stock, for the periods indicated: DIVIDENDS HIGH LOW PAID -------- -------- --------- 1999 First Quarter............................................. $26.50 $21.00 $0.26 Second Quarter............................................ 23.88 21.00 0.26 Third Quarter............................................. 25.63 22.19 0.26 Fourth Quarter............................................ 23.31 20.31 0.26 2000 First Quarter............................................. 25.19 20.44 0.27 Second Quarter............................................ 25.19 20.88 0.27 Third Quarter............................................. 30.13 22.00 0.27 Fourth Quarter............................................ 46.06 27.00 0.27 2001 First Quarter............................................. 45.74 31.00 0.28 Second Quarter (through April 12)......................... 54.00 45.81 -- As of January 31, 2001, the common stock was held by 5,708 holders of record and approximately 11,800 beneficial owners. We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects. Our credit facilities contain restrictions on the payment of cash dividends, the most restrictive of which prohibit the payment of cash dividends if our interest coverage ratio, as calculated in our credit agreements, is less than 2.0:1.0. 17
CAPITALIZATION The table below shows our cash position and capitalization as of December 31, 2000 on an actual basis and on an adjusted basis to give effect to estimated net proceeds from this offering at an assumed public offering price of $52.49 per share and the application of the net proceeds, including the repayment of a portion of our indebtedness under a revolving line of credit, as described under "Use of Proceeds." You should read this table in conjunction with our consolidated financial statements and related notes that are included in this prospectus. DECEMBER 31, 2000 ---------------------- ACTUAL AS ADJUSTED -------- ----------- (IN THOUSANDS) Cash and cash equivalents................................... $ 24,913 $ 24,913 ======== ======== Current portion of long-term debt........................... 13,960 13,960 Short-term debt............................................. 211,679 103,109 -------- -------- Total short-term debt....................................... 225,639 117,069 ======== ======== Long-term debt.............................................. 307,092 307,092 Shareholders' equity: Preferred stock........................................... 4,000 4,000 Common stock.............................................. 23,302 26,302 Additional paid-in capital................................ 73,442 219,012 Retained earnings......................................... 191,482 191,482 Treasury stock............................................ (9,067) (9,067) Accumulated other comprehensive income.................... (813) (813) -------- -------- Total shareholders' equity.................................. 282,346 430,916 -------- -------- Total capitalization........................................ $589,438 738,008 ======== ======== 18
SELECTED CONSOLIDATED FINANCIAL DATA The following table presents a summary of our pro forma and historical consolidated financial data derived from our pro forma and historical consolidated financial statements. The unaudited pro forma consolidated financial data give effect to the Indeck Capital and other related acquisitions pursuant to the purchase method of accounting for business combinations and were prepared based on the assumption that the purchases had been consummated as of January 1, 2000. You should read the unaudited pro forma consolidated financial data along with our pro forma and historical consolidated financial statements and related notes, and the section of this prospectus entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations." The unaudited pro forma consolidated financial data are not necessarily indicative of the results of operations that would have occurred had the transactions described above been consummated on the date assumed, nor are they necessarily indicative of future results of operations. CONSOLIDATED INCOME STATEMENT DATA PRO FORMA HISTORICAL ------------ --------------------------------------------------------- YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, --------------------------------------------------------- 2000 2000 1999 1998 1997 1996 ------------ ---------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Electric...................... $ 173,308 $ 173,308 $133,222 $129,236 $126,497 $118,718 Coal production............... 30,530 30,530 31,095 31,413 31,080 31,315 Fuel marketing................ 1,366,970 1,366,970 614,228 506,043 142,790 -- Oil and gas production........ 20,328 20,328 13,052 12,562 13,295 12,555 Independent power............. 84,675 39,660 -- -- -- -- Communications................ 11,371 11,371 3,423 -- -- -- Intersegment eliminations..... (18,331) (18,331) (3,145) -- -- -- ---------- ---------- -------- -------- -------- -------- Total revenues.............. 1,668,851 1,623,836 791,875 679,254 313,662 162,588 Depreciation, depletion and amortization.................. 35,012 32,864 25,067 24,037 22,311 22,794 Operating income................ 139,053 114,750 61,891 49,233 58,439 54,305 Other income and minority interest............. (11,022) (8,277) 2,614 (44) 45 1,744 Interest expense................ 40,292 30,342 15,460 14,707 14,123 13,942 Income tax expense.............. 34,258 30,358 15,789 11,708 14,326 13,578 Net income available for common stock......................... 57,542 52,770 37,067 25,808 32,359 30,252 Earnings per share--basic....... $ 2.47 $ 2.39 $ 1.73 $ 1.60(1) $ 1.49 $ 1.40 Earnings per share--diluted..... $ 2.45 $ 2.37 $ 1.73 $ 1.60(1) $ 1.49 $ 1.40 Weighted average shares of common stock outstanding: Basic......................... 23,293 22,118 21,445 21,623 21,692 21,660 Diluted....................... 23,543 22,281 21,482 21,665 21,706 21,660 Dividends paid per share of common stock.................. $ 1.08 $ 1.08 $ 1.04 $ 1.00 $ 0.95 $ 0.92 19
CONSOLIDATED BALANCE SHEET DATA AS OF DECEMBER 31, ------------------------------------------------------ 2000 1999 1998 1997 1996 ---------- -------- -------- -------- -------- (IN THOUSANDS) Current assets........................... $ 419,010 $186,357 $140,480 $ 84,009 $ 50,997 Net property, plant and equipment........ 794,281 453,745 389,607 401,127 400,434 Total assets............................. 1,320,320 668,492 559,417 508,741 467,354 Current liabilities...................... 588,856 210,510 102,582 53,807 28,115 Deferred credits and other liabilities... 104,065 80,676 88,139 86,171 81,373 Long-term recourse debt(2)............... 158,687 160,700 162,030 163,360 164,691 Long-term non-recourse debt(2)........... 148,405 -- -- -- -- Stockholders' equity..................... 282,346 216,606 206,666 205,403 193,175 Total liabilities and capitalization..... 1,320,320 668,492 559,417 508,741 467,354 CONSOLIDATED STATEMENT OF CASH FLOWS DATA YEAR ENDED DECEMBER 31, ------------------------------------------------------ 2000 1999 1998 1997 1996 --------- --------- -------- -------- -------- (IN THOUSANDS) Cash flows from operating activities..... $ 74,470 $ 73,743 $ 54,730 $ 56,049 $ 55,397 Cash flows used by investing activities............................. (167,029) (136,057) (35,931) (30,830) (29,093) Cash flows from (used by) financing activities............................. 100,990 64,032 (20,809) (21,785) (21,143) --------- --------- -------- -------- -------- Increase (decrease) in cash and cash equivalents............................ $ 8,431 $ 1,718 $ (2,010) $ 3,434 $ 5,161 ========= ========= ======== ======== ======== OTHER FINANCIAL DATA YEAR ENDED DECEMBER 31, ----------------------------------------------------------------- 2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- (IN THOUSANDS) EBITDA(3)................................ $139,337 $89,572 $86,726 (1) $80,795 $78,843 Return on common stock equity............ 19.0% 17.1% 16.7%(1) 15.8% 15.7% - ------------------------ (1) Excludes $13.5 million pre-tax, $8.8 million after tax, or $0.41 per share, non-cash write-down of oil and gas properties due to historically low crude oil prices, lower natural gas prices and a decline in the value of unevaluated properties. (2) Excluding current maturities of long-term debt. (3) EBITDA represents earnings before interest, income taxes, depreciation and amortization and any non-recurring or non-cash items. 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, as determined by generally accepted accounting principles, or as an indicator of operating performance or cash flows from operating, investing and financing activities, as determined by generally accepted accounting principles, and is thus susceptible to varying calculations. EBITDA as presented may not be comparable to other similarly titled measures of other companies. 20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS You should read the following discussion in conjunction with "Risk Factors," "Selected Consolidated Financial Data" and our consolidated financial statements and the related notes included elsewhere in this prospectus. OVERVIEW 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 58,600 customers in South Dakota, Wyoming and Montana. Our communications group offers state-of-the-art broadband communication services to residential and business customers in Rapid City and the northern Black Hills region of South Dakota. RESULTS OF OPERATIONS CONSOLIDATED RESULTS. Consolidated net income for 2000 was $52.8 million, compared to $37.1 million in 1999 and $25.8 million in 1998 or $2.37 per average common share in 2000, compared to $1.73 and $1.19 per average common share in 1999 and 1998, respectively. This equates to a 19.0%, 17.1% and 12.5% return on year-end common equity in 2000, 1999 and 1998, respectively. We reported record earnings in 2000, primarily due to strong natural gas marketing activity, increased fuel production, expanded power generation and increased wholesale off-system electric utility sales. Strong results in our independent energy business group in 2000 were partially offset by start-up losses in our communications business. Unusual energy market conditions stemming primarily from gas and electricity shortages in California contributed to our strong financial performance in 2000. There was a $0.40 contribution to 2000 earnings per share due to prevailing prices of gas and electricity and unusually wide gas trading margins that may not recur in the future. Earnings in 1999 increased over 1998 due primarily to sales growth in our electric utility and improved results in our independent energy business group, partially offset by expected start-up losses in our communications business. In 1998, we recorded an $8.8 million (after tax) charge to earnings related to a write-down of certain oil and natural gas properties. Absent this charge, our earnings per average common share for 1998 would have been $1.60, and our return on year-end common equity would have been 16.1%. The write-down was primarily due to historically low crude oil prices, lower natural gas prices and a decline in value of certain unevaluated properties. Consolidated revenues were $1,623.8 million, $791.9 million and $679.3 million in 2000, 1999 and 1998, respectively, representing a 105% increase in 2000 and a 17% increase in 1999. The growth in revenues in 2000 was a result of high energy commodity prices 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. Prices of natural gas marketed increased from an average of $1.97 and $2.15 per million British thermal units in 1998 and 1999, respectively, to $4.19 per million British thermal units in 2000. Daily volumes of natural gas marketed increased 35%, from 635,500 million British thermal units per day in 1999 to 860,800 million British thermal units in 2000. 21
Revenue increases in 1999 resulted primarily from the acquisitions and growth in the fuel marketing segment of our independent energy business group and off-system sales by our electric utility. Revenue and net income (loss) provided by each business group as a percentage of our total revenue and net income were as follows: 2000 1999 1998 -------- -------- -------- Revenue: Independent energy....................................... 89% 83% 81% Electric utility......................................... 11 17 19 Communications........................................... -- -- -- --- --- --- 100% 100% 100% === === === 2000 1999 1998 -------- -------- -------- Net Income (Loss): Independent energy....................................... 55% 31% 5% Electric utility......................................... 70 74 96 Communications........................................... (25) (5) (1) --- --- --- 100% 100% 100% === === === Net income from the independent energy group is expected to exceed net income derived from our utility in 2001. 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 continued strength in commodity prices and energy markets 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. See "--Rate Regulation." 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 the western markets. Although our communications business significantly increased residential and business customers in 2000, we expect it will sustain approximately $10 million in net losses in 2001, with annual losses decreasing thereafter and profitability expected in the next three to four years. 22
The following business group and segment information includes intercompany eliminations. INDEPENDENT ENERGY 2000 1999 1998 ---------- -------- -------- (IN THOUSANDS) Revenue: Fuel marketing............................ $1,353,795 $614,228 $506,043 Coal production........................... 30,530 31,095 31,413 Oil and gas production.................... 19,183 13,052 12,562 Independent power......................... 39,331 -- -- ---------- -------- -------- Total revenue........................... 1,442,839 658,375 550,018 Expenses.................................... 1,381,991 644,196 536,048* ---------- -------- -------- Operating income............................ $ 60,848 $ 14,179 $ 13,970* ========== ======== ======== Net income.................................. $ 28,946 $ 11,882 $ 10,068* ========== ======== ======== EBITDA**.................................... $ 65,184 $ 25,016 $ 22,530 ========== ======== ======== - ------------------------ * Excludes $13.5 million pre-tax, $8.8 million after tax, non-cash write-down relating to oil and gas properties due to historically low crude oil prices, lower natural gas prices and a decline in the value of unevaluated properties. ** EBITDA represents earnings before interest, income taxes, depreciation and amortization and any non-recurring or non-cash items. 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, as determined by generally accepted accounting principles, or as an indicator of operating performance or cash flows from operating, investing and financing activities, as determined by generally accepted accounting principles, and is thus susceptible to varying calculations. EBITDA as presented may not be comparable to other similarly titled measures of other companies. The following is a summary of sales volumes of our coal, oil and natural gas production: 2000 1999 1998 --------- --------- --------- Tons of coal sold........................... 3,050,000 3,180,000 3,280,000 Barrels of oil sold......................... 334,000 318,000 344,000 Mcf of natural gas sold..................... 3,274,000 2,791,000 2,056,000 Mcf equivalent sales........................ 5,278,000 4,698,000 4,120,000 The following is a summary of average daily fuel marketing volumes: 2000 1999 1998 -------- -------- -------- Natural gas--MMBtus.......................... 860,800 635,500 524,800 Crude oil--barrels........................... 44,300 19,270 19,000 Coal--tons................................... 4,400 4,500 4,400* - ------------------------ * Since the date of acquisition. 23
The independent energy business group's revenues increased 119% in 2000 and 20% in 1999. The revenue increase in 2000 was a direct result of gas and electricity shortages in the West Coast markets and the closing of the Indeck Capital acquisition. The revenue increase in 1999 was primarily the result of consolidating our three fuel marketing companies' operations from the time of their acquisitions. Additionally, revenues increased in both years as a result of increased volumes and increased fuel and power prices. Daily volumes of natural gas marketed increased 35% in 2000 and 21% in 1999. The July 2000 acquisition of Indeck Capital contributed to our strong earnings growth in 2000. In addition, in December 2000, we sold our ownership interest in a power fund management company which resulted in a $3.7 million pre-tax gain. The independent energy business group's total operating expenses, EBITDA and operating income increased over 115%, 160% and 329%, respectively, in 2000 compared to 1999. Net income of this group increased 144% in 2000. These increases resulted primarily from our gas marketing operations, which experienced a dramatic increase in both trading volumes and margins, a significant increase in fuel production volumes, record fuel and power prices and expanded power generation. The independent energy business group's 1999 net income improved over 1998 (excluding the non-cash charge in 1998) primarily due to record gas production, improved oil prices, lower depletion expense and the sale of certain retail gas marketing operations in 1999, partially offset by a non-cash write-down of certain intangible assets relating to our wholesale gas marketing office in Houston. COAL MINING Coal mining results were as follows: 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Revenue.......................................... $30,530 $31,095 $31,413 Operating income................................. 8,800 12,600 12,700 Net income....................................... 7,200 9,700 9,750 EBITDA........................................... 19,000 15,700 15,600 A planned five-week overhaul of the Wyodak plant resulted in lower coal sales and earnings in 2000 compared to 1999 and 1998. OIL AND GAS Oil and gas operating results were as follows: 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Revenue.......................................... $19,183 $13,052 $12,562 Operating income................................. 7,900 4,000 1,200* Net income....................................... 5,000 2,500 800* EBITDA........................................... 11,900 6,900 6,400 - ------------------------ * Excludes $13.5 million pre-tax, $8.8 million after tax, non-cash write-down relating to oil and gas properties due to historically low crude oil prices, lower natural gas prices and a decline in the value of unevaluated properties. Record net income in 2000 was primarily a result of record natural gas prices, higher crude oil prices and a significant increase in production volumes. Operating results for 1998 decreased primarily as a result of historically low crude oil prices, which not only reduced revenue but also increased depletion expense (lower oil and gas prices reduce the economically recoverable reserve amounts, causing an increase in depletion expense). We recognized approximately $3.7 million, $2.6 million and 24
$4.9 million of depletion expense (excluding the write-down in 1998) related to gas and oil production in 2000, 1999 and 1998, respectively. The following is a summary of our oil and gas reserves at December 31: 2000 1999 1998 -------- -------- -------- Barrels of oil (in millions)........................... 4.41 4.11 2.37 Bcf of natural gas..................................... 18.4 19.5 16.0 Total in Bcf equivalents............................... 44.88 44.11 30.16 These reserves are based on reports prepared by Ralph E. Davis Associates, Inc., an independent consulting and engineering firm. Reserves were determined using constant product prices at the end of the respective years. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results. The increase in oil reserves at December 31, 2000 was due to improved product prices. The increase in reserves at December 31, 1999 was due to strong drilling results, reserve acquisitions and improved product prices. We intend to increase our net proved reserves by selectively increasing our oil and gas exploration and development activities and by acquiring producing properties. FUEL MARKETING Our fuel marketing companies produced the following results: 2000 1999 1998 ---------- -------- -------- (IN THOUSANDS) Revenue..................................... $1,353,795 $614,228 $506,043 Operating income (loss)..................... 23,800 (2,200) -- Net income.................................. 14,000 (200) (300) EBITDA...................................... 23,700 2,500 600 Record volumes marketed and strong margins contributed to the increase in net income from fuel marketing in 2000 compared to 1999 and 1998. During 1999, the fuel marketing companies sold certain of their retail gas marketing operations, resulting in after-tax gains of approximately $1.8 million. In 1999, revenue and the related cost of sales increased primarily due to a full year of coal marketing operations (acquired in September 1998), increased product prices and increased oil volumes marketed. Operating income in 1999 was reduced by a non-cash write-down of certain intangible assets relating to the wholesale gas marketing office in Houston in the amount of approximately $1.2 million (after tax). Our fuel marketing companies generate large amounts of revenue and corresponding expense related to buying and selling energy commodities. Fuel marketing is extremely competitive, and margins are typically very small. The unusual energy market conditions stemming primarily from natural gas and electricity shortages in California contributed to the strong financial performance in 2000 and may not recur in the future. However, we believe that the continued growth of our fuel and power production businesses will create opportunities for us to continue to generate strong fuel marketing operating results in future years. 25
INDEPENDENT POWER PRODUCTION Our independent power segment produced the following results: 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Revenue............................................. $39,331 $ -- $ -- Operating income (loss)............................. 20,400 (160) (160) Net income.......................................... 3,200 (110) (120) EBITDA.............................................. 10,751 (160) (160) Results from the independent power production segment were not significant either in 1999 or 1998. In July 2000, we completed the acquisition of Indeck Capital, representing a significant advancement of our position in the independent power production business. We now own 250 net megawatts in currently operating plants. Of this 250 net megawatts, approximately 179 megawatts is under contracts or tolling arrangements with at least one year remaining, approximately 40 megawatts is owned through minority interests in independent power investment funds which we do not manage, and the remainder is sold under short-term market arrangements. An additional 470 megawatts of generating capacity is currently under construction. We expect to sell substantially all of this output under long-term contracts. We expect to increase revenues and earnings in this segment beyond 2001 through future project development. ELECTRIC UTILITY 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Revenue....................................... $173,308 $133,222 $129,236 Operating expenses............................ 105,100 80,936 79,340 -------- -------- -------- Operating income.............................. $ 68,208 $ 52,286 $ 49,896 ======== ======== ======== Net income.................................... $ 37,105 $ 27,286 $ 24,825 ======== ======== ======== EBITDA........................................ $ 88,853 $ 68,299 $ 64,936 ======== ======== ======== Electric revenue increased 30.1% in 2000 compared to 3.1% in 1999 compared to 1998. The increase in electric revenue in 2000 was primarily due to a 54% increase in wholesale off-system sales at an average price that was 3.1 times higher than the average price in 1999. The increase in off-system sales was driven by high spot market prices for energy in 2000, which enabled us to generate more energy from our combustion turbine facilities, including the Neil Simpson combustion turbine which we placed into commercial operation in June 2000. Megawatt hours generated from our oil-fired diesel and natural gas-fired combustion turbines were 305,767 in 2000, 25,882 in 1999 and 33,082 in 1998. Historically, market prices were not sufficient to support the economics of generating from these facilities, except to meet peak demand and as standby use for native load requirements. Firm kilowatt hour sales increased 2.8% in 2000 compared to 1999 and declined 0.1% in 1999 compared to 1998. Residential and commercial sales increases of 6% and 3%, respectively, in 2000 were partially offset by a 2% decrease in industrial sales, primarily due to load reductions at Homestake Gold Mine. Degree days, a measure of weather trends, were 16% above 1999 and 1% above normal in 2000. Degree days in 1999 were 9% below 1998 and 13% below normal. The increase in electric revenue in 1999 was primarily due to stable firm sales combined with a 20% increase in off-system sales. Revenue per kilowatt hour sold was 6.4 cents in 2000 compared to 5.4 cents in 1999 and 1998. The number of customers in the service area increased to 58,601, from 57,709 in 1999 and 56,856 in 1998. 26
The revenue per kilowatt hour sold in 2000 reflects a 54% increase in wholesale non-firm sales to 684,378 megawatt hours and robust wholesale power prices. The revenue per kilowatt hour sold in 1999 reflects the 20% increase in wholesale non-firm sales to 445,712 megawatt hours. The revenue per kilowatt hour sold in 1998 reflects the 33% increase in wholesale non-firm sales to 371,104 megawatt hours. Electric utility operating expenses increased by 30% in 2000, primarily due to increased fuel, purchased power and operating and maintenance expenses, partially offset by lower depreciation. Fuel expense in 2000 included the cost associated with the additional combustion turbine generation. Operating expenses increased 2.0% in 1999, primarily due to increased purchase power expense, operations and maintenance expenses and depreciation, partially offset by lower fuel expense. We forecast firm energy sales in our retail service territory to increase over the next 10 years at an annual compound growth rate of approximately 1%, with the system demand forecasted to increase at a rate of 2%. We currently have a winter peak of 344 megawatts established in December 1998 and a summer peak of 372 megawatts established in August 2000. These forecasts are derived from studies conducted by us whereby we examined and analyzed our service territory to estimate changes in the needs for electrical energy and demand over a 20-year period. These forecasts are only estimates, and the actual changes in electric sales may be substantially different. Weather deviations can also affect energy sales significantly when compared to forecasts based on normal weather. COMMUNICATIONS 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Revenue.......................................... $ 7,689 $ 278 $ -- Operating expenses............................... 20,175 4,852 1,087 -------- ------- ------- Operating loss................................... $(12,486) $(4,574) $(1,087) ======== ======= ======= Net loss......................................... $(12,027) $(1,262) $ (280) ======== ======= ======= EBITDA........................................... $(13,144) $(2,626) $ (570) ======== ======= ======= In September 1998, we formed our communications business to provide facilities-based communications services for Rapid City and the northern Black Hills of South Dakota. We began serving communications customers in late 1999 and market our services to schools, hospitals, cities, economic development groups, and business and residential customers. Operating losses in 2000 were attributable to increased interest, depreciation and operating expenses. Operating losses in 1999 were primarily due to start-up organizational costs, increased depreciation expense and increased interest expense associated with capital deployment. As of December 31, 2000, we had 8,368 residential customers and 646 business customers. LIQUIDITY AND CAPITAL RESOURCES In 2000, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common stock and to pay long-term debt maturities. We funded property 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 as a result of the acquisition of Indeck Capital in July 2000 and construction of several generating facilities. Cash flows from operations increased $0.7 million, primarily due to increased net income and depreciation partially offset by increased working capital. We expect increased operating cash flows resulting from our investing activities to support the additional indebtedness. 27
As part of our acquisition of Indeck Capital, we incurred $40.3 million of additional debt through an increase in borrowings on our short-term credit facilities, which were used to repay certain obligations of Indeck Capital. In addition, we issued 1.537 million shares of common stock and 4,000 shares of convertible preferred stock to the former Indeck Capital shareholders. In 1999, we generated cash from operations sufficient to meet our operating needs, to pay dividends on our common stock, to pay long-term debt maturities and to provide financing for our investment in independent power assets. Property additions were primarily financed through increased short-term debt and notes payable. Cash flows from operations increased $19 million primarily due to increased net income and decreased working capital. Cash flows from investing activities increased substantially, primarily related to the deployment of our fiber optic communications network and our investment in the construction of generating facilities. Cash flows from financing activities increased primarily due to increased short-term indebtedness to fund our investing activities. In the past, we have relied upon internally generated funds and the issuance of short- and long-term debt to finance our activities. We expect that an appropriate mix of financing options, including short- and long-term debt and preferred and common stock, will be used to finance future activities. Dividends paid on our common stock totaled $1.08 per share in 2000. This reflected increases approved by our board of directors from $1.04 per share in 1999 and $1.00 per share in 1998. All dividends were paid out of current earnings. Our three-year dividend growth rate was 4.4% and our payout ratio for 2000 was 45%. In January 2001, our board of directors increased the quarterly dividend 3.7% to 28 cents per share. If this dividend is maintained during 2001, it will be equivalent to $1.12 per share, an annual increase of 4 cents per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects. CAPITAL REQUIREMENTS. Our primary capital requirements for the three years ended December 31, 2000 were as follows: 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Property and investment additions: Independent energy........................... $130,787 $ 73,656 $12,040 Electric utility............................. 25,257 31,911 11,451 Communications and other..................... 58,922 49,042 1,774 Common stock dividends......................... 23,527 22,602 21,737 Fuel marketing assets.......................... -- -- 1,960 Maturities/redemptions of long-term debt....... 1,330 1,330 1,331 -------- -------- ------- $239,823 $178,541 $50,293 ======== ======== ======= Our capital additions for 2000 were $215 million. The major capital items for the year included the following: acquisition of the net assets of Indeck Capital; completion of construction of the 80 megawatt gas-fired generation units at the Arapahoe site in Denver, Colorado, which we placed in service in May 2000; completion of construction of the 40 megawatt gas-fired Valmont combustion turbine unit located in Boulder, Colorado, which we placed in service in May 2000; acquisitions of various interests in partnerships in which we previously held a minority interest; completion of construction of the 40 megawatt gas-fired Neil Simpson combustion turbine unit at our Wyodak site, which we placed in service in June 2000; and the construction of our communications fiber optic network. 28
Forecasted capital requirements for projected plant construction, other independent energy investments, regulated utility capital improvements and completion of the communications network are as follows: 2001 2002 2003 -------- -------- -------- (IN THOUSANDS) Independent energy............................ $287,200 $208,390 $195,540 Electric utility.............................. 18,340 18,160 16,450 Communications................................ 25,390 5,920 3,290 -------- -------- -------- $330,930 $232,470 $215,280 ======== ======== ======== Our independent energy business group's forecasted capital requirements include the following: - Acquisition of the 240 megawatt Fountain Valley gas-fired turbine generation facility located near Colorado Springs, Colorado, which was completed in April 2001. Construction is expected to be completed in 2001, with an expected total acquisition and construction cost of approximately $175 million. - Completion of construction of a 40 megawatt gas-fired combustion turbine at our Wyodak, Wyoming site (expected in mid-2001). - Completion of construction of a 40 megawatt gas-turbine expansion at our Valmont, Colorado site (expected in mid-2001). - Completion of construction of a 50 megawatt combined-cycle expansion at our Arapahoe, Colorado site (expected in mid-2002). - Expansion of the Harbor Cogeneration plant in Wilmington, California with a 30 megawatt combined-cycle upgrade. This expansion is currently in development, with anticipated completion in the second quarter of 2001. We have a 31.8% financial interest in this project. - Acquisition of operating and non-operating interests in 74 gas and oil wells from Stewart Petroleum Corporation, which is expected to be completed in April 2001. - Construction of a 40 megawatt gas-fired turbine known as the Lange project (expected in mid-2002). - Expected development of an additional 400 megawatts of generating capacity in years 2002-2003. We expect to finance our independent energy business group's purchase and construction of electric generating facilities primarily with long-term, non-recourse project level debt. We expect that any project level debt will contain significant restrictions on distributions of cash from the project to us. In addition to the above forecasted capital items, we will lease the Wygen I plant, a 90 megawatt coal-fired plant under construction at our Wyodak, Wyoming site. Because of the leasing arrangement, the $130 million total construction costs of the plant are not included in the above three-year capital expenditure forecast. Wygen I will be similar in design to our Neil Simpson II facility, which was completed in 1995 at the same site. The plant will run on low-sulfur coal fed by conveyor from our adjacent Wyodak coal mine and will use the latest available environmental control technology. We anticipate that the Wygen I plant will be operational by spring 2003. Forecasted capital expenditures for our electric utility operations include new transmission and substation projects, rebuild projects on existing transmission lines, distribution projects in response to customer requests for electric service, capital projects associated with our utility's existing generation plants, and other miscellaneous items. We do not expect additional generation capacity to be added to our utility over the forecast period. 29
Our communications group's capital requirements forecast primarily consists of 2001 costs related to the completion of our fiber optic network in Rapid City and the northern Black Hills of South Dakota. We expect construction to be substantially completed by November 2001, with forecasted capital expenditures thereafter consisting of capital improvements to the then existing network infrastructure. LINES OF CREDIT. We have lines of credit with various banks totaling $290 million at December 31, 2000 and $115 million at December 31, 1999, which are currently available to support bank borrowings or to provide for letters of credit. There were $211 million of borrowings and $20.6 million of letters of credit issued under these lines of credit at December 31, 2000, and $96.6 million of borrowings and no letters of credit issued at December 31, 1999. We have no compensating balance requirements associated with these lines of credit. The lines of credit are subject to periodic review and renewal during the year by the banks. In addition, Enserco Energy, Inc., our gas marketing unit, has a $90 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. We provide no guarantee to the lender under this facility. At December 31, 2000 and 1999, there were outstanding letters of credit issued under the facility of $69.8 million and $19.9 million, respectively, with no borrowing balances on the facility. Similarly, Black Hills Energy Resources, Inc., our oil marketing unit, has a $25 million uncommitted, discretionary credit facility. This line of credit provides credit support for the purchases of crude oil by Black Hills Energy Resources. We provide no guarantee to the lender under this facility. At December 31, 2000 and 1999, Black Hills Energy Resources had letters of credit outstanding of $8.5 million and $13.2 million, respectively, and no balance outstanding on its overdraft line. COAL RECLAMATION RESERVES. Under our mining permit, we are required to reclaim all land where we have mined coal reserves. The cost of reclaiming the land is accrued as the coal is mined. While the reclamation process takes place on a continual basis, much of the reclamation occurs over an extended period after we mine the area. Approximately $0.7 million is charged to operations as reclamation expense annually. As of December 31, 2000, accrued reclamation costs were approximately $17.7 million. LONG-TERM DEBT/CREDIT RATINGS. The long-term debt component of our capital structure at December 31, 2000 and 1999 was 52% and 43%, respectively. With expected growth within the independent energy business group, we anticipate our long-term debt ratio will increase to 55-60% in the next five years. Our utility's first mortgage bonds are rated "A1" by Moody's Investors Service, Inc. and "A+" by Standard & Poor's Ratings Services. These ratings reflect the respective agencies' opinions of the credit quality of our utility and the security underlying the first mortgage bonds. MARKET RISK DISCLOSURES PRICE RISK MANAGEMENT. Our operations are exposed to market risk arising from changes in commodity prices. These changes could cause fluctuations in our earnings and cash flows. In the normal course of business, we actively manage our exposure to these market risks by entering into various hedging transactions. Hedging transactions involve the use of a variety of derivative financial instruments. Our risk management policies place clear controls on these activities. We have adopted risk management policies and procedures, approved by our board of directors, and reviewed routinely by the audit committee of the board of directors. Our risk management policies and procedures include, but are not limited to, risk tolerance levels relating to authorized derivative financial instruments, position limits, authorization of transactions and credit exposure. 30
Operating margins earned by wholesale gas and crude oil marketing are relatively insensitive to commodity price fluctuations since most of the purchase and sales contracts do not contain fixed-price provisions. Generally, prices contained in these contracts are tied to a current spot or index price and, therefore, adjust directionally with changes in overall market conditions. We generally attempt to balance our fixed-price physical and financial purchase and sales commitments. However, we may at times have a bias in the market, within established guidelines, resulting from the management of our portfolio. To the extent a net open position exists, fluctuating commodity market prices can impact our financial position or results of operations, either favorably or unfavorably. The net open positions are actively managed, and the impact of changing prices on our financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year. Effective January 1, 1999, we adopted the provisions of Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10). The resulting effect of adoption of the provisions of EITF 98-10 was to alter our comprehensive method of accounting for energy-related contracts, as defined in that statement. We account for all energy trading activities at fair value as of the balance sheet date and recognize currently the net gains or losses resulting from the revaluation of these contracts to fair value in our results of operations. As a result, substantially all of the energy trading activities of our gas marketing, crude oil marketing and coal marketing operations are accounted for under fair value accounting methodology as prescribed in EITF 98-10. Through our independent energy business group, we utilize financial instruments for our 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. The derivatives are not held for speculative purposes but rather serve to hedge our exposure related to commodity purchases or sales commitments. Under EITF 98-10, these transactions qualify as 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 we do not speculate with "open" positions, substantially all of our 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 December 31, 2000 and 1999 are as follows: MAXIMUM VOLUME COVERED TERM DECEMBER 31, 2000 (MMBTUS) (YEARS) - ----------------- -------------- -------- 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 MAXIMUM VOLUME COVERED TERM (TONS) (YEARS) -------------- -------- Coal tons sold............................................. 988,000 1 Coal tons purchased........................................ 896,000 1 31
MAXIMUM VOLUME COVERED TERM DECEMBER 31, 1999 (MMBTUS) (YEARS) - ----------------- -------------- -------- Natural gas futures contracts purchased.................... 860,000 1 Natural gas basis swaps purchased.......................... 17,741,500 4 Natural gas basis swaps sold............................... 18,390,517 4 Natural gas fixed-for-float swaps purchased................ 9,490,486 1 Natural gas fixed-for-float swaps sold..................... 10,994,521 1 Natural gas collar transactions; puts purchased, calls sold..................................................... 408,500 1 Natural gas collar transactions; calls purchased, puts sold..................................................... 318,500 1 As required under EITF 98-10, energy trading activities were marked to fair value on December 31, 2000, and the gains and losses recognized in earnings. The entries for the accompanying consolidated balance sheets and income statement are as follows (in thousands): INSTRUMENT ASSET LIABILITY GAIN (LOSS) - ---------- -------- --------- ----------- Natural gas basis swaps..................................... $13,391 $23,963 $(10,572) Natural gas fixed-for-float swaps........................... 24,617 27,110 (2,493) Natural gas physical........................................ 23,391 9,427 13,964 Coal transactions........................................... 5,370 4,460 910 Crude oil transactions...................................... 1,523 1,000 523 ------- ------- -------- Totals.................................................... $68,292 $65,960 $ 2,332 ======= ======= ======== There were no significant differences between the fair values of derivative assets and liabilities at December 31, 1999. NON-TRADING ENERGY ACTIVITIES. To reduce risk from fluctuations in the price of oil and natural gas, we enter into swaps and costless collar transactions. We use these transactions to hedge price risk from sales of our forecasted crude oil and natural gas production. For such transactions, we utilize hedge accounting. At December 31, 2000, we had fixed-for-float swaps for 17,000 barrels of oil per month for the year 2001 to hedge our crude oil price risk with a fair value of $34,000. We had fixed-for-float swaps for 10,000 barrels of oil per month for the year 2002 to hedge our crude oil price risk with a fair value of $416,000. We also had costless collars (purchased puts--sold calls) for 10,000 barrels of oil per month for 2001 with a fair value of $323,000. We hedged our forecasted 2001 natural gas production with fixed-for-float swaps. We had fixed-for-float swaps for 1,581,000 million British thermal units with a fair value of $(3.4) million. These amounts are not reflected in our December 31, 2000 consolidated balance sheet, but will be recorded as part of the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. FINANCING ACTIVITIES. To reduce risk from fluctuations in interest rates, we enter into interest rate swap transactions. We use these transactions to hedge interest rate risk for variable rate debt financing. For such transactions, we utilize hedge accounting. At December 31, 2000, we had interest rate swaps with a notional amount of $127.4 million, which have a maximum term of six years and a fair value of $(7.5) million. These amounts are not reflected in our December 31, 2000 consolidated balance sheet, but will be recorded as part of the adoption of SFAS No. 133 on January 1, 2001. CREDIT RISK. In addition to the risk associated with price movements, credit risk is also inherent in our risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. While we have not experienced significant losses due to the 32
credit risk associated with these arrangements, we have off-balance sheet risk to the extent that the counterparties to these transactions fail to perform as required by the terms of their contracts. INTEREST RATE RISK. Our exposure to market risk for changes in interest rates relates primarily to our short-term investments and long-term debt obligations. As stated in our policy, we are adverse to principal loss and ensure the safety and preservation of our investments by limiting default risk, market risk and reinvestment risk. We mitigate default risk on short-term investments by investing in high credit quality securities consisting primarily of tax-exempt federal, state and local agency obligations, by periodically monitoring the credit rating of any investment issuer or guarantor and by limiting the amount of exposure to any one issuer. Our portfolio includes only securities with active secondary or resale markets to ensure portfolio liquidity. All short-term investments mature, by policy, in two years or less. The effect of a 100 basis point (1%) increase in interest rates would not have a material effect to our results of operations or financial condition, due to the short-term duration of the investment portfolio. At December 31, 2000, we had $162.2 million of outstanding floating rate debt of which $34.8 million was not offset with interest rate swap transactions that effectively convert the interest on that debt to a fixed rate. The table below presents principal (or notional) amounts and related weighted average interest rates by year of maturity for our short-term investments and long-term debt obligations, including current maturities (in thousands). 2001 2002 2003 2004 2005 THEREAFTER TOTAL -------- -------- -------- -------- -------- ---------- -------- Cash equivalents: Fixed rate............... $24,913 $ -- $ -- $ -- $ -- $ -- $ 24,913 Average interest rate.... 6.23% -- -- -- -- -- 6.23% Long-term debt: Fixed rate............... $ 3,070 $18,065 $ 3,122 $ 2,017 $ 2,026 $130,602 $158,902 Average interest rate.... 9.30% 6.98% 9.31% 9.50% 9.52% 8.30% 8.22% Variable rate............ $10,890 $11,919 $12,968 $14,380 $15,560 $ 96,433 $162,150 Average interest rate.... 8.20% 8.20% 8.19% 8.19% 8.19% 8.10% 8.14% Total long-term debt... $13,960 $29,984 $16,090 $16,397 $17,586 $227,035 $321,052 Average interest rate................. 8.44% 7.46% 8.41% 8.35% 8.35% 8.22% 8.18% RATE REGULATION EXISTING RATE REGULATION. In June 1999, the South Dakota Public Utilities Commission approved a settlement, which extended a rate freeze in effect since 1995 until January 1, 2005. The South Dakota settlement provides that, absent an extraordinary event, we may not file for any increase in our rates or invoke any fuel and purchased power adjustment tariff which would take effect during the freeze period. The specified extraordinary events are: - new governmental impositions increasing annual costs for South Dakota customers by more than $2.0 million; - simultaneous forced outages of both our Wyodak plant and Neil Simpson II plant projected to continue at least 60 days; - forced outages occurring to either plant which continue for a period of three months and is projected to last at least nine months; 33
- an increase in the Consumer Price Index at a monthly rate for six months which would result in a 10% or higher annual inflation rate; - the loss of a South Dakota customer or revenue from an existing South Dakota customer that would result in a loss of revenue of $2.0 million or more during any 12-month period; - the cost of coal to our South Dakota customers increases and is projected to increase by more than $2.0 million over the cost for the most recent calendar year; and - electric deregulation occurs as a result of either federal or state mandate, which allows any of our customers to choose its provider of electricity at any time during the freeze period. During the freeze period, except as identified above, we are undertaking the risks of: - machinery failure; - load loss caused by either an economic downturn or changes in regulation; - increased costs under power purchase contracts over which we have no control; - government interferences; and - acts of nature and other unexpected events that could cause material losses of income or increases in costs of doing business. However, the settlement anticipates that we will retain earnings realized from more efficient operations, sales from load growth, and off-system sales of power and energy until a subsequent general rate proceeding is initiated to modify our rates. Over the last three years we have initiated an effort to enter into new contracts with our largest industrial customers. The new contracts contain "meet or release" provisions which grant us a five-year right to continue to serve a customer at market rates in the event of deregulation. Additionally, through our new General Service Large Optional Combined Account Billing Tariff, we have allowed general service customers to aggregate their loads. This tariff also provides us with a five-year right to continue to serve those customers in the event of deregulation. Our "meet or release" contracts currently total more than 116 megawatts of large commercial and industrial load. These contracts provide us the assurance of a firm local market for our power resources, in the event deregulation occurs. These industrial and large commercial customers, together with our wholesale power sale agreements with the City of Gillette, Wyoming and Montana-Dakota Utilities Company, equal approximately 48% of our utility's firm load. REGULATORY ACCOUNTING We follow SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions in which we operate. As a result of our regulatory activity, a 50-year depreciable life for the Neil Simpson II plant is used for financial reporting purposes. If we were not following SFAS 71, a 35- to 40-year life would probably be more appropriate which would increase depreciation expense by approximately $0.6 million per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our generation operations. In the event we determine that we no longer meet the criteria for following SFAS 71, the accounting impact to us would be an extraordinary noncash charge to operations of an amount that could be material. Criteria that may give rise to the discontinuance of SFAS 71 include increasing competition that could restrict our ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. We periodically review these criteria to ensure that the continuing application of SFAS 71 is appropriate. 34
RECENT DEVELOPMENTS AND ACQUISITIONS Although our results of operations for the first quarter of 2001 are not currently available, the following information reflects our expectations with respect to these results based on currently available information. We expect our earnings for the first quarter of 2001 to reach record levels of approximately $1.30 to $1.35 per share, compared to $0.42 per share reported for the same quarter of 2000. The anticipated higher earnings in the first quarter of 2001 are primarily due to the continued strong performance of our wholesale gas marketing business and increased wholesale electric sales. We also expect earnings for our independent energy business group to exceed our electric utility's earnings for the first quarter of 2001. A portion of the increased earnings is attributable to continued unusual conditions in western gas and electricity markets. We also expect that our communications business group will report continued losses in the first quarter due to capital costs and related financing costs. We expect to report our first quarter financial results on or about May 4, 2001. In April 2001, we purchased from Enron Corporation 100% of an independent power project under construction near Colorado Springs, Colorado known as the "Fountain Valley" project. This site will initially house 240 megawatts of gas-fired peaking facilities. Upon completion of construction, the energy and capacity generated by the Fountain Valley project will be sold to Public Service Company of Colorado under a tolling contract expiring in July 2012 pursuant to which we assume no fuel cost risk. We expect the plant to be completed in phases beginning in June 2001 and ending in July 2001 with the total cost expected to approximate $175 million. In addition to the current project, we believe that the Fountain Valley site provides us with attractive expansion and integration opportunities and is well-situated to serve other markets in the Rocky Mountain and southwest regions. We plan to further develop this site, integrating our expanding gas-fired generation resources with our nearby fuel production and marketing activities and complementing our predominantly coal-fired generation facilities in Wyoming. In March 2001, we signed a definitive agreement to purchase certain operating and non-operating interests in 74 oil and gas wells located primarily in Colorado and Wyoming for approximately $10 million from Stewart Petroleum Corporation. These properties have proved reserves of approximately 8.7 billion cubic feet of natural gas and approximately 200,000 barrels of oil, representing an increase of over 20% in our December 31, 2000 proved reserves. We expect to operate 35% of the wells representing approximately 85% of the reserves acquired. This transaction is expected to close in April 2001. 35
BUSINESS GENERAL We are a growth oriented, diversified energy holding company operating principally in the United States. Our regulated and unregulated businesses have expanded significantly in recent years. Our independent energy group produces and markets power and fuel. We produce and sell electricity in a number of markets, with a strong emphasis on the western United States. We also produce coal, natural gas and crude oil primarily in the Rocky Mountain region and market fuel products nationwide. We also own Black Hills Power, Inc., an electric utility serving approximately 58,600 customers in South Dakota, Wyoming and Montana. Our communications group offers state-of-the-art broadband communication services to residential and business customers in Rapid City and the northern Black Hills region of South Dakota. Our predecessor company was incorporated and began providing electric utility service in 1941 and began selling and marketing various forms of energy on an unregulated basis in 1956. As the following table illustrates, we have experienced significant growth over the last five years, primarily as a result of the expansion of our independent energy business and increases in wholesale electric sales. 5-YR. 2000 1999 1998 1997 1996 CAGR(1) ---------- ---------- ---------- ---------- ---------- -------- Net Income ($ in thousands): Electric Utility............... $ 37,105 $ 27,286 $ 24,825 $ 22,106 $ 18,333 Independent Energy............. 28,946 11,882 10,068 10,471 12,132 Communications and other....... (13,203) (2,101) (280) (218) (213) Oil and gas write-down......... -- -- (8,805) -- -- ---------- ---------- ---------- ---------- ---------- $ 52,848 $ 37,067 $ 25,808 $ 32,359 $ 30,252 16% ========== ========== ========== ========== ========== Earnings per Share............... $ 2.37 $ 1.73 $ 1.60(2) $ 1.49 $ 1.40 15% Assets ($ in millions)........... $ 1,320 $ 668 $ 559 $ 509 $ 467 24% Capital Expenditures ($ in millions)...................... $ 177.2 $ 154.6 $ 27.2 $ 28.3 $ 24.4 28% Electric Sales (megawatt hours): Regulated Utility Firm Electric Sales........................ 1,973,066 1,920,005 1,923,331 1,932,347 1,710,571 Wholesale Off-System........... 684,378 445,712 371,104 279,612 249,100 ---------- ---------- ---------- ---------- ---------- Total Utility................ 2,657,444 2,365,717 2,294,435 2,211,959 1,959,671 Non-regulated Sales............ 236,279 -- -- -- -- ---------- ---------- ---------- ---------- ---------- Total Electric Sales......... 2,893,723 2,365,717 2,294,435 2,211,959 1,959,671 11% ========== ========== ========== ========== ========== Average Daily Marketing Volumes: Natural Gas (MMBtus)........... 860,800 635,500 524,800 231,000 28,200(3) Crude Oil (barrels)............ 44,300 19,270 19,000 12,600(3) -- Energy Marketing Gross Margins ($ in thousands)............... $ 41,783 $ 9,275 $ 7,824 $ 1,736 $ 0 Generating Capacity (megawatts): Utility (owned generation)..... 393 353 353 353 353 Utility (purchased capacity)... 70 75 75 75 75 Independent Power.............. 250 -- -- -- -- ---------- ---------- ---------- ---------- ---------- Total Generating Capacity.... 713 428 428 428 428 ========== ========== ========== ========== ========== Exploration and Production Reserves: Total MMcfe Reserves......... 44,882 44,114 30,160 24,022 17,330 - -------------------------- (1) Compound annual growth rate. (2) Excludes $13.5 million pre-tax, $8.8 million after tax, non-cash write-down of oil and gas properties due to historically low crude oil prices, lower natural gas prices and a decline in the value of unevaluated properties. (3) Since date of inception of marketing operations. 36
HOLDING COMPANY FORMATION At our annual meeting of shareholders on June 20, 2000, our shareholders approved the formation of a holding company structure through a "plan of exchange" between Black Hills Corporation and Black Hills Holding Corporation. The plan of exchange provided that each share of Black Hills Corporation common stock would be exchanged for one share of common stock of the holding company. On December 22, 2000, articles of exchange were filed with the South Dakota Secretary of State. As a result: - all common shareholders of Black Hills Corporation became shareholders of Black Hills Holding Corporation, the holding company; - Black Hills Corporation became a wholly-owned subsidiary of Black Hills Holding Corporation; - Black Hills Corporation changed its name to "Black Hills Power, Inc." and the holding company changed its name to "Black Hills Corporation"; and - the debt securities and other financial obligations of Black Hills Power, Inc. continue to be obligations of Black Hills Power, Inc. The formation of our holding company structure allows us to pursue, through separate subsidiaries, business opportunities in both regulated and unregulated markets. The shares offered by this prospectus are shares of common stock of the new holding company, Black Hills Corporation. INDUSTRY OVERVIEW In the last decade, many U.S. regulatory bodies have taken steps to transform the energy sectors which they regulate to encourage competition, introduce customer choice and, in some cases, to improve the operational performance of strategic energy assets. In particular, the electric power industry is undergoing substantial change as a result of regulatory initiatives at the federal and state levels. As early as the mid-1990's, new regulatory initiatives to increase competition in the domestic power generation industry had been adopted or were being considered at the federal level and by many states. The primary focus of such efforts was to increase competition through the disaggregation of the traditional utility functions of generation, transmission, distribution and marketing of electricity into competitive or partially regulated businesses. This resulted in new investment opportunities to enter previously non-competitive or closed markets. In 1992, FERC issued Order 636, followed by Order 888 in 1996, to increase competition by easing entry into natural gas and electricity markets. These orders require owners and operators of natural gas and power transmission systems to make transmission service available on a non-discriminatory basis to energy suppliers. In order to better assure competitive access to the transmission network on a non-discriminatory basis, FERC issued Order 2000 in December 1999, which encourages electric utilities with power transmission assets to voluntarily form regional transmission organizations to provide regional management and control of transmission assets independent of firms that sell electricity. The electric power industry has also witnessed growing consumer demand and increasingly frequent regional shortages of electricity over the past three years. The summers of 1998, 1999 and 2000 and the winter of 2000-2001 have all been characterized by very high peak prices for electricity in a number of recently created wholesale electricity markets. We believe that substantial amounts of new electric generating capacity need to be built to relieve shortages of electricity and to replace inefficient and obsolete facilities. 37
The oil and gas industry has experienced strong increases in commodity prices since the historically low levels experienced in 1998. These price increases have been driven in part by several years of modest drilling activity combined with strong growth in demand for energy commodities. Continued growth of the Internet and other high technology industries is contributing to increasing demand for power. Demand for natural gas is expected to remain strong as an increasing number of gas-fired power plants are brought into service. The telecommunications industry is currently undergoing widespread changes brought about by, among other things, the Telecommunications Act of 1996, the decisions of federal and state regulators to open the monopoly local telephone and cable television markets to competition and the need for higher speed, higher capacity networks to meet the increasing consumer demand for expanded telecommunications services, including broader video choices and high speed data and Internet services. The convergence of these trends and the inherent limitations of most existing networks have created opportunities for new types of communications companies capable of providing a wide range of voice, video and data services through new and advanced high speed, high capacity telecommunications networks. As a result of historical and anticipated regulatory initiatives and the increasing demand for electricity, fuel and broadband services, we believe there are significant opportunities for the development and growth of our independent energy businesses, our regulated utility and our communications business. STRATEGY Our strategy is to build long-term shareholder value by deploying our development, operating and marketing expertise in the energy industry. We plan to operate a mix of unregulated independent energy and regulated utility businesses, with emphasis on the independent power generation and fuel production segments. We expect our independent energy businesses to operate nationwide, with an integrated regional emphasis on the western half of the United States. Our utility and communications businesses intend to continue focusing their retail operations primarily on the northern Black Hills region of South Dakota, with wholesale power sales concentrated primarily in the Rocky Mountain and West Coast regions. Our strategy includes the following key elements: - grow our independent power unit by developing and acquiring power projects primarily in the western United States; - expand the generating capacity of our existing sites through a strategy known as "brownfield development;" - sell a large percentage of the production from our independent power projects through long-term contracts in order to secure attractive investment returns; - increase our reserves of natural gas and expand our coal production; - exploit our fuel cost advantages and our operating and marketing expertise to remain a low-cost power producer; - exploit our knowledge and market expertise while managing the risks inherent in fuel marketing; - build and maintain strong relationships with wholesale energy customers; and - capitalize on our utility's established market presence, relationships and customer loyalty. GROW OUR INDEPENDENT POWER UNIT BY DEVELOPING AND ACQUIRING POWER PROJECTS PRIMARILY IN THE WESTERN UNITED STATES. Our aim is to continue the development of power plants in regional markets based on 38
prevailing supply and demand fundamentals in a manner that complements our existing fuel assets and fuel and energy marketing capabilities. This approach aims to capitalize on market growth while managing our fuel procurement needs. Over the next few years, we intend to grow through a combination of disciplined acquisitions and development of new power generation facilities primarily in the Rocky Mountain region where we believe we have the detailed knowledge of market fundamentals and competitive advantage to achieve attractive returns. We believe the following trends will provide us with growth opportunities in the future: - Demand for electricity in the Rocky Mountain and West Coast regions will continue to grow and new generation capacity will be required over the next several years. - New electric generation construction will be predominantly gas-fired, which may create further competitive cost advantages for new and existing coal-fired generation assets. - Transmission construction will significantly lag new generation development, favoring new development located near load centers or existing, unconstrained transmission locations. - Disaggregation of the electric utility industry from traditionally vertically integrated utilities into separate generation, transmission, distribution and marketing entities will continue, thereby creating opportunities for acquisitions and joint ventures. EXPAND THE GENERATING CAPACITY OF OUR EXISTING SITES THROUGH A STRATEGY KNOWN AS "BROWNFIELD DEVELOPMENT." We believe that existing sites with opportunities for brownfield expansion generally offer the potential for greater returns than development of new sites through a "greenfield" strategy. Brownfield sites typically offer several competitive advantages over greenfield development, including: - proximity to existing transmission systems; - operating cost advantages related to ownership of shared facilities; - a less costly and time consuming permitting process; and - potential ability to share infrastructure with existing facilities at the same site. We are currently expanding our capacity with brownfield development underway at our Arapahoe, Valmont and Wygen sites, and believe that our Fountain Valley and Wygen sites in particular provide further opportunities for a significant expansion of our gas- and coal-fired generating capacity over the next several years. SELL A LARGE PERCENTAGE OF THE PRODUCTION FROM OUR INDEPENDENT POWER PROJECTS THROUGH LONG-TERM CONTRACTS IN ORDER TO SECURE ATTRACTIVE INVESTMENT RETURNS. Recent extreme price volatility in the short-term power markets are resulting in greater demand among our wholesale customers for mid- and long-term power purchase agreements. By selling the majority of our energy and capacity under mid- and long-term contracts, we believe that we can satisfy the requirements of our customers while earning more stable revenues and greater returns over the long term than we could by selling our energy into the more volatile spot markets. In recent months, for example, we have entered into long-term tolling agreements covering nearly all of the gas-fired energy and capacity our independent power unit is adding through brownfield expansion of the Arapahoe and Valmont sites and from the Fountain Valley project. See "--Independent Energy--Independent Power Plants." INCREASE OUR RESERVES OF NATURAL GAS AND EXPAND OUR COAL PRODUCTION. We aim to support the fuel requirements of our growing portfolio of power plants as well as power plants owned by others by emphasizing natural gas and coal production. Our strategy is to expand our natural gas reserves through a combination of acquisitions and drilling programs and expand our coal production through the construction of mine-mouth coal-fired generation plants at our Wyodak mine location. Our objective is to maintain coal reserves to serve our mine-mouth coal-fired generation plants directly, and 39
to maintain sufficient natural gas production either to directly serve or indirectly hedge the fuel cost exposure of our gas-fired generation plants. Specifically, we plan to: - substantially increase our natural gas reserves and minimize exploration risk by focusing on lower-risk exploration and development drilling as well as acquisitions of proven producing properties; - exploit our belief that the long-term demand for natural gas will remain strong by emphasizing natural gas, rather than oil, in our acquisition and drilling activities; - add natural gas reserves and increase production by focusing on various shallow gas plays in the Rocky Mountain region, where the added production can be integrated with our fuel marketing and/or power generation activities; - increase coal production and sales from our Wyodak mine by continuing to develop additional mine-mouth generating facilities at the site, including the Wygen I plant, which is scheduled for completion in spring 2003; and - pursue future sales of coal from the Wyodak mine to rail-served customers by reducing the moisture content of our coal so that we can ship it greater distances. EXPLOIT OUR FUEL COST ADVANTAGES AND OUR OPERATING AND MARKETING EXPERTISE TO REMAIN A LOW-COST POWER PRODUCER. We expect to expand our portfolio of power plants having relatively low marginal costs of producing energy and related products and services. We intend to utilize a low-cost power production strategy, together with access to coal and natural gas reserves, to protect our revenue stream as an increasing number of gas-fired power plants are brought into operation. Low marginal production costs can result from a variety of factors, including low fuel costs, efficiency in converting fuel into energy, and low per unit operation and maintenance costs. We have aggressively managed each of these factors to achieve very low production costs, especially at our coal-fired and hydroelectric generating facilities. Our primary competitive advantage is our coal mine, which is located in close proximity to our retail service territory. We are exploiting the competitive advantage of this native fuel source by building additional mine-mouth coal-fired generating capacity. This strengthens our position as a low-cost producer since transportation costs often represent the largest component of the delivered cost of coal. EXPLOIT OUR KNOWLEDGE AND MARKET EXPERTISE WHILE MANAGING THE RISKS INHERENT IN FUEL MARKETING. We aim to apply our knowledge of and expertise in the natural gas transmission system and trading markets in the western and northwestern regions of the United States and western Canada in order to exploit market inefficiencies and maximize our profits in our fuel marketing businesses. Our fuel marketing operations require effective management of price, counterparty and operational risks. To mitigate these risks, we have implemented risk management policies and procedures for each of our marketing companies that prohibit speculative strategies and establish price risk exposure levels, counterparty credit limits and committees to monitor compliance with our policies. We also limit exposure to energy marketing risks by maintaining separate credit facilities for each of our marketing companies and by avoiding the issuance of parent company performance guarantees to counterparties of our marketing companies. BUILD AND MAINTAIN STRONG RELATIONSHIPS WITH WHOLESALE ENERGY CUSTOMERS. We strive to build strong relationships with utilities, municipalities and other wholesale customers who we believe will continue to be the primary providers of electricity to retail customers in a deregulated environment. We further believe that these entities will need products, such as capacity, in order to serve their customers reliably. By providing these products under long-term contracts, we are able to meet our customers' 40
energy needs. Through this approach, we also believe we can earn more stable revenues and greater returns over the long term than we could by selling energy into the more volatile spot markets. We have been successful in entering into a variety of wholesale contracts based on the specific needs of our customers. For example, in 1999, Public Service Company of Colorado approached us to take over ownership and construction of the 120 megawatt Arapahoe and Valmont facilities in Colorado. Public Service Company of Colorado was subject to regulatory constraints that restricted its ability to own the facilities and needed the plants completed in an efficient and timely manner to meet the rapid growth in demand. We completed construction of the facilities on schedule, and signed tolling agreements with Public Service Company of Colorado for the capacity and energy generated by the original facilities. We subsequently signed agreements to expand the projects by 90 megawatts and signed tolling agreements for these expanded facilities as well as the Fountain Valley project. CAPITALIZE ON OUR UTILITY'S ESTABLISHED MARKET PRESENCE, RELATIONSHIPS AND CUSTOMER LOYALTY. As a result of its firmly established market presence, our electric utility has built solid brand recognition and customer loyalty in the Black Hills region. By ensuring a reliable supply of power to retail customers in our South Dakota and Wyoming service territory at rates below the national average, we have developed a strong, supportive relationship with our utility regulators. Our utility provides a solid foundation of support for the expansion of our independent energy and communications businesses. In addition, industry, technical and market expertise from our utility supports the growth of our independent energy businesses, and our strong brand recognition assists us in achieving rapid customer acceptance of our bundled communications services in our Black Hills service territory. INDEPENDENT ENERGY Our independent energy group engages in the production and sale of electric power through ownership of a diversified portfolio of generating plants, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing of fuel products nationwide. The independent energy group was our primary source of revenue and net income growth in 2000 and the net income from the independent energy group is expected to exceed net income from our regulated utility beginning in 2001. The independent energy group consists of three units: independent power production, fuel production and fuel marketing. INDEPENDENT POWER PRODUCTION. Our independent power production business acquires, develops and expands unregulated power plants. We hold varying interests in operating independent power plants in California, New York, Massachusetts and Colorado with a total net ownership of 210 megawatts, as well as minority interests in several power-related funds with a net ownership interest of 40 megawatts. PROJECT DEVELOPMENT PROGRAM. In April 2001, we purchased from Enron Corporation 100% of an independent power project under construction near Colorado Springs, Colorado and known as the "Fountain Valley" project. This site will initially house 240 megawatts of gas-fired peaking facilities. The energy and capacity generated by the Fountain Valley project will be sold to Public Service Company of Colorado under a tolling contract expiring in July 2012 pursuant to which we assume no fuel cost risk. We expect the plant to be completed in phases beginning in June 2001 and ending in July 2001 with the total cost expected to approximate $175 million. In addition to the current project, we believe that the Fountain Valley site provides us with attractive expansion and integration opportunities and is well-situated to serve other markets in the Rocky Mountain and southwest regions. In addition to Wygen I and the Fountain Valley development, other projects under construction include: - Arapahoe CC5, a 50 megawatt combined cycle expansion of our gas-fired turbines at the Arapahoe site located in the Front Range of Colorado; 41
- Valmont Unit 8, a 40 megawatt gas-fired turbine addition to our Valmont site located in the Front Range of Colorado; - Black Hills Generation Gillette CT, a 40 megawatt gas-fired facility located at the same site as our Wygen I plant; and - Harbor Expansion, a 30 megawatt (10 megawatt net ownership interest) expansion of our Harbor Cogeneration facility located in Wilmington, California. We also have an active acquisition and development program through which we are pursuing a number of additional generation projects in various stages of development, including the following: - the Lange project, a 40 megawatt gas-fired turbine to be located either at the same site as our Wygen I and Black Hills Generation CT plants near Gillette, Wyoming, or adjacent to our transmission system in Rapid City, South Dakota, and which we expect to complete in early 2002; - a coal-fired mine-mouth power plant with generating capacity of up to 500 megawatts, to be located at our Wyodak site near Gillette, Wyoming, which we expect to complete in 2005; - three separate projects in early stage development with a total of 1,100 megawatts of generation to be located at sites we currently own in whole or in part; and - four additional early stage development projects with a total of 1,340 megawatts of generation at new sites which we do not currently control. No assurance can be given that we will be successful in completing any or all of the projects currently under consideration. HOW WE MANAGE OUR PORTFOLIO. We strive to maintain diversification and balance in our portfolio of regulated and unregulated power plants. Our portfolio (including plants currently operating and those under construction) is diversified in terms of fuel mix and geographic location, with 81% of net unregulated capacity being gas-fired, 13% coal-fired, and the remainder hydroelectric. Our independent power plants are located in California, Wyoming, South Dakota, Colorado, New York and Massachusetts. In contrast, our electric utility capacity is approximately 53% coal-fired, 33% oil or gas-fired, and 14% under purchased power contracts, with plants located in South Dakota and Wyoming. We also have a diversified mix of revenue sources. We typically sell two types of products: energy and capacity, including ancillary services. Although these are separate products, both are typically sold together. Energy refers to the actual electricity generated by our facilities for ultimate transmission and distribution to consumers of electricity. Energy is the only one of our products that is subsequently distributed to consumers. Capacity refers to the physical capability of a facility to produce energy. Ancillary services generally are capacity support products used to ensure the safe and reliable operation of the electric power supply system. Examples of ancillary services include: - automatic generation control, which is used to balance energy supply with energy demand, referred to in our industry as "load," on a real-time basis; and - operating reserves, which are used on an hourly or daily basis to generate additional energy if demand increases or if major generating resources go off-line or if transmission facilities become unavailable. Our output is sold under contracts of varying length and subject to merchant pricing, thereby allowing us to take advantage of current favorable price trends, while hedging the impact of a potential downturn in prices in the future. We currently sell energy and capacity under a combination of short-and long-term contracts as well as direct sales into the merchant energy markets. Currently, we sell 70% to 80% of our unregulated generating capacity in operation under contracts greater than one year 42
in duration. We sell the remainder of this capacity under short-term contracts or directly into the merchant markets. The energy and capacity generated by our Arapahoe and Valmont projects, and the additional energy and capacity expected at these sites and at our Fountain Valley project upon its completion, are subject to long-term tolling agreements with Public Service Company of Colorado. Similarly, the electricity generated by the Adirondack Hydro facilities in New York is under a combination of short- and long-term agreements with Niagara Mohawk. HOW WE DEVELOP AND ACQUIRE POWER PLANTS. We plan to actively pursue power plant acquisitions and development opportunities in areas we view as attractive throughout North America. Our current focus has been, and is likely to remain, in the North American Reliability Council region known as the Western Systems Coordinating Council, or "WSCC." Among those factors we consider critical in evaluating the relative attractiveness of new generation opportunities are the following: - electric demand growth potential in the targeted region; - requirements for permitting and siting; - proximity of the proposed site to high transmission capacity corridors; - fuel supply reliability and pricing; - the local regulatory environment; and - the potential to exploit market expertise and operating efficiencies relating to geographic concentration of new generation with our existing power plant portfolio. We intend to target both acquisition and development opportunities which provide a minimum expected return on equity of 12 to 13%. We plan to concentrate on development projects over acquisitions because we believe that development projects generally offer us opportunities for higher rates of return. Our goal is to sell approximately 80% of the independent power generation portfolio under long-term contracts, while leaving the remainder available for merchant, or "spot" sales. We aim to secure long-term power sales contracts in conjunction with non-recourse plant financing. This enables us to design a debt repayment schedule to closely match the term of the power sales contracts so that at the end of the contract term, the debt has typically been repaid. INDEPENDENT POWER PLANTS GENERAL. Power facilities are often classified by cost of production. Facilities that have the lowest costs of production relative to other power plants in the region are usually the facilities that are first used to provide energy. These plants are known as "baseload" facilities and typically operate more than 60% of the time they are available. Our hydroelectric assets in New York and the Wygen I coal-fired facility under construction in Wyoming are examples of low-cost, baseload plants. As demand for electricity rises during the year or even during the course of a day, power plants that have higher costs of production are dispatched to supply additional energy. Facilities that regularly provide additional energy during a day and that are typically used between 10% and 60% of the time are known as "intermediate" facilities. Power plants with the highest costs of production are called upon only in times of exceptionally high demand and are known as "peaking units." Peaking units are generally dispatched less than 10% of the time they are available. ROCKY MOUNTAIN AND WEST COAST FACILITIES. We own approximately 151 megawatts of generating capacity in the WSCC states of California and Colorado, and are in the process of constructing or acquiring another 470 megawatts in the region. All of these facilities in operation are gas-fired, with all but the Harbor Cogeneration facility in California operating under long-term power purchase or tolling 43
agreements. The Harbor Cogeneration facility currently operates as a merchant peaking plant selling ancillary services and energy into the California market. WSCC FACILITIES TOTAL NET FUEL CAPACITY CAPACITY START POWER PLANT TYPE STATE (MWS) INTEREST (MWS) DATE - ----------- -------- -------- -------- -------- -------- -------- IN OPERATION: Arapahoe Unit 5...................... Gas CO 40.0 100% 40.0 2000 Arapahoe Unit 6...................... Gas CO 40.0 100% 40.0 2000 Valmont Unit 7....................... Gas CO 40.0 100% 40.0 2000 Ontario.............................. Gas CA 12.0 50% 6.0 1984 Harbor............................... Gas CA 80.0 31.8% 25.4 1989 ----- ----- TOTAL IN OPERATION................. 212.0 151.4 UNDER CONSTRUCTION: Fountain Valley...................... Gas CO 240.0 100% 240.0 2001 Arapahoe CC5......................... Gas CO 50.0 100% 50.0 2002 Valmont Unit 8....................... Gas CO 40.0 100% 40.0 2001 Wygen I.............................. Coal WY 90.0 100% 90.0 2003 BHG Gillette CT...................... Gas WY 40.0 100% 40.0 2001 Harbor Expansion..................... Gas CA 30.0 31.8% 9.5 2001 ----- ----- TOTAL IN CONSTRUCTION.............. 490.0 469.5 TOTAL WSCC......................... 702.0 620.9 ----- ----- ARAPAHOE, VALMONT AND FOUNTAIN VALLEY FACILITIES IN OPERATION: Our Arapahoe and Valmont plants are wholly-owned gas-fired peaking facilities in the Front Range of Colorado, with a total capacity of 120 megawatts. The projects were acquired from Public Service Company of Colorado in January 2000 jointly by the former Indeck Capital and us, and were put into service on June 1, 2000. We sell all of the output from these plants to Public Service Company of Colorado under tolling contracts expiring in May 2012. These contracts also cover the Fountain Valley project and the Arapahoe and Valmont expansion projects described below. UNDER CONSTRUCTION: We expect to increase our capacity by 40 megawatts at the Valmont project by May 2001 and by 50 megawatts at the Arapahoe plant by May 2002. In August 2000, we closed on a $60 million non-recourse project financing for the first phase of this expansion. We plan to finance our remaining construction costs through internally generated funds and additional non-recourse financing expected to close in the second quarter of 2001. The first phase of our 240 megawatt gas-fired Fountain Valley facility is scheduled for completion in June 2001, with final completion scheduled for July 2001. We anticipate that approximately $36 million of the net proceeds of this offering will be used to repay indebtedness incurred to pay a portion of the $175 million purchase price and related construction costs. The Fountain Valley site, located in Colorado has ample capacity for subsequent expansion if market conditions prove to be attractive. WYGEN I FACILITY The Wygen I facility is a leased mine-mouth coal-fired plant with a total capacity of 90 megawatts, which is expected to be completed by spring 2003. The Wygen I plant will be substantially identical in design to our Neil Simpson II facility, completed in 1995. The two plants will run on pulverized low-sulfur coal fed by conveyor from our adjacent Wyodak mine. The plant will burn approximately 44
500,000 tons of coal per year, and will use the latest available environmental control technology. We intend to sell the majority of the power from the facility under long-term unit contingent capacity and energy sales contracts, under which delivery requirements are reduced or eliminated during plant outages. We have entered into a contract to sell 60 megawatts of unit contingent capacity from this plant to Cheyenne Light, Fuel and Power Company with a term of 10 years from the date the plant becomes operational. We have also signed a contract to sell an additional 20 megawatts of unit contingent capacity and energy to the Municipal Electric Agency of Nebraska for a term of 10 years. BLACK HILLS GENERATION GILLETTE CT The Black Hills Generation Gillette CT facility, a gas-fired combustion turbine facility located at the same site as our Wygen I facility, has a total capacity of 40 megawatts and is scheduled to be completed in May 2001. We plan to utilize this facility as a merchant plant through summer 2001. Beginning in September 2001, we will sell the energy and capacity from this facility to Cheyenne Light, Fuel and Power Company under a 10-year unit contingent tolling agreement. ONTARIO COGENERATION FACILITY Ontario Cogeneration Company is a 12 megawatt, gas-fired power plant in Ontario, California, which is currently being operated as a baseload plant. Electrical output from the plant is subject to a 25-year power purchase agreement with Southern California Edison which expires in January 2010. The project also sells all of its steam production to Sunkist Growers, Inc. under a five-year agreement which terminates in November 2002. For a description of certain issues relating to our operation of this plant, see "--Regulation--Environmental Regulation--Clean Air Act." HARBOR COGENERATION FACILITY IN OPERATION: Harbor Cogeneration, a gas-fired plant located in Wilmington, California, is currently being operated as a merchant peaking plant selling ancillary services and energy into the CAISO market. It formerly operated under a 30-year power purchase agreement with Edison Mission Energy. This contract was terminated in February 1999 under a settlement agreement with Southern California Edison. Under the buyout agreement, Harbor Cogeneration will receive payments pursuant to a termination payment schedule for an amount equal to the total payment under the original contract due for the 11-year period beginning April 1, 1997 and ending on October 1, 2008. The facility currently has no long-term debt outstanding. For a discussion of some issues relating to the operation of the Harbor and Ontario plants, see "Risk Factors--Risks Relating to Our Industry--We have some exposure to market disruptions in California." UNDER CONSTRUCTION/EXPANSION: We are currently expanding the Harbor Cogeneration plant by an additional 30 megawatts (10 megawatt net ownership interest), with a targeted completion date of May 2001. The plant has sold the peaking capacity from its expansion to the CAISO for the peak summer periods of 2001 through 2003 under an agreement that provides for payments to us of $1 million per year for each of 2001, 2002 and 2003. We plan to sell the remaining capacity and all of the energy from this plant expansion in the California market on a merchant basis. LANGE PROJECT In March 2001, we placed an order for a 40 megawatt gas-fired combustion turbine which will be located either adjacent to the Wygen I and our Black Hills Generation Gillette CT plants near Gillette, Wyoming, or at a new site adjacent to our transmission system in Rapid City, South Dakota, where we have received all necessary permits for the construction of two 40 megawatt combustion turbine facilities. We expect the first 40 megawatt turbine unit to be operational in early 2002. NORTHEAST FACILITIES. We currently own approximately 58 net megawatts of generation capacity in eight plants in the Northeast region, all of which are located in New York and Massachusetts. Sixty- 45
seven percent of this generation is "run-of-river" hydroelectric, with the remainder being gas-fired peaking capacity. TOTAL NET FUEL CAPACITY CAPACITY START POWER PLANT TYPE STATE (MWS) INTEREST (MWS) DATE - ----------- -------- -------- -------- -------- -------- -------- NORTHEAST New York State Dam.................. Hydro NY 11.4 100% 11.4 1990 Middle Falls........................ Hydro NY 2.3 50% 1.2 1989 Sissonville......................... Hydro NY 3.0 100% 3.0 1990 Warrensburg......................... Hydro NY 2.9 100% 2.9 1988 Hudson Falls........................ Hydro NY 41.9 30.2% 12.7 1995 South Glens Falls................... Hydro NY 13.9 30.2% 4.2 1994 Fourth Branch....................... Hydro NY 3.4 100% 3.4 1988 Pepperell........................... Gas MA 40.0 48.7% 19.5 1990 ----- ---- TOTAL (NORTHEAST)................. 118.8 58.3 ADIRONDACK HYDRO DEVELOPMENT The seven "run-of-river" hydroelectric plant interests acquired as a result of our acquisition of Indeck Capital are: - New York State Dam, an 11.4 megawatt plant located in Waterford and Cohoes, New York; - Middle Falls, a 2.3 megawatt plant located in Easton, New York; - Sissonville, a 3.0 megawatt plant located in Potsdam, New York; - Warrensburg, a 2.9 megawatt plant located in Warrensburg, New York; - Hudson Falls, a 41.9 megawatt plant located in Moreau, New York; - South Glens Falls, a 13.9 megawatt plant located in South Glens Falls, New York; and - Fourth Branch, a 3.4 megawatt plant located in Waterford, New York. We acquired approximately 10% of the Hudson Falls and the South Glens Falls plants as part of the Indeck Capital acquisition and an additional 20% of these plants in December 2000. These projects run at a high capacity factor because the Hudson River is regulated for power generation and flood control. The seven projects were initially covered by long-term power purchase contracts with Niagara Mohawk for all or most of their output. Currently, three projects have been restructured to allow the power purchase contracts to be bought out and for us eventually to sell power into the New York Independent System Operator. The New York State Dam, Sissonville, Fourth Branch and Warrensburg facilities are currently subject to short-term transition power sales agreements expiring in 2002 and 2003, at which point these plants will sell directly into the market on a merchant basis. The remaining three New York plants, Hudson Falls, South Glens Falls and Middle Falls, continue to operate under long-term power purchase agreements with Niagara Mohawk. PEPPERELL FACILITY The Pepperell facility is a 40 megawatt gas-fired combined-cycle plant located in Pepperell, Massachusetts. The plant is currently subject to a tolling agreement with Enron Power and Trading for the sale of a majority of its energy for the year 2001, and a steam sales agreement with the Pepperell Paper Company expiring in November 2001. 46
POWER FUNDS. In addition to our ownership of the power plants described above, we hold various indirect interests in power plants through our investment in energy and energy-related funds, both domestic and international, as described below: NUMBER TOTAL OUR NET OF CAPACITY EQUITY CAPACITY FUND NAME PLANTS (MWS) INTEREST (MWS) - --------- -------- -------- -------- -------- Energy Investors Fund I..................................... 7 136.0 12.6% 17.1 Energy Investors Fund II.................................... 6 130.0 6.9% 9.0 Project Finance Fund III.................................... 7 239.0 5.3% 12.7 Caribbean Basin............................................. 1 34.0 3.7% 1.3 ----- ---- TOTAL FUND INTERESTS...................................... 539.0 40.1 FINANCING OF OUR INDEPENDENT POWER PROJECTS. We have financed our principal independent power generation facilities primarily with non-recourse debt that is repaid solely from the project's revenues. This type of financing is referred to as "project financing." These financings generally are secured by the physical assets, major project contracts and agreements, cash accounts and, in certain cases, our ownership interest, in the related project. True project financing is not available for all projects, including some assets purchased out of bankruptcy, some merchant plants and some purchases of minority stock positions in publicly-traded companies. Even in those instances, however, we may still be able to finance a smaller portion of the total cost with project financing, with the remainder financed with debt that is either raised or supported at the corporate rather than the project level. Project financing transactions generally are structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds then are payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used first to pay operating expenses, senior debt service and taxes and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratios and certain other conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, to the payment of subordinated debt service. These project financing structures are designed to prevent the lenders from relying on us or our other projects for repayment; that is, they are "non-recourse" to us and our affiliates not involved in the project, unless we or another affiliate expressly agree to undertake liability. In the event of a foreclosure after a default, our project affiliate owning the facility would only retain an interest in the assets, if any, remaining after all debts and obligations were paid. In addition, the debt of each operating project may reduce the liquidity of our equity interest in that project because the interest is typically subject both to a pledge securing the project's debt and to transfer restrictions set forth in the relevant financing agreements. Also, our ability to transfer or sell our interest in certain projects or the project's power is restricted by certain purchase options or rights of first refusal in favor of our partners and certain change of control restrictions in the project financing documents. In August 2000, Black Hills Energy Capital obtained $60 million in non-recourse project financing in conjunction with the Arapahoe (80 megawatt) and Valmont (40 megawatt) projects which were brought into service in 2000. We anticipate using approximately $36 million of the net proceeds of this offering to repay indebtedness incurred to fund our equity contribution in the Fountain Valley project. The remainder of the purchase price was funded, and the related construction costs are expected to be funded, with non-recourse project financing. In addition to project financing, we have obtained a credit facility to provide flexibility in financing the growth of the independent energy group. In July 2000, in conjunction with the closing of the Indeck Capital acquisition, Black Hills Energy Capital obtained a new $115 million revolving credit facility. 47
FUEL PRODUCTION COAL Our coal production unit mines and processes low-sulfur, sub-bituminous coal near Gillette, Wyoming. The Wyodak mine, which we acquired in 1956 from Homestake Gold Mining Company, is located on top of the Powder River Basin, one of the largest coal reserves in the United States. We believe the Wyodak mine is the oldest operating surface coal mine in the nation, with an annual production of approximately three million tons. Mining rights to the coal are based on four federal leases and one state lease. We pay royalties of 12.5% and 9.0%, respectively, of the selling price on all federal and state coal. As of December 31, 2000, we had coal reserves of 275 million tons, enough to satisfy present contracts for over 90 years. Substantially all of our coal production is sold under long-term contracts to Black Hills Power, Inc., our electric utility, and to PacifiCorp. Our coal unit's agreement with Black Hills Power limits earnings from all coal sales to Black Hills Power to a specified return on our original cost depreciated investment base. Black Hills Power made a commitment to the South Dakota Public Utilities Commission, the Wyoming Public Service Commission and the City of Gillette that coal would be furnished and priced as provided by that agreement for the life of our Neil Simpson II plant. The price for unprocessed coal sold to PacifiCorp for its 80% interest in the Wyodak plant is determined under a coal supply agreement terminating in 2022. For a description of litigation with PacifiCorp relating to a predecessor coal supply agreement and the settlement agreement resolving this litigation and establishing a new coal supply agreement, see "--Legal Proceedings." In May 2000, we acquired the K-Fuel plant, a coal enhancement plant located near our Gillette, Wyoming coal mine. The plant, which transforms high-moisture, low-heat-value coal into low-moisture, high-heat-value coal, is currently not in service. We are working in conjunction with Denver-based KFx, Inc. to attract investors to make the capital improvements necessary to re-start the plant. If we do not locate suitable investment partners, the plant will not be re-started. Over the next several years, we expect to increase coal production to supply: - PacifiCorp, under the terms of the new coal supply agreement and other coal sales agreements entered into in connection with the settlement of the PacifiCorp litigation; - the Wygen I 90 megawatt mine-mouth power plant, which is scheduled for completion in 2003; and - additional mine mouth generating capacity of up to 500 megawatts at the same site as the Wygen I plant, which is in the early stages of development. In addition, if our K-Fuel plant is re-started, we expect to increase production from the Wyodak mine and market any low-moisture, high-heat content coal we produce to an expanded customer base. NATURAL GAS AND CRUDE OIL Our oil and gas exploration and production unit operates 298 oil and gas wells, all of which are located in Wyoming. The majority of these wells are in the Finn-Shurley Field area, located in Weston and Niobrara Counties in Wyoming. We also own a working interest in, but do not operate, an additional 341 wells located in California, Montana, North Dakota, Texas, Wyoming, Oklahoma and offshore in the Gulf of Mexico. In addition, we have accumulated significant acreage in the Rocky Mountain region, which we plan to utilize for oil and gas exploration. 48
We plan to substantially increase our natural gas reserves and minimize exploration risk by focusing on lower-risk exploration and development drilling and acquisitions of proven producing properties. A key component of this strategy is the pursuit of shallow gas opportunities in the Rocky Mountain region. We also expect to modestly increase our California and offshore production in the future, but do not plan to serve as the operator for those production activities. As of December 31, 2000, we had proved reserves of 4.4 million barrels of oil and 18.4 billion cubic feet of natural gas, with approximately 62% of current production consisting of natural gas. In 2000, our oil and gas production increased 12% over 1999 levels, with record drilling results and year-end reserves. In March 2001, we signed a definitive agreement to purchase certain operating and non-operating interests in 74 oil and gas wells located primarily in Colorado and Wyoming. We expect this transaction to close in April 2001. These properties have proved reserves of approximately 8.7 billion cubic feet of natural gas and approximately 200,000 barrels of oil, representing an increase in our existing proved reserves of over 20%. FUEL MARKETING. We market natural gas, oil and coal in specific regions of the United States. We offer physical and financial wholesale fuel marketing and price risk management products and services to a variety of customers. These customers include natural gas distribution companies, municipalities, industrial users, oil and gas producers, electric utilities, coal mines, energy marketers and retail gas users. Our fuel marketing businesses collectively have 35 employees. Our average daily marketing volumes for the year ended December 31, 2000, were 860,800 million British thermal units of gas, 44,300 barrels of oil and 4,400 tons of coal. The following table briefly summarizes the location of our fuel marketing operations and sales offices: COMPANY FUEL MARKETING OPERATIONS SALES OFFICES - ------- ----------- -------------------- ----------------------------- Enserco Energy............... Natural Gas Golden, CO Chicago, IL; Calgary, Alberta, Canada Black Hills Energy Resources.................. Crude Oil Houston, TX Tulsa, OK; Midland, TX; Longview, TX Black Hills Coal Network..... Coal Mason, OH St. Clairsville, OH GAS MARKETING Our natural gas marketing operations are headquartered in Golden, Colorado, with satellite offices in Calgary, Canada and Chicago, Illinois. Our gas marketing operations focus primarily on wholesale marketing and producer marketing services. Producer services include providing for direct purchases of wellhead gas and for risk transfer and hedging products. Our gas marketing efforts are concentrated in the Rocky Mountain and West Coast regions and in Western Canada, which are areas in which we believe we have a competitive advantage due to our knowledge of local markets. We contractually hold natural gas storage capacity and both long and short-term transportation capacity on several major pipelines in the western United States and Canada. We utilize this capacity to move relatively low cost natural gas from the producer regions to more expensive end-use market areas. Our gas marketing unit maintains a $90 million credit facility with Bank of America, N.A., as agent. We provide no guarantees or other forms of support for this facility. 49
OIL MARKETING AND TRANSPORTATION Our crude oil marketing and transportation operations are concentrated primarily in Texas, Oklahoma, Louisiana and Arkansas. In July 1999, we acquired a 33% ownership interest in a 200-mile pipeline, with a capacity of 67,000 barrels of oil per day, that transports imported crude oil from Beaumont, Texas to refining and trading markets in northern regions. Our oil marketing unit maintains a $25 million transactional-based credit facility (with a $12.5 million overdraft line) with Bank of America, N.A., as agent. The line of credit provides credit support for the purchase of crude oil. We provide no guarantees or other forms of support for this facility. COAL MARKETING We market coal to various industrial customers and power plants located primarily in the midwest and eastern regions of the United States through our coal marketing subsidiary, Black Hills Coal Network. We formed Black Hills Coal Network in 1998 to acquire the assets and hire the operational management of Coal Network and Coal Niche, based in Mason, Ohio. These predecessor companies were coal brokerage and agency companies with customers located primarily east of the Mississippi River. Our coal marketing unit maintains a $4 million credit facility with Fifth Third Bank, N.A., as agent. Our coal mining subsidiary, Wyodak Resources Development Corporation, provides a $1 million guarantee on this facility. ELECTRIC UTILITY--BLACK HILLS POWER, INC. Our electric utility, Black Hills Power, is engaged in the generation, transmission and distribution of electricity. It provides a solid foundation of revenues, earnings and cash flow that support utility capital expenditures, dividends, and overall performance and growth. EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC CUSTOMER MIX BASED ON 2000 REVENUE RESIDENTIAL 20% Municipal 1% Commercial 26% Off-system Wholesale 29% Industrial 14% Contract Wholesale 10% EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC FUEL MIX DIESEL 3% Coal 62% Gas 10% Oil/Gas 25% DISTRIBUTION AND TRANSMISSION. Our electric utility distribution and transmission businesses serve approximately 58,600 customers, with an electric transmission system of 447 miles of high voltage lines and 541 miles of lower voltage lines. Our utility's service territory covers a 9,300 square mile area of western South Dakota, eastern Wyoming and southeastern Montana with a strong and stable economic base. Over 90% of our utility's retail electric revenues are generated in South Dakota. The following are characteristics of our distribution and transmission businesses: - We have a diverse customer and revenue base. Our revenue mix in 2000 is comprised of 29% wholesale off-system sales, 26% commercial, 20% residential, 14% industrial, 10% contract wholesale and 1% municipal. Approximately 68% of our large commercial and industrial customers are provided service under long-term contracts. We have historically optimized the 50
utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market and through short-term sales contracts. - In 1999, the South Dakota Public Utilities Commission extended our previous retail rate freeze for another five-years, through January 1, 2005. The rate freeze preserves our low-cost rate structure at levels below the national average for our retail customers while allowing us to retain the benefits from cost savings and from wholesale "off-system" sales, which are not covered by the rate freeze. This provides us with flexibility in allocating our generating capacity to maximize returns in changing market environments. - Twenty-nine percent of our electric revenues for the year ended December 31, 2000 consisted of off-system sales compared to 8% in 1999 and 5% in 1998. Further increases in the volume of off-system sales are expected in the future due to demand growth in the Rocky Mountain region and the June 2000 addition of 40 megawatts of gas-fired generating capacity. - Our system has the capability of connecting to either the midwestern or western transmission systems, which provides us with access between the WSCC region and the Mid-Continent Area Power Pool, or "MAPP" region. This allows us the opportunity to improve system reliability and take advantage of power price differentials between the two electric grids. We are able to transmit up to 80 megawatts of our generation into the MAPP. Alternatively, we can receive up to 20 megawatts of power from MAPP into our WSCC-based system. We expect to increase this capability to 50 megawatts in 2001 through an upgrade of our facilities at a cost of less than $1 million. - We have firm transmission access to deliver up to 65 megawatts of power on PacifiCorp's system to wholesale customers in the western region. On October 15, 2000, we indicated to FERC our intent to participate in a regional transmission organization, or RTO. Our transmission system is a part of the western transmission grid governed by the Western Systems Coordinating Council, and it interconnects with transmission systems operated by the Western Area Power Administration, or WAPA, and by PacifiCorp. WAPA is evaluating participation in the Desert Star RTO which will involve transmission systems in Colorado and the southwest region, while PacifiCorp is evaluating participation in the RTO West which will involve transmission systems in Wyoming and the northwest region. Neither Desert Star RTO nor RTO West has been formally organized at this time, but we expect that Desert Star RTO and RTO West will be making their final FERC filings late this year or in early 2002. If FERC approves these two RTOs, the organizations anticipate being fully operational in late 2002. We will continue to monitor the development of these two RTOs and decide in the future which RTO best fits our transmission system and operations. POWER PURCHASE AGREEMENTS. We sell approximately 40% of our utility's current load under long-term contracts. Our key contracts include a 10-year contract expiring in 2007 with Montana-Dakota Utilities Company for the sale of up to 55 megawatts of energy and capacity to service the Sheridan, Wyoming electric service territory, and a contract with the City of Gillette, Wyoming, expiring in 2012, to provide the city's first 23 megawatts of capacity and energy. Both contracts are integrated into our control system and are treated as firm native load. In addition, we recently entered into an agreement with the Municipal Electric Agency of Nebraska for the sale of 30 megawatts of unit contingent energy and capacity for a period through the completion of construction of the Wygen I independent power facility, which is expected in spring 2003. For the 10-year period beginning with the completion of the Wygen I facility, our utility and our independent power unit will each provide 20 megawatts of unit contingent energy and capacity to the Municipal Electric Agency of Nebraska. 51
Our utility's electric load is served by coal-, oil- and natural gas-fired generating units providing 393 megawatts of generation capacity and from the following purchased power and capacity contracts with PacifiCorp: - a power sales agreement expiring in 2023, involving the purchase by us of 65 megawatts of baseload power in 2001, and scheduled to decline to 50 megawatts by 2004; - a reserve capacity integration agreement expiring in 2012, which makes available to us 100 megawatts of reserve capacity in connection with the utilization of the Ben French CT units; and - a capacity option call, which gives us an option to purchase up to 60 megawatts of peaking capacity seasonally through March 31, 2007. REGULATED POWER PLANTS. Since 1995, our utility has been a net producer of energy. Our utility owns 393 megawatts of generating capacity, all of which is located in the Rocky Mountain region. Our utility's peak system load of 372 megawatts was reached in July 2000. None of our generation is restricted by hours of operation, thereby providing us with the ability to generate power to meet demand whenever necessary and feasible. The following table describes our utility's portfolio of power plants: TOTAL NET FUEL CAPACITY CAPACITY START POWER PLANT TYPE STATE (MWS) INTEREST (MWS) DATE - ----------- -------- -------- -------- -------- -------- --------- Ben French............... Coal SD 25.0 100% 25.0 1960 Ben French Diesels 1-5... Diesel SD 10.0 100% 10.0 1965 Ben French CT's 1-4...... Gas/Oil SD 100.0 100% 100.0 1977-1979 Neil Simpson I........... Coal WY 21.8 100% 21.8 1969 Neil Simpson II.......... Coal WY 88.9 100% 88.9 1995 Osage.................... Coal WY 34.5 100% 34.5 1948 Wyodak................... Coal WY 362.0 20% 72.4 1978 Neil Simpson CT.......... Gas WY 40.0 100% 40.0 2000 ----- ----- TOTAL................ 682.2 392.6 ----- ----- BEN FRENCH Ben French is a wholly-owned coal-fired plant situated in Rapid City, South Dakota, with a capacity of 25 megawatts. This plant was put into service in 1960 and has since been operating as a baseload plant. Coal for the plant is purchased from our Wyodak mine and delivered by truck. BEN FRENCH DIESEL UNITS 1-5 The Ben French Diesel Units 1-5 are wholly-owned diesel-fired plants located in Rapid City, South Dakota, with a capacity of 10 megawatts. These plants were put into service in 1965, and are being operated as peaking plants. BEN FRENCH CT'S 1-4 The Ben French Combustion Turbines 1-4 are wholly-owned gas and oil-fired units with a capacity of 100 megawatts located in Rapid City, South Dakota. These facilities were put into service from 1977 to 1979, and are being operated as peaking units. 52
NEIL SIMPSON I AND II Neil Simpson I and II are air-cooled, coal-fired wholly-owned facilities located near Gillette, Wyoming. Neil Simpson I has a capacity of 21.8 megawatts and was put into service in 1969. Neil Simpson II has a capacity of 88.9 megawatts and was put into service in 1995. These plants are operated as baseload facilities, and are mine-mouth coal-supplied plants, receiving their coal directly from the Wyodak mine. OSAGE The Osage plant is a wholly-owned coal-fired plant in Osage, Wyoming with a total capacity of 34.5 megawatts and was put into service from 1948 to 1952. This plant has three turbine generation units, and is being operated as a baseload plant. Coal for the plant is purchased from our Wyodak mine and delivered by truck. WYODAK Wyodak is a 362 megawatt mine mouth coal-fired plant owned jointly by PacifiCorp and us and in which we hold a 20% (72.4 net megawatt) ownership interest. Our Wyodak mine furnishes all the coal fuel supply for the Wyodak plant. The plant was put into service in 1978, and is currently being operated as a baseload plant. NEIL SIMPSON CT The Neil Simpson Combustion Turbine is a wholly-owned gas-fired plant located near Gillette, Wyoming with a capacity of 40 megawatts. This plant was put into service in 2000, and was installed to provide peaking capabilities. COMMUNICATIONS Our communications group, known as Black Hills FiberCom, was formed to provide state-of-the-art broadband telecommunications services to the underserved markets of Rapid City and the northern Black Hills of South Dakota. We offer residential and business customers a full suite of telecommunications services, including local and long distance telephone service, expanded cable television service, cable modem Internet access and high speed data and video services. We have completed a 210-mile inter- and intra-city fiber optic network and currently operate 588 miles of two-way interactive hybrid fiber coaxial or "HFC" cable. We believe we are one of the first companies in the United States to provide video entertainment service, high-speed Internet access, and local and long distance telephone services over an advanced broadband infrastructure. We have bundled these services into value packages with a single consolidated bill for all of these services. We introduced our broadband communications services to the Rapid City and northern Black Hills areas in November 1999. As of December 31, 2000, we had attracted 8,368 residential customers and 646 business customers. Our goal is to double the number of our customers, and to attain 50% residential market penetration within our service territory while serving 35% of all broadband business customers in that territory. The construction of our communications network is approximately 75% complete and we expect to substantially complete construction in 2001. We estimate that completing our network will require approximately $25 million of capital expenditures in 2001. We expect our communications unit to sustain approximately $10 million in net losses in 2001, with annual losses decreasing and profitability expected in the next three to four years. 53
COMPETITION The independent power, fuel production and fuel marketing industries are characterized by numerous strong and capable competitors, some of which may have more extensive operating experience, larger staffs or greater financial resources than us. In particular, the independent power industry in recent years has been characterized by increased competition for asset purchases and development opportunities. In addition, Congress has considered various pieces of legislation to restructure the electric industry that would require, among other things, customer choice and/or repeal of PUHCA. The debate is likely to continue and perhaps intensify. The effect of enacting such legislation cannot be predicted with any degree of certainty. Industry deregulation may encourage the disaggregation of vertically integrated utilities into separate generation, transmission and distribution businesses. As a result of these potential regulatory changes, significant additional competitors could become active in the generation segment of our industry. Our communications unit faces competition from numerous well established companies, including Qwest Communications, Rapid City's incumbent local exchange carrier, Midcontinent Communications, the area's incumbent cable television provider, as well as long distance providers and Internet service providers. Our success in this business will depend upon, among other things, the quality of our customer service, the willingness of residential and business customers to accept us as an alternative provider of broadband communications services, our products and services and our ability to offer an attractive package of bundled products. FINANCING In the past, we have relied upon internally generated funds and short- and long-term debt to finance our activities. We expect that an appropriate mix of financing options, including short- and long-term debt and preferred and common stock, will be used to finance future activities. With expected growth in the independent energy business unit, we anticipate that our long-term debt ratio will increase to 55% to 60% over the next five years. We expect to finance the growth of our independent power unit primarily with project financing. See "--Independent Power Plants--Financing of our Independent Power Projects." We currently have bank lines of credit totaling $290 million which provide for interim borrowings and the opportunity for timing of permanent financing. As of December 31, 2000, we had $211 million in notes and $20.6 million in letters of credit outstanding under these lines. There are no compensating balance requirements associated with these lines of credit. In addition to the above lines of credit, Enserco Energy, Inc., our gas marketing unit, has a $90 million uncommitted, discretionary credit facility. This borrowing base line of credit provides credit support for the purchase of natural gas. We and our subsidiaries provide no guarantee to the lender. At December 31, 2000, Enserco had letters of credit outstanding of $69.8 million. Black Hills Energy Resources, Inc., our oil marketing and transportation unit, has a $25 million, uncommitted, discretionary credit facility. This transaction line of credit provides credit support for the purchases of crude oil. We and our subsidiaries provide no guarantee to the lender. At December 31, 2000, Black Hills Energy Resources had letters of credit outstanding of $8.5 million. RISK MANAGEMENT Our fuel marketing operations require efficient risk management of price, counterparty performance and operational risks. Price risk is created through the volatility of energy prices. Counterparty performance risk is the risk that a counterparty will fail to satisfy its contractual 54
obligations to us, and includes credit risk. Operational risk arises from a lack of internal controls. We have implemented controls to mitigate each of these risks. Our fuel marketing operations are conducted in accordance with guidelines established through separate risk management policies and procedures for each marketing company and through our credit policy. These policies are established by our board of directors, reviewed on a regular basis and monitored as described below. We maintain a working risk management committee for each of our marketing companies, and a credit committee at the parent company level. The risk management committees focus on implementation of risk management procedures and on monitoring compliance with established policies. The credit committee sets counterparty credit limits, monitors credit exposure levels and reviews compliance with established credit policies. Additionally, we employ a risk manager and a credit manager responsible for overseeing these functions. Our risk management policies and procedures specify maximum price risk exposure levels within which each respective marketing company must operate. These policies and procedures establish relatively low exposure levels and prohibit speculative trading strategies. As part of our enterprise-wide risk management strategy, we limit our exposure to energy marketing risks by maintaining separate credit facilities within each of our fuel marketing companies. These credit facilities have security interests solely against the assets of the respective marketing company, with the exception of a $1 million guarantee by our coal mining subsidiary on our coal marketing unit's credit facility. We do not currently issue parent company performance guarantees to counterparties of our marketing companies. A significant potential risk related to power sales is the price risk arising from the sale of wholesale power that exceeds our generating capacity. Short positions can arise from unplanned plant outages or from unanticipated load demands. To control such risks, we restrict wholesale off-system sales to amounts by which our anticipated generation capabilities exceed our anticipated load requirements plus a required reserve margin. We further control this risk by selling only in the day-ahead power market and by entering into longer-term sales contracts that are made on a "unit contingent" basis, under which delivery is not required during unplanned outages at specified power plants. REGULATION We are subject to a broad range of federal, state and local energy and environmental laws and regulations applicable to the development, ownership and operation of our projects. These laws and regulations generally require that a wide variety of permits and other approvals be obtained before construction or operation of a power plant commences and that, after completion, the facility operate in compliance with their requirements. We strive to comply with the terms of all such laws, regulations, permits and licenses and believe that all of our operating plans are in material compliance with all such applicable requirements. ENERGY REGULATION FEDERAL POWER ACT. The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC's jurisdiction are required to file rate schedules with FERC prior to commencement of wholesale sales or interstate transmission of electricity. Public utilities with cost-based rate schedules are also subject to accounting, record-keeping and reporting requirements administered by FERC. 55
THE ENERGY POLICY ACT. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing certain exemptions from regulation for exempt wholesale generators, or EWGs. All of our subsidiaries that would otherwise be treated as public utilities are currently treated as EWGs under the Energy Policy Act. An EWG is an entity that is exclusively engaged, directly or indirectly, in the business of owning or operating facilities that are exclusively engaged in generation and selling electric energy at wholesale. An EWG will not be regulated under PUHCA, but is subject to FERC and state public utility commission regulatory reviews, including rate approval. Since EWGs are only allowed to sell power at wholesale, their rates must receive initial approval from FERC rather than the states. All of our EWGs to date that have sought rate approval from FERC have been granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates. However, FERC customarily reserves the right to suspend, upon complaint, market-based rate authority on a prospective basis if it is subsequently determined that we or any of our EWGs exercised market power. If FERC were to suspend market-based rate authority, it would most likely be necessary to file, and obtain FERC acceptance of, cost-based rate schedules for any of our EWGs. Also, the loss of market-based rate authority would subject the EWGs to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules. In addition, if there occurs a "material change" in facts that might affect any of our subsidiaries' eligibility for EWG status, within 60 days of the material change, the relevant EWG must (1) file a written explanation of why the material change does not affect its EWG status, (2) file a new application for EWG status, or (3) notify FERC that it no longer wishes to maintain EWG status. If any of our subsidiaries were to lose EWG status, we, along with our affiliates, would be subject to regulation under PUHCA as a public utility company. Absent a substantial restructuring of our business, it would be difficult for us to comply with PUHCA without a material adverse effect on our business. STATE ENERGY REGULATION. In areas outside of wholesale rate regulation (such as financial or organizational regulation), some state utility laws may give their public utility commissions broad jurisdiction over steam sales or EWGs that sell power in their service territories. The actual scope of the jurisdiction over steam or independent power projects depends on state law and varies significantly from state to state. ENVIRONMENTAL REGULATION The construction and operation of power projects are subject to extensive environmental protection and land use regulation in the United States. These laws and regulations often require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. If such laws and regulations are changed and our facilities are not grandfathered, extensive modifications to project technologies and facilities could be required. GENERAL. Based on current trends, we expect that environmental and land use regulation will continue to be stringent. Accordingly, we actively review proposed construction projects that could subject us to stringent pollution controls imposed on "major modifications," as defined under the Clean Air Act, and changes in "discharge characteristics," as defined under the Clean Water Act. The goal of these actions is to achieve compliance with applicable regulations, administrative consent orders and variances from applicable air-quality related regulations. CLEAN AIR ACT. Our Neil Simpson II and Wyodak plants located in Gillette, Wyoming are subject to Title IV of the Clean Air Act, which requires certain fossil-fuel-fired combustion devices to hold sulphur dioxide "allowances" for each ton of sulphur dioxide emitted. We currently hold sufficient allowances credited to us as a result of sulfur removal equipment previously installed at the Wyodak plant to apply to the operation of the Neil Simpson II plant and our interest in the Wyodak plant 56
through 2030 without requiring the purchase of any additional allowances. With respect to any future plants, we plan to comply with the need for holding the appropriate number of allowances by reducing sulphur dioxide emissions through the use of low sulphur fuels, installation of "back end" control technology and the purchase of allowances on the open market. We expect to integrate the costs of obtaining the required number of allowances needed for future projects into our overall financial analysis of such projects. On July 14, 2000, the South Coast Air Quality Management District, known as SCAQMD, sent a letter to our affiliate, now called Black Hills Ontario, L.L.C., the operator of a 12 megawatt natural-gas fired cogeneration facility located in Ontario, California, stating that the SCAQMD had determined, as a result of a facility audit completed for the compliance year ended June 1, 1999, that the facility's nitrogen oxide, or NOx, emissions were 28,958 pounds over the facility's NOx allocation established by the SCAQMD's RECLAIM emissions trading program. As a result, the SCAQMD indicated that it would be reducing the facility's NOx allocation by the same number of allowance for the compliance year subsequent to a final determination on this issue. If a final determination is reached prior to June 30, 2001, the NOx allowances would be deducted from the facility's allocation for the compliance year ended June 30, 2002. Black Hills Ontario has provided documentation to the SCAQMD disputing this proposed reduction. In addition to this proposed reduction, which could affect the facility's compliance with RECLAIM requirements for the 2001-2002 compliance period, Black Hills Ontario also projects that its NOx emissions for the compliance year ended June 30, 2001 may be approximately 30,000 pounds over its current NOx allocation. There is currently significant volatility in the price and supply of RECLAIM NOx allowances; although the SCAQMD has proposed a revision to its regulations to stabilize the RECLAIM market, it is unclear whether these rules will mitigate Black Hills Ontario's potential exposure for its projected allowance shortfall. Accordingly, no assurance can be given at this time regarding whether RECLAIM NOx allowances will be available for purchase to allow Black Hills Ontario to comply with RECLAIM requirements for the year ended June 30, 2001, or, if allowances are available, as to the cost of those allowances. Black Hills Ontario may also be subject to administrative or civil penalties with respect to alleged violations of the SCAQMD's regulation for the compliance year ended June 30, 1999, although no notice of any penalties has been issued. In July 1999, the United States Environmental Protection Agency finalized rules designed to protect and improve visibility impairment resulting from air emissions. Among other things, the regulations required states to identify sources of emissions (including some coal-fired generating units built between 1962 and 1977) by 2004 that would be subject to "best available retrofit technology", known as BART. These sources would be required to implement BART within five years after the EPA approved state plans adopted to combat visibility impairment. The submission of these plans is due between 2004 and 2008. In January 2001, the EPA proposed guidance to assist states in determining which sources should be subject to the BART requirement, but the proposed guidance has not been published pending a review by the newly appointed administrator of the EPA. See "Risk Factors--Risks Relating to our Industry." If the proposed rules are adopted, management believes that the only existing plant which may be required to comply with Clean Air Act requirements is our Neil Simpson I plant and that any capital expenditures associated with bringing the plant into compliance would not have a material adverse effect on our financial condition or results of operations. Title V of the Clean Air Act imposes federal requirements which dictate that all of our fossil fuel-fired generation facilities must obtain operating permits. All of our existing facilities subject to this requirement have submitted timely Title V permit applications and received permits. On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's "new source review" requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these lawsuits. In addition, the EPA has also issued administrative notices of violation alleging similar violations at additional power plants 57
owned by some of the same utilities named as defendants in the Department of Justice lawsuit, and also issued an administrative order to the Tennessee Valley Authority for similar violations at some of its power plants. The EPA has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities seeking to determine whether those utilities also engaged in activities that may have been in violation of the Clean Air Act's new source review requirements. To date, we are aware of three large utilities that have either settled with the United States or have reached agreements in principle to resolve these actions. In each case, the settling party has agreed (or agreed in principle) to incur over $1 billion in expenditures for the installation of additional pollution control, the retirement or repowering of coal-fired generating units, supplemental environmental projects and civil penalties. No such proceedings have been initiated or requests for information issued with respect to any of our facilities, but there can be no assurance that we will not be subject to similar proceedings in the future. In December 2000, the EPA announced its intention to regulate mercury emissions from coal-fired and oil-fired electric power plants under Section 112 of the Clean Air Act. The EPA is committed to proposing a rule to regulate these emissions by no later than 2003. Because we do not know what the EPA may require with respect to this issue, we are not able to evaluate the impact of potential mercury regulations on the operation of our facilities. Since the adoption of the United Nations Framework on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton administration participated in the Kyoto, Japan negotiations, where the basis of a climate change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required between 2008 and 2012 to reduce its greenhouse gas emissions by 7% from 1990 levels. However, because of opposition to the treaty in the United States Senate, the Kyoto Protocol has not been submitted to the Senate for ratification. Although legislative developments on the state level related to controlling greenhouse gas emissions have occurred, we are not aware of any similar developments in the states in which we operate. If the United States ratifies the Kyoto Protocol or we otherwise become subject to limitations on emissions of carbon dioxide from our plants, these requirements could have a significant impact on our operations. In March 2001, the Bush administration announced that it would not seek to impose any limitations on carbon dioxide emissions. CLEAN WATER ACT. Our existing facilities are also subject to a variety of state and federal regulations governing existing and potential water/wastewater discharges. Generally, such regulations are promulgated under authority of the Clean Water Act and govern overall water/wastewater discharges through National Pollutant Discharge Elimination System, or NPDES, permits. Under current provisions of the Clean Water Act, existing NPDES permits must be renewed every five years, at which time permit limits are extensively reviewed and can be modified to account for changes in regulations or program initiatives. In addition, the permits have re-opener clauses which allow the permitting authority (which may be the United States or an authorized state) to attempt to modify a permit to conform to changes in applicable laws and regulations. Some of our existing facilities have been operating under NPDES permits for many years and have gone through one or more NPDES permit renewal cycles. Two of these facilities are currently in the process of renewing their existing NPDES permits. SOLID WASTE DISPOSAL. We dispose of all solid wastes collected as a result of burning coal at our power plants in approved solid waste disposal sites. Each disposal site has been permitted by the state of its location in compliance with law. Ash and wastes from flue gas and sulfur removal from the Wyodak and Neil Simpson II plants are deposited in mined areas. These disposal areas are located below some shallow water aquifers in the mine. None of the solid wastes from the burning of coal is classified as hazardous material, but the wastes do contain minute traces of metals that would be perceived as polluting if such metals were leached into underground water. Recent investigations have concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground 58
water quality. While management does not believe that any substances from our solid waste disposal activities will pollute underground water, they can give no assurances that pollution will not occur over time. In this event, we could experience material costs to mitigate any resulting damages. Agreements in place require PacifiCorp to be responsible for any such costs that would be related to the solid waste from its 80% interest in the Wyodak plant. Additional unexpected material costs could also result in the future if the federal or state government determines that solid waste from the burning of coal contains some hazardous material that requires special treatment, including solid waste of which we previously disposed. In that event, the government regulator could consequently hold those entities that disposed of such waste responsible for such treatment. MINE RECLAMATION. Under federal and state laws and regulations, we are required to submit to the regulation by, and receive approval from, the Wyoming Department of Environmental Quality ("DEQ") for a mining and reclamation plan which provides for orderly mining, reclamation and restoration of all of our Wyodak coal mine in conformity with state laws and regulations. We have an approved mining permit and are otherwise in compliance with other land quality permitting programs. Based on extensive reclamation studies, we currently estimate the cost of reclamation for our mine at approximately $26 million and have currently accrued approximately $17.7 million on our balance sheet for these reclamation costs. No assurance can be given that additional requirements in the future will not be imposed that would cause an unexpected material increase in reclamation costs. One situation that could result in substantial unexpected increases in costs relating to our reclamation permit concerns three depressions--the "south" depression, the "Peerless" depression and the "North Pit" depression--that have or will result from our mining activities at the Wyodak mine. Because of the thick coal seam and relatively shallow overburden, the current restoration plan would leave these depressions, which have limited reclamation potential, with interior drainage only. Although the DEQ has accepted the current plan to limit reclamation of these depressions, it has reserved the right to review and evaluate future reclamation plans or to reevaluate the existing reclamation plan. If as a result of our mining activities, additional overburden becomes available, the DEQ may require us to conduct additional reclamation of the depressions, particularly if the DEQ finds that the current limited reclamation is resulting in exceedances in the DEQ's water quality standards. BEN FRENCH OIL SPILL. In 1990 and 1991, we discovered extensive underground fuel oil contamination at the Ben French plant site. With the help of expert consultants, we worked closely with the South Dakota Department of Environment and Natural Resources to assess and remediate the site. Our assessment and remediation efforts continue today and we continue to monitor the site. All of our underground oil-carrying facilities from which the contamination occurred are now above ground. There have been no significant recoveries of free fuel oil product since 1994. Soil borings and monitoring wells on the perimeters of our Ben French plant property provide no indication of contamination beyond the property's limits. Management believes that the underground spill has been sufficiently remedied so as to prevent any oil from migrating off site. However, due to underground gypsum deposits in this area, the fuel oil has the potential of migrating to area waterways. In such event, cleanup costs could be greatly increased. Management believes that sufficient remediation efforts to prevent such a migration are currently in place, but due to the uncertainties of underground geology, no assurance can be given. Cleanup costs recognized to date total approximately $472,000, of which amount $386,000 has been reimbursed by the South Dakota Petroleum Release Compensation Fund. To date, no penalties, claims or actions have been taken or threatened against us because of this oil spill. PCBS. Under the federal Toxic Substances Control Act, the Environmental Protection Agency has issued regulations that control the use and disposal of polychlorinated biphenyls, or PCBs. PCBs were 59
widely used as insulating fluids in many electric utility transformers and capacitors manufactured before the Toxic Substances Control Act prohibited any further manufacture of PCB equipment. We remove and dispose of PCB-contaminated equipment in compliance with law as it is discovered. Release of PCB-contaminated fluids, especially any involving a fire or a release into a waterway, could result in substantial cleanup costs. Several years ago, we began a testing program of potential PCB-contaminated transformers, and in 1997 completed testing of all transformers and capacitors which are not located in our electric substations. We have not completed the testing of sealed potential transformers and bushings located in our electric substations as the testing of this equipment requires their destruction. Release of PCB-contaminated fluid, if present, from our equipment is unlikely and the volume of fluid in such equipment is generally less than one gallon. Moreover, any release of this fluid would be confined to our substation site. EXPLORATION AND PRODUCTION Our oil and gas exploration and production operations are subject to various types of regulation at the federal, state and local levels. They include: - requiring permits for the drilling of wells; - maintaining bonding requirements in order to drill or operate wells; - submitting and implementing spill prevention plans; - submitting notification relating to the presence, use and release of certain contaminants incidental to oil and gas operations; - regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities; and - regulating surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. Our operations are also subject to various conservation matters, including the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a unit and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill. In addition, various federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants and the protection of public health, natural resources, wildlife and environment affect our exploration, development and production operations and our related costs. OTHER PROPERTIES In addition to the other properties discussed in this prospectus, we own an eight-story office building consisting of approximately 47,000 square feet of office space in Rapid City, South Dakota. We occupy approximately 27,000 square feet in this building and lease the remainder to others. 60
EMPLOYEES At December 31, 2000, we had 635 employees, approximately 332 of whom are employed in our utility business, 170 of whom are employed in our independent energy businesses and 133 of whom are employed in our communications business. Approximately one-half of our utility employees are covered by collective bargaining agreements with the International Brotherhood of Electrical Workers which expire on April 1, 2003. We have experienced no significant labor stoppages or labor disputes at our facilities. LEGAL PROCEEDINGS In August 2000, we initiated an action in the United States District Court for the District of Wyoming against PacifiCorp relating to a coal supply agreement between PacifiCorp and us for the Wyodak plant. We believe that PacifiCorp failed to make complete payment to us for coal sold under the coal supply agreement and that PacifiCorp was underpaying its coal bill by approximately $100,000 per month. We asked for relief in the amount of $5 million, plus all underpayments since the commencement of our lawsuit. PacifiCorp subsequently brought a counterclaim against us, alleging that we had not properly adjusted upward and downward the components which make up the coal price under the coal supply agreement, resulting in alleged overbilling to PacifiCorp of $35 to $40 million over an undefined period. In April 2001, we entered into a settlement agreement with PacifiCorp whereby ongoing litigation between the parties has been withdrawn. A new coal supply contract and other agreements were executed as a result of the settlement. The new coal supply contract for the Wyodak plant extends the term of the prior contract from 2013 to 2022. Our subsidiary, Wyodak Resources, will receive a lump sum cash payment, while the coal sales price will be reduced and PacifiCorp's minimum annual coal purchase obligation will increase. Under the terms of a new coal sales agreement, Wyodak Resources will sell additional coal for delivery to other PacifiCorp power plants from late 2001 through 2003, and Wyodak Resources will also have an option to sell additional coal to PacifiCorp through 2010. There are no material legal proceedings pending, other than ordinary routine litigation incidental to our business, to which we are a party. There are no material legal proceedings to which an officer or director is a party or has a material interest adverse to us or our subsidiaries. Except as otherwise described in this prospectus, there are no material administrative or judicial proceedings arising under environmental quality or civil rights statutes pending or known to be contemplated by governmental agencies to which we are or would be a party. 61
MANAGEMENT The name, age and title of each of our directors and executive officers and some of our key employees are as follows: NAME AGE TITLE - ---- -------- -------------------------------------------------------- Daniel P. Landguth................... 54 Director, Chairman of the Board and Chief Executive Officer Adil M. Ameer........................ 48 Director Bruce B. Brundage.................... 65 Director David C. Ebertz...................... 55 Director Gerald R. Forsythe................... 60 Director John R. Howard....................... 60 Director Everett E. Hoyt...................... 61 Director, President and Chief Operating Officer Kay S. Jorgensen..................... 49 Director David S. Maney....................... 37 Director Thomas J. Zeller..................... 53 Director Gary R. Fish......................... 42 President and Chief Operating Officer of Independent Energy Mark T. Thies........................ 37 Senior Vice President and Chief Financial Officer Thomas M. Ohlmacher.................. 49 Senior Vice President--Power Supply and Power Marketing James M. Mattern..................... 46 Senior Vice President--Corporate Administration Ronald D. Schaible................... 56 Senior Vice President and General Manager-- Communications Roxann R. Basham..................... 39 Vice President--Controller David R. Emery....................... 38 Vice President--Fuel Resources Kyle D. White........................ 41 Vice President--Corporate Affairs Steven J. Helmers.................... 44 General Counsel and Corporate Secretary Shawn T. McLaughlin.................. 31 President of Enserco Energy, Inc. John W. Salyer, Jr................... 42 President and Chief Operating Officer of Black Hills Energy Capital, Inc. DANIEL P. LANDGUTH was elected our Chairman of the Board and Chief Executive Officer in January 1991. He has been a director since 1989 and currently chairs the Executive Committee. He has 30 years of experience with Black Hills. Mr. Landguth holds a B.S. degree in Electrical Engineering from the South Dakota School of Mines and Technology. ADIL M. AMEER has been President and Chief Executive Officer of Rapid City Regional Hospital since 1991. From 1982 to 1991, he held several executive positions at the hospital. The hospital system owns and manages several health care facilities in Rapid City and the Black Hills area, and in Nebraska and Wyoming. Mr. Ameer was elected to the board of directors in 1997 and currently chairs the Audit Committee. BRUCE B. BRUNDAGE has been President and Director of Brundage & Company, Englewood, Colorado, since 1973. Brundage & Company specializes in negotiation, appraisal and arrangement of mergers and acquisitions for a nationwide client base and in providing financial, advisory and private placement financing to businesses in the western United States. Mr. Brundage has been a director since 1986. He also serves as a director of Vicorp Restaurants, Inc. 62
DAVID C. EBERTZ has been a consultant with Dave Ebertz Risk Management Consulting, a firm specializing in insurance and risk management services for schools and public entities, since January 2000. From 1976 until December 1999, he was President and majority owner of Barlow Agency, Inc., Gillette, Wyoming, which provides risk management and insurance services primarily to the manufacturing, oil and gas, and mining industries. Mr. Ebertz has served on the board of directors since 1998 and currently chairs the Compensation Committee. GERALD R. FORSYTHE is Chairman and Chief Executive Officer of Indeck Power Equipment Company, the largest emergency and back-up steam generating source in North America. Mr. Forsythe has been employed in various positions with Indeck Power Equipment Company since 1963. He is also Chairman and Chief Executive Officer of Indeck Energy Services, Inc. Mr. Forsythe joined our board of directors in July 2000. He also serves as a director of Championship Auto Racing Team, Inc. JOHN R. HOWARD has been President of Industrial Products, Inc. since 1992. Industrial Products, Inc. provides equipment and supplies to the mining and manufacturing industries. He is also Special Projects Manager for Linweld, Inc. Mr. Howard joined the board of directors in 1977. EVERETT E. HOYT has been our President and Chief Operating Officer since February 2001. From 1989 to February 2001, he was President and Chief Operating Officer of our regulated utility business. Mr. Hoyt was elected to the board of directors in 1991. Prior to joining us, Mr. Hoyt was employed by NorthWestern Corporation for 16 years where he served as Senior Vice President-Legal and as a member of the board of directors. He holds a B.S. degree in Mechanical Engineering from the South Dakota School of Mines and Technology and a J.D. from the University of South Dakota School of Law. KAY S. JORGENSEN is a co-owner and Vice President of Jorgensen-Thompson Creative Broadcast Services, providing radio broadcast services in the western United States. Previously, she served in the South Dakota State Legislature for several terms and has served on various state and local boards and commissions. Ms. Jorgensen joined the board of directors in 1992. DAVID S. MANEY has been a telecommunications venture capital investor and consultant since November 2000. Prior to that, he founded Worldbridge Broadband Services, Inc., a nationwide provider of outsourced field operations and technical services to the telecommunications industry, in 1994, and served as its President and Chief Executive Officer. In 1999, he co-founded, as a spin-off from Worldbridge, Open Access Broadband Networks, Inc., whose mission was to build and operate broadband carriers' carrier telecommunications networks in the residential local loop. He served as President and Chief Executive Officer of Open Access Broadband until November 2000. Previously, he held management positions with InterMedia Partners and Chronicle Publishing Company. Mr. Maney has been a member of the board of directors since 1999. THOMAS J. ZELLER has been President of RE/SPEC Inc. since 1995. RE/SPEC is a technical consulting and services firm with expertise in engineering, environmental and information technologies. Mr. Zeller is also Chairman of the Board of Teachmaster Technologies, Inc., an educational software and consulting firm. Mr. Zeller has been a member of the board of directors since 1997 and currently chairs the Nominating Committee. GARY R. FISH has been the President and Chief Operating Officer of our Independent Energy Group since September 1999. Prior to that, he served in several development and accounting officer positions for us since August 1988. Mr. Fish holds a B.S. in Business Administration from the University of South Dakota and is a certified public accountant. MARK T. THIES has been our Senior Vice President and Chief Financial Officer since March 2000. From May 1997 to March 2000, he was our Controller. From 1990 to 1997, Mr. Thies served in a number of accounting positions with InterCoast Energy Company, an unregulated energy company and a wholly-owned subsidiary of MidAmerican Energy Holdings Company. Mr. Thies holds B.A.s in 63
Accounting and Business Administration from Saint Ambrose College and is a certified public accountant. THOMAS M. OHLMACHER has been our Senior Vice President-Power Supply and Power Marketing since January 2001 and Vice President-Power Supply of Black Hills Power, Inc. since August 1994. Prior to that, he held several positions with us since 1974. Mr. Ohlmacher holds a B.S. in Chemistry from the South Dakota School of Mines and Technology. JAMES M. MATTERN has been our Senior Vice President-Corporate Administration since September 1999, and was Vice President-Corporate Administration from January 1994 to September 1999. From 1997 to 1999, he was also Assistant to the CEO. Mr. Mattern has 12 years of experience with us. He holds a B.S. in Social Sciences and an M.S. in Administration from Northern State University. RONALD D. SCHAIBLE has been our Senior Vice President of Communications and Vice President and General Manager of Black Hills FiberCom since October 1998. Mr. Schaible has more than 25 years experience in the telecommunications industry. From 1995 to 1998, he was Vice President and General Manager of the Kansas City and Missouri subsidiaries of Brooks Fiber Properties. Mr. Schaible was responsible for both network construction and operations in Kansas City. He holds a B.S. in Electrical Engineering from South Dakota State University. ROXANN R. BASHAM has been our Vice President-Controller since March 2000. From December 1997 to March 2000, she was Vice President-Finance and Secretary/Treasurer. From 1993 until December 1997, she served as our Secretary/Treasurer, and has a total of 16 years of experience with us. She holds a B.S. in Business Administration from the University of South Dakota and is a certified public accountant. DAVID R. EMERY has been our Vice President-Fuel Resources since January 1997. From June 1993 to January 1997, he was General Manager of Black Hills Exploration and Production. Mr. Emery has 12 years of experience with us. He holds a B.S. in Petroleum Engineering from the University of Wyoming and an M.S. in Business Administration from the University of South Dakota. KYLE D. WHITE has been our Vice President-Corporate Affairs since January 2001 and Vice President-Marketing and Regulatory Affairs of Black Hills Power, Inc. since July 1998. Mr. White served as Director-Strategic Marketing and Sales from 1993 to January 1998 and Vice President-Energy Services from January 1998 to July 1998. He has a total of 18 years of experience with us. Mr. White holds a B.S. and M.S. in Business Administration from the University of South Dakota. STEVEN J. HELMERS has been our General Counsel and Corporate Secretary since January 2001. Prior to joining us, Mr. Helmers was a shareholder with the Rapid City, South Dakota law firms of Truhe, Beardsley, Jensen, Helmers & VonWald, from 1997 to January 2001, and Lynn, Jackson, Schultz & Lebrun, P.C., from 1983 to 1997. He holds a J.D. from the University of South Dakota School of Law. SHAWN T. MCLAUGHLIN has been an officer of Enserco Energy, Inc., our natural gas marketing subsidiary, since its inception in August 1996 and has been President since November 1998. Prior to that, Mr. McLaughlin was a trading analyst at KN Energy, Inc. from 1995 until August 1996. From 1991 to 1995, he was a floor trader at the Chicago Board of Trade. Mr. McLaughlin holds a B.A. in Economics from Colorado State University. JOHN W. SALYER, JR. has been President and Chief Operating Officer of Black Hills Energy Capital, Inc. since its formation in mid-2000. Prior to that, he was co-founder and served as a Director, President and Chief Operating Officer of Indeck Capital, Inc. since its formation in 1994. Mr. Salyer also served as a Director and Senior Vice President of Finance from 1987 to 1994 for the affiliated company Indeck Energy Services, Inc. He holds a B.S. in Economics and Management from Elmhurst College. 64
ELECTION OF OFFICERS AND DIRECTORS Our executive officers are elected by the board of directors and serve at its discretion. The members of our board of directors are elected to three classes of staggered three-year terms. Under a shareholders agreement among some of our shareholders and us, these shareholders currently have the right to nominate one director to our board. Gerald R. Forsythe is the current designee of these shareholders. For more information regarding the shareholders agreement, see "Principal Shareholders--Shareholders Agreement." BOARD COMMITTEES Our executive committee is comprised of Adil M. Ameer, Gerald R. Forsythe, John R. Howard, Everett E. Hoyt, Daniel P. Landguth, David S. Maney and Thomas J. Zeller, with Mr. Landguth serving as chairperson. The executive committee exercises the authority of the board of directors in the interval between meetings of the board, and recommends to the board of directors persons to be elected as officers or to be appointed to board committees. Our compensation committee is comprised of Bruce B. Brundage, David C. Ebertz, Gerald R. Forsythe, John R. Howard, Kay S. Jorgensen and David S. Maney, with Mr. Ebertz serving as chairperson. The compensation committee monitors compliance with all federal and state statutes relating to employment and compensation, recommends to the board of directors compensation for officers, and approves our compensation program including benefits, stock option plans and stock ownership plans. Our audit committee is comprised of Adil M. Ameer, David C. Ebertz, John R. Howard, Kay S. Jorgensen and Thomas J. Zeller, with Mr. Ameer serving as chairperson. The audit committee recommends to the board of directors an independent accounting firm to conduct our annual audit, reviews the scope and results of the annual audit including reports and recommendations of the firm, reviews our internal audit function, and periodically confers with the internal audit group, our management and our independent accountants. Our nominating committee is comprised of Bruce B. Brundage, Kay S. Jorgensen, David S. Maney and Thomas J. Zeller, with Mr. Zeller serving as chairperson. The nominating committee recommends to the board of directors persons to be nominated as directors or to be elected to fill vacancies on the board. Our bylaws require that an outside director serve as chairperson of the committee. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION Our compensation committee is solely comprised of the following outside directors: Bruce B. Brundage, David C. Ebertz, Gerald R. Forsythe, John R. Howard, Kay S. Jorgensen and David S. Maney. Mr. Forsythe is the owner of two companies providing services to Black Hills Energy Capital, one of our subsidiaries. Forsythe Building Fund leases an office building to Black Hills Energy Capital for approximately $8,200 per month and A&R Leasing leases vehicles to Black Hills Energy Capital for approximately $3,200 per month. On March 15, 2001, Black Hills Power, Inc., one of our subsidiaries, began leasing 10 two megawatt mobile diesel electric generators from Indeck Power Equipment Co., which is controlled by Mr. Forsythe, for $250,000 per month in the aggregate. There is a separate lease for each generator with a lease term of March 15, 2001 through September 15, 2002. The leases, however, may be canceled on September 15, 2001 with a cancellation fee of $125,000 per generator. On July 7, 2000, we completed the acquisition of Indeck Capital. Mr. Forsythe was the majority shareholder of Indeck. We issued approximately 1.54 million shares of our common stock and 4,000 shares of our convertible preferred stock to the shareholders of Indeck for a total consideration of 65
approximately $38 million. In addition, we assumed approximately $40 million of debt. Additional consideration, consisting of our common stock and convertible preferred stock may be paid in the form of an earn-out over a four-year period. The earn-out is based on the acquired company's earnings during that period and cannot exceed $35 million in total. The purchase price was determined through arm's-length negotiations between us and the Indeck shareholders. The other shareholders of Indeck were Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. These individuals and Mr. Forsythe, as holders of our convertible preferred stock, are entitled to receive cumulative quarterly cash dividends at a rate equal to 1% per year computed on the basis of $1,000 per share plus an amount equal to any dividend payable with respect to our common stock. CERTAIN TRANSACTIONS Western Health, a division of Rapid City Regional Hospital, is a third party administrator for our healthcare plans. Adil M. Ameer, one of our directors, is President and Chief Executive Officer of Rapid City Regional Hospital. We paid approximately $103,000 to Western Health in 2000 for its services. For additional disclosures with respect to transactions with related parties, see "--Compensation Committee Interlocks and Insider Participation." DIRECTORS' FEES Directors who are not also our officers or employees receive an annual fee of $15,500 plus a fee of $600 for each board meeting and committee attended, provided such committee meetings are substantive in nature and content. In addition, each outside director receives common stock equivalents equal to $7,000 per year divided by the market price of our common stock on a specified date. The common stock equivalents are payable in stock or cash at retirement or can be deferred at the election of the director. Members of our board of directors are required to beneficially own 100 shares of our common stock when they are initially elected a director and to apply at least 50% of his or her annual fees toward the purchase of additional shares until the director has accumulated at least 2,000 shares of our common stock. 66
EXECUTIVE COMPENSATION SUMMARY COMPENSATION The following table sets forth the compensation we paid to each of our five most highly compensated executive officers for 2000: LONG-TERM COMPENSATION --------------- ANNUAL COMPENSATION SECURITIES ALL ------------------- UNDERLYING OTHER NAME AND PRINCIPAL POSITION YEAR SALARY BONUS(1) OPTIONS GRANTED COMPENSATION - --------------------------- -------- -------- -------- --------------- ------------ Daniel P. Landguth..................... 2000 $314,800 $233,955 84,000 -0- Chairman and Chief Executive 1999 262,600 127,350 23,500 -0- Officer 1998 237,550 47,683 18,000 -0- Everett E. Hoyt........................ 2000 $191,200 $ 92,430 41,000 -0- President and Chief Operating 1999 169,100 53,100 8,000 -0- Officer 1998 158,100 18,135 7,500 -0- Gary R. Fish........................... 2000 $190,050 $107,677 41,000 $4,025(2) President and Chief Operating 1999 142,300 61,250 10,500 -0- Officer of Independent Energy 1998 123,350 18,154 10,500 -0- Mark T. Thies.......................... 2000 $145,035 $ 81,000 30,000 $5,100(2) Senior Vice President and Chief 1999 102,300 31,800 8,000 -0- Financial Officer 1998 94,300 11,092 7,500 -0- Thomas M. Ohlmacher.................... 2000 $137,000 $269,750 30,000 $3,335(2) Senior Vice President-Power Supply 1999 126,500 35,700 8,000 -0- and Power Marketing 1998 112,350 12,825 7,500 -0- - ------------------------ (1) Bonus amounts include amounts earned under the short-term annual incentive plan, a bonus program for our executive officers based on the attainment of predetermined profitability measures. Mr. Ohlmacher's bonus in 2000 includes a $200,000 energy marketing bonus. (2) Represents our matching contributions to our 401(k) plan. STOCK OPTION GRANTS IN 2000 The following table sets forth information with respect to options granted during 2000 to each of our five most highly compensated officers. INDIVIDUAL GRANTS - --------------------------------------------------------------------------------------------- NUMBER OF PERCENT OF SECURITIES TOTAL OPTIONS GRANT UNDERLYING GRANTED TO EXERCISE DATE OPTIONS EMPLOYEES IN PRICE EXPIRATION PRESENT NAME GRANTED(1) FISCAL YEAR PER SHARE DATE VALUE(2) - ---- ---------- ------------- --------- ---------- -------- Daniel P. Landguth...................... 84,000 17.1% $21.875 04/25/10 $220,080 Everett E. Hoyt......................... 41,000 8.3% $21.875 04/25/10 $107,420 Gary R. Fish............................ 41,000 8.3% $21.875 04/25/10 $107,420 Mark T. Thies........................... 30,000 6.1% $21.875 04/25/10 $ 78,600 Thomas M. Ohlmacher..................... 30,000 6.1% $21.875 04/25/10 $ 78,600 - ------------------------ (1) Options vest annually in installments of 33% per year beginning on the first anniversary of the date of grant. All options become fully vested if a change in control occurs. (2) We used the Black-Scholes option-pricing model to determine the present value of the options granted and made the following assumptions: an expected volatility of 20.14%; a 6.62% risk-free rate of return; a 4.2% dividend yield; and a 10-year exercise period. 67
AGGREGATED STOCK OPTION EXERCISES IN 2000 AND YEAR-END OPTION VALUES The following table provides information on stock option exercises in 2000 by the named executive officers and the value of such officers' unexercised options at December 31, 2000: NUMBER OF SECURITIES UNDERLYING UNEXERCISED VALUE OF UNEXERCISED SHARES OPTIONS AT IN-THE-MONEY OPTIONS AT ACQUIRED ON VALUE 12/31/00 12/31/00 NAME EXERCISE REALIZED EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE(1) - ---- ----------- -------- ------------------------- ---------------------------- Daniel P. Landguth................ -0- $0 93,433 / 71,667 $2,437,440 / $1,443,066 Everett E. Hoyt................... -0- $0 40,332 / 32,668 $1,036,623 / $ 680,439 Gary R. Fish...................... -0- $0 47,166 / 34,334 $1,215,484 / $ 697,671 Mark T. Thies..................... -0- $0 27,666 / 25,334 $700,014 / $ 512,674 Thomas M. Ohlmacher............... -0- $0 36,666 / 25,334 $952,764 / $ 512,674 - ------------------------ (1) The value of unexercised options is the market value of the shares at year-end minus the exercise price. RETIREMENT PLANS We offer a tax-qualified defined benefit retirement plan for our employees. This pension plan provides benefits at retirement based on length of employment service and average monthly pay in the five consecutive calendar years of highest earnings out of the last 10 years. Our employees do not contribute to the plan. The amount of our annual contribution to the plan is based on an actuarial determination. Accrued benefits become 100% vested after an employee completes five years of service. In 2000, we amended our retirement plan by decreasing future benefits while providing a matching contribution under our 401(k) plan in return. Our employees who were age 50 on or before December 31, 1999 made a one-time election to remain under the old plan or to accept lower benefits under the revised plan in return for 401(k) matching contributions. We also offer a pension equalization plan. The pension equalization plan is a nonqualified supplemental plan in which benefits are not tax deductible until paid. The plan is designed to provide our higher paid executive employees a retirement benefit which, when added to social security benefits and the pension to be received under the defined benefit retirement plan, will approximate retirement benefits being paid by other employers to their employees in similar executive positions. The employee's pension payable from the qualified pension plan is limited under current law to $140,000 annually, and the compensation taken into account in determining contributions and benefits cannot exceed $170,000 and cannot include nonqualified deferred compensation. The amount of deferred compensation paid under nonqualified plans such as the pension equalization plan is not subject to these limits. A participant under the pension equalization plan does not qualify for benefits until the benefits become vested under a vesting schedule--20% after three years of employment under the plan, increasing up to 100% vesting after eight years of employment under the plan. No credit for past service is granted under the pension equalization plan. The annual benefit is 25% of the employee's average earnings, if salary was less than two times the Social Security wage base, or 30%, if the employee's salary was more than two times the Social Security wage base, multiplied by the vesting percentage. Average earnings are normally an employee's average earnings for the five highest consecutive full years of employment during the 10 full years of employment immediately preceding the year of calculation. The annual pension equalization plan benefit is paid on a monthly basis for 15 years to each participating employee and, if deceased, to the employee's designated beneficiary or estate, commencing at the earliest of death or when the employee is both retired and 62 years of age or more. 68
In the event that at the time of a participant's retirement, the participant's salary level exceeds the qualified pension plan annual compensation limitation of $170,000 or includes nonqualified deferred compensation, the participant will receive an additional benefit which is measured by the difference between the monthly benefit which would have been provided to the participant under the defined benefit retirement plan as if there were no annual compensation limitation and no exclusion on nonqualified deferred compensation, and the monthly benefit to be provided to the participant under the defined benefit retirement plan. We amended the pension equalization plan, effective January 30, 2001, to compensate for the $140,000 annual defined benefit pension limitation. The additional benefit is equal to the difference between the monthly benefit which would have been provided to the participant under the defined benefit retirement plan as if there were no annual defined benefit pension limitation and the monthly benefit to be provided to the participant under the defined benefit retirement plan. Participants in the pension equalization plan are designated by our board of directors upon recommendation of the Chief Executive Officer. Selection is based on key employees as determined by management and considerations of performance, rather than being based solely on salary. The minimum salary component applied in the selection process is the maximum annual Social Security taxable wage base that is presently $80,400. RETIREMENT BENEFITS The following table illustrates estimated annual benefits payable under the defined benefit retirement plan and the pension equalization plan to our employees who retire at the normal retirement date: YEARS OF SERVICE ---------------------------------------------------- 15 20 25 30 35 ANNUAL PAY YEARS YEARS YEARS YEARS YEARS - ---------- -------- -------- -------- -------- -------- $110,000 $ 51,464 $ 59,562 $ 67,660 $ 75,758 $ 83,856 125,000 58,769 68,067 77,365 86,663 95,961 150,000 70,944 82,242 93,540 104,838 116,136 175,000 91,869 105,167 118,465 131,763 145,061 200,000 105,294 120,592 135,890 151,188 166,486 225,000 118,719 136,017 153,315 170,613 187,911 250,000 132,144 151,442 170,740 190,038 209,336 275,000 145,569 166,867 188,165 209,463 230,761 300,000 158,994 182,292 205,590 228,888 252,186 350,000 185,844 213,142 240,440 267,738 295,036 400,000 212,694 243,992 275,290 306,588 337,886 450,000 239,544 274,842 310,140 345,438 380,736 The years of credited service under the defined benefit retirement plan for our five most highly compensated officers are as follows: - Daniel P. Landguth, 31 years; - Everett E. Hoyt, 26 years, subject to reduction for service from prior employment; - Gary R. Fish, 14 years; - Mark T. Thies, three years; and - Thomas M. Ohlmacher, 26 years. 69
The benefits in the foregoing table were calculated as a straight life annuity. Amounts shown exclude Social Security benefits and include benefits from both the defined benefit retirement plan and from the pension equalization plan, assuming a 100% vested interest in the pension equalization plan. SEVERANCE AGREEMENTS We have entered into change of control severance agreements with each of our five most highly compensated executive officers and some of our other executive officers and key employees. The change of control severance agreements provide for specified payments and other benefits to be payable upon a change in control and a subsequent termination of employment, either involuntary or by the employee for a "good reason." A "change in control" is defined in the agreements as: - an acquisition of 30% or more of our common stock, except for certain defined acquisitions, such as acquisitions by employee benefit plans, us or any of our subsidiaries; or - members of our incumbent board of directors at the time the agreements were executed cease to constitute at least two-thirds of the members of the board of directors, with the incumbent board of directors being defined as those individuals consisting of the board of directors on the date the agreement was executed and any other directors elected subsequently whose election was approved by the incumbent board of directors; or - approval by our shareholders of: - a merger, consolidation, or reorganization; - a liquidation or dissolution; or - an agreement for the sale or other disposition of all or substantially all of our assets, with exceptions for transactions which do not involve an effective change in control of voting securities or board of directors membership, and transfers to subsidiaries or sales of subsidiaries. A change in control will not be deemed to occur until all regulatory approvals required to effect a change in control have been obtained. A "good reason" is defined in the agreements to include: - a change in the executive's status, title, position or responsibilities; - a reduction in the executive's annual compensation or any failure to pay the executive any compensation or benefits to which he or she is entitled within seven days of the date due; - any material breach by us of any provisions of the change of control severance agreement; - requiring the executive to be based outside a 50-mile radius from Rapid City, South Dakota; or - our failure to obtain an agreement from any successor company to assume and agree to perform under the change of control severance agreement. The agreement with Mr. Landguth also contains an "optional window period," a 30-day period of time beginning on the one-year anniversary after a change in control, during which time Mr. Landguth may resign for any reason and receive his full compensation payments and benefits. Upon a change in control, our executives will have an employment contract for a three-year period, but not beyond age 65. During this employment term, each executive will receive annual compensation at least equal to the highest rate in effect at any time during the one-year period preceding the change in control and will also receive employment welfare benefits, pension benefits and 70
supplemental retirement benefits on a basis no less favorable than those received prior to the change in control. If an executive's employment is terminated during the three-year term involuntarily, for a "good reason," or, in the case of the Chief Executive Officer, for any reason during the "optional window period," that executive will be entitled to the following benefits: - severance pay equal to 2.99 times the executive's five-year average taxable compensation for the remainder of the three-year employment term; and - continuation of employee welfare benefits for the remainder of the employment term, with an offset for similar benefits received, along with additional credit for service under our pension equalization plan and our defined benefit retirement plan equal to the remainder of the employment term. The change of control severance agreements contain a "cap" provision which reduces any amounts payable to an amount which would prevent any payments from being nondeductible under the Internal Revenue Code. The change of control severance agreements also provide for reimbursement of legal fees and expenses of the executive incurred by the executive after the change in control in seeking to obtain or enforce any benefits provided by the change of control severance agreement. Our executives are not required to mitigate the amount of any payment or benefit by seeking other employment or otherwise, and the payments or benefits are not reduced if our executive obtains other employment and/or benefits, except for employee welfare benefits. 71
PRINCIPAL SHAREHOLDERS The following table sets forth the beneficial ownership of our common stock as of February 28, 2001 for: - each person or entity known by us to beneficially own more than 5% of our outstanding shares of common stock; - each of our directors and each of our executive officers named in the summary compensation table; and - all of our directors and executive officers as a group. Beneficial ownership includes shares a director or executive officer has the power to vote or transfer, and stock options that are exercisable currently or within 60 days of February 28, 2001. Except as otherwise indicated by footnotes below, we believe that each individual or entity named has sole investment and voting power with respect to the shares of common stock indicated as beneficially owned by that individual or entity. SHARES OF OPTIONS DIRECTORS' COMMON STOCK EXERCISABLE COMMON BENEFICIALLY WITHIN STOCK NAME AND ADDRESS OF BENEFICIAL OWNER OWNED 60 DAYS EQUIVALENTS(1) TOTAL PERCENTAGE(2) - ------------------------------------ ------------ ----------- -------------- --------- ------------- DIRECTORS AND NAMED EXECUTIVE OFFICERS Adil M. Ameer.......................... 1,401(3) -0- 910 2,311 * Bruce B. Brundage...................... 5,422(4) -0- 6,381 11,803 * David C. Ebertz........................ 2,182(5) -0- 638 2,820 * Gary R. Fish........................... 9,218(6) 47,166 -0- 56,384 * Gerald R. Forsythe..................... 1,029,577(7) -0- 119 1,029,696 4.5% John R. Howard......................... 16,864 -0- 5,135 21,999 * Everett E. Hoyt........................ 12,289 40,332 -0- 52,621 * Kay S. Jorgensen....................... 2,967 -0- 2,015 4,982 * Daniel P. Landguth..................... 18,620 93,433 -0- 112,053 * David S. Maney......................... 1,438(8) -0- 411 1,849 * Thomas M. Ohlmacher.................... 6,407(9) 36,666 -0- 43,073 * Mark T. Thies.......................... 3,506(10) 27,666 -0- 31,172 * Thomas J. Zeller....................... 1,476(11) -0- 910 2,386 * All directors and executive officers as a group (19 persons)................. 1,137,293 379,043 16,519 1,532,855 6.7% FIVE PERCENT SHAREHOLDERS Gerald R. Forsythe, Michelle R. Fawcett, et al........... 1,657,191(12) -0- 119 1,657,310 7.2% 1111 S. Willis Avenue Wheeling, IL 60090 FMR Corp. ............................. 1,546,145(13) -0- -0- 1,546,145 6.7% 82 Devonshire Street Boston, MA 02109 - ------------------------ * Represents less than 1% of the common stock outstanding. (1) Represents common stock allocated to the directors' accounts in the directors' stock-based compensation plan, of which the trustee has sole voting and investment authority. (2) Shares of common stock which were not outstanding but could be acquired by a person upon exercise of an option within sixty days of February 28, 2001, or conversion of the Series 2000-A Convertible Preferred Stock are deemed outstanding for the purpose of computing the percentage of outstanding shares beneficially owned by such person. Such shares, however, are not deemed 72
to be outstanding for the purpose of computing the percentage of outstanding shares beneficially owned by any other person. (3) Includes 150 shares owned jointly with Mr. Ameer's spouse as to which he shares voting and investment authority. (4) Includes 5,400 shares owned by the Brundage & Co. Pension Plan and Trust of which Mr. Brundage is the trustee with sole voting and investment authority. (5) Shares owned jointly with Mr. Ebertz's spouse as to which he shares voting and investment authority. (6) Includes 7,592 shares owned jointly with Mr. Fish's spouse as to which he shares voting and investment authority. (7) Includes 11,400 shares owned by Indeck Power Equipment, Inc., which Mr. Forsythe controls, and 70,857 shares of common stock issuable upon conversion of 2,480 shares of Series 2000-A Preferred Stock, which are currently convertible at his option and which will be automatically converted on July 7, 2005. Does not include other shares of common stock that Mr. Forsythe may be deemed to beneficially own as a result of membership in a group. See Note 12 below for further information with respect to this group. Mr. Forsythe disclaims beneficial ownership of such other shares. (8) Includes 1,000 shares owned jointly with Mr. Maney's spouse as to which he shares voting and investment authority. (9) Includes 2,400 shares owned jointly with Mr. Ohlmacher's spouse as to which he shares voting and investment authority. (10) Includes 3,106 shares owned jointly with Mr. Thies's spouse as to which he shares voting and investment authority. (11) Includes 225 shares owned jointly with Mr. Zeller's spouse as to which he shares voting and investment authority. (12) Represents shares held by the following individuals who became shareholders as a result of the Indeck Capital acquisition: Gerald R. Forsythe (1,029,696 shares), Michelle R. Fawcett (107,317 shares), Marsha Fournier (107,317 shares), Monica J. Breslow (107,428 shares), Melissa S. Forsythe (107,428 shares) and John W. Salyer, Jr. (198,124 shares). The shares include 114,286 shares of common stock issuable upon conversion of 4,000 shares of Series 2000-A Preferred Stock, which are currently convertible at their option and which will be automatically converted on July 7, 2005. Information relating to the shareholders is based on the shareholders' Schedule 13D dated July 5, 2000, Mr. Forsythe's Forms 3 and 4 filed with the Securities and Exchange Commission and our shareholder records. The Schedule 13D indicates that the shareholders may be deemed to be a group for purposes of the Securities Exchange Act of 1934. Each shareholder disclaims beneficial ownership of shares over which that shareholder does not have sole investment authority. (13) As of December 31, 2000, (a) FMR Corp. had sole dispositive power with respect to all of these shares and sole voting power with respect to 1,045,405 of these shares, (b) Edward C. Johnson 3d, Chairman of FMR Corp., and Abigail P. Johnson, a Director of FMR Corp., each had sole dispositive power with respect to all of these shares, and (c) these shares represent (i) 500,740 shares beneficially owned by Fidelity Management & Research Company, a wholly-owned subsidiary of FMR Corp. ("Fidelity"), as a result of acting as investment adviser to various investment companies, (ii) 934,655 shares beneficially owned by Fidelity Management Trust Company, a wholly-owned subsidiary of FMR Corp., as a result of serving as investment manager of certain institutional accounts, and (iii) 110,750 shares beneficially owned by Fidelity International Limited, which is independent of FMR Corp. and Fidelity, as a result of investment advisory and management services and those 110,750 shares are included on a voluntary basis by 73
FMR Corp. Information relating to this shareholder is based on the shareholder's Schedule 13G dated February 14, 2001. SHAREHOLDERS AGREEMENT In connection with the Indeck Capital acquisition, we entered into a shareholders agreement with various new shareholders (namely, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Melissa S. Forsythe, Monica Breslow and John W. Salyer, Jr.) on June 30, 2000. CORPORATE GOVERNANCE AND VOTING. Under the terms of the agreement, these shareholders have the right to nominate one director to our board of directors and one director to the boards of directors of each of our direct or indirect wholly-owned subsidiaries. This right terminates: - on any date before June 30, 2004 on which the new shareholders collectively own less than 5% of the shares of common stock (after giving effect to and assuming conversion of any shares of preferred stock owned by them) outstanding as of June 30, 2000; - on any date after June 30, 2004 on which the new shareholders collectively own less that 5% of the shares of common stock (after giving effect to and assuming conversion of any shares of preferred stock owned by them) then outstanding; or - in any event no later than the date of the annual meeting of shareholders in 2010. GENERAL RESTRICTION ON TRANSFER. The shares acquired by the new shareholders in connection with the Indeck acquisition may not be sold, transferred, assigned or otherwise disposed of until June 30, 2002, either pursuant to Rule 144 under the Securities Act or otherwise, except as specifically permitted in the shareholders agreement. STANDSTILL. Prior to June 30, 2004, the new shareholders may not, without the written consent of our board of directors, own any of our common stock or preferred stock other than: - the shares of common stock and preferred stock the new shareholders acquired in connection with the Indeck acquisition; - shares of common stock acquired as a result of the conversion of preferred stock acquired by the new shareholders in connection with the Indeck acquisition; - shares of common stock or options for common stock acquired by a new shareholder who is an officer and/or director pursuant to an employee benefit plan; and - shares of common stock or preferred stock acquired pursuant to any pro rata stock dividend, stock split, exchange, recapitalization, reclassification or other distribution. From July 1, 2004, through June 30, 2010, the new shareholders may not, without the written consent of our board of directors, acquire any shares of common stock or preferred stock (other than the acquisition of shares in the manner specified above) if immediately following the acquisition of those shares, the new shareholders would own more than 9.9% of the then outstanding shares of common stock on a fully-diluted basis. The new shareholders also may not, until June 30, 2010, take any action, either individually, as a group, or in concert with any other group, to acquire us or which involves the solicitation of proxies or any attempt to control or influence the board of directors. The new shareholders also may not transfer any shares of common stock or preferred stock to a person who holds or would hold following that transfer 5% or more of our then outstanding shares of common stock. RIGHT OF FIRST OFFER. The new shareholders are required to notify our board of directors before a new shareholder transfers 500,000 shares or more of common stock. We then have the right to purchase those shares before any other person or entity. 74
DESCRIPTION OF CAPITAL STOCK GENERAL Our authorized capital stock consists of (a) 100,000,000 shares of common stock, having a par value of $1 per share, and (b) 25,000,000 shares of preferred stock, without par value. As of February 28, 2001, 22,951,394 shares of common stock and 4,000 shares of preferred stock were outstanding. Upon completion of this offering, we will have outstanding 25,951,394 shares of common stock, or 26,401,394 shares if the underwriters' over-allotment option is exercised in full. COMMON STOCK The holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of shareholders. Holders may use cumulative voting for the election of directors. Subject to preferences that may be applicable to any outstanding series of preferred stock, holders of common stock are entitled to receive equally dividends as they may be declared by our board of directors out of funds legally available for the payment of dividends. In the event of our liquidation or dissolution, holders of common stock are entitled to share equally in all assets remaining after payment of liabilities and the liquidation preference of any outstanding series of preferred stock. Holders of common stock have no preemptive rights and have no rights to convert their common stock into any other securities. All of the outstanding shares of common stock are, and the shares of common stock we sell in this offering will be, duly authorized, validly issued, fully paid and nonassessable. PREFERRED STOCK Our board of directors has the authority, without further action by our shareholders, to issue shares of undesignated preferred stock from time to time in one or more series and to fix the related number of shares and the designations, voting powers, preferences, optional and other special rights, and restrictions or qualifications of that preferred stock. The rights, preferences, privileges and restrictions or qualifications of different series of preferred stock may differ from common stock and other series of preferred stock with respect to dividend rates, amounts payable on liquidation, voting rights, conversion rights, redemption provisions, sinking fund provisions and other matters. The issuance of additional series of preferred stock could: - decrease the amount of earnings and assets available for distribution to holders of common stock; - adversely affect the rights and powers, including voting rights, of holders of common stock; and - have the effect of delaying, deferring or preventing a change in control. NO PAR PREFERRED STOCK, SERIES 2000-A. We currently have 4,000 shares of No Par Preferred Stock, Series 2000-A issued and outstanding. The shares of preferred stock currently issued and outstanding are cumulative, convertible, no par shares and are non-voting except as generally discussed below or as otherwise required by law. The holders of our preferred stock are entitled to receive cumulative quarterly cash dividends at a rate equal to 1% per year computed on the basis of $1,000 per share plus an amount equal to any dividend payable with respect to our common stock, multiplied by the number of shares of common stock into which each share of preferred stock is convertible. Dividends on our preferred stock must be paid or declared and set apart for payment before any dividends may be paid or declared and set apart for payment on our common stock. In addition, no dividend may be declared or paid with respect to our common stock unless the same dividend is declared and paid with respect to our preferred stock. 75
We have the authority to redeem our preferred stock in whole or in part, at any time. The redemption price per share for the preferred stock is $1,000 plus all accrued and unpaid dividends. Each share of preferred stock is convertible at the option of the shareholder into shares of our common stock at any time prior to July 7, 2005 and, unless redeemed, will be automatically converted into shares of our common stock on July 7, 2005. Each share of preferred stock is convertible into 28.57 shares (the liquidation preference amount of $1,000 divided by the conversion price of $35.00 per share). Upon delivery to a shareholder of a notice of redemption, the conversion price will be adjusted to equal the lesser of the conversion price then in effect and the current market price of our common stock on the redemption notice date. The holders of our preferred stock are not entitled to any right to vote at any meeting of our shareholders for the election of directors, except that whenever dividends accrued on the preferred stock remain unpaid in an amount equivalent to at least four quarterly dividends, but less than eight, the holders of the preferred stock, voting separately as one class for such purpose, will be entitled at the next succeeding annual meeting of shareholders to elect that number of directors as will constitute one-third of the then board members, and the holders of common stock will be entitled to elect the remaining directors. Whenever the accrued and unpaid dividends on the preferred stock become equivalent to or exceed eight quarterly dividends, the holders of the preferred stock, voting separately as one class for such purpose, will be entitled to elect at the next succeeding annual meeting of shareholders the smallest number of directors necessary to constitute a majority of our board, and the holders of common stock will be entitled to elect the remaining directors. After the accrued and unpaid dividends are paid, the holders of the preferred stock will be divested of these voting rights at the next succeeding annual meeting of shareholders. We must obtain the consent of the holders of two-thirds of the outstanding shares of our preferred stock, voting separately as one class for such purpose, before we may: - create or increase the authorized amount of any other class of stock which will rank prior to the preferred stock in respect of dividends or assets; - reclassify shares of stock of any class ranking junior to the preferred stock in respect of dividends or assets, wholly or partially into shares of stock of any class ranking on a parity with or prior to the preferred stock in respect of dividends or assets; - sell all or substantially all of our property and assets to, or merge or consolidate into or with, any other company; or - make any distribution out of capital or capital surplus, other than dividends payable in stock ranking junior to the preferred stock in respect of dividends and assets, to holders of stock ranking junior to the preferred stock in respect of dividends or assets. REGISTRATION RIGHTS In conjunction with our acquisition of Indeck Capital in July 2000, we entered into a registration rights agreement with various new shareholders (namely, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Melissa S. Forsythe, Monica Breslow and John W. Salyer, Jr.). A total of 1,651,033 shares of common stock (assuming conversion of our outstanding shares of preferred stock into common stock) are currently covered by the registration rights agreement. In the event that the new shareholders receive additional shares of our common stock and convertible preferred stock pursuant to the earn-out provisions related to the acquisition of Indeck, the additional shares of common stock, including shares received upon conversion of preferred stock, will be covered by the registration rights agreement. The registration rights granted under the registration rights agreement entitle the parties to demand, at any time after June 30, 2002, a total of three registrations of common stock, one of which 76
can be a shelf registration. The parties also have "piggyback" registration rights, although they have no registration rights with respect to this offering. The registration rights agreement also contains customary provisions regarding the payment of expenses by us and mutual indemnification agreements between us and the new shareholders for securities law violations. ANTI-TAKEOVER EFFECTS OF SOUTH DAKOTA LAW AND PROVISIONS OF OUR CHARTER AND BYLAWS South Dakota law and our articles of incorporation and bylaws contain certain provisions that might be characterized as anti-takeover provisions. These provisions may make it more difficult to acquire control of us or remove our management. CONTROL SHARE ACQUISITIONS. The control share acquisition provisions of the South Dakota Domestic Public Corporation Takeover Act provide generally that the shares of a publicly-held South Dakota corporation acquired by a person that exceed the thresholds of voting power described below will have the same voting rights as other shares of the same class or series only if approved by: - the affirmative vote of the majority of all outstanding shares entitled to vote, including all shares held by the acquiring person; and - the affirmative vote of the majority of all outstanding shares entitled to vote, excluding all interested shares. Each time an acquiring person reaches a threshold, an election must be held as described above before the acquiring person will have any voting rights with respect to shares in excess of such threshold. The thresholds which require shareholder approval before voting powers are obtained with respect to shares acquired in excess of such thresholds are 20%, 33 1/3% and 50%, respectively. We have elected in our articles of incorporation not to be subject to these provisions of South Dakota law. BUSINESS COMBINATIONS. We are subject to the provisions of Section 47-33-17 of the South Dakota Domestic Public Corporation Takeover Act. In general, Section 47-33-17 prohibits a publicly-held South Dakota corporation from engaging in a "business combination" with an "interested shareholder" for a period of four years after the date that the person became an interested shareholder unless the business combination or the transaction in which the person became an interested shareholder is approved in a prescribed manner. After the four-year period has elapsed, the business combination must still be approved, if not previously approved in the manner prescribed, by the affirmative vote of the holders of a majority of the outstanding voting shares exclusive, in some instances, of those shares beneficially owned by the interested shareholder. Generally, a "business combination" includes a merger, a transfer of 10% or more of the corporation's assets, the issuance or transfer of stock equal to 5% or more of the aggregate market value of all of the corporation's outstanding shares, the adoption of a plan of liquidation or dissolution, or other transaction resulting in a financial benefit to the interested shareholder. Generally, an "interested shareholder" is a person who, together with affiliates and associates, owns 10% or more of the corporation's voting stock. This provision may delay, defer or prevent a change in control of us without the shareholders taking further action. The South Dakota Domestic Public Corporation Takeover Act further provides that our board, in determining whether to approve a merger or other change of control, may take into account both the long-term as well as short-term interests of us and our shareholders, the effect on our employees, customers, creditors and suppliers, the effect upon the community in which we operate and the effect on the economy of the state and nation. This provision may permit our board to vote against some proposals that, in the absence of this provision, it would have a fiduciary duty to approve. FAIR PRICE PROVISION. Our articles of incorporation require the affirmative vote of the holders of 80% or more of the outstanding shares of our voting stock to approve any "business transaction" with any "related person" or any "business transaction" in which a "related person" has an interest. However, if a majority of the members of our board who are not affiliated with the related party 77
approve the business transaction, or if the cash or fair market value of any consideration received by our shareholders pursuant to a business transaction meets certain enumerated requirements, then the 80% voting requirement will not be applicable. Generally, our articles of incorporation define a "business transaction" to include a merger, asset or stock sale. Our articles of incorporation define a "related person" as any person or entity that owns 10% or more of our outstanding voting stock. The likely effect of this provision is to delay, defer or prevent a change in control of us. BOARD COMPOSITION. Our articles of incorporation and bylaws provide for a staggered board of directors divided into three classes, with the term of office of one class expiring each year. Our articles of incorporation and bylaws also provide that our directors may be removed only for cause and by the affirmative vote of the majority of the remaining members of the board of directors. The likely effect of our staggered board of directors and the limitation on the removal of directors is an increase in the time required for the shareholders to change the composition of our board of directors. AUTHORIZED BUT UNISSUED SHARES. The authorized but unissued shares of our common stock and preferred stock are available for future issuance without shareholder approval. These additional shares may be used for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of authorized but unissued and unreserved common stock and preferred stock could also render more difficult or discourage an attempt to obtain control of us by means of a proxy contest, tender offer, merger or otherwise. Our board of directors has no present intention to issue any new series of preferred stock; however, our board has the authority, without further shareholder approval, to issue one or more series of preferred stock that could, depending on the terms of the series, either impede or facilitate the completion of a merger, tender offer or other takeover attempt. Although our board of directors is required to make any determination to issue such stock based on its judgment as to the best interest of our shareholders, our board could act in a manner that would discourage an acquisition attempt or other transaction that some, or a majority, of the shareholders might believe to be in their best interests or in which shareholders might receive a premium for their stock over the then market price of such stock. Our board of directors does not intend to seek shareholder approval prior to any issuance of preferred stock, unless otherwise required by law or the rules of the stock exchange on which our common stock is listed. SHAREHOLDER ACTION BY WRITTEN CONSENT MUST BE UNANIMOUS. South Dakota law provides that any action which may be taken at a meeting of shareholders may be taken without a meeting if a written consent, setting forth the action taken, is signed by all of the shareholders entitled to vote with respect to the action taken. This provision prevents holders of less than all of our common stock from unilaterally using the written consent procedure to take shareholder action. TRANSFER AGENT AND REGISTRAR The transfer agent and registrar for our common stock is Wells Fargo Shareowner Services. 78
UNITED STATES FEDERAL TAX CONSIDERATIONS FOR NON-U.S. HOLDERS The following discussion is a general discussion of the material U.S. federal income and estate tax consequences of the ownership and disposition of our common stock by a beneficial owner that is a "non-U.S. holder." For purposes of this discussion, a non-U.S. holder is any person or entity other than: - a citizen or resident of the United States; - a partnership, corporation or other entity created or organized in or under the laws of the United States or of any political subdivision thereof; - a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust or the trust has a valid election in effect under applicable U.S. Treasury regulations to be treated as a U.S. person; or - an estate, the income of which is includible in gross income for U.S. income tax purposes regardless of its source. This discussion is based on the Internal Revenue Code of 1986, as amended, and administrative interpretations as of the date of this prospectus, all of which are subject to change, including changes with retroactive effect. This discussion does not address all aspects of U.S. federal income and estate taxation that may be relevant to non-U.S. holders in light of their particular circumstances and does not address any tax consequences arising under the laws of any state, local or foreign jurisdiction. Prospective holders should consult their tax advisors with respect to the particular tax consequences to them of owning and disposing of common stock. DIVIDENDS Dividends paid to a non-U.S. holder of common stock generally will be subject to withholding of United States federal income tax at a 30% rate or a reduced rate specified by an applicable income tax treaty. To obtain a reduced rate of withholding for dividends paid, a non-U.S. holder will be required to provide us with an Internal Revenue Service Form W-8BEN certifying its entitlement to benefits under a treaty. In addition, in certain cases where dividends are paid to a non-U.S. holder that is a partnership or other pass-through entity, persons holding an interest in the entity will need to provide us with the required certification. For example, an individual non-U.S. holder who holds through a non-U.S. partnership will be required to provide us with an Internal Revenue Service Form W-8BEN. The withholding of U.S. federal income tax does not apply to dividends paid to a non-U.S. holder that provides an Internal Revenue Service Form W-8ECI, certifying that the dividends are effectively connected with the non-U.S. holder's conduct of a trade or business within the United States. Instead, the effectively connected dividends will be subject to regular U.S. income tax as if the non-U.S. holder were a U.S. resident. A non-U.S. corporation receiving effectively connected dividends may also be subject to an additional "branch profits tax" imposed at a rate of 30% (or a lower treaty rate) on an earnings amount that is net of the regular tax. GAIN ON DISPOSITION OF COMMON STOCK A non-U.S. holder generally will not be subject to U.S. federal income tax on gain realized on a sale or other disposition of common stock unless: - the gain is effectively connected with a trade or business of the non-U.S. holder in the United States, or where a treaty applies, is attributable to a United States permanent establishment of the non-U.S. holder; 79
- in the case of certain non-U.S. holders who are non-resident alien individuals and hold the common stock as a capital asset, the individuals are present in the United States for 183 or more days in the taxable year of the disposition and meet other requirements; or - the non-U.S. holder is subject to tax under the provisions of the Internal Revenue Code regarding the taxation of U.S. expatriates. In addition, if we are or have been a "United States real property holding corporation" for U.S. federal income tax purposes, a non-U.S. holder who is otherwise not subject to U.S. federal income tax on gain realized on a sale or other disposition of common stock (as discussed above) would not be subject to such taxation, but only if our common stock continues to be "regularly traded on an established securities market" for U.S. federal income tax purposes and such non-U.S. holder does not own, directly or indirectly, at any time during the five-year period ending on the date of disposition or such shorter period the shares were held, more than five percent of the outstanding common stock. Our common stock currently is regularly traded for this purpose. We currently believe that we are a United States real property holding corporation for U.S. federal income tax purposes. A non-U.S. holder who owns, directly or indirectly, more than five percent of the common stock (as described above) would be subject to U.S. federal income tax on a sale or other disposition of common stock. INFORMATION REPORTING REQUIREMENTS AND BACKUP WITHHOLDING We must report annually to the Internal Revenue Service the amount of dividends paid to each non-U.S. holder, the name and address of the recipient, and the amount of any tax withheld. A similar report is sent to the non-U.S. holder. Under tax treaties or other agreements, the Internal Revenue Service may make its reports available to tax authorities in the recipient's country of residence. A non-U.S. holder must certify its non-U.S. status to avoid backup withholding at a 31% rate on dividends. Generally a non-U.S. holder will provide this certification on Internal Revenue Service Form W-8BEN. U.S. information reporting and backup withholding generally will not apply to a payment of proceeds of a disposition of common stock where the transaction is effected outside the United States through a non-U.S. office of a non-U.S. broker. However, a non-U.S. holder must certify its non-U.S. status to avoid information reporting and backup withholding at a 31% rate on disposition proceeds where the transaction is effected by or through a U.S. office of a broker. In addition, U.S. information reporting requirements generally will apply to the proceeds of a disposition effected by or through a non-U.S. office of a U.S. broker, or by a non-U.S. broker with specified connections to the United States. Backup withholding is not an additional tax. Rather, the tax liability of persons subject to backup withholding will be reduced by the amount of tax withheld. When withholding results in an overpayment of taxes, a refund may be obtained if the required information is furnished to the Internal Revenue Service. FEDERAL ESTATE TAX An individual non-U.S. holder who is treated as the owner of, or has made certain lifetime transfers of, an interest in the common stock will be required to include the value of the stock in the individual's gross estate for U.S. federal estate tax purposes, and may be subject to U.S. federal estate tax unless an applicable estate tax treaty provides otherwise. 80
UNDERWRITING Under the terms and subject to the conditions contained in an underwriting agreement dated , 2001, we have agreed to sell to the underwriters named below, for whom Credit Suisse First Boston Corporation, Lehman Brothers Inc., CIBC World Markets Corp. and UBS Warburg LLC are acting as representatives, the following respective numbers of shares of common stock: NUMBER UNDERWRITER OF SHARES - ----------- --------- Credit Suisse First Boston Corporation...................... Lehman Brothers Inc. ....................................... CIBC World Markets Corp..................................... UBS Warburg LLC ............................................ --------- Total..................................................... 3,000,000 ========= The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated. We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to 450,000 additional shares from us and at the public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock. The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $ per share. The underwriters and selling group members may allow a discount of $ per share on sales to other broker/dealers. After the public offering, the public offering price and concession and discount to broker/dealers may be changed by the representatives. The following table summarizes the compensation and estimated expenses we will pay: PER SHARE TOTAL --------------------------------- --------------------------------- WITHOUT WITH WITHOUT WITH OVER-ALLOTMENT OVER-ALLOTMENT OVER-ALLOTMENT OVER-ALLOTMENT --------------- --------------- --------------- --------------- Underwriting discounts and commissions paid by us...................... $ $ $ $ Expenses payable by us.... $ $ $ $ The offering is being made in compliance with the requirements of Rule 2710(c)(8) of the Conduct Rules of the National Association of Securities Dealers, Inc. We have agreed that we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act of 1933 relating to, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any such offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse First Boston Corporation for a period of 90 days after the date of this prospectus, except (a) issuances pursuant to the exercise of employee stock options currently outstanding or subsequently granted pursuant to the terms of a plan in effect on the date hereof or pursuant to our dividend reinvestment plan, our employee stock purchase plan, our retirement savings plan or our non-qualified deferred compensation plan and (b) the registration of shares reserved for issuance under our omnibus incentive compensation plan. 81
Our officers and directors have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction which would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse First Boston Corporation for a period of 90 days after the date of this prospectus. We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect. In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934. - Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. - Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing shares in the open market. - Syndicate covering transactions involve purchase of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering. - Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions. These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time. A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters participating in this offering. The representatives may agree to allocate a number of shares to underwriters for sale to their online brokerage account holders. Credit Suisse First Boston Corporation may effect an on-line distribution through its affiliate, CSFBDIRECT, Inc., an on-line broker dealer, as a selling group member. Internet distributions will be allocated by the underwriters that will make internet distributions on the same basis as other allocations. Some of the underwriters or their affiliates have provided, and may in the future provide, commercial banking, investment banking and other services to us. 82
NOTICE TO CANADIAN RESIDENTS RESALE RESTRICTIONS The distribution of the common stock in Canada is being made only on a private placement basis exempt from the requirement that we prepare and file a prospectus with the securities regulatory authorities in each province where trades of common stock are made. Any resale of the common stock in Canada must be made under applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the common stock. REPRESENTATIONS OF PURCHASERS By purchasing common stock in Canada and accepting a purchase confirmation a purchaser is representing to us and the dealer from whom the purchase confirmation is received that: - the purchaser is entitled under applicable provincial securities laws to purchase the common stock without the benefit of a prospectus qualified under those securities laws, - where required by law, that the purchaser is purchasing as principal and not as agent, and - the purchaser has reviewed the text above under "--Resale Restrictions." RIGHTS OF ACTION (ONTARIO PURCHASERS) The securities being offered are those of a foreign issuer and Ontario purchasers will not receive the contractual right of action prescribed by Ontario securities law. As a result, Ontario purchasers must rely on other remedies that may be available, including common law rights of action for damages or rescission or rights of action under the civil liability provisions of the U.S. federal securities laws. ENFORCEMENT OF LEGAL RIGHTS All of the issuer's directors and officers as well as the experts named herein may be located outside of Canada and, as a result, it may not be possible for Canadian purchasers to effect service of process within Canada upon the issuer or such persons. All or a substantial portion of the assets of the issuer and such persons may be located outside of Canada and, as a result, it may not be possible to satisfy a judgment against the issuer or such persons in Canada or to enforce a judgment obtained in Canadian courts against such issuer or persons outside of Canada. NOTICE TO BRITISH COLUMBIA RESIDENTS A purchaser of common stock to whom the SECURITIES ACT (British Columbia) applies is advised that the purchaser is required to file with the British Columbia Securities Commission a report within ten days of the sale of any common stock acquired by the purchaser pursuant to this offering. The report must be in the form attached to British Columbia Securities Commission Blanket Order BOR #95/17, a copy of which may be obtained from us. Only one report must be filed for common stock acquired on the same date and under the same prospectus exemption. TAXATION AND ELIGIBILITY FOR INVESTMENT Canadian purchasers of common stock should consult their own legal and tax advisors with respect to the tax consequences of an investment in the common stock in their particular circumstances and about the eligibility of the common stock for investment by the purchaser under relevant Canadian legislation. 83
LEGAL OPINIONS Morrill Thomas Nooney & Braun, LLP, Rapid City, South Dakota, will issue an opinion for us regarding the validity of the shares of common stock being offered. Certain legal matters will be passed on for us by Conner & Winters, A Professional Corporation, Tulsa, Oklahoma, and for the underwriters by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York. As of the date of this prospectus, attorneys of Morrill Thomas Nooney & Braun, LLP, owned approximately 4,200 shares of our common stock, in the aggregate. EXPERTS The audited financial statements of Black Hills Corporation included in this prospectus have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in giving said report. The audited financial statements of Indeck Capital, Inc. and Subsidiaries, Indeck North American Power Fund, L.P., Indeck North American Power Partners, L.P., Northern Electric Power Co., L.P. and South Glen Falls Limited Partnership as of December 31, 1999 and for the year ended December 31, 1999 included in this prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting. In its report with respect to Indeck Capital, Inc. and Subsidiaries, it states that with respect to EIF Investors, Inc., a wholly-owned subsidiary of Indeck Capital, Inc., its opinion is based on the reports of other independent public accountants, namely Arthur Andersen LLP. The estimated reserve evaluations of Ralph E. Davis Associates, Inc. for Black Hills Exploration and Production, Inc. at December 31, 2000, included in this prospectus, have been included in reliance on the firm's authority as experts in petroleum engineering. WHERE YOU CAN FIND MORE INFORMATION We file annual, quarterly and special reports, proxy statements and other information with the SEC. You may read and copy any reports, statements or other information we file at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549, or at the SEC's public reference rooms in New York, New York, and Chicago, Illinois. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms. Our filings with the SEC are also available to the public from the SEC's web site at HTTP://WWW.SEC.GOV. Our reports, proxy statements and other information filed with the SEC can also be inspected at the New York Stock Exchange, 20 Broad Street, New York, New York. We have filed with the SEC a registration statement on Form S-1, including all amendments and exhibits to the registration statement, under the Securities Act with respect to the common stock to be sold in this offering. This prospectus constitutes a part of that registration statement. As allowed by the rules and regulations of the SEC, this prospectus does not contain all the information you can find in the registration statement and the exhibits to the registration statement. For further information with respect to us and the common stock offered in this offering, you should refer to the registration statement, including its exhibits. Furthermore, the statements contained in this prospectus concerning any document filed as an exhibit are not necessarily complete and, in each instance, we refer you to a copy of such document filed as an exhibit to the registration statement. 84
INDEX TO FINANCIAL STATEMENTS PAGE -------- Unaudited Pro Forma Consolidated Condensed Financial Statements of Black Hills Corporation..................... F-3 Unaudited Pro Forma Consolidated Condensed Statement of Income for the year ended December 31, 2000............. F-4 Notes to Unaudited Pro Forma Consolidated Statement of Income.................................................. F-5 Black Hills Corporation Historical Audited Financial Statements: Report of Independent Public Accountants................ F-6 Consolidated Statements of Income for the three years ended December 31, 2000................................ F-7 Consolidated Balance Sheets as of December 31, 2000 and 1999................................................... F-8 Consolidated Statements of Cash Flows for the three years ended December 31, 2000.......................... F-9 Consolidated Statements of Common Stockholders' Equity for the three years ended December 31, 2000............ F-10 Notes to Consolidated Financial Statements.............. F-11 Indeck Capital, Inc. and Subsidiaries Historical Audited Financial Statements: Reports of Independent Accountants...................... F-36 Consolidated Balance Sheet as of December 31, 1999...... F-47 Consolidated Statement of Operations for the year ended December 31, 1999...................................... F-48 Consolidated Statement of Changes in Stockholders' Equity for the year ended December 31, 1999............ F-49 Consolidated Statement of Cash Flows for the year ended December 31, 1999...................................... F-50 Notes to Consolidated Financial Statements.............. F-51 Interim Financial Statements: Consolidated Balance Sheet as of June 30, 2000 (unaudited)............................................ F-59 Consolidated Statements of Income for the six months ended June 30, 2000 and 1999 (unaudited)............... F-60 Consolidated Statements of Cash Flows for the six months ended June 30, 2000 and 1999 (unaudited)............... F-61 Indeck North American Power Fund, L.P. Historical Audited Financial Statements: Report of Independent Accountants....................... F-62 Consolidated Balance Sheet as of December 31, 1999...... F-63 Consolidated Statement of Income for the year ended December 31, 1999...................................... F-64 Consolidated Statement of Partners' Equity for the year ended December 31, 1999................................ F-65 Consolidated Statement of Cash Flows for the year ended December 31, 1999...................................... F-67 Notes to Consolidated Financial Statements.............. F-68 Interim Financial Statements: Consolidated Balance Sheet as of June 30, 2000 (unaudited)............................................ F-72 Consolidated Statements of Income for the six months ended June 30, 2000 and 1999 (unaudited)............... F-73 Consolidated Statements of Cash Flows for the six months ended June 30, 2000 and 1999 (unaudited)............... F-74 F-1
PAGE -------- Indeck North American Power Partners, L.P. Historical Audited Financial Statements: Report of Independent Accountants....................... F-75 Balance Sheet as of December 31, 1999................... F-76 Statement of Operations for the year ended December 31, 1999................................................... F-77 Statement of Partners' Equity for the year ended December 31, 1999...................................... F-78 Statement of Cash Flows for the year ended December 31, 1999................................................... F-80 Notes to Financial Statements........................... F-81 Interim Financial Statements: Balance Sheet as of June 30, 2000 (unaudited)........... F-83 Statements of Operations for the six months ended June 30, 2000 and 1999 (unaudited).......................... F-84 Statements of Cash Flows for the six months ended June 30, 2000 and 1999 (unaudited).......................... F-85 Northern Electric Power Co., L.P. Historical Audited Financial Statements: Report of Independent Accountants....................... F-86 Balance Sheet as of December 31, 1999................... F-87 Statement of Earnings for the year ended December 31, 1999................................................... F-88 Statement of Partners' Equity for the year ended December 31, 1999...................................... F-89 Statement of Cash Flows for the year ended December 31, 1999................................................... F-90 Notes to Financial Statements........................... F-91 Interim Financial Statements: Balance Sheet as of September 30, 2000 (unaudited)...... F-94 Statements of Income for the nine months ended September 30, 2000 and 1999 (unaudited).......................... F-95 Statements of Cash Flows for the nine months ended September 30, 2000 and 1999 (unaudited)................ F-96 South Glens Falls Limited Partnership Historical Audited Financial Statements: Report of Independent Accountants....................... F-97 Balance Sheet as of December 31, 1999................... F-98 Statement of Earnings for the year ended December 31, 1999................................................... F-99 Statement of Partners' Equity for the year ended December 31, 1999...................................... F-100 Statement of Cash Flows for the year ended December 31, 1999................................................... F-101 Notes to Financial Statements........................... F-102 Interim Financial Statements: Balance Sheet as of September 30, 2000 (unaudited)...... F-105 Statements of Income for the nine months ended September 30, 2000 and 1999 (unaudited)................ F-106 Statements of Cash Flows for the nine months ended September 30, 2000 and 1999 (unaudited)................ F-107 F-2
PRO FORMA CONSOLIDATED CONDENSED FINANCIAL STATEMENTS The Unaudited Pro Forma Consolidated Condensed Statement of Income of Black Hills Corporation (the "Company") for the fiscal year ended December 31, 2000, has been prepared to illustrate the estimated effect of the Indeck Capital, Inc. ("Indeck"), Indeck North American Power Fund, L.P. ("INAPF"), Indeck North American Power Partners, L.P. ("INAPP"), Northern Electric Power Company, L.P. ("NEPCO"), and South Glens Falls, L.P. ("SGF") transactions (collectively "the Transactions") described in Note 14 to the Company's notes to consolidated financial statements included elsewhere in this prospectus. The Pro Forma Statement of Income gives pro forma effect to the Transactions as if they had occurred on January 1, 2000. The accompanying pro forma information is presented for illustrative purposes only and is not necessarily indicative of the results of operations which would actually have been reported had the Transactions been in effect during the period presented, or which may be reported in the future. The accompanying Unaudited Pro Forma Consolidated Condensed Statement of Income should be read in conjunction with the historical financial statements and related notes thereto for the Company, Indeck, INAPF, INAPP, NEPCO and SGF included elsewhere in this prospectus. F-3
BLACK HILLS CORPORATION UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 2000 12/31/00 YTD THRU YTD THRU YTD THRU COMPANY 6/30/00 6/30/00 6/30/00 CONSOLIDATED INDECK INAPF INAPP ------------ ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES Operating revenues............. $1,623,836 $ 7,351 $ 2,102 $ 896 Equity in income of unconsolidated affiliates.... -- 4,643 4,231 42 ---------- ---------- ---------- ---------- TOTAL REVENUES............... 1,623,836 11,994 6,333 938 ---------- ---------- ---------- ---------- OPERATING EXPENSES Fuel and purchased power expense...................... 1,370,841 -- -- -- Operations and maintenance..... 46,054 3,828 2,045 -- Administrative and general..... 44,423 2,607 950 910 Depreciation, depletion and amortization................. 32,864 280 -- -- Taxes other than income........ 14,904 230 -- -- ---------- ---------- ---------- ---------- TOTAL OPERATING EXPENSES..... 1,509,086 6,945 2,995 910 ---------- ---------- ---------- ---------- INCOME FROM OPERATIONS........... 114,750 5,049 3,338 28 ---------- ---------- ---------- ---------- OTHER INCOME (EXPENSES) Other, net..................... 2,996 35 -- -- Interest income................ 7,075 72 -- -- Interest expense............... (30,342) (3,019) -- -- ---------- ---------- ---------- ---------- TOTAL OTHER INCOME (EXPENSES)................. (20,271) (2,912) -- -- ---------- ---------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST.......... 94,479 2,137 3,338 28 Minority interest.............. (11,273) (5) (42) -- Income tax (expense) benefit... (30,358) (881) -- -- ---------- ---------- ---------- ---------- NET INCOME (LOSS)................ 52,848 1,251 3,296 28 Preferred stock dividends........ (78) -- -- -- ---------- ---------- ---------- ---------- NET INCOME (LOSS) AVAILABLE FOR COMMON STOCK................... $ 52,770 $ 1,251 $ 3,296 $ 28 ========== ========== ========== ========== Earnings per share: basic........ $ 2.39 ========== Earnings per share: diluted...... $ 2.37 ========== Weighted average common share outstanding: basic............. 22,118 Weighted average common share outstanding: diluted........... 22,281 YTD THRU YTD THRU YTD 12/31/00 12/31/00 PRO FORMA NEPCO SGF ADJUSTMENTS 12/31/00 ---------- ---------- ----------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES Operating revenues............. $ 20,907 $ 7,401 $ -- $1,662,493 Equity in income of unconsolidated affiliates.... -- -- (2,558)(a) 6,358 ---------- ---------- ---------- ---------- TOTAL REVENUES............... 20,907 7,401 (2,558) 1,668,851 ---------- ---------- ---------- ---------- OPERATING EXPENSES Fuel and purchased power expense...................... -- -- -- 1,370,841 Operations and maintenance..... 2,024 664 -- 54,615 Administrative and general..... 3,764 1,542 -- 54,196 Depreciation, depletion and amortization................. -- -- 1,868 (b) 35,012 Taxes other than income........ -- -- -- 15,134 ---------- ---------- ---------- ---------- TOTAL OPERATING EXPENSES..... 5,788 2,206 1,868 1,529,798 ---------- ---------- ---------- ---------- INCOME FROM OPERATIONS........... 15,119 5,195 (4,426) 139,053 ---------- ---------- ---------- ---------- OTHER INCOME (EXPENSES) Other, net..................... 133 53 -- 3,217 Interest income................ -- -- (2,922)(c) 4,225 Interest expense............... (7,618) (2,235) 2,922 (c) (40,292) ---------- ---------- ---------- ---------- TOTAL OTHER INCOME (EXPENSES)................. (7,485) (2,182) -- (32,850) ---------- ---------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST.......... 7,634 3,013 (4,426) 106,203 Minority interest.............. -- -- (2,919)(d) (14,239) Income tax (expense) benefit... -- -- (3,019)(e) (34,258) ---------- ---------- ---------- ---------- NET INCOME (LOSS)................ 7,634 3,013 (10,364) 57,706 Preferred stock dividends........ -- -- (86)(f) (164) ---------- ---------- ---------- ---------- NET INCOME (LOSS) AVAILABLE FOR COMMON STOCK................... $ 7,634 $ 3,013 $ (10,450) $ 57,542 ========== ========== ========== ========== Earnings per share: basic........ $ 2.47 ========== Earnings per share: diluted...... $ 2.45 ========== Weighted average common share outstanding: basic............. 1,175(g) 23,293 Weighted average common share outstanding: diluted........... 1,262(g),(h) 23,543 F-4
NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF INCOME NOTE 1: For the purpose of the Pro Forma Consolidated Condensed Statement of Income for the fiscal year ended December 31, 2000, Condensed Statements of Income for the six month period ended June 30, 2000 have been included for Indeck, INAPF and INAPP. The six month period for these companies combined with their results of operations for the six month period ended December 31, 2000, as consolidated into the Company's December 31, 2000 Consolidated Income Statement, give effect to the fiscal year ended December 31, 2000 for pro forma presentation. NOTE 2: The following is a description of each of the pro forma adjustments: (a) Eliminate the earnings in INAPF, INAPP, NEPCO and SGF recorded under the equity method of accounting. (b) Additional depreciation and amortization expense resulting from fair value adjustments of depreciable assets and goodwill related to the acquisitions. (c) Elimination of interest on loans between the Company and Indeck. (d) Adjust the minority interest in earnings on a pro forma basis. (e) Related tax effect of adjustments (a), (b) and (d). (f) Additional preferred stock dividends on the shares issued in the Indeck acquisition. (g) Additional weighted-average shares outstanding for common stock issued in the Indeck acquisition. (h) Effect on the diluted weighted average shares for the conversion of preferred shares issued in the Indeck acquisition. F-5
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders of Black Hills Corporation: We have audited the accompanying consolidated balance sheets of Black Hills Corporation (a South Dakota corporation) and Subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Black Hills Corporation and Subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Minneapolis, Minnesota, January 26, 2001 F-6
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 2000 1999 1998 - ------------------------ ---------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Operating revenues.......................................... $1,623,836 $791,875 $679,254 ---------- -------- -------- Operating expenses: Fuel and purchased power.................................. 1,370,841 637,302 531,518 Operations and maintenance................................ 46,054 36,463 32,701 Administrative and general................................ 44,423 18,272 15,747 Depreciation, depletion and amortization.................. 32,864 25,067 24,037 Oil and gas ceilings test write down...................... -- -- 13,546 Taxes, other than income taxes............................ 14,904 12,880 12,472 ---------- -------- -------- 1,509,086 729,984 630,021 ---------- -------- -------- Operating income............................................ 114,750 61,891 49,233 ---------- -------- -------- Other income (expense): Interest expense.......................................... (30,342) (15,460) (14,707) Interest income........................................... 7,075 3,614 2,861 Other, net................................................ 2,996 876 129 ---------- -------- -------- (20,271) (10,970) (11,717) ---------- -------- -------- Income before minority interest and income taxes............ 94,479 50,921 37,516 Minority interest........................................... (11,273) 1,935 -- Income taxes................................................ (30,358) (15,789) (11,708) ---------- -------- -------- Net income.............................................. 52,848 37,067 25,808 Preferred stock dividends................................... (78) -- -- ---------- -------- -------- Net income available for common stock....................... $ 52,770 $ 37,067 $ 25,808 ========== ======== ======== Earnings per share of common stock: Basic..................................................... $ 2.39 $ 1.73 $ 1.19 ========== ======== ======== Diluted................................................... $ 2.37 $ 1.73 $ 1.19 ========== ======== ======== Weighted average common shares outstanding: Basic..................................................... 22,118 21,445 21,623 ========== ======== ======== Diluted................................................... 22,281 21,482 21,665 ========== ======== ======== The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. F-7
BLACK HILLS CORPORATION CONSOLIDATED BALANCE SHEETS AT DECEMBER 31, 2000 1999 - --------------- ---------- --------- (IN THOUSANDS, EXCEPT SHARE AMOUNTS) ASSETS Current assets: Cash and cash equivalents................................. $ 24,913 $ 16,482 Securities available for sale............................. 2,113 7,586 Receivables (net of allowance for doubtful accounts of $3,631 and $278, respectively) - Customers............................................... 278,436 84,331 Other................................................... 21,283 55,694 Materials, supplies and fuel.............................. 16,545 14,278 Prepaid expenses.......................................... 7,428 2,828 Derivatives at market value............................... 68,292 5,158 ---------- --------- 419,010 186,357 ---------- --------- Investments................................................. 63,965 10,444 ---------- --------- Property and equipment...................................... 1,072,129 700,044 Less accumulated depreciation and depletion............... (277,848) (246,299) ---------- --------- 794,281 453,745 ---------- --------- Other assets: Regulatory asset.......................................... 4,134 3,944 Other, principally goodwill............................... 38,930 14,002 ---------- --------- 43,064 17,946 ---------- --------- $1,320,320 $ 668,492 ========== ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current maturities of long-term debt...................... $ 13,960 $ 1,330 Notes payable............................................. 211,679 97,579 Accounts payable.......................................... 247,596 80,355 Accrued liabilities....................................... 49,661 26,088 Derivatives at market value............................... 65,960 5,158 ---------- --------- 588,856 210,510 ---------- --------- Long-term debt, net of current maturities................... 307,092 160,700 ---------- --------- Deferred credits and other liabilities: Investment tax credits.................................... 2,530 3,022 Federal income taxes...................................... 62,679 47,668 Reclamation and regulatory liability...................... 22,340 22,494 Other..................................................... 16,516 7,492 ---------- --------- 104,065 80,676 ---------- --------- Minority interest in subsidiaries........................... 37,961 -- ---------- --------- Commitments and contingencies (Notes 10, 11 and 14) Stockholders' equity: Preferred stock--no par Series 2000-A; 21,500 shares authorized; Issued and outstanding: 4,000 shares in 2000, -0- shares in 1999................................ 4,000 -- ---------- --------- Common stock equity-- Common stock $1 par value; 100,000,000 shares authorized; Issued: 23,302,111 shares in 2000 and 21,739,030 shares in 1999.............................. 23,302 21,739 Additional paid-in capital.............................. 73,442 40,658 Retained earnings....................................... 191,482 162,239 Treasury stock.......................................... (9,067) (8,030) Accumulated other comprehensive income (loss)........... (813) -- ---------- --------- 278,346 216,606 ---------- --------- Total stockholders' equity............................ 282,346 216,606 ---------- --------- $1,320,320 $ 668,492 ========== ========= The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. F-8
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 2000 1999 1998 - ------------------------ --------- --------- -------- (IN THOUSANDS) Operating activities: Net income available for common........................... $ 52,770 $ 37,067 $ 25,808 Principal non-cash items- Depreciation, depletion and amortization................ 32,864 25,067 24,037 Oil and gas ceilings test write down.................... -- -- 13,546 Derivative fair value adjustment........................ (2,332) -- -- Gain on sales of assets................................. (3,736) (2,541) -- Deferred income taxes and investment tax credits........ 1,937 2,291 (2,535) Minority interest....................................... 11,273 (1,935) -- Change in operating assets and liabilities- Accounts receivable..................................... (201,309) 2,232 (46,821) Materials, supplies, fuel and other current assets...... (3,513) (4,003) (2,954) Accounts payable........................................ 165,394 6,268 41,465 Accrued liabilities..................................... 18,678 4,013 2,244 Other, net.............................................. 2,444 5,284 (60) --------- --------- -------- 74,470 73,743 54,730 --------- --------- -------- Investing activities: Property additions........................................ (134,855) (102,290) (25,265) Increase in investments................................... (13,646) (52,319) (1,960) Payment for acquisition of net assets, net of cash acquired................................................ (28,688) -- -- Proceeds from sales of assets............................. 5,500 3,463 -- Available for sale securities purchased................... -- (7,870) (22,361) Available for sale securities sold........................ 4,660 22,959 13,655 --------- --------- -------- (167,029) (136,057) (35,931) --------- --------- -------- Financing activities: Dividends paid............................................ (23,527) (22,602) (21,737) Treasury stock purchased.................................. (1,037) (4,949) (3,081) Common stock issued....................................... 3,854 424 273 Increase in short-term borrowings......................... 73,848 92,489 5,067 Long-term debt--issuance.................................. 60,082 -- -- Long-term debt--repayments................................ (1,330) (1,330) (1,331) Subsidiary distributions to minority interests............ (10,900) -- -- --------- --------- -------- 100,990 64,032 (20,809) --------- --------- -------- Increase (decrease) in cash and cash equivalents........ 8,431 1,718 (2,010) Cash and cash equivalents: Beginning of year......................................... 16,482 14,764 16,774 --------- --------- -------- End of year............................................... $ 24,913 $ 16,482 $ 14,764 ========= ========= ======== Supplemental disclosure of cash flow information: Cash paid during the period for- Interest................................................ $ 31,309 $ 18,819 $ 14,742 Income taxes............................................ $ 18,518 $ 13,173 $ 13,135 Non cash net assets acquired through issuance of common and preferred stock (Note 14)................................. $ 34,493 $ -- $ -- The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. F-9
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY ACCUMULATED COMMON STOCK ADDITIONAL TREASURY STOCK OTHER ------------------- PAID-IN RETAINED ------------------- COMPREHENSIVE SHARES AMOUNT CAPITAL EARNINGS SHARES AMOUNT INCOME (LOSS) TOTAL -------- -------- ---------- -------- -------- -------- ------------- -------- (IN THOUSANDS) BALANCE AT DECEMBER 31, 1997..................... 21,705 $21,705 $39,995 $143,703 -- $ -- $ -- $205,403 ------ ------- ------- -------- ---- ------- ----- -------- Comprehensive Income: Net income............... -- -- -- 25,808 -- -- -- 25,808 ------ ------- ------- -------- ---- ------- ----- -------- -- -- -- 25,808 -- -- -- 25,808 Dividends on common stock.. -- -- -- (21,737) -- -- -- (21,737) Issuance of common stock... 14 14 259 -- -- -- -- 273 Treasury stock acquired, net...................... -- -- -- -- (141) (3,081) -- (3,081) ------ ------- ------- -------- ---- ------- ----- -------- BALANCE AT DECEMBER 31, 1998..................... 21,719 21,719 40,254 147,774 (141) (3,081) $ -- $206,666 ------ ------- ------- -------- ---- ------- ----- -------- Comprehensive Income: Net income............... -- -- -- 37,067 -- -- -- 37,067 ------ ------- ------- -------- ---- ------- ----- -------- -- -- -- 37,067 -- -- -- 37,067 Dividends on common stock.. -- -- -- (22,602) -- -- -- (22,602) Issuance of common stock... 20 20 404 -- -- -- -- 424 Treasury stock acquired, net...................... -- -- -- -- (227) (4,949) -- (4,949) ------ ------- ------- -------- ---- ------- ----- -------- BALANCE AT DECEMBER 31, 1999..................... 21,739 21,739 40,658 162,239 (368) (8,030) $ -- $216,606 ------ ------- ------- -------- ---- ------- ----- -------- Comprehensive Income: Net income............... -- -- -- 52,848 -- -- -- 52,848 Unrealized loss on available for sale securities............. -- -- -- -- -- -- (813) (813) ------ ------- ------- -------- ---- ------- ----- -------- -- -- -- 52,848 -- -- (813) 52,035 Dividends on preferred stock.................... -- -- -- (78) -- -- -- (78) Dividends on common stock.. -- -- -- (23,527) -- -- -- (23,527) Issuance of common stock... 26 26 544 -- -- -- -- 570 Issuance of common stock for acquisition.......... 1,537 1,537 32,240 -- -- -- -- 33,777 Treasury stock acquired, net...................... -- -- -- -- (13) (1,037) -- (1,037) ------ ------- ------- -------- ---- ------- ----- -------- BALANCE AT DECEMBER 31, 2000..................... 23,302 $23,302 $73,442 $191,482 (381) $(9,067) $(813) $278,346 ====== ======= ======= ======== ==== ======= ===== ======== The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. F-10
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BUSINESS DESCRIPTION Black Hills Corporation and its subsidiaries operate in three primary operating groups: non-regulated independent energy, regulated electric utility and communications. The Company operates its independent energy businesses through its direct and indirect subsidiaries: Wyodak Resources related to coal, Black Hills Exploration and Production related to oil and natural gas, Enserco Energy, Black Hills Energy Resources and Black Hills Coal Network related to fuel marketing of natural gas, oil and coal, respectively, and Black Hills Energy Capital and its subsidiaries and Black Hills Generation related to independent power activities, all consolidated for reporting purposes as Black Hills Energy Ventures; operates its public utility electric operations through its subsidiary, Black Hills Power, Inc.; and operates its communication operations through its indirect subsidiaries Black Hills Fiber Systems, Black Hills FiberCom and Daksoft. For further descriptions of the Company's business segments see Note 13. In December 2000, the Company effected a holding company structure under the renamed holding company Black Hills Corporation. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned subsidiaries. Generally, the Company uses equity accounting for investments of which it owns between 20 and 50 percent and investments in partnerships under 20 percent if the Company exercises significant influence. All significant intercompany balances and transactions have been eliminated in consolidation except for revenues and expenses associated with intercompany coal sales in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Total intercompany coal sales not eliminated were $9.7 million, $7.7 million and $10.3 million in 2000, 1999 and 1998, respectively. The Company owns 51 percent of the voting securities of Black Hills FiberCom, LLC (FiberCom). During 2000 FiberCom's operating losses reduced its members' equity below zero. At that point the Company began to recognize 100 percent of FiberCom's operating losses and will continue to do so until such time as additional equity investments are made by third parties or future net income restores members' equity to a positive amount. As noted in Note 14, Black Hills Energy Capital made several acquisitions during 2000. The Company's consolidated statements of income include operating activity of these companies beginning with their acquisition date. The Company uses the proportionate consolidation method to account for its working interests in oil and gas properties. MINORITY INTEREST IN SUBSIDIARIES Minority interest in results of operations of consolidated subsidiaries represents the minority shareholders' share of the income or loss of various consolidated subsidiaries. The minority interest in F-11
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) the consolidated balance sheets reflect the amount of the underlying net assets of various consolidated subsidiaries attributable to the minority shareholders. REGULATORY ACCOUNTING Black Hills Power is subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company's non-regulated businesses. Black Hills Power follows the provisions of SFAS No. 71, and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating Black Hills Power. As a result of Black Hills Power's 1995 rate case settlement, a 50-year depreciable life for Neil Simpson II is used for financial reporting purposes. If Black Hills Power were not following SFAS 71, a 35 to 40 year life would be more appropriate, which would increase depreciation expense by approximately $0.6 million per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to Black Hills Power's generation operations. In the event Black Hills Power determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company would be an extraordinary non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that could restrict Black Hills Power's ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews these criteria to ensure the continuing application of SFAS 71 is appropriate. CASH EQUIVALENTS The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. AVAILABLE FOR SALE SECURITIES The Company has investments in marketable securities that are classified as available-for-sale securities and are carried at fair value in accordance with the provisions of SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." The unrealized gain or loss resulting from the difference between the securities' fair value and cost basis is included as a component of accumulated other comprehensive income in common stockholders' equity. INVENTORY Materials, supplies and fuel are stated at the lower of cost or market on a first-in, first-out basis. F-12
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) PROPERTY, PLANT AND EQUIPMENT The components of property, plant and equipment are as follows, at December 31: 2000 1999 ---------- -------- (IN THOUSANDS) Independent energy.................................... $ 430,979 $125,371 Electric utility...................................... 530,529 523,461 Communications........................................ 110,486 50,621 Other................................................. 135 591 ---------- -------- $1,072,129 $700,044 ========== ======== Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is an allowance for funds used during construction (AFUDC) which represents the approximate composite cost of borrowed funds and a return on capital used to finance the project. The AFUDC was computed at an annual composite rate of 9.7, 8.3 and 10.1 percent during 2000, 1999 and 1998, respectively. In addition, the Company capitalizes interest, when applicable, on certain non-regulated construction projects. The amount of AFUDC and interest capitalized was $2.0 million, $1.2 million and $0.2 million in 2000, 1999 and 1998, respectively. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, together with removal cost less salvage, is charged to accumulated depreciation. Retirement or disposal of all other assets, except for oil and gas properties as described below, result in gains or losses recognized as a component of income. Repairs and maintenance of property are charged to operations as incurred. Depreciation provisions for regulated electric property, plant and equipment is computed on a straight-line basis using an annual composite rate of 2.8 percent in 2000, 3.1 percent in 1999 and 3.0 percent in 1998. Non-regulated property, plant and equipment is depreciated on a straight-line basis using estimated useful lives ranging from 3 to 39 years. Depletion of coal, oil and gas properties is computed using the cost method. The Company periodically evaluates assets under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of," which requires that such assets be probable of future recovery at each balance sheet date. As of December 31, 2000 and 1999, no significant write-downs were required. GOODWILL AND INTANGIBLE ASSETS Goodwill represents the excess of acquisition costs over the fair market value of the net assets of acquired businesses and is being amortized on a straight-line basis over the estimated useful lives of such assets, which range from 8 to 25 years. The cost of other acquired intangibles is amortized on a straight-line basis over their estimated useful lives. Amortization expense was $3.1 million, $2.7 million and $0.7 million in 2000, 1999 and 1998, respectively. Accumulated amortization was $6.7 million, $3.6 million and $0.9 million at December 31, 2000, 1999 and 1998, respectively. F-13
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) INCOME TAXES The Company uses the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax bases of assets and liabilities. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. To the extent such income taxes are recoverable or payable through future rates, regulatory assets and liabilities have been recorded in the accompanying consolidated balance sheets. Deferred taxes are provided on all significant temporary differences, principally depreciation and depletion. Investment tax credits have been deferred in the electric operation and the accumulated balance is amortized as a reduction of income tax expense over the useful lives of the related electric property which gave rise to the credits. REVENUE RECOGNITION Generally, revenue is recognized at the time products and services are delivered. Fuel marketing businesses also use the mark-to-market method of accounting. Under that method all energy trading activities are recorded at fair value as of the balance sheet date and net gains or losses resulting from the revaluation of these contracts to fair value are recognized currently in the results of operations. In the fourth quarter of 2000, the Company adopted Securities and Exchange Commission Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB 101), which provides guidance on the recognition, presentation and disclosure of revenue in financial statements. The adoption of SAB 101 did not have a material impact on the financial statements. OIL AND GAS OPERATIONS The Company accounts for its oil and gas activities under the full cost method. Under the full cost method, all productive and nonproductive costs related to acquisition, exploration and development drilling activities are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized. Under the full cost method, net capitalized costs may not exceed the present value of proved reserves. EARNINGS PER SHARE OF COMMON STOCK Basic earnings per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed under the treasury stock method and is calculated to compute the dilutive effect of outstanding stock options and conversion of preferred shares. F-14
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Ultimate results could differ from those estimates. RECLASSIFICATIONS Certain 1999 and 1998 amounts in the financial statements have been reclassified to conform to the 2000 presentation. These reclassifications had no effect on the Company's common stockholders' investment or results of operations, as previously reported. ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board (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. The Statement 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. The Statement 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 (APB) Opinion No. 20, "Accounting Changes." 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) will fall under the purview of SFAS 133. The effect from this adoption on the energy trading companies and energy trading activities will not be material because, unless otherwise noted, the trading companies will not designate their energy trading activities as hedge F-15
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) instruments. This "no hedge" designation will result in these derivatives being measured at fair value and gains and losses recognized currently in earnings. This treatment under SFAS 133 will be comparable to the accounting under EITF 98-10. At December 31, 2000, the Company had certain non-trading energy contracts documented as cash flow hedges. These contracts are defined as derivatives under SFAS 133 and meet the requirements for cash flow hedges. Because these non-trading energy contracts were documented as hedges prior to adoption, the transition adjustment will be reported in accumulated other comprehensive income. The aggregated entry for the derivatives identified as energy cash flow hedges will increase derivative assets by $1.4 million, increase the derivative liabilities by $4.0 million and decrease accumulated other comprehensive income by $2.6 million. At December 31, 2000, the Company had interest rate swaps documented as cash flow hedges. These contracts are defined as derivatives under SFAS 133 and meet the requirements for cash flow hedges. Because these contracts were documented as hedges prior to adoption, the transition adjustment will be reported in accumulated other comprehensive income. The interest rate swap transactions have a notional amount of $127.4 million and the associated transition adjustments will increase derivative liabilities by $7.5 million and decrease accumulated other comprehensive income by $7.5 million. (2) 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, which are authorized under its policies that place clear controls on these activities. Hedging transactions involve the use of a variety of derivative financial instruments. Effective January 1, 1999, the Company adopted the provisions of EITF 98-10, pursuant to the implementation requirements stated therein. The resulting effect of adoption of the provisions of EITF 98-10 was to alter the Company's comprehensive method of accounting for energy-related contracts, as defined in that Statement. 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 EITF 98-10. 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 EITF 98-10, these transactions qualify as energy trading activities that must be accounted for at fair value. As such, realized and F-16
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (2) PRICE RISK MANAGEMENT (CONTINUED) 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 December 31, 2000 and 1999 are as follows: VOLUME COVERED MAX. TERM DECEMBER 31, 2000 (MMBTUS) (YEARS) - ----------------- -------------- --------- 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 VOLUME COVERED MAX. TERM (TONS) (YEARS) -------------- --------- Coal tons sold...................................... 988,000 1 Coal tons purchased................................. 896,000 1 VOLUME COVERED MAX. TERM DECEMBER 31, 1999 (MMBTUS) (YEARS) - ----------------- -------------- --------- Natural gas futures contracts purchased............. 860,000 1 Natural gas basis swaps purchased................... 17,741,500 4 Natural gas basis swaps sold........................ 18,390,517 4 Natural gas fixed-for-float swaps purchased......... 9,490,486 1 Natural gas fixed-for-float swaps sold.............. 10,994,521 1 Natural gas collar transactions; puts purchased, calls sold........................................ 408,500 1 Natural gas collar transactions; calls purchased, puts sold......................................... 318,500 1 As required under EITF 98-10, energy trading activities were marked to fair value on December 31, 2000, and the gains and losses recognized in earnings. The entries for the accompanying consolidated balance sheet and income statement are as follows (in thousands): INSTRUMENT ASSET LIABILITY GAIN (LOSS) - ---------- -------- --------- ----------- Natural gas basis swaps......................... $13,391 $23,963 $(10,572) Natural gas fixed-for-float swaps............... 24,617 27,110 (2,493) Natural gas physical............................ 23,391 9,427 13,964 Coal transactions............................... 5,370 4,460 910 Crude oil transactions.......................... 1,523 1,000 523 ------- ------- -------- Totals........................................ $68,292 $65,960 $ 2,332 ======= ======= ======== F-17
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (2) PRICE RISK MANAGEMENT (CONTINUED) There were no significant differences between the fair values of derivative assets and liabilities at December 31, 1999. NON-TRADING ENERGY ACTIVITIES To reduce risk from fluctuations in the price of 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 utilizes hedge accounting. At December 31, 2000, the Company had fixed-for-float swaps for 17,000 barrels per month for the year 2001 to hedge its crude oil price risk with a fair value that approximates cost. The Company had fixed-for-float swaps for 10,000 barrels per month for the year 2002 to hedge its crude oil price risk with a fair value of $0.4 million. The Company also had costless collars (purchased puts--sold calls) for 10,000 barrels per month for 2001 with a fair value of $0.3 million. The Company hedged its forecasted 2001 natural gas production with fixed-for-float swaps. The Company had fixed-for-float swaps for 1,581,000 MMBtus with a fair value of $(3.4) million. These amounts are not reflected in the Company's December 31, 2000 consolidated balance sheet, but will be recorded as part of the adoption of SFAS 133 on January 1, 2001. 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 utilizes hedge accounting. At December 31, 2000, the Company had interest rate swaps with notional amount of $127.4 million, having a maximum term of six years and a fair value of $(7.5) million. At December 31, 2000, the Company had $162.2 million of outstanding, floating-rate debt of which $34.8 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. (3) INVESTMENTS IN ASSOCIATED COMPANIES Included in Investments on the Consolidated Balance Sheets are the following investments that have been recorded on the equity method of accounting: - A 33.33 percent interest in Millennium Pipeline Company, L.P., a Texas limited partnership which owns and operates an oil pipeline in the Gulf Coast region of Texas. The Company has a F-18
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (3) INVESTMENTS IN ASSOCIATED COMPANIES (CONTINUED) carrying amount in the investment of $6.9 million and $4.8 million as of December 31, 2000 and 1999, respectively. The partnership had assets of $22.0 million and $15.7 million, liabilities of $1.0 million and $1.6 million, and net income (loss) of $2.8 million and $(0.2) million as of, and for the years ended December 31, 2000 and 1999, respectively. - As part of the Indeck Capital acquisition, the Company acquired a 5 percent, 6 percent and 5 percent interest in Energy Investors Fund, L.P., Energy Investors Fund II, L.P., and Project Finance Fund III, L.P., respectively, which in turn have investments in numerous electric generating facilities in the United States and elsewhere. The Company has a carrying amount in the investment of $8.4 million at December 31, 2000. As of, and for the year ended December 31, 2000, the funds had assets of $186.8 million, liabilities of $16.0 million and net income of $27.1 million. - As part of the Indeck Capital acquisition, the Company acquired a 50 percent interest in two natural gas-fired cogeneration facilities located in Rupert and Glenns Ferry, Idaho. At December 31, 2000 the Company's carrying amount in the investment is $4.1 million which includes $0.5 million that represents the cost of the investment over the value of the underlying net assets of the projects. This excess is being amortized over 19 years. As of, and for the year ended December 31, 2000, these projects had assets of $26.0 million, liabilities of $18.7 million and net income of $0.9 million. - As part of the Indeck Capital acquisition, the Company directly and indirectly acquired approximately 32 percent of Harbor Cogeneration Company, which in turn owns an 80 megawatt cogeneration facility located near the City of Long Beach in Los Angeles County, California. At December 31, 2000 the Company's carrying amount in the investment is $42.2 million, which includes $13.7 million that represents the cost of the investment over the value of the underlying net assets of Harbor. This excess is being amortized over 15 years. As of, and for the year ended December 31, 2000, Harbor had assets of $41.7 million, liabilities of $0.8 million and net income of $28.8 million. (4) COMMON STOCK STOCK OPTION AND EMPLOYEE STOCK PURCHASE PLANS The Company has a stock option plan (Stock Option Plan), which allows for the granting of stock options with exercise prices equal to the stock's market value on the date of grant, and an employee stock purchase plan (ESPP Plan). The Company accounts for such plans under APB Opinion No. 25, and has adopted the disclosure-only provisions of SFAS No. 123, "Accounting for Stock Based Compensation" (SFAS No. 123). Accordingly, no compensation cost has been recognized. The Company may grant options for up to 1,000,000 shares of common stock under the Stock Option Plan. The Company has granted options on 934,450 shares through December 31, 2000. The option exercise price equals the fair market value of the stock on the day of the grant. The options granted vest one-third a year for three years and all expire after ten years from the grant date. F-19
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (4) COMMON STOCK (CONTINUED) A summary of the status of the stock option plans at December 31, 2000, 1999 and 1998, and changes during the years then ended are as follows: 2000 1999 1998 ------------------- ------------------- ------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE -------- -------- -------- -------- -------- -------- Balance at beginning of year.............. 431,450 $21.35 292,700 $20.29 182,700 $18.69 Granted................................... 492,500 25.22 140,250 23.58 113,000 22.79 Forfeited................................. (4,000) 23.25 (1,500) 23.06 -- -- Exercised................................. (5,033) 21.33 -- -- (3,000) 16.67 ------- ------- ------- Balance at end of year.................... 914,917 23.43 431,450 21.35 292,700 20.29 ======= ======= ======= Exercisable at end of year................ 292,891 20.43 182,400 19.19 84,800 18.06 ======= ======= ======= Exercise prices on options outstanding at December 31, 2000, range from $16.67 to $37.69 with a weighted average remaining contractual life of approximately 8.5 years. The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model. The weighted average fair value of the options granted and the assumptions used to estimate the fair value of options are as follows: 2000 1999 1998 -------- -------- -------- Fair value of options at grant date.................... $3.88 $4.16 $0.69 Weighted average risk-free interest rate............... 6.30% 6.68% 4.70% Weighted average expected price volatility............. 20.60% 19.85% 16.74% Weighted average expected dividend yield............... 4.20% 4.50% 4.20% Expected life in years................................. 10 10 10 Had compensation cost been determined consistent with SFAS No. 123, the Company's net income and earnings per share would have been reduced to the following pro forma amounts for the years ended December 31: 2000 1999 1998 --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Net income available for common: As reported.................................... $52,770 $37,067 $25,808 Pro forma...................................... $52,432 $36,877 $25,717 Earnings per share (basic and diluted): As reported-- --Basic...................................... $ 2.39 $ 1.73 $ 1.19 --Diluted.................................... $ 2.37 $ 1.73 $ 1.19 Pro forma-- --Basic...................................... $ 2.38 $ 1.72 $ 1.19 --Diluted.................................... $ 2.35 $ 1.72 $ 1.19 F-20
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (4) COMMON STOCK (CONTINUED) The Company issued 21,394, 19,565 and 12,824 shares of common stock under the ESPP Plan in 2000, 1999 and 1998, respectively. At December 31, 2000, 226,176 shares are reserved and available for issuance under the ESPP Plan. The Company sells the shares to employees at 90 percent of the stock's market price on the offering date. The fair value per share of shares sold in 2000 was $21.66. DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN The Company has a Dividend Reinvestment and Stock Purchase Plan under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100 percent of the recent average market price. The Company has the option of issuing new shares or purchasing the shares on the open market. The Company purchased shares on the open market in 2000, 1999 and 1998. At December 31, 2000, 1,290,797 shares of unissued common stock were available for future offerings under the Plan. (5) PREFERRED STOCK The Company has 25,000,000 authorized shares of no-par preferred stock. During 2000, the Company issued 4,000 preferred shares in the Indeck Capital acquisition. The preferred shares issued are non-voting, cumulative, no-par shares with a dividend rate equal to 1 percent per annum per share, computed on the basis of $1,000 per share plus an amount equal to any dividend declared payable with respect to the common stock, multiplied by the number of shares of common stock into which each share of preferred stock is convertible. The record and payment dates are the same as the record and payment dates with respect to the payment of dividends on common stock. No dividend may be declared or paid with respect to common stock unless such a dividend is declared and paid with respect to the preferred stock. The preferred stock is senior to the common stock in liquidation events. The Company may redeem the preferred stock in whole or in part, at any time solely at its option. The redemption price per share for the preferred stock shall be $1,000 per share plus all accrued and unpaid dividends. Each share of the preferred stock is convertible at the option of the holder into common stock at any time prior to July 7, 2005 and automatically converted into common stock on July 7, 2005. Each share of preferred stock is convertible into 28.57 common shares. If the Company delivers a notice of redemption, the conversion price shall be adjusted to equal the lesser of (i) the conversion price then in effect, and (ii) the current market price on the redemption notice date. F-21
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (6) LONG-TERM DEBT Long-term debt outstanding at December 31 is as follows: 2000 1999 -------- -------- (IN THOUSANDS) First mortgage bonds: 6.50% due 2002........................................ $ 15,000 $ 15,000 9.00% due 2003........................................ 3,215 4,255 8.06% due 2010........................................ 30,000 30,000 9.49% due 2018........................................ 5,130 5,420 9.35% due 2021........................................ 35,000 35,000 8.30% due 2024........................................ 45,000 45,000 -------- -------- 133,345 134,675 -------- -------- Other long-term debt: Pollution control revenue bonds at 6.7% due 2010...... 12,300 12,300 Pollution control revenue bonds at 7.5% due 2024...... 12,200 12,200 Other................................................. 3,911 2,855 -------- -------- 28,411 27,355 -------- -------- Project financing debt: Floating-rate term loans at a weighted average rate of 8.05% at December 31, 2000 due 2009 through 2010 (a)................................................. 159,296 -- -------- -------- Total long-term debt.................................... 321,052 162,030 Less current maturities................................. (13,960) (1,330) -------- -------- Net long-term debt...................................... $307,092 $160,700 ======== ======== - ------------------------ (a) Approximately 80 percent of the December 31, 2000 balance has been hedged with an interest rate swap moving the floating rates to fixed rates with a weighted average interest rate of 7.69 percent (see Note 2-Price Risk Management). Substantially all of the Company's utility property is subject to the lien of the indenture securing its first mortgage bonds. First mortgage bonds of the Company may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. Project financing debt is non-recourse debt collateralized by a mortgage on each respective project's land and facilities, leases and rights, including rights to receive payments under long-term purchase power contracts. Certain debt instruments of the Company and its subsidiaries contain restrictive covenants, all of which the Company and its subsidiaries are in compliance with at December 31, 2000. Scheduled maturities for the next five years are: $14.0 million in 2001, $30.0 million in 2002, $16.0 million in 2003, $16.4 million in 2004 and $17.6 million in 2005. F-22
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (7) NOTES PAYABLE The Company had committed lines of credit with various banks of $290.0 million at December 31, 2000 and $115.0 million at December 31, 1999, which were available to support bank borrowings or to provide for letters of credit. There were $211.0 million of borrowings and $20.6 million of letters of credit issued under these lines of credit at December 31, 2000, and there were $96.6 million of borrowings and no letters of credit issued at December 31, 1999. The Company has no compensating balance requirements associated with these lines of credit. The lines of credit are subject to periodic review and renewal during the year by the banks. In addition to the above lines of credit, Enserco Energy, Inc. has a $90.0 million uncommitted, discretionary line of credit to provide support for the purchases of natural gas. The Company and its subsidiaries provide no guarantee to the lender. At December 31, 2000 and 1999, there were outstanding letters of credit issued under the facility of $69.8 million and $19.9 million respectively, with no borrowing balances on the facility. In addition to the above lines of credit, Black Hills Energy Resources, Inc. has a $25.0 million uncommitted, discretionary credit facility. The transactional line of credit provides credit support for the purchases of crude oil of Black Hills Energy Resources. The Company and its subsidiaries provide no guarantee to the lender. At December 31, 2000 and 1999, Black Hills Energy Resources, Inc. had letters of credit outstanding of $8.5 million and $13.2 million, respectively and no balance outstanding on the overdraft line. Our credit facilities contain restrictive covenants and include commitment fees ranging from 0.125 percent to 0.375 percent; our credit facilities with ABN AMRO Bank, NV also include utilization fees of 0.75 percent on the amount by which facility loans exceed 50 percent of the total facility commitment. The Company and its subsidiaries had complied with all the covenants at December 31, 2000. Interest rates under the facility borrowings vary and are based, at the option of the Company at the time of the loan origination, on either (i) a prime based borrowing rate varying from prime rate (9.5 percent at December 31, 2000) to prime rate plus 1.5 percent, or (ii) on the London Interbank Offered Rate (LIBOR) (6.5 percent for a one-month LIBOR at December 31, 2000) based borrowings rates varying from LIBOR plus 0.625 percent to LIBOR plus 1.375 percent. (8) FAIR VALUE OF FINANCIAL INSTRUMENTS Cash of the Company is invested in money market investments such as municipal put bonds, money market preferreds, commercial paper, Eurodollars and certificates of deposit. The following methods and assumptions were used to estimate the fair value of each class of the Company's financial instruments. CASH AND CASH EQUIVALENTS The carrying amount approximates fair value due to the short maturity of these instruments. F-23
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (8) FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED) AVAILABLE FOR SALE SECURITIES The fair value of the Company's investments equals the quoted market price when available and a quoted market price for similar securities if a quoted market price is not available. The Company has classified all of its marketable securities as available-for-sale as of December 31, 2000 and 1999. An unrealized loss on the Company's investments of $0.8 million was recorded as of December 31, 2000. At December 31, 1999 fair value approximated cost. LONG-TERM DEBT The fair value of the Company's long-term debt is estimated based on quoted market rates for utility debt instruments having similar maturities and similar debt ratings. The Company's outstanding bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for the Company to call and refinance the bonds. The estimated fair values of the Company's financial instruments are as follows: 2000 (IN THOUSANDS) ---------------------------- CARRYING AMOUNT FAIR VALUE --------------- ---------- Cash and cash equivalents.......................... $ 24,913 $ 24,913 Securities available for sale...................... 2,113 2,113 Long-term debt..................................... 321,052 337,446 1999 (IN THOUSANDS) ---------------------------- CARRYING AMOUNT FAIR VALUE --------------- ---------- Cash and cash equivalents.......................... $ 16,482 $ 16,482 Securities available for sale...................... 7,586 7,586 Long-term debt..................................... 162,030 165,958 (9) WYODAK PLANT The Company owns a 20 percent interest and Pacific Power owns an 80 percent interest in the Wyodak plant (the Plant), a 330 megawatt coal-fired electric generating station located in Campbell County, Wyoming. Pacific Power is the operator of the Plant. The Company receives 20 percent of the Plant's capacity and is committed to pay 20 percent of its additions, replacements and operating and maintenance expenses. As of December 31, 2000, the Company's investment in the Plant included $71.8 million in electric plant and $22.4 million in accumulated depreciation. The Company's share of direct expenses of the Plant was $5.6 million, $4.9 million and $5.8 million for the years ended December 31, 2000, 1999 and 1998, respectively, and is included in the corresponding categories of operating expenses in the accompanying consolidated statements of income. Wyodak Resources supplies coal to the Plant under an agreement expiring in 2013 with a Pacific Power option to renew the agreement for an additional 10 years. This coal supply agreement is collateralized by a mortgage on and a security interest in some of Wyodak Resources' coal reserves. At December 31, 2000, approximately 17,966,000 tons of coal were covered under this agreement. Wyodak Resources' sales to F-24
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (9) WYODAK PLANT (CONTINUED) the Plant were $23.2 million, $24.9 million and $23.2 million, for the years ended December 31, 2000, 1999 and 1998, respectively. (10) COMMITMENTS AND CONTINGENCIES PACIFIC POWER'S POWER SALES AGREEMENT In 1983 the Company entered into a 40 year power agreement with Pacific Power providing for the purchase by the Company of 75 megawatts of electric capacity and energy from Pacific Power's system. An amended agreement signed in October 1997 reduces the contract capacity by 25 megawatts (5 megawatts per year starting in 2000). The price paid for the capacity and energy is based on the operating costs of one of Pacific Power's coal-fired electric generating plants. Costs incurred under this agreement were $14.6 million, $17.8 million and $17.5 million in 2000, 1999 and 1998, respectively. RECLAMATION Under its mining permit, Wyodak Resources is required to reclaim all land where it has mined coal reserves. The cost of reclaiming the land is accrued as the coal is mined. While the reclamation process takes place on a continual basis, much of the reclamation occurs over an extended period after the area is mined. Approximately $0.7 million is charged to operations as reclamation expense annually. As of December 31, 2000, accrued reclamation costs were approximately $17.7 million. LEGAL PROCEEDINGS On August 14, 2000, Wyodak Resources Development Corp. (Wyodak) initiated an action against PacifiCorp as it concerns the Further Restated and Amended Coal Supply Agreement, dated as of May 5, 1987 (Coal Supply Agreement). The action has been filed in the United States District Court for the District of Wyoming as Case No. 00CV155-B. Wyodak alleges that PacifiCorp has failed and refused to make complete payment to Wyodak for coal sold under the Coal Supply Agreement, and there was at that time approximately $5.0 million outstanding and allegedly due Wyodak from PacifiCorp. Wyodak alleged that PacifiCorp's actions constitute a breach of contract and asked for the appropriate monetary relief. On August 31, 2000, PacifiCorp answered the Wyodak Complaint and additionally brought a counterclaim against Wyodak and Black Hills Corporation. In its action, PacifiCorp alleged that as a result of Wyodak's actions as it concerns its billings under the Coal Supply Agreement, PacifiCorp was entitled to cancel and terminate the Coal Supply Agreement and Coal Handling Agreement, as well as the recovery of damages. PacifiCorp alleged that Wyodak had not properly adjusted upward and downward the components which make up the coal price under the Coal Supply Agreement, and as a result PacifiCorp had been overbilled appproximately $35.0 million to $40.0 million and that Wyodak continued to overcharge PacifiCorp under the Coal Supply Agreement and the Coal Handling Agreement. PacifiCorp further alleged that the overcharges would result in additional overcharges of approximately $150.0 million through the balance of the term of the Coal Supply Agreement, which expires in June of 2013. In its action, PacifiCorp sought not only to cancel and terminate the contract but also to discharge and excuse any further obligation under the same, as well as recovery of damages as set forth above. F-25
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (10) COMMITMENTS AND CONTINGENCIES (CONTINUED) Management is of the opinion that Wyodak has properly billed PacifiCorp under the terms of the Coal Supply Agreement and Coal Handling Agreement and PacifiCorp's withholding of payment constitutes a breach of contract on their part. Although it is impossible to predict whether or not Black Hills Corporation and Wyodak will ultimately be successful in defending the claim or, if not, what the impact might be, management believes that the disposition of this matter will not have a material adverse effect on the Company's consolidated results of operations. In addition, the Company is subject to various legal proceedings and claims which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect the consolidated financial position or results of operations of the company. (11) EMPLOYEE BENEFIT PLANS DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS The Company has a noncontributory defined benefit pension plan (Plan) covering the employees of Black Hills Power, Wyodak Resources Development Corp., Black Hills Exploration and Production and Daksoft who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. The Company's funding policy is in accordance with the federal government's funding requirements. The Plan's assets are held in trust and consist primarily of equity securities and cash equivalents. Net pension income for the Plan was as follows: 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Service cost...................................... $ 967 $ 1,174 $ 895 Interest cost..................................... 2,885 2,598 2,406 Estimated return on assets........................ (5,257) (4,162) (4,146) Amortization of transition amount................. (90) (90) (90) Amortization of prior service cost................ 231 89 89 Recognized net actuarial gain..................... (537) -- (272) ------- ------- ------- Net pension income................................ $(1,801) $ (391) $(1,118) ======= ======= ======= Actuarial assumptions: Discount rate................................... 7.5% 6.75% 7.5% Expected long-term rate of return on assets..... 10.5% 10.5% 10.5% Rate of increase in compensation levels......... 5.0% 5.0% 5.0% F-26
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (11) EMPLOYEE BENEFIT PLANS (CONTINUED) A reconciliation of the beginning and ending balances of the projected benefit obligation is as follows: 2000 1999 -------- -------- (IN THOUSANDS) Beginning projected benefit obligation.................... $39,615 $39,490 ------- ------- Service cost.............................................. 967 1,174 Interest cost............................................. 2,885 2,598 Actuarial losses.......................................... (48) (3,590) Benefits paid............................................. (2,105) (1,903) Plan amendments........................................... -- 1,846 ------- ------- Net increase.............................................. 1,699 125 ------- ------- Ending projected benefit obligation....................... $41,314 $39,615 ======= ======= A reconciliation of the fair value of plan assets as of October 1 of each year is as follows: 2000 1999 -------- -------- (IN THOUSANDS) Beginning market value of plan assets..................... $51,212 $40,638 Benefits paid............................................. (2,105) (1,903) Investment income......................................... 7,453 12,477 ------- ------- Ending market value of plan assets........................ $56,560 $51,212 ======= ======= Funding information for the Plan as of October 1 each year was as follows: 2000 1999 -------- -------- (IN THOUSANDS) Fair value of plan assets............................... $ 56,560 $ 51,212 Projected benefit obligation............................ (41,314) (39,615) -------- -------- Funded status........................................... 15,246 11,597 Unrecognized: Net gain.............................................. (13,812) (12,105) Prior service cost.................................... 2,054 2,285 Transition asset...................................... -- (90) -------- -------- Prepaid pension cost.................................... $ 3,488 $ 1,687 ======== ======== Accumulated benefit obligation.......................... $ 33,374 $ 31,914 ======== ======== The Company has various supplemental retirement plans for outside directors and key executives of the Company. The plans are nonqualified defined benefit plans. Expenses recognized under the plans were $0.5 million, $0.4 million and $0.4 million in 2000, 1999 and 1998, respectively. F-27
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (11) EMPLOYEE BENEFIT PLANS (CONTINUED) Employees who are participants in the Plan and who retire from the Company on or after attaining age 55 after completing at least five years of service to the Company are entitled to postretirement healthcare benefits coverage. These benefits are subject to premiums, deductibles, copayment provisions and other limitations. The Company may amend or change the plan periodically. The Company is not pre-funding its retiree medical plan. The net periodic postretirement cost was as follows: 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Service cost........................................... $ 282 $225 $135 Interest cost.......................................... 523 362 290 Amortization of transition obligation.................. 150 150 150 (Gain)/loss............................................ 68 1 (42) ------ ---- ---- $1,023 $738 $533 ====== ==== ==== Funding information as of October 1 was as follows: 2000 1999 -------- -------- (IN THOUSANDS) Accumulated postretirement benefit obligation: Retirees................................................ $ 2,478 $ 2,608 Fully eligible active participants...................... 1,203 1,195 Other active participants............................... 3,172 3,278 ------- ------- Unfunded accumulated postretirement benefit obligation.... 6,853 7,081 Unrecognized net loss..................................... (1,001) (1,667) Unrecognized transition obligation........................ (1,797) (1,947) ------- ------- Accrued postretirement cost............................... $ 4,055 $ 3,467 ======= ======= For measurement purposes, an 8.5 percent annual rate of increase in healthcare benefits was assumed for 2000; the rate was assumed to decrease gradually to 6 percent in 2005 and remain at that level thereafter. The healthcare cost trend rate assumption has a significant effect on the amounts reported. A one percent increase in the healthcare cost trend assumption would increase the service and interest cost $0.2 million or 21.8 percent and the net periodic postretirement cost $0.2 million or 24.1 percent. A one percent decrease would reduce the service and interest cost by $0.1 million or 16.9 percent and decrease the net periodic postretirement cost $0.2 million or 18.6 percent. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 7.5 percent. DEFINED CONTRIBUTION PLAN The Company also sponsors a 401(k) savings plan for eligible employees. Participants elect to invest up to 20 percent of their eligible compensation on a pre-tax basis. Effective January 1, 2000 (May 1, 2000 for employees covered by the collective bargaining agreement), the Company provides a F-28
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (11) EMPLOYEE BENEFIT PLANS (CONTINUED) matching contribution of 100 percent of the employee's tax deferred contribution up to a maximum 3 percent of the employee's eligible compensation. Matching contributions vest at 20 percent per year and are fully vested when the participant has 5 years of service with the Company. The Company's matching contributions totaled $0.6 million for 2000. (12) INCOME TAXES Income tax expense for the years indicated was: 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) Current.......................................... $28,421 $13,498 $14,243 Deferred......................................... 2,576 2,931 (1,886) Tax credits, net................................. (639) (640) (649) ------- ------- ------- $30,358 $15,789 $11,708 ======= ======= ======= The temporary differences which gave rise to the net deferred tax liability at December 31, 2000 and 1999 were as follows: NET DEFERRED INCOME TAX ASSET DECEMBER 31, 2000 ASSETS LIABILITIES (LIABILITY) - ----------------- -------- ----------- ------------ (IN THOUSANDS) Accelerated depreciation and other plant-related differences................... $ 5,393 $63,559 $(58,166) Regulatory asset.............................. 1,621 -- 1,621 Regulatory liability.......................... -- 1,447 (1,447) Unamortized investment tax credits............ 886 -- 886 Mining development and oil exploration........ 3,605 8,450 (4,845) Employee benefits............................. 3,308 1,347 1,961 Other......................................... 3,711 6,400 (2,689) ------- ------- -------- $18,524 $81,203 $(62,679) ======= ======= ======== F-29
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (12) INCOME TAXES (CONTINUED) NET DEFERRED INCOME TAX ASSET DECEMBER 31, 1999 ASSETS LIABILITIES (LIABILITY) - ----------------- -------- ----------- ------------ (IN THOUSANDS) Accelerated depreciation and other plant-related differences................... $ -- $48,223 $(48,223) Regulatory asset.............................. 1,792 -- 1,792 Regulatory liability.......................... -- 1,380 (1,380) Unamortized investment tax credits............ 1,058 -- 1,058 Mining development and oil exploration........ 3,605 6,893 (3,288) Employee benefits............................. 2,833 695 2,138 Other......................................... 2,184 1,949 235 ------- ------- -------- $11,472 $59,140 $(47,668) ======= ======= ======== The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2000 1999 1998 -------- -------- -------- Federal statutory rate................................ 35.0% 35.0% 35.0% State income tax...................................... 1.4 -- -- Amortization of investment tax credits................ (1.0) (0.9) (1.3) Tax-exempt interest income............................ -- (0.5) (1.1) Percentage depletion in excess of cost................ (1.1) (1.6) (1.7) Other................................................. 2.2 (2.1) 0.3 ---- ---- ---- 36.5% 29.9% 31.2% ==== ==== ==== (13) BUSINESS SEGMENTS 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 December 31, 2000, 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, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; Independent Energy consisting of: 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 power to wholesale customers; and Communications and Others, which primarily markets communications and software development services. Segment information follows the same accounting policies as described in Note 1--BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES. Segment F-30
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (13) BUSINESS SEGMENTS (CONTINUED) information included in the accompanying Consolidated Balance Sheets and Consolidated Statements of Income is as follows (in thousands): INDEPENDENT ENERGY ---------------------------------------------- OIL AND FUEL INDEPENDENT COMMUNICATIONS ELECTRIC MINING GAS MARKETING POWER & OTHERS ELIMINATIONS -------- -------- -------- ---------- ----------- -------------- ------------ ASSETS AT DECEMBER 31, 2000 Current assets............... $133,542 $167,820 $ 3,452 $ 330,352 $ 25,645 $ 13,215 $(255,016) Total assets................. 627,930 251,136 36,396 346,333 375,811 132,724 (450,010) AT DECEMBER 31, 1999 Current assets............... $ 93,837 $ 57,427 $ 1,988 $ 84,867 $ 52,471 $ 9,698 $(113,931) Total assets................. 522,285 136,372 29,381 99,064 52,690 72,711 (244,011) AT DECEMBER 31, 1998 Current assets............... $ 43,760 $ 25,872 $ 1,335 $ 77,402 $ 4 $ 6,067 $ (13,960) Total assets................. 451,404 93,480 26,666 86,300 57 18,441 (116,931) TOTAL ---------- ASSETS AT DECEMBER 31, 2000 Current assets............... $ 419,010 Total assets................. 1,320,320 AT DECEMBER 31, 1999 Current assets............... $ 186,357 Total assets................. 668,492 AT DECEMBER 31, 1998 Current assets............... $ 140,480 Total assets................. 559,417 INDEPENDENT ENERGY ---------------------------------------------- OIL AND FUEL INDEPENDENT COMMUNICATIONS ELECTRIC MINING GAS MARKETING POWER & OTHERS ELIMINATIONS -------- -------- -------- ---------- ----------- -------------- ------------ YEAR ENDED DECEMBER 31, 2000 Electric revenues............ $173,308 $ -- $ -- $ -- $ -- $ -- $ -- Coal revenues................ -- 30,530 -- 37,099 -- -- -- Gas revenues................. -- -- 9,335 871,296 -- -- (14,320) Oil revenues................. -- -- 7,211 458,575 -- -- -- Other operating revenues..... -- -- 3,782 -- 39,660 11,371 (4,011) -------- -------- -------- ---------- -------- -------- --------- Total operating revenues..... $173,308 $ 30,530 $ 20,328 $1,366,970 $ 39,660 $ 11,371 $ (18,331) -------- -------- -------- ---------- -------- -------- --------- Depreciation, depletion & amortization............... $ 14,966 $ 3,525 $ 4,071 $ 644 $ 3,646 $ 6,012 $ -- Operating income (loss)...... 68,208 8,794 7,906 23,774 20,374 (14,306) -- Interest expense............. 17,411 8,006 372 535 11,911 6,350 (14,243) Income taxes (benefit)....... 19,469 2,660 2,609 9,323 3,154 (6,857) -- Net income (loss) available for common................. 37,100 7,173 4,992 14,009 3,241 (12,557) (1,188) Property additions, investments and acquisition of net assets.............. 25,257 2,419 9,259 (3) 81,335* 58,922 -- TOTAL ---------- YEAR ENDED DECEMBER 31, 2000 Electric revenues............ $ 173,308 Coal revenues................ 67,629 Gas revenues................. 866,311 Oil revenues................. 465,786 Other operating revenues..... 50,802 ---------- Total operating revenues..... $1,623,836 ---------- Depreciation, depletion & amortization............... $ 32,864 Operating income (loss)...... 114,750 Interest expense............. 30,342 Income taxes (benefit)....... 30,358 Net income (loss) available for common................. 52,770 Property additions, investments and acquisition of net assets.............. 177,189 - ------------------------------ * Excludes the non-cash acquisition of Indeck Capital, Inc. as described in Note 14. F-31
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (13) BUSINESS SEGMENTS (CONTINUED) INDEPENDENT ENERGY ---------------------------------------------- OIL AND FUEL INDEPENDENT COMMUNICATIONS ELECTRIC MINING GAS MARKETING POWER & OTHERS ELIMINATIONS -------- -------- -------- ---------- ----------- -------------- ------------ YEAR ENDED DECEMBER 31, 1999 Electric revenues............ $133,222 $ -- $ -- $ -- $ -- $ -- $ -- Coal revenues................ -- 31,095 -- 39,212 -- -- -- Gas revenues................. -- -- 5,399 382,809 -- -- -- Oil revenues................. -- -- 4,676 192,207 -- -- -- Other operating revenues..... -- -- 2,977 -- -- 3,423 (3,145) -------- -------- -------- ---------- -------- -------- --------- Total operating revenues..... $133,222 $ 31,095 $ 13,052 $ 614,228 $ -- $ 3,423 $ (3,145) -------- -------- -------- ---------- -------- -------- --------- Depreciation, depletion & amortization............... $ 15,552 $ 3,259 $ 2,953 $ 2,757 $ -- $ 546 $ -- Operating income (loss)...... 52,286 12,606 3,978 (2,248) (157) (4,574) -- Interest expense............. 13,830 1,260 568 719 111 1,172 (2,200) Income taxes (benefit)....... 12,446 3,439 968 50 (58) (1,056) -- Net income (loss) available for common................. 27,362 9,715 2,462 (185) (109) (1,263) (915) Property additions, investments and acquisition of net assets.............. 31,911 5,422 9,968 5,947 52,319 49,042 -- TOTAL ---------- YEAR ENDED DECEMBER 31, 1999 Electric revenues............ $ 133,222 Coal revenues................ 70,307 Gas revenues................. 388,208 Oil revenues................. 196,883 Other operating revenues..... 3,255 ---------- Total operating revenues..... $ 791,875 ---------- Depreciation, depletion & amortization............... $ 25,067 Operating income (loss)...... 61,891 Interest expense............. 15,460 Income taxes (benefit)....... 15,789 Net income (loss) available for common................. 37,067 Property additions, investments and acquisition of net assets.............. 154,609 INDEPENDENT ENERGY ---------------------------------------------- OIL AND FUEL INDEPENDENT COMMUNICATIONS ELECTRIC MINING GAS MARKETING POWER & OTHERS ELIMINATIONS -------- -------- -------- ---------- ----------- -------------- ------------ YEAR ENDED DECEMBER 31, 1998 Electric revenues............ $129,236 $ -- $ -- $ -- $ -- $ -- $ -- Coal revenues................ -- 31,413 -- 12,924 -- -- -- Gas revenues................. -- -- 4,073 375,136 -- -- -- Oil revenues................. -- -- 5,131 117,185 -- -- -- Other operating revenues..... -- -- 3,358 798 -- 2,437 (2,437) -------- -------- -------- ---------- -------- -------- --------- Total operating revenues..... $129,236 $ 31,413 $ 12,562 $ 506,043 $ -- $ 2,437 $ (2,437) Depreciation, depletion & amortization............... $ 14,881 $ 3,252 $ 18,760** $ 690 $ -- $ -- $ -- Operating income (loss)...... 49,896 12,723 (12,340)** 41 -- (1,087) -- Interest income.............. 13,572 10 355 731 -- 39 -- Income taxes (benefit)....... 12,612 4,126 (4,689)** (116) (64) (161) -- Net income (loss) available for common................. 24,825 9,750 (7,976)** (346) (118) (226) (101) Property additions, investments and acquisition of net assets.............. 11,451 1,406 10,169 2,384 -- 1,815 -- TOTAL ---------- YEAR ENDED DECEMBER 31, 1998 Electric revenues............ $ 129,236 Coal revenues................ 44,337 Gas revenues................. 379,209 Oil revenues................. 122,316 Other operating revenues..... 4,156 ---------- Total operating revenues..... $ 679,254 Depreciation, depletion & amortization............... $ 37,583 Operating income (loss)...... 49,233 Interest income.............. 14,707 Income taxes (benefit)....... 11,708 Net income (loss) available for common................. 25,808 Property additions, investments and acquisition of net assets.............. 27,225 - ------------------------------ ** Includes the impact of a $13.5 million pretax write-down of certain oil and natural gas properties. (14) ACQUISITIONS On July 7, 2000, the Company acquired Indeck Capital, Inc., and merged it into Black Hills Energy Capital, Inc. The new entity owns varying interests in 14 operating independent power plants in California, New York, Massachusetts, Colorado and Idaho totaling approximately 350 megawatts. The acquisition was a stock transaction with the Company issuing 1,536,747 shares of common stock to the shareholders of Indeck priced at $21.98 per share (approximately 7 percent of the Company's common stock after the transaction), along with $4 million in preferred stock, resulting in a F-32
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (14) ACQUISITIONS (CONTINUED) purchase price of approximately $37.8 million. Additional consideration, consisting of common and preferred stock, may be paid in the form of an earn-out over a four-year period. The earn-out consideration will be based on the acquired company's earnings during such period and cannot exceed $35.0 million in total. Additional consideration paid out under the earn-out will be recorded as an increase to goodwill. The acquisition has been accounted for under the purchase method of accounting and, accordingly, the purchase price has been allocated to the acquired assets and liabilities based on 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 $151.1 million (excluding goodwill) and liabilities assumed of approximately $138.7 million. As of December 31, 2000, the purchase price and related acquisition costs exceeded the fair values assigned to net tangible assets by approximately $25.4 million, which was recorded as goodwill and is being amortized over 25 years on a straight-line basis. Prior to the closing of the Indeck Capital transaction, there was no material relationship between its shareholders and the Company or any of its affiliates, any director or officer of the Company or any of their associates, except that the Company through its subsidiaries and Indeck jointly owned Black Hills Colorado, LLC and both parties held interests in Indeck North American Power Partners, L.P. and Indeck North American Power Fund, L.P. Black Hills Colorado owns 111 megawatts of combustion turbine generating facilities in the Front Range of Colorado. In addition, the Company made several step-acquisitions resulting in consolidation of $169.5 million of assets and $138.8 million of liabilities. The related transactions are as follows: - Through various transactions, acquired an additional 27.11 percent interest in Indeck North American Power Fund, L.P. and an additional 46.66 percent interest in Indeck North American Power Partners, L.P., for approximately $13.0 million in cash. - Acquired a 39.6 percent interest in each of Northern Electric Power Company, L.P. and South Glens Falls Limited Partnership for approximately $4.2 million in cash. - Acquired substantially all of the partnership interests in Middle Falls Limited Partnership, Sissonville Limited Partnership and New York State Dam Limited Partnership for approximately $12.9 million in cash. Operating activities of the above acquired companies have been included in the accompanying consolidated financial statements since their respective acquisition dates. The following unaudited pro forma condensed results of operations presents the effect of the acquisitions as if they had occurred on January 1, 1999. The pro forma financial data is provided for informational purposes only and does not purport to be indicative of the results that would have been obtained if the acquisitions had been effected on January 1, 1999. The pro forma financial information reflects the amortization of the excess F-33
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (14) ACQUISITIONS (CONTINUED) purchase price over the fair value of net assets acquired and the income tax effect thereof for the years ended December 31, 2000 and 1999 as follows: 2000 1999 ------------ ---------- (UNAUDITED, IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues.............................................. $1,668,851 $840,891 Operating income...................................... $ 139,053 $ 73,900 Net income available for common....................... $ 57,542 $ 34,310 Net income per share:................................. Basic............................................... $ 2.47 $ 1.49 Diluted............................................. $ 2.45 $ 1.49 (15) OIL AND GAS RESERVES (UNAUDITED) Black Hills Exploration and Production has interests in 639 producing oil and gas properties in seven states. Black Hills Exploration and Production also holds leases on approximately 185,926 net undeveloped acres. The following table summarizes Black Hills Exploration and Production's quantities of proved developed and undeveloped oil and natural gas reserves, estimated using constant year-end product prices, as of December 31, 2000, 1999 and 1998, and a reconciliation of the changes between these dates. These estimates are based on reserve reports by Ralph E. Davis Associates, Inc., an independent engineering company selected by the Company. Such reserve estimates are based upon a number of variable factors and assumptions which may cause these estimates to differ from actual results. 2000 1999 1998 ------------------- ------------------- ------------------- OIL GAS OIL GAS OIL GAS -------- -------- -------- -------- -------- -------- (IN THOUSANDS OF BARRELS OF OIL AND MMCF OF GAS) Proved developed and undeveloped reserves....... Balance at beginning of year.................. 4,109 19,460 2,368 15,952 2,495 9,052 Production.................................. (352) (3,285) (309) (2,801) (353) (2,068) Additions................................... 625 4,228 376 7,718 1,149 10,721 Property sales.............................. -- -- (164) (66) -- -- Revisions to previous estimates............. 31 (1,999) 1,838 (1,343) (923) (1,753) ------ ------- ------ ------- ------ ------- Balance at end of year........................ 4,413 18,404 4,109 19,460 2,368 15,952 ====== ======= ====== ======= ====== ======= Proved developed reserves at end of year included above................................ 3,047 16,418 2,819 14,391 1,463 10,041 ====== ======= ====== ======= ====== ======= Year-end prices................................. $26.80 $ 9.78 $24.28 $ 1.99 $ 9.16 $ 1.93 ====== ======= ====== ======= ====== ======= In December 1998, Black Hills Exploration and Production recognized a $13.5 million pretax loss related to a write-down of oil and gas properties. The write-down was primarily due to historically low crude oil prices, lower natural gas prices and decline in value of certain unevaluated properties. F-34
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2000, 1999 AND 1998 (16) QUARTERLY HISTORICAL DATA (UNAUDITED) The Company operates on a calendar year basis. The following table sets forth selected unaudited historical operating results and market data for each quarter of 2000 and 1999. FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 2000: Operating revenues................................ $247,959 $336,978 $453,231 $585,668 Operating income.................................. 16,872 15,200 42,519 40,159 Net income available for common stock............. 9,061 8,061 16,285 19,363 Earnings per common share: Basic........................................... 0.42 0.38 0.71 0.84 Diluted......................................... 0.42 0.38 0.71 0.83 Dividends paid per share.......................... 0.27 0.27 0.27 0.27 Common stock prices: High............................................ 25.19 25.19 30.13 46.06 Low............................................. 20.44 20.88 22.00 27.00 1999: Operating revenues................................ $168,201 $186,195 $219,779 $217,700 Operating income.................................. 15,980 13,786 16,675 15,450 Net income available for common stock............. 9,035 7,763 9,725 10,544 Earnings per common share: Basic........................................... 0.42 0.36 0.45 0.50 Diluted......................................... 0.42 0.36 0.45 0.50 Dividends paid per share.......................... 0.26 0.26 0.26 0.26 Common stock prices: High............................................ 26.50 23.88 25.63 23.31 Low............................................. 21.00 21.00 22.19 20.31 (17) SUBSEQUENT EVENT (UNAUDITED) On March 8, 2001, Black Hills Energy Capital, Inc., the Company's independent power subsidiary, announced it had signed a definitive agreement to purchase a 240 megawatt gas-fired turbine generation facility (Fountain Valley) located near Colorado Springs, Colorado from Enron Corporation. The transaction is expected to close around March 31, 2001. The Fountain Valley facility features six LM-6000 simple-cycle, gas-fired turbines, a technology identical to existing Company facilities in Colorado and Wyoming. All necessary permitting has been approved and the plant is expected to phase in its generation capacity beginning in May 2001. The Company also announced that it has signed an 11-year contract with Public Service of Colorado to utilize the plant for peaking purposes. The contract is a tolling arrangement in which the Company assumes no fuel costs. The cost of the project is expected to be approximately $175 million. The Company expects to finance the project primarily with non-recourse debt and negotiations are presently under way with certain lenders. F-35
REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of Indeck Capital, Inc. and Subsidiaries In our opinion, based upon our audit and the report of other auditors, the accompanying consolidated balance sheet and the related consolidated statements of operations, changes in stockholders' equity and cash flows present fairly, in all material respects, the financial position of Indeck Capital, Inc. and Subsidiaries (the "Company") at December 31, 1999, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States. These consolidated financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these consolidated financial statements based on our audit. We did not audit the financial statements of EIF Investors, Inc., a wholly-owned subsidiary, which statements reflect total assets of approximately $5,884,000 at December 31, 1999, and total revenues of approximately $2,900,000 for the year ended December 31, 1999. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for EIF Investors, Inc., is based solely on the report of other auditors. We conducted our audit of the consolidated financial statements in accordance with auditing standards generally accepted in the United States which require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall consolidated financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Milwaukee, Wisconsin June 9, 2000, except for information in Note 11, for which the date is August 30, 2000 F-36
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Members of EIF Management Holdings, LLC: We have audited the accompanying consolidated balance sheet of EIF Management Holdings, LLC (a Delaware limited liability company) and its subsidiaries as of December 31, 1999 and the related consolidated statements of operations and members' equity and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of EIF Management Holdings, LLC and its subsidiaries as of December 31, 1999 and the consolidated results of their operations and their cash flows for the year then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts February 11, 2000 (except for Note 5, as to which the date is February 28, 2000) F-37
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of EIF Group Management Company: We have audited the accompanying balance sheets of EIF Group Management Company (a Massachusetts general partnership) as of December 31, 1999 and 1998 and the related statements of operations, partners' capital and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of EIF Group Management Company as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts February 11, 2000 F-38
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Project Finance Partners, L.P.: We have audited the accompanying balance sheets of Project Finance Partners, L.P. (a Delaware limited partnership) as of December 31, 1999 and 1998 and the related statements of operations, partners' capital (deficit) and cash flows for the years then ended. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Project Finance Partners, L.P. as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts April 21, 2000 F-39
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Project Finance Fund III, L.P.: We have audited the accompanying balance sheets of Project Finance Fund III, L.P. (a Delaware limited partnership) as of December 31, 1999 and 1998 and the related statements of operations, partners' capital and cash flows for the years then ended. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Project Finance Fund III, L.P. as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts April 21, 2000 F-40
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Energy Investors Management Company: We have audited the accompanying balance sheets of Energy Investors Management Company (a Massachusetts general partnership) as of December 31, 1999 and 1998 and the related statements of operations, partners' capital and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Energy Investors Management Company as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts February 11, 2000 F-41
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Energy Investors Partners II, L.P.: We have audited the accompanying balance sheets of Energy Investors Partners II, L.P. (a Delaware limited partnership) as of December 31, 1999 and 1998 and the related statements of operations, comprehensive income, partners' capital (deficit) and cash flows for the years then ended. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Energy Investors Partners II, L.P. as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts April 21, 2000 F-42
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Energy Investors Fund II, L.P.: We have audited the accompanying balance sheets of Energy Investors Fund II, L.P. (a Delaware limited partnership) as of December 31, 1999 and 1998 and the related statements of operations, comprehensive income, partners' capital and cash flows for the years then ended. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Energy Investors Fund II, L.P. as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts April 21, 2000 F-43
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders of Energy Investors Management, Inc.: We have audited the accompanying balance sheets of Energy Investors Management, Inc. (a Delaware corporation) as of December 31, 1999 and 1998 and the related statements of operations and retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Energy Investors Management, Inc. as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts February 11, 2000 F-44
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Energy Investors Partners, L.P.: We have audited the accompanying balance sheets of Energy Investors Partners, L.P. (a Delaware limited partnership) as of December 31, 1999 and 1998 and the related statements of operations, comprehensive income, partners' deficit and cash flows for the year then ended. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Energy Investors Partners, L.P. as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States. Arthur Andersen LLP Boston, Massachusetts April 21, 2000 F-45
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Energy Investors Fund, L.P.: We have audited the accompanying consolidated balance sheets of Energy Investors Fund, L.P. (a Delaware limited partnership) and its subsidiary as of December 31, 1999 and 1998 and the related consolidated statements of operations, comprehensive income, partners' capital and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energy Investors Fund, L.P. and its subsidiary as of December 31, 1999 and 1998 and the consolidated results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts April 21, 2000 F-46
INDECK CAPITAL, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET DECEMBER 31, 1999 ASSETS Current assets: Cash and cash equivalents................................. $ 1,552,886 Accounts receivable....................................... 1,222,144 Accounts receivable, related parties...................... 188,928 Notes receivable, related parties......................... 1,407,815 Inventory................................................. 233,379 Prepaid expenses and other................................ 290,350 ------------ Total current assets.................................... 4,895,502 Property and equipment, net................................. 6,614,617 Construction in progress.................................... 52,690,392 Equity investments.......................................... 38,821,406 Goodwill.................................................... 423,678 Other....................................................... 29,016 ------------ Total assets............................................ $103,474,611 ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.......................................... $ 1,536,370 Accounts payable, related parties......................... 10,250 Deferred management fee income............................ 717,750 Interest payable (including interest payable to related parties of $813,423).................................... 994,911 Income taxes payable...................................... 134,580 Notes payable............................................. 22,439 Other..................................................... 51,943 ------------ Total current liabilities............................... 3,468,243 Contracts payable........................................... 4,770,966 Power sales receipts in excess of avoided costs............. 6,133,856 Notes payable............................................... 88,001,408 Deferred income tax liability............................... 110,800 Minority interest in subsidiaries........................... 134,531 ------------ Total liabilities....................................... 102,619,804 Stockholders' equity: Common stock, no par value, 200,000 shares authorized, 200,000 issued.......................................... 40,080 Retained earnings......................................... 814,727 ------------ Total stockholders' equity.............................. 854,807 ------------ Total liabilities and stockholders' equity.............. $103,474,611 ============ The accompanying notes are an integral part of these consolidated financial statements. F-47
INDECK CAPITAL, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1999 Revenues and income from equity investments: Management fees........................................... $ 2,434,112 Project fees.............................................. 1,761,459 Consulting fees........................................... 529,879 Income from equity investments............................ 3,600,448 Reimbursable costs and other.............................. 2,134,413 ----------- 10,460,311 Administrative and general expenses......................... 10,140,500 ----------- Income from operations.................................. 319,811 Other income (expense): Interest expense, related parties of $2,107,153........... (4,522,988) Interest income, related parties.......................... 746,821 Financing fees............................................ (60,000) Other income, net......................................... 631,438 ----------- Loss before income taxes.................................... (2,884,918) Income tax benefit.......................................... (867,556) ----------- Net loss................................................ $(2,017,362) =========== The accompanying notes are an integral part of these consolidated financial statements. F-48
INDECK CAPITAL, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY FOR THE YEAR ENDED DECEMBER 31, 1999 COMMON STOCK ------------------- RETAINED SHARES AMOUNT EARNINGS TOTAL -------- -------- ----------- ----------- Balances, December 31, 1998....................... 160,000 $ 80 $ 1,817,953 $ 1,818,033 Net loss.......................................... -- -- (2,017,362) (2,017,362) Issuance of common stock in conjunction with the acquisition of North American Funding, L.L.C. (Note 3)........................................ 40,000 40,000 1,014,136 1,054,136 ------- ------- ----------- ----------- Balances, December 31, 1999....................... 200,000 $40,080 $ 814,727 $ 854,807 ======= ======= =========== =========== The accompanying notes are an integral part of these consolidated financial statements. F-49
INDECK CAPITAL, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1999 Cash flows from operating activities: Net loss.................................................. $ (2,017,362) Adjustments to reconcile net loss to net cash used in operating activities: Depreciation and amortization........................... 415,455 Loss on sale of property and equipment.................. 6,313 Write-off of note receivable............................ 227,505 Deferred income taxes................................... (1,086,600) Income from equity investments.......................... (3,600,448) Distributions from equity investments................... 3,600,448 Changes in assets and liabilities, net of effects of business acquisitions: Accounts receivable................................... (250,026) Income taxes.......................................... 217,302 Accounts payable and accrued liabilities.............. 729,812 Power sales receipts in excess of avoided costs....... 642,679 Other................................................. 164,935 ------------ Net cash used in operating activities............... (949,987) ------------ Cash flows from investing activities: Business acquisitions, net of cash acquired............... 245,894 Capital expenditures...................................... (52,771,891) Investments............................................... (672,593) Notes receivable.......................................... (140,279) Payments on notes receivable.............................. 945,018 Distributions from equity investments in excess of earnings................................................ 2,847,711 Other..................................................... 116,722 ------------ Net cash used in investing activities............... (49,429,418) ------------ Cash flows from financing activities: Payments under revolving credit agreement, net............ (1,800,000) Proceeds from notes payable............................... 52,319,000 Payments on long-term debt................................ (28,616) ------------ Net cash provided by financing activities........... 50,490,384 ------------ Net change in cash and cash equivalents..................... 110,979 Cash and cash equivalents at beginning of year.............. 1,441,907 ------------ Cash and cash equivalents at end of year.................... $ 1,552,886 ============ Cash paid during the year for interest...................... $ 4,943,000 ============ Cash paid during the year for income taxes.................. $ 142,000 ============ The accompanying notes are an integral part of these consolidated financial statements. F-50
INDECK CAPITAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION OF INDECK CAPITAL, INC.: Indeck Capital, Inc. (the "Company") was incorporated in 1994 to participate in the rapidly changing power generation industry. The Company is engaged in the acquisition, development, ownership and operation of power generation facilities through direct investment and investment in various projects and funds. The Company has primarily focused on the North American market. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the accounts of Indeck Capital, Inc. and its majority-owned subsidiaries. All significant intercompany accounts and transactions are eliminated in consolidation. Investments in partially-owned affiliates are accounted for by the equity method when the Company's interest exceeds 20%. ESTIMATES: Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. CASH EQUIVALENTS: The Company considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. PROPERTY AND EQUIPMENT: Property and equipment are stated at cost. Depreciation is provided using the straight line method over the lives of the related assets, ranging from 3-30 years. INVESTMENTS: As they represent interests in limited partnerships, the Company's investments are recorded under the equity method. The Company's investments are increased by its share of earnings and reduced by distributions received from or losses incurred by the investment. GOODWILL: Goodwill is amortized on the straight-line method over 37 years. The Company continually assesses the carrying value of goodwill for potential impairment using an undiscounted cash flow approach. POWER SALES RECEIPTS IN EXCESS OF AVOIDED COSTS: The Company's wholly-owned subsidiary, Adirondack Hydro Development Corporation ("AHDC"), entered into a 40-year power purchase agreement ("PPA") with Niagara Mohawk Power Company ("NMPC") between 1985 and 1992, committing the parties to sell and buy, respectively, the output of the Otter Creek facility. The Warrensburg Hydro Power facility, which is owned through subsidiaries of AHDC, also has a 40-year PPA with NMPC. The contracts establish a base rate per kilowatt hour of energy and an annual fixed escalator for the first 15-year period. The cumulative difference between the base payment and "avoided cost" (the greater of $0.06 per kwh or NMPC's actual cost of production avoided by reason of its agreement with AHDC for the Otter Creek facility, and NMPC's actual cost of production avoided by reason of its agreement for the Warrensburg Hydro Power facility), including interest at 125 percent of the 360-day Treasury bill rate, is tracked by NMPC and will be used to adjust the contractual rate over the second 15 years of the respective agreements. In addition, if the projected cumulative difference exceeds the cost of the facilities at any time during years 6 through 15, the fixed escalation is suspended and the respective rates may be reduced. Revenue is recognized when the power is transmitted in accordance with the terms of the PPA and is included in project fees in the consolidated statement of operations. F-51
INDECK CAPITAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED) At December 31, 1999, the cumulative excess of the base payment over the avoided cost (power sales receipts in excess of avoided costs), plus interest, was $6,133,856. INCOME TAXES: Deferred income taxes are provided on a liability method whereby deferred income tax assets are recognized for deductible temporary differences and operating loss and tax credit carryforwards, and deferred income tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax basis. Deferred income tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred income tax assets will not be realized. Deferred income tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. 3. ACQUISITIONS: INDECK COLORADO, L.L.C.: On November 23, 1999, the Company entered into an agreement with the Public Service Company of Colorado ("PSCC") to purchase PSCC's ownership interests in two power plants, the Arapahoe plant and the Valmont plant, and to operate these plants for PSCC. To execute this transaction, the Company formed Indeck Colorado, L.L.C. ("Indeck Colorado") with Black Hills Corporation ("Black Hills"). The Company and Black Hills are each 50% members in Indeck Colorado, although the Company is the managing member of the venture and has the exclusive authority to manage the operations and affairs of Indeck Colorado. Indeck Colorado obtained an $82,000,000 financing arrangement from Black Hills and borrowed $52,319,000 under this arrangement on December 22, 1999 to purchase the plant ownership interests from PSCC (Note 7). The acquisition was accounted for using the purchase method of accounting, with the entire purchase price allocated to the plant assets purchased, which consisted of construction in progress at December 31, 1999. NORTH AMERICAN FUNDING, L.L.C.: On December 10, 1999, the Company issued 40,000 shares of common stock to the members of North American Funding, L.L.C. ("NAF"), a related entity, in exchange for each member's ownership interest in NAF. The assets and liabilities of NAF were transferred to the Company at historical cost as NAF and the Company are under common ownership control. NAF's total assets and liabilities were approximately $7,100,000 and $6,200,000, respectively, at December 10, 1999, including $246,000 of cash acquired. The following unaudited information presents, on a pro forma basis, the results of operations as if the acquisitions had occurred at the beginning of 1999: Revenues and income from equity investments................. $11,600,000 Net loss.................................................... (1,500,000) 4. NOTES RECEIVABLE: The Company has demand notes receivable with certain members of executive management and affiliated entities for approximately $1,408,000 at December 31, 1999. Notes receivable of approximately $1,408,000 at December 31, 1999, bear interest at prime rate plus 1% (9.50% at December 31, 1999). A $200,000 note receivable (including accrued interest of approximately $28,000) was written off during 1999. F-52
INDECK CAPITAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 4. NOTES RECEIVABLE: (CONTINUED) A $5,908,000 note receivable from a related party outstanding at December 31, 1998 was eliminated as part of the acquisition of NAF by the Company (Note 3). 5. INVESTMENTS: INDECK NORTH AMERICAN POWER FUND, L.P.: The Company has a 17.1% limited partnership interest in Indeck North American Power Fund, L.P. at December 31, 1999. The investment balance as of December 31, 1999 was approximately $8,028,000. INDECK NORTH AMERICAN POWER PARTNERS, L.P.: The Company has a 13.3% limited partnership interest in Indeck North American Power Partners, L.P. The investment balance as of December 31, 1999 was approximately $62,000. EIF FUNDS: The Company's wholly-owned subsidiary, EIF Investors, Inc., has general and limited partnership interests in various entities as follows: BALANCE OF OWNERSHIP INVESTMENT INVESTMENT % 12/31/99 - ---------- --------- ----------- Energy Investors Fund, L.P............................ 5 $ 1,861,062 Energy Investors Partners, L.P........................ 50 (1,530,467) Energy Investors Mgmt. Inc............................ 50 121,427 Energy Investors Fund II, L.P......................... 6 1,694,850 Energy Investors Partners II, L.P..................... 38 (98,608) Energy Investors Mgmt. Company........................ 50 242,716 Project Finance Fund III, L.P......................... 5 2,930,714 Project Finance Partners.............................. 50 105,552 EIF Group Management Company.......................... 50 303,693 EIF Management Holdings, LLC.......................... 50 253,255 Goodwill.............................................. -- 1,732,384 ----------- Total............................................... $ 7,616,578 =========== During 1999, EIF Investors, Inc. purchased a 50% interest in EIF Management Holdings, LLC, a limited liability company that was organized on March 17, 1998 and commenced operations on January 1, 1999. NORTHERN ELECTRIC POWER CO., L.P.: The Company's wholly-owned subsidiary, AHDC, has general and limited partnership interests of 1.0% and 19.8%, respectively, in Northern Electric Power Co., L.P. The investment balance as of December 31, 1999 was approximately $11,626,000. SOUTH GLENS FALLS LIMITED PARTNERSHIP: The Company's wholly-owned subsidiary, AHDC, has general and limited partnership interests of 1.0% and 19.8%, respectively, in South Glens Falls Limited Partnership. The investment balance as of December 31, 1999 was approximately $3,661,000. F-53
INDECK CAPITAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 5. INVESTMENTS: (CONTINUED) INDECK IDAHO PARTNERSHIPS: The Company's wholly-owned subsidiary, Indeck Idaho, has general and limited partnership interests in two entities as follows: BALANCE OF OWNERSHIP INVESTMENT INVESTMENT % 12/31/99 - ---------- --------- ---------- Rupert Cogeneration Partners, Ltd..................... 50 $1,807,849 Glenns Ferry Cogeneration Partners, Ltd............... 50 1,512,934 Operating and Maintenance Agreements.................. -- 1,791,013 Goodwill.............................................. -- 1,694,414 ---------- Total............................................... $6,806,210 ========== CARIBBEAN BASIN POWER FUND, LTD.: During 1999, the Company purchased a 3.3% interest in Caribbean Basin Power Fund, Ltd. The investment balance at December 31, 1999 was approximately $555,000. INDECK HARBOR, L.L.C.: As part of the acquisition of NAF (Note 3), the Company acquired a 1% limited partnership interest in Indeck Harbor, L.L.C. The investment balance at December 31, 1999 was approximately $406,000. INDECK PEPPERELL POWER ASSOCIATES, INC.: As part of the acquisition of NAF (Note 3), the Company acquired a 1% ownership interest in Indeck Pepperell Power Associates, Inc. The investment balance at December 31, 1999 was approximately $56,000. Summarized financial information of the Company's significant investments is as follows: INDECK ENERGY ENERGY ENERGY PROJECT NORTH AMERICAN INVESTORS INVESTORS INVESTORS FINANCE POWER FUND, L.P. PARTNERS, L.P. FUND, L.P. FUND II, L.P. FUND III, L.P. ---------------- -------------- ----------- ------------- -------------- 1999 - ---------------------------- Assets...................... $48,577,035 $ 37,075 $60,408,170 $58,225,746 $59,588,473 Liabilities................. 1,536,388 3,074,150 19,007,824 253,116 316,242 Minority interest........... 461,982 -- -- -- -- Equity...................... 46,578,665 (3,037,075) 41,400,346 57,972,630 59,272,231 Total revenues.............. 16,742,881 3,634,537 27,282,383 9,730,477 5,701,157 Net income (loss)........... 2,155,503 2,205,035 22,508,907 6,328,379 (428,339) Equity investment........... 8,028,235 (1,530,467) 1,861,062 1,694,850 2,930,714 Company's share of net income (loss)............. 219,778 1,096,898 925,470 472,152 70,368 Company's percentage ownership................. 17% 50% 5% 6% 5% CONTINUED ON NEXT PAGE F-54
INDECK CAPITAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 5. INVESTMENTS: (CONTINUED) CONTINUED SOUTH NORTHERN GLENS FALLS RUPERT GLENNS FERRY ELECTRIC LIMITED COGENERATION COGENERATION POWER CO., L.P. PARTNERSHIP PARTNERS, LTD. PARTNERS, LTD. --------------- ----------- -------------- -------------- 1999 - ------------------------------------------ Assets.................................... $94,565,394 $35,993,255 $13,868,875 $13,954,925 Liabilities............................... 78,796,269 28,577,111 10,216,655 10,898,491 Minority interest......................... -- -- -- -- Equity.................................... 15,769,125 7,416,144 3,652,220 3,056,434 Total revenues............................ 14,630,540 5,401,474 5,561,875 5,479,366 Net income (loss)......................... 1,708,777 879,698 615,626 524,946 Equity investment......................... 11,626,387 3,660,725 1,807,849 1,512,934 Company's share of net income (loss)...... 355,426 182,977 304,735 259,848 Company's percentage ownership............ 21% 21% 50% 50% 6. PROPERTY AND EQUIPMENT: Property and equipment at December 31, 1999 consists of: Land........................................................ $ 308,015 Power generation facilities................................. 7,080,959 Leasehold improvements...................................... 322,333 Furniture and fixtures...................................... 264,202 Equipment................................................... 1,293,377 Vehicles.................................................... 46,902 ---------- 9,315,788 Accumulated depreciation.................................... 2,701,171 ---------- $6,614,617 ========== F-55
INDECK CAPITAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 7. NOTES PAYABLE: Notes payable at December 31, 1999 consists of: Note payable to Black Hills Corporation, due June 30, 2000 with interest at LIBOR plus 2% (8.00% at December 31, 1999), collateralized by property and equipment of Indeck Colorado L.L.C. (Note 3). This note was refinanced subsequent to December 31, 1999 (Note 11)................................. $52,319,000 Note payable with a bank under a $25 million revolving credit agreement dated June 30, 1998 with interest at the corporate base rate (9.00% at December 31, 1999), collateralized by pledge agreements and guarantees by current stockholders of the Company; includes covenants that require, among other things, the Company to maintain positive levels of tangible net worth. The bank has extended the due date for repayment of the note to June 30, 2000. The Company's contract payable is guaranteed by the available credit under the revolving credit agreement, therefore the amount available under revolving credit agreement at December 31, 1999 is further reduced by the contract payable amount of $4,770,966 at December 31, 1999. This note was refinanced subsequent to December 31, 1999 (Note 11)........ 18,433,693 Note payable to Indeck Energy Services, Inc. (a related entity), due on demand with interest at 11.22%, guaranteed by current stockholder of the Company. Indeck Energy Services, Inc. did not intend to demand payment before December 31, 1999. This note was refinanced subsequent to December 31, 1999 (Note 11)................................. 17,002,902 Note payable to a bank, due August 8, 2001 with interest at the prime rate plus .50% (9.00% at December 31, 1999), collateralized by property and equipment. This note was paid in full in June 2000........................................ 268,252 ----------- 88,023,847 Less current portion........................................ 22,439 ----------- Notes payable, non-current.................................. $88,001,408 =========== 8. RELATED PARTY TRANSACTIONS: Management fees, project fees, consulting fees and reimbursable costs are earned by the Company as services are performed under management agreements for related entities that are not consolidated in the Company's consolidated financial statements. F-56
INDECK CAPITAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 9. INCOME TAXES: The provision for income taxes is comprised of the following: Current provision: Federal................................................... $ -- State..................................................... 219,044 ----------- 219,044 Deferred benefit: Federal................................................... (855,100) State..................................................... (231,500) ----------- (1,086,600) ----------- $ (867,556) =========== The components of the deferred income tax assets and liabilities as of December 31, 1999 were as follows: Deferred income tax assets: Management fees/other..................................... $ 286,700 Investments............................................... 515,600 Net operating loss carryforwards--federal................. 2,124,000 Net operating loss carryforwards--state................... 633,000 Power sales receipts in excess of avoided costs........... 200,600 Alternative minimum tax credits........................... 359,100 Note receivable........................................... 90,900 Deferred income tax liabilities: Investments............................................... (4,311,900) Property and equipment.................................... (8,800) ----------- Deferred income taxes, net.................................. $ (110,800) =========== The following is a reconciliation of the statutory income tax rate to the effective tax rates reflected in the statement of income: Statutory federal income tax rate........................... 34.0% Increase (reduction) in tax rate resulting from: Non-deductible goodwill amortization...................... (3.2) State taxes............................................... 0.3 Other..................................................... (1.0) ---- 30.1% ==== At December 31, 1999, federal net operating loss carryforwards of approximately $6,247,000 expiring in 2013-2020, were available for the reduction of future taxable income. If certain substantial changes in the Company's ownership should occur, there may be an annual limitation on the amount of carryforwards which can be utilized. F-57
INDECK CAPITAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 10. COMMITMENTS: The Company may be required to make additional portfolio investments, pursuant to capital call provisions of certain investment agreements, of up to $7,900,000 at December 31, 1999. These commitments expire at various times through 2001. 11. SUBSEQUENT EVENTS: In January 2000, the Company and its stockholders entered into a definitive agreement to sell all of the outstanding stock of the Company to Black Hills Corporation ("Black Hills). The sale of the Company was completed July 7, 2000. In conjunction with the sale of the Company to Black Hills, a new debt arrangement (the "Arrangement") with various financial institutions was negotiated by the Company on June 30, 2000. Under the terms of the Arrangement, the Company may borrow up to $115,000,000 under a credit revolver. The Arrangement expires July 6, 2003 with interest at various rates based on the conditions of the Arrangement and includes covenants, the most restrictive of which require the Company to maintain certain debt ratios and levels of net worth. Proceeds from this Arrangement were used to pay the $18,433,693 note payable to a bank and the $17,002,902 note payable to Indeck Energy (Note 7). An additional debt arrangement (the "Credit Facility") with a bank was negotiated by the Company on August 30, 2000. Under the terms of the Credit Facility, the Company may borrow up to $60,000,000 under a term loan arrangement. The Credit Facility expires May 31, 2007, but may be extended to May 31, 2010 provided certain conditions are met. The Credit Facility bears interest at various rates based on the conditions of the Credit Facility and includes covenants, the most restrictive of which require the Company to maintain certain debt ratios and levels of net worth. Proceeds from this Credit Facility were used to pay the $52,319,000 note payable to Black Hills Corporation (Note 7). F-58
INDECK CAPITAL, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET JUNE 30, 2000 (UNAUDITED) ASSETS Current assets: Cash and cash equivalents................................. $ 3,339,140 Accounts receivable....................................... 3,094,299 Inventory................................................. 680,985 Prepaid expenses and other................................ 337,256 ------------ Total current assets.................................... 7,451,680 Property and equipment, net of accumulated depreciation of $1,439,346................................................ 85,781,912 Equity in investments....................................... 40,578,710 Goodwill.................................................... 417,551 Deferred tax assets......................................... 286,700 Other....................................................... 88,105 ------------ Total assets............................................ $134,604,658 ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable............................................. $113,030,183 Accounts payable.......................................... 1,079,570 Deferred management fee income............................ 332,006 Accrued liabilities....................................... 4,917,723 ------------ Total current liabilities............................... 119,359,482 Long term liabilities: Contracts payable......................................... 4,770,966 Power sales receipts in excess of avoided costs........... 6,524,224 Capital lease obligation.................................. 12,389 Deferred income tax liability............................. 1,229,287 Minority interest......................................... 602,921 ------------ Total long term liabilities............................. 13,139,787 Total liabilities....................................... 132,499,269 Stockholders' equity: Common stock.............................................. 40,080 Retained earnings......................................... 2,065,309 ------------ Total stockholders' equity.............................. 2,105,389 ------------ Total liabilities and equity............................ $134,604,658 ============ F-59
INDECK CAPITAL, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME FOR THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999 (UNAUDITED) 2000 1999 ----------- ----------- Revenues: Operating revenue......................................... $ 4,314,065 $ 371,459 Management fees........................................... 1,027,450 1,216,759 Project fees.............................................. 670,807 613,356 Consulting fees revenue................................... 71,840 236,266 Income from equity investments............................ 4,643,163 2,526,534 Reimbursable costs and other.............................. 1,266,835 991,807 ----------- ----------- Total revenues.......................................... 11,994,160 5,956,181 Administrative and general expenses......................... 6,945,328 3,353,111 ----------- ----------- Income from operations...................................... 5,048,832 2,603,070 Other income: Interest expense.......................................... (2,923,917) (2,237,422) Interest income........................................... 72,446 433,749 Financing fees............................................ (95,000) (50,000) Other income.............................................. 28,750 5,153 ----------- ----------- Income before income taxes.................................. 2,131,111 754,550 Income tax provision........................................ (880,540) (304,333) ----------- ----------- Net income............................................ $ 1,250,571 $ 450,217 =========== =========== F-60
INDECK CAPITAL, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999 (UNAUDITED) 2000 1999 ------------ ----------- Cash flows from operating activities: Net income................................................ $ 1,250,571 $ 450,217 Adjustments to reconcile net income to net cash used in operating activities: Equity income from investments.......................... (4,543,163) (2,526,534) Cash distributions from investments..................... 2,785,859 2,124,731 Depreciation and amortization........................... 535,166 204,510 Deferred income taxes................................... 1,119,702 (70,118) Increase in accounts receivable and other current assets.................................................. (769,923) (258,098) Increase in accounts payable and other current liabilities............................................. 2,882,295 (115,290) Other..................................................... 531,480 366,872 ------------ ----------- 3,791,987 176,290 ------------ ----------- Cash flows from investing activities: Property and investment additions......................... (27,012,069) (21,078) ------------ ----------- Cash flows from financing activities: Increase in short-term borrowings......................... 25,006,336 485,837 ------------ ----------- Increase in cash and cash equivalents....................... 1,786,254 641,049 Cash and cash equivalents: Beginning of six month period............................. 1,552,886 1,441,907 ------------ ----------- End of six month period................................... $ 3,339,140 $ 2,082,956 ============ =========== F-61
REPORT OF INDEPENDENT ACCOUNTANTS To the Partners of Indeck North American Power Fund, L.P. In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, partners' equity and cash flows present fairly, in all material respects, the financial position of Indeck North American Power Fund, L.P. (the "Partnership") at December 31, 1999, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Milwaukee, Wisconsin February 25, 2000 F-62
INDECK NORTH AMERICAN POWER FUND, L.P. CONSOLIDATED BALANCE SHEET DECEMBER 31, 1999 ASSETS Cash and cash equivalents................................... $ 509,208 Accounts receivable......................................... 1,266,166 Prepaid management fee...................................... 717,750 Investment in Harbor Cogeneration Company................... 40,335,958 Plant and equipment, less accumulated depreciation of $1,335,000................................................ 5,625,140 Other assets................................................ 122,813 ----------- Total assets.............................................. $48,577,035 =========== LIABILITIES AND PARTNERS' EQUITY Accounts payable............................................ $ 1,536,388 Minority interest........................................... 461,982 Partners' equity............................................ 46,578,665 ----------- Total liabilities and partners' equity.................... $48,577,035 =========== The accompanying notes are an integral part of these consolidated financial statements. F-63
INDECK NORTH AMERICAN POWER FUND, L.P. CONSOLIDATED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1999 Revenues and income from equity investments: Equity income from investment............................. $ 5,646,341 Operating revenues........................................ 10,672,645 Other..................................................... 423,895 ----------- 16,742,881 Expenses: Operating expenses........................................ 11,819,558 Selling, general and administrative expenses.............. 2,722,838 ----------- Total expenses.......................................... 14,542,396 ----------- Income before minority interest............................. 2,200,485 Minority interest........................................... 44,982 ----------- Net income.................................................. $ 2,155,503 =========== The accompanying notes are an integral part of these consolidated financial statements. F-64
INDECK NORTH AMERICAN POWER FUND, L.P. CONSOLIDATED STATEMENT OF PARTNERS' EQUITY FOR THE YEAR ENDED DECEMBER 31, 1999 INDECK NORTH NORTH CHASE DYNEGY AMERICAN AMERICAN MANHATTAN MARKETING MIAMI POWER INDECK FUNDING, INVESTMENT AND TRADE VALLEY PARTNERS, L.P. CAPITAL, INC. L.L.C. HOLDINGS, INC. CAPITAL CORP. LEASING, INC. --------------- ------------- ----------- -------------- ------------- ------------- Balances at December 31, 1998...................... $ 530,888 $3,665,003 $ 5,606,679 $3,701,395 $3,665,003 $3,722,912 Capital contributions....... 5,750 41,708 63,889 42,150 41,708 41,708 Capital distributions....... (121,117) (672,041) (1,027,934) (678,665) (672,041) (672,041) Net income.................. 43,088 219,778 131,153 140,110 138,804 138,804 Partner ownership transaction............... -- 4,773,787 (4,773,787) -- -- -- --------- ---------- ----------- ---------- ---------- ---------- Balances at December 31, 1999...................... $ 458,609 $8,028,235 $ -- $3,204,990 $3,173,474 $3,231,383 ========= ========== =========== ========== ========== ========== CONTINUED ON NEXT PAGE The accompanying notes are an integral part of these consolidated financial statements. F-65
INDECK NORTH AMERICAN POWER FUND, L.P. CONSOLIDATED STATEMENT OF PARTNERS' EQUITY (CONTINUED) FOR THE YEAR ENDED DECEMBER 31, 1999 CONTINUED DRESDNER BANK, A.G., PARIBAS ABB GRAND PSEG IGC NORTH ENERGY CAYMAN GLOBAL, INC. ACQUISITIONS, INC. AMERICAN, INC. VENTURES, INC. BRANCH TOTAL ------------- ------------------- --------------- -------------- ----------- ----------- Balances at December 31, 1998.................. $3,230,796 $3,665,003 $11,140,574 $ 9,271,681 $ 5,606,678 $53,806,612 Capital Contributions... -- 41,708 126,893 105,597 63,889 575,000 Capital Distributions... (672,041) (672,041) (2,042,620) (1,699,975) (1,027,934) (9,958,450) Net income.............. 220,264 138,804 421,640 350,931 212,127 2,155,503 Partner ownership transaction........... -- -- -- -- -- -- ---------- ---------- ----------- ----------- ----------- ----------- Balances at December 31, 1999.................. $2,779,019 $3,173,474 $ 9,646,487 $ 8,028,234 $ 4,854,760 $46,578,665 ========== ========== =========== =========== =========== =========== The accompanying notes are an integral part of these consolidated financial statements. F-66
INDECK NORTH AMERICAN POWER FUND, L.P. CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1999 Cash flows from operating activities: Net income................................................ $ 2,155,503 Adjustments to reconcile net income to net cash provided by operating activities: Equity income from investment........................... (5,646,341) Cash distributions from investment...................... 5,646,341 Minority interest....................................... 44,982 Amortization and depreciation........................... 736,941 Changes in assets and liabilities: Account receivable.................................... (772,996) Accounts payable...................................... 1,049,593 Other................................................. 12,721 ----------- Net cash provided by operating activities............. 3,226,744 ----------- Cash flows from investing activities: Capital expenditures for plant and equipment.............. (75,898) Return of capital from investment......................... 6,183,659 ----------- Net cash provided by investing activities............. 6,107,761 ----------- Cash flows from financing activities: Capital contributions from partners....................... 575,000 Capital distributions to partners......................... (9,958,450) Capital contributions from minority interests............. 5,808 Capital distributions to minority interests............... (118,300) ----------- Net cash used in financing activities................. (9,495,942) ----------- Decrease in cash and cash equivalents....................... (161,437) Cash and cash equivalents, beginning of year................ 670,645 ----------- Cash and cash equivalents, end of year...................... $ 509,208 =========== The accompanying notes are an integral part of these consolidated financial statements. F-67
INDECK NORTH AMERICAN POWER FUND, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND OPERATIONS Indeck North American Power Fund, L.P. (the "Partnership") is a limited partnership whose operations commenced May 16, 1995. The Partnership terminates in 2005. The purpose and business of the Partnership is to invest in established utility and non-utility generating assets in the United States and Canada. Indeck North American Power Partners, L.P. (the "General Partner") serves as the general partner and has the exclusive authority for the management, operation and policy of the Partnership. The General Partner has a 1% interest in the Partnership. Profits and losses are generally allocated in a manner such that the capital accounts of partners, immediately after making such allocation, are proportionate to the distributions that would have been made pursuant to the agreement if the partnership were dissolved. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Indeck North American Power Fund, L.P. and its subsidiaries, Indeck Harbor, L.L.C. ("Indeck Harbor") and Indeck Pepperell Power Associates, Inc. ("Indeck Pepperell"), both of which are 99% owned. All significant intercompany transactions have been eliminated. ESTIMATES The preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. CASH EQUIVALENTS The Partnership considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. INCOME TAXES The profits and losses of the Partnership are subject to income taxes directly at the partner level. Accordingly, the Partnership's financial statements do not reflect a provision for income taxes at the Partnership level. Deferred income taxes at Indeck Pepperell are provided on a liability method whereby deferred income tax assets are recognized for deductible temporary differences and operating loss and tax credit carryforwards, and deferred income tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred income tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred income tax assets will not be realized. Deferred income tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. F-68
INDECK NORTH AMERICAN POWER FUND, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) PLANT AND EQUIPMENT Plant and equipment are stated at cost. Depreciation is provided for using the straight-line method over the estimated lives of the related assets, ranging from 5-25 years. The majority of these assets relate to the generation facility. Depreciation expense was $556,000 for 1999. REVENUE RECOGNITION Operating revenue is recognized when steam is transmitted. 3. EQUITY INVESTMENT IN HARBOR COGENERATION COMPANY Under the terms of the general partnership agreement, Indeck Harbor, L.L.C. cannot exercise effective control over the investment in Harbor Cogeneration Company (the "Venture"). Accordingly, Indeck Harbor records its investment in the Venture under the equity method, whereby the investment is increased by its share of the Venture's earnings and reduced by distributions received from the Venture. The Venture entered into a power sales agreement (the "Agreement") with Southern California Edison ("Edison") for the sale of energy produced by the cogeneration facility operated by the Venture. The Agreement has a term of 30 years from April 12, 1989. The Venture is paid energy prices based on 20% of the stated marginal cost of energy and 80% of avoided cost for a period of 10 years, both as defined in the Agreement. For the remaining term of the Agreement, energy prices will equal 100% of avoided cost. In addition to the above energy prices, the Venture is paid capacity revenues over the term of the Agreement based on a stated amount per kilowatt hour as adjusted by a performance bonus factor. Effective February 15, 1999, the Venture entered into a Contract Termination Agreement with Edison which terminated the Agreement. Upon termination, the Venture may continue to sell power, which it did during certain months in 1999, but operations are presently suspended while management explores available options for the Venture, which may include entering into new power sales arrangements that would terminate the Contract Termination Agreement. The Contract Termination Agreement requires Edison to pay the Venture $126.5 million, in quarterly payments ranging from $4.6 million to $2.1 million from the effective date through October 1, 2008 for early termination of the Agreement. During 1999, the Venture recorded approximately $16.4 million related to the Contract Termination Agreement, which is included in operating revenues in the Venture's Statement of Income. F-69
INDECK NORTH AMERICAN POWER FUND, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 3. EQUITY INVESTMENT IN HARBOR COGENERATION COMPANY (CONTINUED) The summarized balance sheet of Harbor Cogeneration Company at December 31, 1999 is as follows: Assets: Cash and cash equivalents................................. $ 4,202,215 Accounts receivable....................................... 16,746 Other..................................................... 1,652,161 Plant and equipment, net.................................. 31,634,894 ----------- Total assets............................................ $37,506,016 =========== Liabilities: Accounts payable.......................................... $ 1,250,440 Partners' equity............................................ 36,255,576 ----------- Total liabilities and partners' equity.................. $37,506,016 =========== The summarized statement of income of Harbor Cogeneration Company for the year ended December 31, 1999 is as follows: Operating and contract termination revenues................. $18,733,612 Operating expenses.......................................... 11,141,525 ----------- Operating income.......................................... 7,592,087 Other income................................................ 2,562,147 Interest expense............................................ (3,991) ----------- Net income................................................ $10,150,243 =========== 4. OTHER INCOME In 1999, other income is primarily comprised of a settlement payment received related to a breach of contract dispute. 5. RELATED PARTY TRANSACTIONS In accordance with the Limited Partnership Agreement, the General Partner receives an annual management fee equal to 1.5% of the Limited Partners' aggregate capital commitments as defined. In 1999, the Partnership paid a management fee of $2,153,000, as well as reimbursement of certain expenditures of $376,000. On December 10, 1999, Indeck Capital, Inc. ("Indeck"), a limited partner, acquired North American Funding, L.L.C. ("NAF"), also a limited partner. As a result of this transaction, Indeck assumed NAF's partnership interest in the Partnership. F-70
INDECK NORTH AMERICAN POWER FUND, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 6. INCOME TAXES The components of the deferred tax assets and liabilities at Indeck Pepperell are as follows at December 31, 1999: Deferred tax asset: Net operating loss carryforward........................... $2,274,000 Deferred tax liability: Plant and equipment....................................... 304,000 ---------- 1,970,000 Valuation allowance......................................... 1,970,000 ---------- Net deferred income taxes................................... $ -- ========== Indeck Pepperell has net operating loss carryforwards of approximately $5,647,000 expiring in 2011-2014, available to offset future taxable income. A valuation allowance has been established for the deferred tax assets due to the uncertainty regarding their ultimate realization. 7. SUBSEQUENT EVENT On January 28, 2000, Dynegy Marketing and Trade Capital Corp. ("DMTCC") was acquired by Black Hills Energy Capital, Inc. ("Black Hills"). As a result of this transaction, Black Hills assumed DMTCC's partnership interest in the Partnership. F-71
INDECK NORTH AMERICAN POWER FUND, L.P. CONSOLIDATED BALANCE SHEET JUNE 30, 2000 (UNAUDITED) ASSETS Current assets: Cash and cash equivalents................................. $ 1,197,276 Accounts receivable....................................... 1,049,114 Prepaid management fee.................................... 332,006 Other..................................................... 96,038 ----------- Total current assets.................................... 2,674,434 Investment in Harbor Cogeneration Company................... 39,207,389 Plant and equipment, net of $1,508,427 of accumulated depreciation.............................................. 5,607,319 Other assets................................................ 964 ----------- Total assets............................................ $47,490,106 =========== LIABILITIES AND PARTNERS' EQUITY Current liabilities: Accounts payable.......................................... $ 719,017 Minority interest........................................... 462,166 Partners' equity............................................ 46,308,923 ----------- Total liabilities and partners' equity.................. $47,490,106 =========== F-72
INDECK NORTH AMERICAN POWER FUND, L.P. CONSOLIDATED STATEMENTS OF INCOME FOR THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999 (UNAUDITED) 2000 1999 ----------- ----------- Revenues: Equity income from investment............................. $ 4,231,430 $ 1,758,781 Operating revenues........................................ 2,013,605 4,497,821 Other..................................................... 88,090 414,022 ----------- ----------- Total revenues.......................................... 6,333,125 6,670,624 Expenses: Operating expenses........................................ 2,045,404 5,006,460 Selling, general and administrative expenses.............. 950,337 1,488,660 ----------- ----------- Total expenses.......................................... 2,995,741 6,495,120 ----------- ----------- Income before minority interest............................. 3,337,384 175,504 Minority interest........................................... 42,733 12,439 ----------- ----------- Net income.................................................. $ 3,294,651 $ 163,065 =========== =========== F-73
INDECK NORTH AMERICAN POWER FUND, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999 (UNAUDITED) 2000 1999 ----------- ----------- Cash flows from operating activities: Net income................................................ $ 3,294,651 $ 163,065 Adjustments to reconcile net income to net cash provided by operating activities: Equity income from investments.......................... (3,631,430) (1,758,781) Cash distribution from investment....................... 3,631,430 1,758,781 Minority interest....................................... 42,733 4,989 Amortization and depreciation........................... 173,646 365,860 Changes in assets and liabilities: Accounts receivable................................... 217,052 (655,641) Prepaid management fee................................ 385,744 0 Accounts payable...................................... (817,372) 435,648 Other................................................. 25,811 14,506 ----------- ----------- Net cash provided by operating activities............. 3,322,265 328,427 ----------- ----------- Cash flows from investing activities: Return of capital from investment......................... 1,128,570 5,661,219 Capital expenditures for plant and equipment.............. (155,826) (19,950) ----------- ----------- Net cash provided by investing activities............. 972,744 5,641,269 ----------- ----------- Cash flows from financing activities: Capital contributions..................................... 650,000 575,000 Capital distributions to partners......................... (4,214,391) (6,669,176) Capital contributions from minority interest.............. 5,050 5,750 Capital distributions to minority interest................ (47,600) (66,692) ----------- ----------- Net cash used in financing activities................. (3,606,941) (6,155,118) ----------- ----------- Increase (decrease) in cash................................. 688,068 (185,422) Cash, beginning of period................................... 509,208 670,645 ----------- ----------- Cash, end of period......................................... $ 1,197,276 $ 485,223 =========== =========== F-74
REPORT OF INDEPENDENT ACCOUNTANTS To the Partners of Indeck North American Power Partners, L.P. In our opinion, the accompanying balance sheet and the related statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of Indeck North American Power Partners, L.P. (the "Partnership") at December 31, 1999, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Milwaukee, Wisconsin February 25, 2000 F-75
INDECK NORTH AMERICAN POWER PARTNERS, L.P. BALANCE SHEET DECEMBER 31, 1999 ASSETS Cash........................................................ $ 3,535 Accounts receivable, affiliates............................. 38,405 Prepaid management fee...................................... 717,750 Investment in Indeck North American Power Fund, L.P......... 458,609 ---------- Total assets.............................................. $1,218,299 ========== LIABILITIES AND PARTNERS' EQUITY Accounts payable, affiliates................................ $ 39,627 Unearned management fee revenue............................. 717,750 ---------- Total liabilities......................................... 757,377 Partners' equity............................................ 460,922 ---------- Total liabilities and partners' equity.................... $1,218,299 ========== The accompanying notes are an integral part of these consolidated financial statements. F-76
INDECK NORTH AMERICAN POWER PARTNERS, L.P. STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1999 Revenues and income from equity investments: Fees and reimbursable expenses............................ $2,529,062 Equity income from investment............................. 43,088 ---------- 2,572,150 Expenses: Selling, general and administrative expenses.............. 3,088,000 ---------- Net loss.................................................... $ (515,850) ========== The accompanying notes are an integral part of these consolidated financial statements. F-77
INDECK NORTH AMERICAN POWER PARTNERS, L.P. STATEMENT OF PARTNERS' EQUITY FOR THE YEAR ENDED DECEMBER 31, 1999 CHASE DYNEGY INDECK MANHATTAN MARKETING MIAMI NORTH INDECK INVESTMENT AND TRADE VALLEY AMERICA, INC. CAPITAL, INC. HOLDINGS, INC. CAPITAL CORP. LEASING, INC. ------------- ------------- -------------- ------------- ------------- Balances at December 31, 1998.... $10,824 $134,503 $ 72,661 $145,316 $146,662 Capital contributions............ 57 826 442 885 885 Capital distributions............ (1,111) (13,702) (7,407) (14,816) (14,816) Net loss......................... (5,158) (63,854) (34,505) (69,010) (69,010) ------- -------- -------- -------- -------- Balances at December 31, 1999.... $ 4,612 $ 57,773 $ 31,191 $ 62,375 $ 63,721 ======= ======== ======== ======== ======== CONTINUED ON NEXT PAGE The accompanying notes are an integral part of these consolidated financial statements. F-78
INDECK NORTH AMERICAN POWER PARTNERS, L.P. STATEMENT OF PARTNERS' EQUITY (CONTINUED) FOR THE YEAR ENDED DECEMBER 31, 1999 CONTINUED PARIBAS ABB PSEG IGC NORTH ENERGY GLOBAL, INC. ACQUISITIONS, INC. AMERICAN INC. VENTURES, INC. TOTAL ------------ ------------------ ------------- -------------- ---------- Balances at December 31, 1998......................... $136,224 $145,316 $145,316 $145,316 $1,082,138 Capital contributions.......... -- 885 885 885 5,750 Capital distributions.......... (14,816) (14,816) (14,816) (14,816) (111,116) Net loss....................... (67,283) (69,010) (69,010) (69,010) (515,850) -------- -------- -------- -------- ---------- Balances at December 31, 1999......................... $ 54,125 $ 62,375 $ 62,375 $ 62,375 $ 460,922 ======== ======== ======== ======== ========== The accompanying notes are an integral part of these consolidated financial statements. F-79
INDECK NORTH AMERICAN POWER PARTNERS, L.P. STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1999 Cash flows from operating activities: Net loss.................................................. $(515,850) Adjustments to reconcile net loss to net cash provided by operating activities: Amortization............................................ 545,417 Equity income from investment........................... (43,088) Cash distributions from investment...................... 43,088 Changes in operating assets and liabilities: Account receivable, affiliates........................ (2,410) Accounts payable, affiliates.......................... 3,882 --------- Net cash provided by operating activities........... 31,039 --------- Cash flows from investing activities: Contributions to Indeck North American Power Fund, L.P.... (5,750) Return of capital from investment......................... 78,029 --------- Net cash provided by investing activities........... 72,279 --------- Cash flows from financing activities: Capital contributions from partners....................... 5,750 Capital distributions to partners......................... (111,116) --------- Net cash used in financing activities............... (105,366) --------- Decrease in cash............................................ (2,048) Cash, beginning of year..................................... 5,583 --------- Cash, end of year........................................... $ 3,535 ========= The accompanying notes are an integral part of these consolidated financial statements. F-80
INDECK NORTH AMERICAN POWER PARTNERS, L.P. NOTES TO FINANCIAL STATEMENTS 1. ORGANIZATION AND OPERATIONS Indeck North American Power Partners, L.P. (the "Partnership") is a limited partnership whose operations commenced May 16, 1995. The partnership terminates in 2005. The purpose and business of the Partnership is to own a 1% interest in Indeck North American Power Fund, L.P. ("INAPF") and act as its General Partner. The Partnership received $2,153,000 in 1999 for management fees, which are recognized as management services are performed, and $376,000 for reimbursable expenditures in 1999, from INAPF and incurred expenses of the same amount to Indeck North America, Inc., the General Partner of the Partnership. Profits and losses are generally to be allocated based on the partners' respective percentage interests, except for amortization costs which are not to be allocated to the General Partner. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ESTIMATES Preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. INCOME TAXES The profits and losses of the Partnership are subject to income taxes directly at the partner level. Accordingly, the Partnership's financial statements do not reflect a provision for income taxes. INVESTMENTS As it represents an interest in a limited partnership, the investment in INAPF is recorded under the equity method. The Partnership's investment is increased by its share of INAPF's earnings and reduced by distributions received from INAPF. F-81
INDECK NORTH AMERICAN POWER PARTNERS, L.P. NOTES TO FINANCIAL STATEMENTS (CONTINUED) 3. EQUITY INVESTMENT IN INAPF The summarized balance sheet of INAPF at December 31, 1999 is as follows: Assets: Cash and cash equivalents................................. $ 509,208 Accounts receivable....................................... 1,266,166 Prepaid management fee.................................... 717,750 Investment in Harbor Cogeneration Company................. 40,335,958 Plant and equipment, net.................................. 5,625,140 Other assets, net......................................... 122,813 ----------- Total assets............................................ $48,577,035 =========== Liabilities: Accounts payable.......................................... $ 1,536,388 Minority interest........................................... 461,982 Partners' equity............................................ 46,578,665 ----------- Total liabilities and partners' equity.................. $48,577,035 =========== The summarized statement of income for INAPF for the year ended December 31, 1999 is as follows: Revenues and income from equity investments: Equity income from investment............................. $ 5,646,341 Operating expenses........................................ 10,672,645 Other..................................................... 423,895 ----------- 16,742,881 ----------- Expenses: Operating................................................. 11,819,558 Selling, general and administrative....................... 2,722,838 Minority interest........................................... 44,982 ----------- Total expenses and minority interest.................... 14,587,378 ----------- Net income.................................................. $ 2,155,503 =========== 4. COMMITMENTS The Partnership has an unfunded capital commitment to INAPF of $878,992 at December 31, 1999. Funding is required as INAPF makes additional portfolio investments. The commitment expires in 2000. 5. SUBSEQUENT EVENT On January 28, 2000, Dynegy Marketing and Trade Capital Corp. ("DMTCC") was acquired by Black Hills Energy Capital, Inc. ("Black Hills"). As a result of this transaction, Black Hills assumed DMTCC's partnership interest in the Partnership. F-82
INDECK NORTH AMERICAN POWER PARTNERS, L.P. BALANCE SHEET JUNE 30, 2000 (UNAUDITED) ASSETS Current assets: Cash...................................................... $ 12 Accounts receivable, affiliates........................... 6,834 Prepaid management fee.................................... 332,006 -------- Total current assets.................................... 338,852 Other assets Investment in INAPF....................................... 464,749 -------- Total assets............................................ $803,601 ======== LIABILITIES AND PARTNERS' CAPITAL Current liabilities: Accounts payable, affiliates.............................. 17,964 Accrued management fee.................................... 332,005 -------- Total current liabilities............................... 349,969 Partners' capital: Beginning capital......................................... 460,921 Contributions............................................. 6,500 Distributions............................................. (42,144) Net income................................................ 28,355 -------- Total partners' capital................................. 453,632 -------- Total liabilities and partners' capital................. $803,601 ======== F-83
INDECK NORTH AMERICAN POWER PARTNERS, L.P. STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999 (UNAUDITED) 2000 1999 -------- ---------- Revenues.................................................... $896,154 $1,353,133 Equity in income on investment.............................. 41,784 12,397 -------- ---------- Total revenues.............................................. 937,938 1,365,530 Selling, general and administrative expenses................ 909,583 1,638,022 -------- ---------- Net income (loss)........................................... $ 28,355 $ (272,492) ======== ========== F-84
INDECK NORTH AMERICAN POWER PARTNERS, L.P. STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2000 AND 1999 (UNAUDITED) 2000 1999 -------- --------- Cash flows from operating activities: Net income................................................ $ 28,355 $(272,492) Adjustments to reconcile net income to net cash provided by operating activities: Equity income from investment........................... (41,784) (12,397) Cash distributions from investment...................... 41,784 12,397 Amortization............................................ 0 272,709 Changes in assets and liabilities: Accounts receivable................................... 56,369 12,619 Accounts payable...................................... (46,463) (5,896) -------- --------- Net cash provided by operating activities........... 38,261 6,940 -------- --------- Cash flows from investing activities: Contribution to Indeck North American Power Fund, L.P..... (6,500) (5,750) Return of capital from investment......................... 360 65,061 -------- --------- Net cash used in (provided by) investing activities........................................ (6,140) 59,311 -------- --------- Cash flows from financing activities: Contributions............................................. 6,500 5,750 Distributions to partners................................. (42,144) (77,458) -------- --------- Net cash used in financing activities............... (35,644) (71,708) -------- --------- Decrease in cash............................................ (3,523) (5,457) Cash, beginning of period................................... 3,535 5,583 -------- --------- Cash, end of period......................................... $ 12 $ 126 ======== ========= F-85
REPORT OF INDEPENDENT ACCOUNTANTS To the Partners of Northern Electric Power Co., L.P. In our opinion, the accompanying balance sheet and the related statements of earnings, of partners' equity and of cash flows present fairly, in all material respects, the financial position of Northern Electric Power Co., L.P. (the "Partnership") at December 31, 1999, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Milwaukee, Wisconsin February 25, 2000 F-86
NORTHERN ELECTRIC POWER CO., L.P. BALANCE SHEET DECEMBER 31, 1999 Assets: Cash and cash equivalents (Note 1)........................ $ 75,906 Accounts receivable--power sales.......................... 1,049,813 Prepaid expenses and supplies............................. 427,325 Property and equipment: Hydroelectric facilities (Notes 1 and 2)................ 99,037,055 Less accumulated depreciation........................... (10,284,710) ------------ Property and equipment, net........................... 88,752,345 Deferred financing costs, net of accumulated amortization of $1,638,464 (Note 1)....................................... 4,260,005 ------------ Total assets.......................................... $ 94,565,394 ============ Liabilities and Partners' Equity: Accounts payable (Note 3)................................. $ 52,085 Accrued expenses (Note 3)................................. 575,137 Operating loan (Note 2)................................... 200,000 Long-term debt (Note 2)................................... 77,969,047 ------------ Total liabilities..................................... 78,796,269 Partners' equity............................................ 15,769,125 ------------ Total liabilities and partners' equity................ $ 94,565,394 ============ See notes to financial statements. F-87
NORTHERN ELECTRIC POWER CO., L.P. STATEMENT OF EARNINGS FOR THE YEAR ENDED DECEMBER 31, 1999 Revenues: Power sales............................................... $14,557,815 Other income.............................................. 72,725 ----------- Total revenues.......................................... 14,630,540 ----------- Expenses: General and administrative................................ 1,309,829 Operations................................................ 401,367 Insurance................................................. 220,683 Property taxes............................................ 304,549 Depreciation and amortization............................. 2,891,003 Interest.................................................. 7,794,332 ----------- Total expenses.......................................... 12,921,763 ----------- Net earnings................................................ $ 1,708,777 =========== See notes to financial statements. F-88
NORTHERN ELECTRIC POWER CO., L.P. STATEMENT OF PARTNERS' EQUITY FOR THE YEAR ENDED DECEMBER 31, 1999 GENERAL LIMITED PARTNER PARTNERS TOTAL -------- ----------- ----------- Balance at December 31, 1998............................. $ (6,286) $15,066,634 $15,060,348 Partner distributions.................................... (10,000) (990,000) (1,000,000) Net earnings............................................. 17,088 1,691,689 1,708,777 -------- ----------- ----------- Balance at December 31, 1999............................. $ 802 $15,768,323 $15,769,125 ======== =========== =========== See notes to financial statements. F-89
NORTHERN ELECTRIC POWER CO., L.P. STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1999 Cash flows from operating activities: Net earnings.............................................. $ 1,708,777 ----------- Adjustments to reconcile net earnings to cash provided by operating activities: Depreciation and amortization............................. 2,891,003 Changes in operating assets and liabilities: Accounts receivable..................................... (88,929) Prepaid expenses and supplies........................... (4,082) Accounts payable........................................ (4,316) Accrued expenses........................................ 21,444 ----------- Total adjustments..................................... 2,815,120 ----------- Cash provided by operating activities................. 4,523,897 ----------- Cash flows from investing activities: Purchases of property and equipment....................... (59,301) ----------- Cash used in investing activities..................... (59,301) ----------- Cash flows from financing activities: Repayment of long-term debt............................... (3,467,267) Partner distributions..................................... (1,000,000) ----------- Cash used in financing activities..................... (4,467,267) ----------- Net change in cash.......................................... (2,671) Cash and cash equivalents, beginning of year.............. 78,577 ----------- Cash and cash equivalents, end of year.................... $ 75,906 =========== Supplemental disclosure of cash flow information: Cash paid during the year for interest.................... $ 7,794,332 =========== See notes to financial statements. F-90
NORTHERN ELECTRIC POWER CO., L.P. NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: a. ORGANIZATION: Northern Electric Power Co., L.P. (the "Partnership") was formed as a limited partnership under the laws of the State of New York on March 11, 1992; it organized and began business on March 1, 1994 for the purpose of developing, rehabilitating, and operating a hydroelectric facility located on the Hudson River, Town of Moreau, Saratoga County, New York. The facility began generating power on November 22, 1995. The financial statements include only the assets and liabilities which relate to the Partnership and do not include any items attributable to the partners' individual activity. b. USE OF ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions (e.g., depreciable lives) that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. c. CASH AND CASH EQUIVALENTS: Cash includes all cash equivalents that are highly liquid investments with a maturity of three months or less when purchased. d. PROPERTY AND EQUIPMENT: Property and equipment are carried at cost. Cost includes expenditures for construction, capitalized interest, on-site and title insurance, and attorney's costs of acquisition. The hydroelectric facilities are being depreciated on a straight-line basis over 40 years. The Partnership evaluates the recoverability of the net carrying amount of the hydroelectric facilities on an ongoing basis by reference to the anticipated future undiscounted cash flows from the operations of the project. Depreciation expense was $2,475,918 for the year ended December 31, 1999. e. DEFERRED FINANCING COSTS: Deferred financing costs are amortized over the term of the related debt agreement (15 years). f. INCOME TAXES: No provision has been made for federal and state income taxes because these taxes are the responsibility of the partners. 2. LONG-TERM DEBT: Long-term debt consists of the following at December 31, 1999: Term loan, Toronto-Dominion Bank, floating interest (7.625% at December 31, 1999), quarterly principal and interest payments of varying amounts, final maturity December 31, 2010....................................................... $77,969,047 =========== Collateral for the term loan and the operating line of credit discussed below includes a mortgage on all facilities, leases and rights, including the right to receive payments from Niagara Mohawk Power Corporation ("NMPC") pursuant to a Power Purchase Agreement ("PPA") with a 40-year term. The loan agreement contains various restrictive covenants including the maintenance of a minimum debt service coverage ratio. F-91
NORTHERN ELECTRIC POWER CO., L.P. NOTES TO FINANCIAL STATEMENTS (CONTINUED) 2. LONG-TERM DEBT: (CONTINUED) Minimum principal payments under the existing term loan agreement for the five years following December 31, 1999 and thereafter are as follows: 2000........................................................ $ 3,822,883 2001........................................................ 4,667,474 2002........................................................ 5,200,900 2003........................................................ 5,689,873 2004........................................................ 6,490,011 Thereafter.................................................. 52,097,906 ----------- $77,969,047 =========== The Partnership also has a $5 million operating line of credit with the Toronto-Dominion Bank ("Bank") through April 2000, which automatically renews every three years through December 31, 2010. The Partnership had borrowings of $200,000 outstanding under this agreement at December 31, 1999. Borrowings under the agreement bear interest at LIBOR plus 1.875% (LIBOR was 6.44% at December 31, 1999). To provide some degree of protection against the potential impact of rising interest rates, effective March 29, 1996, the Partnership entered into an amortizing interest rate swap agreement that expires June 29, 2006. This agreement effectively changes the Partnership's interest rate exposure on approximately 75% of the future floating rate term loan to a fixed rate. Under the agreement, each quarter the Partnership pays a fixed rate of 8.835% on the notional amount to the Bank (notional amount was $58,785,814 at December 31, 1999), and receives a variable rate from the Bank (6.18125% at December 31, 1999). The net amount payable or receivable is recorded as interest expense. At December 31, 1999, the carrying amount of all debt obligations approximate their fair values, and the fair value of the interest rate swap agreement was $4,797,300, representing the cost the Partnership would incur to terminate the agreement. 3. RELATED PARTY TRANSACTIONS: Fees to Adirondack Hydro Development Corporation ("Adirondack"), a limited partner, during 1999 were $750,000, of which $324,144 is included in accrued expenses at December 31, 1999. Included in accounts payable at December 31, 1999 are amounts payable to affiliated companies of $37,377. 4. POWER PURCHASE AGREEMENT: The Partnership has entered into a 40-year power purchase agreement with NMPC, committing the parties to sell and buy, respectively, the output of the hydroelectric facility. The PPA establishes contract energy payment rates for each of the 40 years. The contract energy payment rate was $0.09002 per kilowatt hour at December 31, 1999. Revenue is recognized when the power is transmitted in accordance with the terms of the PPA. On August 1, 1996, NMPC submitted a proposal to nineteen Independent Power Producers ("IPPs") to restructure 44 of the IPPs' PPAs with NMPC concurrent with an internal restructuring of NMPC. Adirondack's projects, including the Partnership, made up seven of the 44 PPAs subject to F-92
NORTHERN ELECTRIC POWER CO., L.P. NOTES TO FINANCIAL STATEMENTS (CONTINUED) 4. POWER PURCHASE AGREEMENT: (CONTINUED) NMPC's proposal. However, in June 1997, NMPC withdrew its proposal for all hydroelectric projects included in the original group of 44 PPAs. As of December 31, 1997, agreements had been reached with sixteen of the nineteen IPPs on the restructuring of 29 of the PPAs. As of March 20, 1998, the New York State Public Service Commission approved NMPC's restructuring plan. The plan included the restructuring of 29 PPAs which represent over 80% of NMPC's "out-of-market" PPAs. Adirondack initiated separate discussions with NMPC in November 1997 regarding the restructuring of its seven PPAs. Discussions are ongoing. A term sheet was signed for two of the seven PPAs (Warrensburg Hydro Power Limited Partnership and Sissonville Limited Partnership) in 1999. Adirondack management anticipates that a final settlement for the restructuring of the remaining PPAs will be reached in 2000. 5. LEASES The Partnership leases the land upon which its hydroelectric facilities are situated from NMPC and the adjacent riverbed from the State of New York. These lease agreements extend through the end of the PPA with NMPC. Total rental expense in 1999 was $60,349. F-93
NORTHERN ELECTRIC POWER CO., L.P. BALANCE SHEET SEPTEMBER 30, 2000 (UNAUDITED) Assets: Cash...................................................... $ 2,382,160 Accounts receivable....................................... 1,175,127 Prepaid expenses and supplies............................. 233,559 ------------ Total current assets.................................... 3,790,846 Property and equipment: Hydroelectric facilities.................................. 99,037,055 Less accumulated depreciation............................. (12,142,317) ------------ Property and equipment, net................................. 86,894,738 Deferred financing costs.................................. 3,965,082 ------------ Total assets............................................ $ 94,650,666 ============ Liabilities and Equity: Accounts payable.......................................... $ 1,707 Accrued expenses.......................................... 2,099,741 ------------ Total current liabilities............................... 2,101,448 Term debt--Toronto Dominion............................... 75,101,885 Partners' equity.......................................... 17,447,333 ------------ Total liabilities and equity............................ $ 94,650,666 ============ F-94
NORTHERN ELECTRIC POWER CO., L.P. STATEMENTS OF INCOME FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999 (UNAUDITED) 2000 1999 ----------- ----------- Revenue: Electricity sales......................................... $16,504,955 $11,309,072 ----------- ----------- Expenses: Operations................................................ 1,393,350 1,278,130 Administrative and general................................ 198,299 267,111 Depreciation/amortization................................. 2,152,531 2,168,612 Taxes other than income................................... 348,954 217,411 ----------- ----------- Total expenses.......................................... 4,093,134 3,931,264 Miscellaneous non-operating income.......................... 100,554 60,367 Interest expense............................................ 5,734,167 5,862,561 ----------- ----------- Net earnings................................................ $ 6,778,208 $ 1,575,614 =========== =========== F-95
NORTHERN ELECTRIC POWER CO., L.P. STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999 (UNAUDITED) 2000 1999 ----------- ----------- Cash flows from operating activities: Net earnings.............................................. $ 6,778,208 $ 1,575,614 ----------- ----------- Adjustments to reconcile net earnings to cash provided by (used in) operating activities: Depreciation and amortization............................. 2,152,531 2,168,612 Changes in operating assets and liabilities: Accounts receivable..................................... (125,314) 89,218 Prepaid expenses and supplies........................... 193,766 197,763 Accounts payable........................................ (50,378) 20,302 Accrued partner distribution payable.................... (1,500,000) -- Accrued expenses........................................ 1,524,603 (156,733) ----------- ----------- Total adjustments..................................... 2,195,208 2,319,162 ----------- ----------- Cash provided by operating activities................. 8,973,416 3,894,776 ----------- ----------- Cash flows from investing activities: Purchases of property and equipment....................... -- (60,660) ----------- ----------- Cash used in investing activities..................... -- (60,660) ----------- ----------- Cash flows from financing activities: Repayment of operating loan............................... (200,000) (200,000) Repayment of long-term debt............................... (2,867,162) (2,600,450) Partner distributions..................................... (3,600,000) (1,000,000) ----------- ----------- Cash used in financing activities..................... (6,667,162) (3,800,450) ----------- ----------- Net change in cash.......................................... 2,306,254 33,666 Cash and cash equivalents, beginning of period............ 75,906 78,577 ----------- ----------- Cash and cash equivalents, end of period.................. $ 2,382,160 $ 112,243 =========== =========== F-96
REPORT OF INDEPENDENT ACCOUNTANTS To the Partners of South Glens Falls Limited Partnership In our opinion, the accompanying balance sheet and the related statements of earnings, of partners' equity and of cash flows present fairly, in all material respects, the financial position of South Glens Falls Limited Partnership (the "Partnership") at December 31, 1999, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Milwaukee, Wisconsin February 25, 2000 F-97
SOUTH GLENS FALLS LIMITED PARTNERSHIP BALANCE SHEET DECEMBER 31, 1999 Assets: Cash and cash equivalents (Note 1)........................ $ 76,870 Accounts receivable--power sales.......................... 388,237 Prepaid expenses and supplies............................. 180,734 Property and equipment: Hydroelectric facilities (Notes 1 and 2)................ 39,428,866 Less accumulated depreciation........................... (5,338,783) ----------- Property and equipment, net........................... 34,090,083 Deferred financing costs, net of accumulated amortization of $710,666 (Note 1)......................................... 1,257,331 ----------- Total assets.......................................... $35,993,255 =========== Liabilities and Partners' Equity: Accounts payable (Note 3)................................. $ 43,426 Accrued expenses (Note 3)................................. 369,158 Operating loan (Note 2)................................... 100,000 Long-term debt (Note 2)................................... 28,064,527 ----------- Total liabilities..................................... 28,577,111 Partners' equity............................................ 7,416,144 ----------- Total liabilities and partners' equity................ $35,993,255 =========== See notes to financial statements. F-98
SOUTH GLENS FALLS LIMITED PARTNERSHIP STATEMENT OF EARNINGS FOR THE YEAR ENDED DECEMBER 31, 1999 Revenues: Power sales............................................... $5,372,443 Other income.............................................. 29,031 ---------- Total revenues.......................................... 5,401,474 ---------- Expenses: General and administrative................................ 658,607 Operations................................................ 201,096 Insurance................................................. 101,496 Property taxes............................................ 158,351 Depreciation and amortization............................. 1,121,800 Interest.................................................. 2,280,426 ---------- Total expenses.......................................... 4,521,776 ---------- Net earnings................................................ $ 879,698 ========== See notes to financial statements. F-99
SOUTH GLENS FALLS LIMITED PARTNERSHIP STATEMENT OF PARTNERS' EQUITY FOR THE YEAR ENDED DECEMBER 31, 1999 GENERAL LIMITED PARTNER PARTNERS TOTAL -------- ---------- ---------- Balance at December 31, 1998................................ $ 5,108 $6,731,338 $6,736,446 Partner distributions....................................... (2,000) (198,000) (200,000) Net earnings................................................ 8,797 870,901 879,698 ------- ---------- ---------- Balance at December 31, 1999................................ $11,905 $7,404,239 $7,416,144 ======= ========== ========== See notes to financial statements. F-100
SOUTH GLENS FALLS LIMITED PARTNERSHIP STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1999 Cash flows from operating activities: Net earnings.............................................. $ 879,698 ----------- Adjustments to reconcile net earnings to cash provided by operating activities: Depreciation and amortization............................. 1,121,800 Changes in operating assets and liabilities: Accounts receivable..................................... (41,472) Prepaid expenses and supplies........................... (644) Accounts payable........................................ 19,155 Accrued expenses........................................ 190,714 ----------- Total adjustments..................................... 1,289,553 ----------- Cash provided by operating activities................. 2,169,251 ----------- Cash flows from financing activities: Repayment of long-term debt............................... (2,010,908) Partner distributions..................................... (200,000) Net proceeds from operating loans......................... 100,000 ----------- Cash used in financing activities..................... (2,110,908) ----------- Net change in cash.......................................... 58,343 Cash and cash equivalents, beginning of year.............. 18,527 ----------- Cash and cash equivalents, end of year.................... $ 76,870 =========== Supplemental disclosure of cash flow information: Cash paid during the year for interest.................... $ 2,280,426 =========== See notes to financial statements. F-101
SOUTH GLENS FALLS LIMITED PARTNERSHIP NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: a. ORGANIZATION: South Glens Falls Limited Partnership (the "Partnership") was formed as a limited partnership under the laws of the State of New York on March 11, 1992; it organized and began business on August 24, 1993 for the purpose of developing, rehabilitating, and operating a hydroelectric facility located on the Hudson River in the Village of South Glens Falls, Saratoga County, New York. The Partnership began generating power on August 11, 1994. The financial statements include only the assets and liabilities which relate to the Partnership and do not include any items attributable to the partners' individual activity. b. USE OF ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions (e.g., depreciable lives) that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. c. CASH AND CASH EQUIVALENTS: Cash includes all cash equivalents that are highly liquid investments with a maturity of three months or less when purchased. d. PROPERTY AND EQUIPMENT: Property and equipment are carried at cost. Cost includes expenditures for construction, capitalized interest, on-site and title insurance, and attorney's costs of acquisition. The hydroelectric facilities are being depreciated on a straight-line basis over 40 years. The Partnership evaluates the recoverability of the net carrying amount of the hydroelectric facilities on an ongoing basis by reference to the anticipated future undiscounted cash flows from the operations of the project. Depreciation expense was $985,722 for the year ended December 31, 1999. e. DEFERRED FINANCING COSTS: Deferred financing costs are amortized over the term of the related debt agreement (15 years). f. INCOME TAXES: No provision has been made for federal and state income taxes because these taxes are the responsibility of the partners. 2. LONG-TERM DEBT: Long-term debt consists of the following at December 31, 1999: Term loan, Toronto-Dominion Bank, floating interest (7.625% at December 31, 1999), quarterly principal and interest payments of varying amounts, final maturity December 31, 2009....................................................... $28,064,527 =========== Collateral for the term loan and the operating line of credit discussed below includes a mortgage on all land and facilities, leases and rights, including the right to receive payments from Niagara Mohawk Power Corporation ("NMPC") pursuant to a Power Purchase Agreement ("PPA") with a 40-year term. The loan agreement contains various restrictive covenants including the maintenance of a minimum debt service coverage ratio. F-102
SOUTH GLENS FALLS LIMITED PARTNERSHIP NOTES TO FINANCIAL STATEMENTS (CONTINUED) 2. LONG-TERM DEBT: (CONTINUED) Minimum principal payments under the existing term loan agreement for the five years following December 31, 1999 and thereafter are as follows: 2000........................................................ $ 1,940,351 2001........................................................ 2,116,746 2002........................................................ 2,257,863 2003........................................................ 2,434,258 2004........................................................ 2,628,293 Thereafter.................................................. 16,687,016 ----------- $28,064,527 =========== The Partnership also has a $2.5 million operating line of credit with the Toronto-Dominion Bank ("Bank") through March 7, 2001, which can be renewed each year through December 31, 2009. The Partnership had borrowings of $100,000 outstanding under this agreement at December 31, 1999. Borrowings under the agreement bear interest at LIBOR plus 1.875% (LIBOR was 6.44% at December 31, 1999). To provide some degree of protection against the potential impact of rising interest rates, effective February 3, 1995, the Partnership entered into an amortizing interest rate swap agreement with the Bank that expires December 31, 2004. This agreement effectively changes the Partnership's interest rate exposure on approximately 70% of the future floating rate term loan to a fixed rate. Under the agreement, each quarter the Partnership pays a fixed rate of 6.375% on the notional amount to the Bank (notional amount was $19,887,500 at December 31, 1999), and receives a variable rate from the Bank (6.18375% at December 31,1999). The net amount payable or receivable is recorded as interest expense. At December 31, 1999, the carrying amount of all debt obligations approximate their fair values, and the fair value of the interest rate swap agreement was $339,093, representing the amount the Partnership would receive if the agreement was terminated. 3. RELATED PARTY TRANSACTIONS: Fees to Adirondack Hydro Development Corporation ("Adirondack"), a limited partner, during 1999 were $375,000, of which $187,500 is included in accrued expenses at December 31, 1999. Included in accounts payable at December 31, 1999 is $18,070, payable to affiliated companies. 4. POWER PURCHASE AGREEMENT: The Partnership has entered into a 40-year power purchase agreement with NMPC, committing the parties to sell and buy, respectively, the output of the hydroelectric facility. The PPA establishes contract energy payment rates for each of the 40 years. The contract payment rate was $0.09182 per kilowatt hour at December 31, 1999. Revenue is recognized when the power is transmitted in accordance with the terms of the PPA. On August 1, 1996, NMPC submitted a proposal to nineteen Independent Power Producers ("IPPs") to restructure 44 of the IPPs' PPAs with NMPC concurrent with an internal restructuring of NMPC. Adirondack's projects, including the Partnership, made up seven of the 44 PPAs subject to NMPC's proposal. However, in June 1997, NMPC withdrew its proposal for all hydroelectric projects F-103
SOUTH GLENS FALLS LIMITED PARTNERSHIP NOTES TO FINANCIAL STATEMENTS (CONTINUED) 4. POWER PURCHASE AGREEMENT: (CONTINUED) included in the original group of 44 PPAs. As of December 31, 1997, agreements had been reached with sixteen of the nineteen IPPs on the restructuring of 29 of the PPAs. As of March 20, 1998, the New York State Public Service Commission approved NMPC's restructuring plan. The plan included the restructuring of 29 PPAs which represent over 80% of NMPC's "out-of-market" PPAs. Adirondack initiated separate discussions with NMPC in November 1997 regarding the restructuring of its seven PPAs. Discussions are ongoing. A term sheet was signed for two of the seven PPAs (Warrensburg Hydro Power Limited Partnership and Sissonville Limited Partnership) in 1999. Adirondack management anticipates that a final settlement for the restructuring of the remaining PPAs will be reached in 2000. 5. LEASES: The Partnership leases the land upon which its hydroelectric facilities are situated from NMPC and the adjacent riverbed from the State of New York. These lease agreements extend through the end of the PPA with NMPC. Total rental expense in 1999 was $98,746. F-104
SOUTH GLENS FALLS LIMITED PARTNERSHIP BALANCE SHEET SEPTEMBER 30, 2000 (UNAUDITED) Assets: Cash...................................................... $ 941,921 Accounts receivable....................................... 415,103 Prepaid expenses and supplies............................. 137,182 ----------- Total current assets.................................... 1,494,206 Property and equipment: Hydroelectric facilities.................................. 39,428,866 Less accumulated depreciation............................. (6,078,074) ----------- Property and equipment, net............................. 33,350,792 Deferred financing costs.................................... 1,158,931 ----------- Total assets............................................ $36,003,929 =========== Liabilities and Equity: Accounts payable.......................................... $ 3,350 Accrued expenses.......................................... 665,025 Term debt--Toronto Dominion................................. 26,609,263 ----------- Total liabilities....................................... 27,277,638 Partners' equity............................................ 8,726,291 ----------- Total liabilities and partners' equity.................. $36,003,929 =========== F-105
SOUTH GLENS FALLS LIMITED PARTNERSHIP STATEMENTS OF INCOME FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999 (UNAUDITED) 2000 1999 ---------- ---------- Revenue: Electricity sales......................................... $5,868,821 $4,172,908 ---------- ---------- Expenses: Operations................................................ 603,758 572,430 Administrative and general................................ 99,634 138,568 Depreciation/amortization................................. 837,691 841,350 Taxes other than income................................... 123,931 118,752 ---------- ---------- Total expenses.......................................... 1,665,014 1,671,100 Miscellaneous non-operating income.......................... 38,977 24,230 Interest expense............................................ 1,682,637 1,717,396 ---------- ---------- Net earnings................................................ $2,560,147 $ 808,642 ========== ========== F-106
SOUTH GLENS FALLS LIMITED PARTNERSHIP STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999 (UNAUDITED) 2000 1999 ----------- ----------- Cash flows from operating activities: Net earnings.............................................. $ 2,560,147 $ 808,642 ----------- ----------- Adjustments to reconcile net earnings to cash provided by operating activities: Depreciation and amortization........................... 837,691 841,350 Changes in operating assets and liabilities: Accounts receivable................................... (26,866) 19,617 Prepaid expenses and supplies......................... 43,552 43,134 Accounts payable...................................... (40,076) (5,075) Accrued partner distribution payable.................. (450,000) -- Accrued expenses...................................... 295,867 32,081 ----------- ----------- Total adjustments................................... 660,168 931,107 ----------- ----------- Cash provided by operating activities............... 3,220,315 1,739,749 ----------- ----------- Cash flows from financing activities: Repayment of operating loan............................... (100,000) -- Repayment of long-term debt............................... (1,455,264) (1,508,181) Partner distributions..................................... (800,000) (200,000) ----------- ----------- Cash used in financing activities................... (2,355,264) (1,708,181) ----------- ----------- Net change in cash.......................................... 865,051 31,568 Cash and cash equivalents, beginning of period............ 76,870 18,527 ----------- ----------- Cash and cash equivalents, end of period.................. $ 941,921 $ 50,095 =========== =========== F-107
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PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION. All amounts, which are payable by the Registrant, except the SEC and NASD fees, are estimates. SEC registration fee........................................ $ 37,364 NASD filing fee............................................. 15,445 Printing and shipping expenses.............................. 250,000 Legal fees and expenses..................................... 250,000 Accounting fees and expenses................................ 150,000 New York Stock Exchange additional listing fee.............. 15,000 Transfer agent's fees and expenses.......................... 5,000 Consulting fees and expenses................................ 250,000 Miscellaneous............................................... 52,191 ---------- Total..................................................... $1,025,000 ========== ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS. Section 47-5-27 of the South Dakota Codified Laws provides generally that a corporation may indemnify any person who was or is a party to or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative in nature, other than an action by or in the right of the corporation, by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, limited liability company, partnership, joint venture, trust or other enterprise, against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with the action, suit or proceeding if that person acted in good faith and in a manner that person reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe such conduct was unlawful. The Bylaws of the Registrant provide that, with respect to actions, suits or proceedings other than by or in the right of the Registrant, the Registrant shall indemnify an officer or director against liability incurred by such person as authorized under the South Dakota Codified Laws. With respect to actions or suits by or in the right of the Registrant, the Bylaws of the Registrant provide that the Registrant shall indemnify any officer or director for any action or proceeding he is made a party to by reason of the fact that he is or was a director or officer of the Registrant, against expenses (including attorneys' fees) actually and reasonably incurred by him in connection with the action or suit, if he acted in good faith and in a manner he reasonably believed to be within the scope of his authority and in, or not opposed to, the best interests of the Registrant, except for those claims, issues or matters as to which such officer or director shall have been adjudged to be liable to the Registrant, unless such indemnification is deemed proper by a court. In addition, the Registrant has entered into specific agreements with the directors and officers of the Registrant providing for indemnification of such persons under certain circumstances. The Registrant's Articles of Incorporation also eliminate the liability of the Registrant's directors for monetary damages for breach of their fiduciary duty as directors. This provision, however, does not eliminate a director's liability (a) for any breach of the director's duty of loyalty to the Registrant or its shareholders, (b) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (c) for any violation of Sections 47-5-15 to 47-5-19, inclusive, of the South Dakota Codified Laws, which relate in part to certain unlawful dividend payments or stock redemptions or repurchases, or (d) for any transaction from which the director derived an improper personal benefit. II-1
The Registrant carries directors' and officers' liability insurance to insure its directors and officers against liability for certain errors and omissions and to defray costs of a suit or proceeding against an officer or director. The Underwriting Agreement that the Registrant will enter into with respect to the offer and sale of the common stock covered by this Registration Statement will contain certain provisions for the indemnification of the Registrant's directors and officers and the underwriters, as applicable, against civil liabilities under the Securities Act of 1933. ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES. On April 28, 2000, Black Hills Power, Inc. (formerly known as Black Hills Corporation) formed the Registrant as a wholly-owned subsidiary in order to effect the formation of a holding company structure, and was issued 100 shares of common stock of the Registrant for total cash consideration of $1,000. This sale was effected under Section 4(2) of the Securities Act for transactions by an issuer not involving any public offering. On July 7, 2000, in connection with the acquisition of Indeck Capital, Inc., Black Hills Power, Inc. issued 1,536,747 shares of common stock and 4,000 shares of $1,000 par value preferred stock to the six shareholders of Indeck Capital, Inc. On December 22, 2000, pursuant to a "plan of exchange" Black Hills Power, Inc. effected a holding company structure, and the 1,536,747 shares of common stock and 4,000 shares of preferred stock held by the former shareholders of Indeck were exchanged for 1,536,747 shares of common stock and 4,000 shares of preferred stock of the Registrant. To the extent that such exchange is considered to be a sale, the common and preferred shares so issued are exempt from registration under Section 4(2) of the Securities Act. Each of the former shareholders of Indeck was an "accredited investor." ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. (a) Exhibits: The following is a list of all exhibits filed as a part of this Registration Statement, including those incorporated by reference herein. EXHIBIT NUMBER DESCRIPTION - --------------------- ------------------------------------------------------------ 1 Form of Underwriting Agreement. 2* Plan of Exchange between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.1* Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.2* Articles of Amendment of the Registrant (filed as an exhibit to the Registrant's Current Report on Form 8-K filed on December 26, 2000). 3.3* Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.4* Statement of Designations, Preferences and Relative Rights and Limitations of No Par Preferred Stock, Series 2000-A of the Registrant (filed as an exhibit to the Registrant's Current Report on Form 8-K filed on December 26, 2000). 4.1* Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant's Form 10-K for 2000). II-2
EXHIBIT NUMBER DESCRIPTION - --------------------- ------------------------------------------------------------ 4.2* Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Power, Inc. dated as of September 1, 1999 (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 5** Opinion of Morrill Thomas Nooney & Braun, LLP, regarding the legality of the common stock. 10.1* Agreement for Transmission Service and the Common Use of Transmission Systems dated January 1, 1986, among Black Hills Power, Inc., Basin Electric Power Cooperative, Rushmore Electric Power Cooperative, Inc., Tri-County Electric Association, Inc., Black Hills Electric Cooperative, Inc. and Butte Electric Cooperative, Inc. (filed as Exhibit 10(d) to the Registrant's Form 10-K for 1987). 10.2* Restated and Amended Coal Supply Agreement for NS #2 dated February 12, 1993 (filed as Exhibit 10(c) to the Registrant's Form 10-K for 1992). 10.3* Coal Leases between Wyodak Resources Development Corp. and the Federal Government --Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant's Form S-7, File No. 2-60755) --Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant's Form 10-K for 1989) --Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant's Form S-7, File No. 2-60755) --Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant's Form 10-K for 1989) --Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant's Form S-7, File No. 2-60755) --Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant's Form 10-K for 1989). 10.4 New Restated and Amended Coal Supply Agreement dated as of January 1, 2001 between Wyodak Resources Development Corp. and PacifiCorp. 10.5* Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10(e) to the Registrant's Form 10-K for 1997). 10.6* Coal Supply Agreement for Wyodak Unit #2 dated February 3, 1983, and Ancillary Agreement dated February 3, 1982, between Wyodak Resources Development Corp., Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(o) to the Registrant's Form 10-K for 1983). Amendment to Agreement for Coal Supply for Wyodak #2 dated May 5, 1987 (filed as Exhibit 10(o) to the Registrant's Form 10-K for 1987). 10.7* Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1987). 10.8* Marketing, Capacity and Storage Service Agreement between Black Hills Power, Inc. and PacifiCorp dated September 1, 1995 (filed as Exhibit 10(ag) to the Registrant's Form 10-K for 1995). 10.9* Assignment of Mining Leases and Related Agreement effective May 27, 1997, between Wyodak Resources Development Corp. and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1997). 10.10* Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999). 10.11* Amended and Restated Pension Equalization Plan of Black Hills Corporation dated January 6, 2000 (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2000). 10.12* First Amendment to the Pension Equalization Plan of Black Hills Corporation dated January 30, 2001 (filed as Exhibit 10.12 to the Registrant's Form 10-K for 2000). 10.13* Black Hills Corporation Nonqualified Deferred Compensation Plan dated June 1, 1999 (filed as Exhibit 10.13 to the Registrant's Form 10-K for 2000). II-3
EXHIBIT NUMBER DESCRIPTION - --------------------- ------------------------------------------------------------ 10.14* Black Hills Corporation 1996 Stock Option Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1997). 10.15* Black Hills Corporation 1999 Stock Option Plan (filed as Exhibit 10.14 to the Registrant's Form 10-K for 2000). 10.16* Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (filed as Exhibit 10(gg) to the Registrant's Form 10-K for 1992). 10.17* Change in Control Agreements for various officers (filed as Exhibit 10(af) to the Registrant's Form 10-K for 1995). 10.18* Outside Directors Stock Based Compensation Plan (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1997). 10.19* Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1999). 10.20* Agreement and Plan of Merger, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 2 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. dated July 7, 2000 (the "Indeck Schedule 13D"). 10.21* Addendum to the Agreement and Plan of Merger, dated as of April 6, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 3 to the Indeck Schedule 13D). 10.22* Supplemental Agreement Regarding Contingent Merger Consideration, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 4 to the Indeck Schedule 13D). 10.23* Supplemental Agreement Regarding Restructuring of Certain Qualifying Facilities (filed as Exhibit 5 to the Indeck Schedule 13D). 10.24* Addendum to the Agreement and Plan of Merger, dated as of June 30, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 6 to the Indeck Schedule 13D). 10.25* Registration Rights Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 7 to the Indeck Schedule 13D). 10.26* Shareholders Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 8 to the Indeck Schedule 13D). 21* List of Subsidiaries of Black Hills Corporation (filed as Exhibit 21 to the Registrant's Form 10-K for 2000). 23.1 Consents of Arthur Andersen LLP. 23.2 Consent of PricewaterhouseCoopers LLP. 23.3** Consent of Morrill Thomas Nooney & Braun, LLP (included in Exhibit 5). II-4
EXHIBIT NUMBER DESCRIPTION - --------------------- ------------------------------------------------------------ 23.4** Consent of Ralph E. Davis Associates, Inc. 24** Power of Attorney. - ------------------------ * Previously filed as part of the filing indicated and incorporated by reference herein. ** Previously filed with this Registration Statement. (b) Financial Statement Schedules: All schedules are omitted as inapplicable or because the required information is contained in the financial statements or notes thereto. ITEM 17. UNDERTAKINGS. (h) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions referred to in Item 14 of this Registration Statement, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. (i) The undersigned Registrant undertakes that: (1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as a part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective. (2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. II-5
SIGNATURES Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Amendment No. 2 to Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Rapid City, State of South Dakota, on the 16th day of April, 2001. BLACK HILLS CORPORATION By: /s/ DANIEL P. LANDGUTH ----------------------------------------- Daniel P. Landguth CHAIRMAN OF THE BOARD AND CHIEF EXECUTIVE OFFICER Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 2 to Registration Statement has been signed below by the following persons in the capacities and on the dates indicated: SIGNATURE TITLE DATE --------- ----- ---- /s/ DANIEL P. LANDGUTH Chairman of the Board and April 16, 2001 ------------------------------------------- Chief Executive Officer Daniel P. Landguth (Principal Executive Officer) /s/ MARK T. THIES Senior Vice President and April 16, 2001 ------------------------------------------- Chief Financial Officer Mark T. Thies (Principal Financial Officer) /s/ ROXANN R. BASHAM Vice President-Controller April 16, 2001 ------------------------------------------- (Principal Accounting Roxann R. Basham Officer) JOHN R. HOWARD* Director April 16, 2001 ------------------------------------------- John R. Howard DAVID C. EBERTZ* Director April 16, 2001 ------------------------------------------- David C. Ebertz ADIL M. AMEER* Director April 16, 2001 ------------------------------------------- Adil M. Ameer /s/ EVERETT E. HOYT Director April 16, 2001 ------------------------------------------- Everett E. Hoyt II-6
SIGNATURE TITLE DATE --------- ----- ---- THOMAS J. ZELLER* Director April 16, 2001 ------------------------------------------- Thomas J. Zeller DAVID S. MANEY* Director April 16, 2001 ------------------------------------------- David S. Maney BRUCE B. BRUNDAGE* Director April 16, 2001 ------------------------------------------- Bruce B. Brundage KAY S. JORGENSEN* Director April 16, 2001 ------------------------------------------- Kay S. Jorgensen GERALD R. FORSYTHE* Director April 16, 2001 ------------------------------------------- Gerald R. Forsythe *By: /s/ DANIEL P. LANDGUTH -------------------------------------- Daniel P. Landguth Attorney-in-Fact II-7
INDEX TO EXHIBITS The following is a list of all exhibits filed as a part of this Registration Statement, including those incorporated by reference herein. EXHIBIT NUMBER DESCRIPTION - --------------------- ------------------------------------------------------------ 1 Form of Underwriting Agreement. 2* Plan of Exchange between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.1* Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.2* Articles of Amendment of the Registrant (filed as an exhibit to the Registrant's Current Report on Form 8-K filed on December 26, 2000). 3.3* Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.4* Statement of Designations, Preferences and Relative Rights and Limitations of No Par Preferred Stock, Series 2000-A of the Registrant (filed as an exhibit to the Registrant's Current Report on Form 8-K filed on December 26, 2000). 4.1* Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant's Form 10-K for 2000). 4.2* Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Power, Inc. dated as of September 1, 1999 (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 5** Opinion of Morrill Thomas Nooney & Braun, LLP, regarding the legality of the common stock. 10.1* Agreement for Transmission Service and the Common Use of Transmission Systems dated January 1, 1986, among the Black Hills Power, Inc., Basin Electric Power Cooperative, Rushmore Electric Power Cooperative, Inc., Tri-County Electric Association, Inc., Black Hills Electric Cooperative, Inc. and Butte Electric Cooperative, Inc. (filed as Exhibit 10(d) to the Registrant's Form 10-K for 1987). 10.2* Restated and Amended Coal Supply Agreement for NS #2 dated February 12, 1993 (filed as Exhibit 10(c) to the Registrant's Form 10-K for 1992). 10.3* Coal Leases between Wyodak Resources Development Corp. and the Federal Government --Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant's Form S-7, File No. 2-60755) --Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant's Form 10-K for 1989) --Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant's Form S-7, File No. 2-60755) --Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant's Form 10-K for 1989) --Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant's Form S-7, File No. 2-60755) --Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant's Form 10-K for 1989). 10.4 New Restated and Amended Coal Supply Agreement dated as of January 1, 2001 between Wyodak Resources Development Corp. and PacifiCorp. 10.5* Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10(e) to the Registrant's Form 10-K for 1997). 10.6* Coal Supply Agreement for Wyodak Unit #2 dated February 3, 1983, and Ancillary Agreement dated February 3, 1982, between Wyodak Resources Development Corp., Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(o) to the Registrant's Form 10-K for 1983). Amendment to Agreement for Coal Supply for Wyodak #2 dated May 5, 1987 (filed as Exhibit 10(o) to the Registrant's Form 10-K for 1987).
EXHIBIT NUMBER DESCRIPTION - --------------------- ------------------------------------------------------------ 10.7* Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1987). 10.8* Marketing, Capacity and Storage Service Agreement between Black Hills Power, Inc. and PacifiCorp dated September 1, 1995 (filed as Exhibit 10(ag) to the Registrant's Form 10-K for 1995). 10.9* Assignment of Mining Leases and Related Agreement effective May 27, 1997, between Wyodak Resources Development Corp. and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1997). 10.10* Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999). 10.11* Amended and Restated Pension Equalization Plan of Black Hills Corporation dated January 6, 2000 (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2000). 10.12* First Amendment to the Pension Equalization Plan of Black Hills Corporation dated January 30, 2001 (filed as Exhibit 10.12 to the Registrant's Form 10-K for 2000). 10.13* Black Hills Corporation Nonqualified Deferred Compensation Plan dated June 1, 1999 (filed as Exhibit 10.13 to the Registrant's Form 10-K for 2000). 10.14* Black Hills Corporation 1996 Stock Option Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1997). 10.15* Black Hills Corporation 1999 Stock Option Plan (filed as Exhibit 10.14 to the Registrant's Form 10-K for 2000). 10.16* Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (filed as Exhibit 10(gg) to the Registrant's Form 10-K for 1992). 10.17* Change in Control Agreements for various officers (filed as Exhibit 10(af) to the Registrant's Form 10-K for 1995). 10.18* Outside Directors Stock Based Compensation Plan (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1997). 10.19* Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1999). 10.20* Agreement and Plan of Merger, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 2 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. dated July 7, 2000 (the "Indeck Schedule 13D"). 10.21* Addendum to the Agreement and Plan of Merger, dated as of April 6, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 3 to the Indeck Schedule 13D). 10.22* Supplemental Agreement Regarding Contingent Merger Consideration, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 4 to the Indeck Schedule 13D). 10.23* Supplemental Agreement Regarding Restructuring of Certain Qualifying Facilities (filed as Exhibit 5 to the Indeck Schedule 13D). 10.24* Addendum to the Agreement and Plan of Merger, dated as of June 30, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 6 to the Indeck Schedule 13D).
EXHIBIT NUMBER DESCRIPTION - --------------------- ------------------------------------------------------------ 10.25* Registration Rights Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 7 to the Indeck Schedule 13D). 10.26* Shareholders Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (filed as Exhibit 8 to the Indeck Schedule 13D). 21* List of Subsidiaries of Black Hills Corporation (filed as Exhibit 21 to the Registrant's Form 10-K for 2000). 23.1 Consents of Arthur Andersen LLP. 23.2 Consent of PricewaterhouseCoopers LLP. 23.3** Consent of Morrill Thomas Nooney & Braun, LLP (included in Exhibit 5). 23.4** Consent of Ralph E. Davis Associates, Inc. 24** Power of Attorney. - ------------------------ * Previously filed as part of the filing indicated and incorporated by reference herein. ** Previously filed with this Registration Statement.
Exhibit 1 3,000,000 SHARES BLACK HILLS CORPORATION COMMON STOCK UNDERWRITING AGREEMENT April __, 2001 CREDIT SUISSE FIRST BOSTON CORPORATION LEHMAN BROTHERS INC. CIBC WORLD MARKETS CORP. UBS WARBURG LLC, As Representatives of the Several Underwriters, c/o Credit Suisse First Boston Corporation, Eleven Madison Avenue, New York, N.Y. 10010-3629 Dear Sirs: 1. INTRODUCTORY. Black Hills Corporation, a South Dakota corporation ("COMPANY"), proposes to issue and sell 3,000,000 shares ("FIRM SECURITIES") of its Common Stock, par value $1.00 per share ("SECURITIES") and also proposes to issue and sell to the several Underwriters named in Schedule A hereto ("UNDERWRITERS"), at the option of the Underwriters, an aggregate of not more than 450,000 additional shares ("OPTIONAL SECURITIES") of its Securities as set forth below. The Firm Securities and the Optional Securities are herein collectively called the "OFFERED SECURITIES". The Company hereby agrees with the Underwriters as follows: 2. REPRESENTATIONS AND WARRANTIES OF THE COMPANY. The Company represents and warrants to, and agrees with, the several Underwriters that: (a) A registration statement (No. 333-57440) relating to the Offered Securities, including a form of prospectus, has been filed with the Securities and Exchange Commission ("COMMISSION") and either (i) has been declared effective under the Securities Act of 1933, as amended ("ACT"), and is not proposed to be amended or (ii) is proposed to be amended by amendment or post-effective amendment. If such registration statement ("INITIAL REGISTRATION STATEMENT") has been declared effective, either (i) an additional registration statement ("ADDITIONAL REGISTRATION STATEMENT") relating to the Offered Securities may have been filed with the Commission pursuant to Rule 462(b) ("RULE 462(b)") under the Act and, if so filed, has become effective upon filing pursuant to such Rule and the Offered Securities all have been duly registered under the Act pursuant to the initial registration statement and, if applicable, the additional registration statement or (ii) such an additional registration statement is proposed to be filed with the Commission pursuant to Rule 462(b) and will become effective upon filing pursuant to
such Rule and upon such filing the Offered Securities will all have been duly registered under the Act pursuant to the initial registration statement and such additional registration statement. If the Company does not propose to amend the initial registration statement or if an additional registration statement has been filed and the Company does not propose to amend it, and if any post-effective amendment to either such registration statement has been filed with the Commission prior to the execution and delivery of this Agreement, the most recent amendment (if any) to each such registration statement has been declared effective by the Commission or has become effective upon filing pursuant to Rule 462(c) ("RULE 462(c)") under the Act or, in the case of the additional registration statement, Rule 462(b). For purposes of this Agreement, "EFFECTIVE TIME" with respect to the initial registration statement or, if filed prior to the execution and delivery of this Agreement, the additional registration statement means (i) if the Company has advised the Representatives that it does not propose to amend such registration statement, the date and time as of which such registration statement, or the most recent post-effective amendment thereto (if any) filed prior to the execution and delivery of this Agreement, was declared effective by the Commission or has become effective upon filing pursuant to Rule 462(c), or (ii) if the Company has advised the Representatives that it proposes to file an amendment or post-effective amendment to such registration statement, the date and time as of which such registration statement, as amended by such amendment or post-effective amendment, as the case may be, is declared effective by the Commission. If an additional registration statement has not been filed prior to the execution and delivery of this Agreement but the Company has advised the Representatives that it proposes to file one, "EFFECTIVE TIME" with respect to such additional registration statement means the date and time as of which such registration statement is filed and becomes effective pursuant to Rule 462(b). "EFFECTIVE DATE" with respect to the initial registration statement or the additional registration statement (if any) means the date of the Effective Time thereof. The initial registration statement, as amended at its Effective Time, including all information contained in the additional registration statement (if any) and deemed to be a part of the initial registration statement as of the Effective Time of the additional registration statement pursuant to the General Instructions of the Form on which it is filed and including all information (if any) deemed to be a part of the initial registration statement as of its Effective Time pursuant to Rule 430A(b) ("RULE 430A(b)") under the Act, is hereinafter referred to as the "INITIAL REGISTRATION STATEMENT". The additional registration statement, as amended at its Effective Time, including the contents of the initial registration statement incorporated by reference therein and including all information (if any) deemed to be a part of the additional registration statement as of its Effective Time pursuant to Rule 430A(b), is hereinafter referred to as the "ADDITIONAL REGISTRATION STATEMENT". The Initial Registration Statement and the Additional Registration Statement are herein referred to collectively as the "REGISTRATION STATEMENTS" and individually as a "REGISTRATION STATEMENT". The form of prospectus relating to the Offered Securities, as first filed with the Commission pursuant to and in accordance with Rule 424(b) ("RULE 424(b)") under the Act or (if no such filing is required) as included in a Registration Statement, is hereinafter referred to as the "PROSPECTUS". No document has been or will be prepared or distributed in reliance on Rule 434 under the Act. (b) If the Effective Time of the Initial Registration Statement is prior to the execution and delivery of this Agreement: (i) on the Effective Date of the Initial Registration Statement, the Initial Registration Statement conformed in all material 2
respects to the requirements of the Act and the rules and regulations of the Commission ("RULES AND REGULATIONS") and did not include any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein not misleading, (ii) on the Effective Date of the Additional Registration Statement (if any), each Registration Statement conformed, or will conform, in all material respects to the requirements of the Act and the Rules and Regulations and did not include, or will not include, any untrue statement of a material fact and did not omit, or will not omit, to state any material fact required to be stated therein or necessary to make the statements therein not misleading and (iii) on the date of this Agreement, the Initial Registration Statement and, if the Effective Time of the Additional Registration Statement is prior to the execution and delivery of this Agreement, the Additional Registration Statement each conforms, and at the time of filing of the Prospectus pursuant to Rule 424(b) or (if no such filing is required) at the Effective Date of the Additional Registration Statement in which the Prospectus is included, each Registration Statement and the Prospectus will conform, in all material respects to the requirements of the Act and the Rules and Regulations, and neither of such documents includes, or will include, any untrue statement of a material fact or omits, or will omit, to state any material fact required to be stated therein or necessary to make the statements therein not misleading. If the Effective Time of the Initial Registration Statement is subsequent to the execution and delivery of this Agreement, on the Effective Date of the Initial Registration Statement, the Initial Registration Statement and the Prospectus will conform in all material respects to the requirements of the Act and the Rules and Regulations, neither of such documents will include any untrue statement of a material fact or will omit to state any material fact required to be stated therein or necessary to make the statements therein not misleading, and no Additional Registration Statement has been or will be filed. The two preceding sentences do not apply to statements in or omissions from a Registration Statement or the Prospectus based upon written information furnished to the Company by any Underwriter through the Representatives specifically for use therein, it being understood and agreed that the only such information is that described as such in Section 7(b) hereof. (c) The Company has been duly incorporated and is an existing corporation in good standing under the laws of the State of South Dakota, with power and authority (corporate and other) to own its properties and conduct its business as described in the Prospectus; and the Company is duly qualified to do business as a foreign corporation in good standing in all other jurisdictions in which its ownership or lease of property or the conduct of its business requires such qualification. (d) Each subsidiary of the Company has been duly incorporated or organized, as the case may be, and is an existing corporation, limited partnership, general partnership or limited liability company in good standing under the laws of the jurisdiction of its incorporation or organization, as the case may be, with power and authority (corporate and other) to own its properties and conduct its business as described in the Prospectus; and each subsidiary of the Company is duly qualified to do business as a foreign corporation, limited partnership, general partnership or limited liability company, as the case may be, in good standing in all other jurisdictions in which its ownership or lease of property or the conduct of its business requires such qualification, except where the failure to be so qualified and in good standing would not individually or in the aggregate have a material adverse effect on the condition (financial or other), business, properties 3
or results of operations of the Company and its subsidiaries taken as a whole ("MATERIAL ADVERSE EFFECT"); all of the issued and outstanding capital stock or partnership or limited liability company interests, as the case may be, of each subsidiary of the Company has been duly authorized and validly issued and, in the case of capital stock, is fully paid and nonassessable; and the capital stock or partnership or limited liability company interests, as the case may be, of each subsidiary owned by the Company, directly or through subsidiaries, is owned free from liens, encumbrances and defects, except as disclosed in the Prospectus. (e) The Offered Securities and all other outstanding shares of capital stock of the Company have been duly authorized; all outstanding shares of capital stock of the Company are, and, when the Offered Securities have been delivered and paid for in accordance with this Agreement on each Closing Date (as defined below), such Offered Securities will have been, validly issued, fully paid and nonassessable and will conform to the description thereof contained in the Prospectus; and the stockholders of the Company have no preemptive rights with respect to the Securities. (f) Except as disclosed in the Prospectus, there are no contracts, agreements or understandings between the Company and any person that would give rise to a valid claim against the Company or any Underwriter for a brokerage commission, finder's fee or other like payment in connection with this offering. (g) Except as disclosed in the Prospectus, there are no contracts, agreements or understandings between the Company and any person granting such person the right to require the Company to file a registration statement under the Act with respect to any securities of the Company owned or to be owned by such person or to require the Company to include such securities in the securities registered pursuant to a Registration Statement or in any securities being registered pursuant to any other registration statement filed by the Company under the Act. (h) The Company's Securities are listed on the New York Stock Exchange. The Offered Securities have been approved for listing on the New York Stock Exchange subject to notice of issuance. (i) No consent, approval, authorization, or order of, or filing with, any governmental agency or body or any court is required for the consummation of the transactions contemplated by this Agreement in connection with the issuance and sale of the Offered Securities by the Company, except such as have been obtained and made under the Act and such as may be required under state securities laws. (j) The execution, delivery and performance of this Agreement, and the issuance and sale of the Offered Securities will not result in a breach or violation of any of the terms and provisions of, or constitute a default under, (i) any statute, any rule, regulation or order of any governmental agency or body or any court, domestic or foreign, having jurisdiction over the Company or any subsidiary of the Company or any of their 4
properties, or (ii) any agreement or instrument to which the Company or any such subsidiary is a party or by which the Company or any such subsidiary is bound or to which any of the properties of the Company or any such subsidiary is subject, or (iii) the charter or by-laws of the Company or any such subsidiary, except in the case of clause (ii) for such breaches, violations or defaults that would not individually or in the aggregate have a Material Adverse Effect; and the Company has full corporate power and authority to authorize, issue and sell the Offered Securities as contemplated by this Agreement. (k) This Agreement has been duly authorized, executed and delivered by the Company. (l) Except as disclosed in the Prospectus, the Company and its subsidiaries have good and defensible title to all interests in oil and gas properties owned by them and good and marketable title to all other real properties and all other properties and assets owned by them, in each case free from liens, encumbrances and defects that would materially affect the value thereof or materially interfere with the use made or to be made thereof by them; and except as disclosed in the Prospectus, the Company and its subsidiaries hold any leased real or personal property under valid and enforceable leases with no exceptions that would materially interfere with the use made or to be made thereof by them. (m) The Company and its subsidiaries possess adequate certificates, authorities or permits issued by appropriate governmental agencies or bodies necessary to conduct the business now operated by them and have not received any notice of proceedings relating to the revocation or modification of any such certificate, authority or permit that, if determined adversely to the Company or any of its subsidiaries, would individually or in the aggregate have a Material Adverse Effect. (n) No labor dispute with the employees of the Company or any subsidiary exists or, to the knowledge of the Company, is imminent that might have a Material Adverse Effect. (o) The Company and its subsidiaries own, possess, have the right to use or can acquire on reasonable terms, adequate trademarks, trade names and other rights to inventions, know-how, patents, copyrights, confidential information and other intellectual property (collectively, "INTELLECTUAL PROPERTY RIGHTS") necessary to conduct the business now operated by them, or presently employed by them, and have not received any notice of infringement of or conflict with asserted rights of others with respect to any intellectual property rights that, if determined adversely to the Company or any of its subsidiaries, would individually or in the aggregate have a Material Adverse Effect. (p) Except as disclosed in the Prospectus, neither the Company nor any of its subsidiaries is in violation of any statute, any rule, regulation, decision or order of any governmental agency or body or any court, domestic or foreign, relating to the use, disposal or release of hazardous or toxic substances or relating to the protection or 5
restoration of the environment or human exposure to hazardous or toxic substances (collectively, "ENVIRONMENTAL LAWS"), owns or operates any real property contaminated with any substance that is subject to any environmental laws, is liable for any off-site disposal or contamination pursuant to any environmental laws, or is subject to any claim relating to any environmental laws, which violation, contamination, liability or claim would individually or in the aggregate have a Material Adverse Effect; and the Company is not aware of any pending investigation which might lead to such a claim. (q) Except as disclosed in the Prospectus, there are no pending actions, suits or proceedings against or affecting the Company, any of its subsidiaries or any of their respective properties that, if determined adversely to the Company or any of its subsidiaries, would individually or in the aggregate have a Material Adverse Effect, or would materially and adversely affect the ability of the Company to perform its obligations under this Agreement, or which are otherwise material in the context of the sale of the Offered Securities; and no such actions, suits or proceedings are, to the Company's knowledge, threatened or contemplated. (r) Each of (i) Arthur Andersen LLP, who have certified the financial statements of the Company and certain subsidiaries of the Company included in each Registration Statement and Prospectus, and (ii) PricewaterhouseCoopers LLP, who have certified the financial statements of certain subsidiaries of the Company included in each Registration Statement and Prospectus, are independent public accountants as required by the Act and the Rules and Regulations. The historical financial statements included in each Registration Statement and the Prospectus present fairly the financial position of the Company and its consolidated subsidiaries as of the dates shown and their results of operations and cash flows for the periods shown, and such financial statements have been prepared in conformity with the generally accepted accounting principles in the United States applied on a consistent basis and the schedules included in each Registration Statement present fairly the information required to be stated therein; the pro forma consolidated financial statements and data contained in each Registration Statement and Prospectus have been prepared on a basis consistent with the historical financial statements and include all material adjustments to the historical financial information required by Rule 11-02 of Regulation S-X under the Act and the Securities Exchange Act of 1934, as amended ("EXCHANGE ACT"), to reflect the transactions described therein; and the assumptions used in preparing the pro forma financial statements and data included in each Registration Statement and the Prospectus provide a reasonable basis for presenting the significant effects directly attributable to the transactions or events described therein, the related pro forma adjustments give appropriate effect to those assumptions, and the pro forma columns therein reflect the proper application of those adjustments to the corresponding historical financial statement amounts. (s) Except as disclosed in the Prospectus, since the date of the latest audited financial statements of the Company included in the Prospectus there has been no material adverse change, nor any development or event involving a prospective material adverse change, in the condition (financial or other), business, properties or results of operations of the Company and its subsidiaries taken as a whole, and, except as disclosed in or contemplated by the Prospectus, there has been no dividend or distribution of any kind declared, paid or made by the Company on any class of its capital stock. 6
(t) The Company is not and, after giving effect to the offering and sale of the Offered Securities and the application of the proceeds thereof as described in the Prospectus, will not be an "investment company" as defined in the Investment Company Act of 1940. (u) The Company is subject to Section 13 or 15(d) of the Exchange Act. (v) The Company is a public utility holding company that is exempt from regulation under the Public Utility Holding Company Act of 1935 ("PUHCA") (except for Sections 9(a)(2) and 10 thereof) pursuant to Section 3(a) of PUHCA. 3. PURCHASE, SALE AND DELIVERY OF OFFERED SECURITIES. On the basis of the representations, warranties and agreements herein contained, but subject to the terms and conditions herein set forth, the Company agrees to sell to the Underwriters, and the Underwriters agree, severally and not jointly, to purchase from the Company, at a purchase price of $ per share, the respective numbers of shares of Firm Securities set forth opposite the names of the Underwriters in Schedule A hereto. The Company will deliver the Firm Securities to the Representatives for the accounts of the Underwriters, against payment of the purchase price in Federal (same day) funds by official bank check or checks or wire transfer to an account at a bank acceptable to Credit Suisse First Boston Corporation ("CSFBC") drawn to the order of the Company at the offices of Skadden, Arps, Slate, Meagher & Flom LLP, Four Times Square, New York, New York 10036, at 9:00 A.M., New York time, on April __, 2001, or at such other time not later than seven full business days thereafter as CSFBC and the Company determine, such time being herein referred to as the "FIRST CLOSING DATE". For purposes of Rule 15c6-1 under the Exchange Act, the First Closing Date (if later than the otherwise applicable settlement date) shall be the settlement date for payment of funds and delivery of securities for all the Offered Securities sold pursuant to the offering. The certificates for the Firm Securities so to be delivered will be in definitive form, in such denominations and registered in such names as CSFBC requests and will be made available for checking and packaging at the above offices of Skadden, Arps, Slate, Meagher & Flom LLP at least 24 hours prior to the First Closing Date. In addition, upon written notice from CSFBC given to the Company from time to time not more than 30 days subsequent to the date of the Prospectus, the Underwriters may purchase all or less than all of the Optional Securities at the purchase price per Security to be paid for the Firm Securities. The Company agrees to sell to the Underwriters the number of shares of Optional Securities specified in such notice and the Underwriters agree, severally and not jointly, to purchase such Optional Securities. Such Optional Securities shall be purchased for the account of each Underwriter in the same proportion as the number of shares of Firm Securities set forth opposite such Underwriter's name bears to the total number of shares of Firm Securities (subject to adjustment by CSFBC to eliminate fractions) and may be purchased by the Underwriters only for the purpose of covering over-allotments made in connection with the sale of the Firm Securities. No Optional Securities shall be sold or delivered unless the Firm Securities previously have been, or simultaneously are, sold and delivered. The right to purchase the Optional Securities or any portion thereof may be exercised from time to time and to the extent not previously exercised may be surrendered and terminated at any time upon notice by CSFBC to the Company. 7
Each time for the delivery of and payment for the Optional Securities, being herein referred to as an "OPTIONAL CLOSING DATE", which may be the First Closing Date (the First Closing Date and each Optional Closing Date, if any, being sometimes referred to as a "CLOSING DATE"), shall be determined by CSFBC but shall be not later than five full business days after written notice of election to purchase Optional Securities is given. The Company will deliver the Optional Securities being purchased on each Optional Closing Date to the Representatives for the accounts of the several Underwriters, against payment of the purchase price therefor in Federal (same day) funds by official bank check or checks or wire transfer to an account at a bank acceptable to CSFBC drawn to the order of the Company, at the above offices of Skadden, Arps, Slate, Meagher & Flom LLP. The certificates for the Optional Securities being purchased on each Optional Closing Date will be in definitive form, in such denominations and registered in such names as CSFBC requests upon reasonable notice prior to such Optional Closing Date and will be made available for checking and packaging at the above offices of Skadden, Arps, Slate, Meagher & Flom LLP at a reasonable time in advance of such Optional Closing Date. 4. OFFERING BY UNDERWRITERS. It is understood that the several Underwriters propose to offer the Offered Securities for sale to the public as set forth in the Prospectus. 5. CERTAIN AGREEMENTS OF THE COMPANY. The Company agrees with the several Underwriters that: (a) If the Effective Time of the Initial Registration Statement is prior to the execution and delivery of this Agreement, the Company will file the Prospectus with the Commission pursuant to and in accordance with subparagraph (1) (or, if applicable and if consented to by CSFBC, subparagraph (4)) of Rule 424(b) not later than the earlier of (A) the second business day following the execution and delivery of this Agreement or (B) the fifteenth business day after the Effective Date of the Initial Registration Statement. The Company will advise CSFBC promptly of any such filing pursuant to Rule 424(b). If the Effective Time of the Initial Registration Statement is prior to the execution and delivery of this Agreement and an additional registration statement is necessary to register a portion of the Offered Securities under the Act but the Effective Time thereof has not occurred as of such execution and delivery, the Company will file the additional registration statement or, if filed, will file a post-effective amendment thereto with the Commission pursuant to and in accordance with Rule 462(b) on or prior to 10:00 P.M., New York time, on the date of this Agreement or, if earlier, on or prior to the time the Prospectus is printed and distributed to any Underwriter, or will make such filing at such later date as shall have been consented to by CSFBC. (b) The Company will advise CSFBC promptly of any proposal to amend or supplement the initial or any additional registration statement as filed or the related prospectus or the Initial Registration Statement, the Additional Registration Statement (if any) or the Prospectus and will not effect such amendment or supplementation without CSFBC's consent; and the Company will also advise CSFBC promptly of the effectiveness of each Registration Statement (if its Effective Time is subsequent to the execution and delivery of this Agreement) and of any amendment or supplementation of a Registration Statement or the Prospectus and of the institution by the Commission of any stop order proceedings in respect of a Registration Statement and will use its best efforts to prevent the issuance of any such stop order and to obtain as soon as possible its lifting, if issued. 8
(c) If, at any time when a prospectus relating to the Offered Securities is required to be delivered under the Act in connection with sales by any Underwriter or dealer, any event occurs as a result of which the Prospectus as then amended or supplemented would include an untrue statement of a material fact or omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, or if it is necessary at any time to amend the Prospectus to comply with the Act, the Company will promptly notify CSFBC of such event and will promptly prepare and file with the Commission, at its own expense, an amendment or supplement which will correct such statement or omission or an amendment which will effect such compliance. Neither CSFBC's consent to, nor the Underwriters' delivery of, any such amendment or supplement shall constitute a waiver of any of the conditions set forth in Section 6. (d) As soon as practicable, but not later than the Availability Date (as defined below), the Company will make generally available to its securityholders an earnings statement covering a period of at least 12 months beginning after the Effective Date of the Initial Registration Statement (or, if later, the Effective Date of the Additional Registration Statement) which will satisfy the provisions of Section 11(a) of the Act. For the purpose of the preceding sentence, "AVAILABILITY DATE" means the 45th day after the end of the fourth fiscal quarter following the fiscal quarter that includes such Effective Date, except that, if such fourth fiscal quarter is the last quarter of the Company's fiscal year, "AVAILABILITY DATE" means the 90th day after the end of such fourth fiscal quarter. (e) The Company will furnish to the Representatives copies of each Registration Statement (five of which will be signed and will include all exhibits), each related preliminary prospectus, and, so long as a prospectus relating to the Offered Securities is required to be delivered under the Act in connection with sales by any Underwriter or dealer, the Prospectus and all amendments and supplements to such documents, in each case in such quantities as CSFBC requests. The Prospectus shall be so furnished on or prior to 3:00 P.M., New York time, on the business day following the later of the execution and delivery of this Agreement or the Effective Time of the Initial Registration Statement. All other documents shall be so furnished as soon as available. The Company will pay the expenses of printing and distributing to the Underwriters all such documents. (f) The Company will arrange for the qualification of the Offered Securities for sale under the laws of such jurisdictions as CSFBC reasonably designates and will continue such qualifications in effect so long as required for the distribution; provided that in connection therewith the Company shall not be required to qualify as a foreign corporation or to take any action that would subject it to a general consent to service of process in any such jurisdiction. (g) During the period of five years hereafter, the Company will furnish to the Representatives and, upon request, to each of the other Underwriters, as soon as practicable after the end of each fiscal year, a copy of its annual report to stockholders for such year; and the Company will furnish to the Representatives (i) as soon as available, a copy of each report and any definitive proxy statement of the Company filed with the Commission under the Exchange Act or mailed 9
to stockholders, and (ii) from time to time, such other information concerning the Company as CSFBC may reasonably request. (h) The Company will pay all expenses incident to the performance of its obligations under this Agreement, for any filing fees and other expenses (including fees and disbursements of counsel) incurred in connection with qualification of the Offered Securities for sale under the laws of such jurisdictions as CSFBC reasonably designates and the printing of memoranda relating thereto, for the filing fee incident to the review by the National Association of Securities Dealers, Inc. of the Offered Securities, for any travel expenses of the Company's officers and employees and any other expenses of the Company in connection with attending or hosting meetings with prospective purchasers of the Offered Securities and for expenses incurred in distributing preliminary prospectuses and the Prospectus (including any amendments and supplements thereto) to the Underwriters. (i) For a period of 90 days after the date of the initial public offering of the Offered Securities, the Company will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Commission a registration statement under the Act relating to, any additional shares of its Securities or securities convertible into or exchangeable or exercisable for any shares of its Securities, or publicly disclose the intention to make any such offer, sale, pledge, disposition or filing, without the prior written consent of CSFBC, except (A) issuances of Securities pursuant to grants of employee stock options pursuant to the terms of a plan in effect on the date hereof, (B) issuances of Securities pursuant to the exercise of such options or the exercise of any other employee stock options outstanding on the date hereof, (C) issuances of Securities pursuant to the Company's dividend reinvestment plan, employee stock purchase plan, retirement savings plan or non-qualified deferred compensation plan or (D) the filing with the Commission of a registration statement under the Act relating to Securities reserved for issuance under the Company's omnibus incentive compensation plan. 6. CONDITIONS OF THE OBLIGATIONS OF THE UNDERWRITERS. The obligations of the several Underwriters to purchase and pay for the Firm Securities on the First Closing Date and the Optional Securities to be purchased on each Optional Closing Date will be subject to the accuracy of the representations and warranties on the part of the Company herein, to the accuracy of the statements of Company officers made pursuant to the provisions hereof, to the performance by the Company of its obligations hereunder and to the following additional conditions precedent: (a) The Representatives shall have received a letter, dated the date of delivery thereof (which, if the Effective Time of the Initial Registration Statement is prior to the execution and delivery of this Agreement, shall be on or prior to the date of this Agreement or, if the Effective Time of the Initial Registration Statement is subsequent to the execution and delivery of this Agreement, shall be prior to the filing of the amendment to the registration statement to be filed shortly prior to such Effective Time), of Arthur Andersen LLP confirming that they are independent public accountants within the meaning of the Act and the applicable published Rules and Regulations thereunder and stating to the effect that: 10
(i) in their opinion the financial statements and any schedules and any summary of earnings audited, reviewed or examined by them and included in the Registration Statements comply as to form in all material respects with the applicable accounting requirements of the Act and the related published Rules and Regulations; (ii) on the basis of a reading of the latest available interim financial statements of the Company, inquiries of officials of the Company who have responsibility for financial and accounting matters and other specified procedures, nothing came to their attention that caused them to believe that: (A) at the date of the latest available balance sheet read by such accountants, or at a subsequent specified date not more than three business days prior to the date of this Agreement, there was any change in the capital stock or any increase in short-term indebtedness or long-term debt of the Company and its consolidated subsidiaries or, at the date of the latest available balance sheet read by such accountants, there was any increase in consolidated net current liabilities or any decrease in consolidated net assets, as compared with amounts shown on the latest balance sheet included in the Prospectus; or (B) for the period from the closing date of the latest income statement included in the Prospectus to the closing date of the latest available income statement read by such accountants, or at a subsequent specified date not more than three business days prior to the date of this Agreement, there were any decreases, as compared with the corresponding period of the previous year, in consolidated operating revenues, gross income, or in the total or per share amounts of consolidated income before extraordinary items or net income, except in all cases set forth in clauses (A) and (B) above for changes, increases or decreases which the Prospectus discloses have occurred or may occur or which are described in such letter; and (iii) they have compared specified dollar amounts (or percentages derived from such dollar amounts) and other financial information contained in the Registration Statements (in each case to the extent that such dollar amounts, percentages and other financial information are derived from the general accounting records of the Company and its subsidiaries subject to the internal controls of the Company's accounting system or are derived directly from such records by analysis or computation) with the results obtained from inquiries, a reading of such general accounting records and other procedures specified in such letter and have found such dollar amounts, percentages and other financial information to be in agreement with such results, except as otherwise specified in such letter. For purposes of this subsection, (i) if the Effective Time of the Initial Registration Statement is subsequent to the execution and delivery of this Agreement, "REGISTRATION STATEMENTS" shall mean the initial registration statement as proposed to be amended by 11
the amendment or post-effective amendment to be filed shortly prior to its Effective Time, (ii) if the Effective Time of the Initial Registration Statement is prior to the execution and delivery of this Agreement but the Effective Time of the Additional Registration is subsequent to such execution and delivery, "REGISTRATION STATEMENTS" shall mean the Initial Registration Statement and the additional registration statement as proposed to be filed or as proposed to be amended by the post-effective amendment to be filed shortly prior to its Effective Time, and (iii) "PROSPECTUS" shall mean the prospectus included in the Registration Statements. (b) If the Effective Time of the Initial Registration Statement is not prior to the execution and delivery of this Agreement, such Effective Time shall have occurred not later than 10:00 P.M., New York time, on the date of this Agreement or such later date as shall have been consented to by CSFBC. If the Effective Time of the Additional Registration Statement (if any) is not prior to the execution and delivery of this Agreement, such Effective Time shall have occurred not later than 10:00 P.M., New York time, on the date of this Agreement or, if earlier, the time the Prospectus is printed and distributed to any Underwriter, or shall have occurred at such later date as shall have been consented to by CSFBC. If the Effective Time of the Initial Registration Statement is prior to the execution and delivery of this Agreement, the Prospectus shall have been filed with the Commission in accordance with the Rules and Regulations and Section 5(a) of this Agreement. Prior to such Closing Date, no stop order suspending the effectiveness of a Registration Statement shall have been issued and no proceedings for that purpose shall have been instituted or, to the knowledge of the Company or the Representatives, shall be contemplated by the Commission. (c) Subsequent to the execution and delivery of this Agreement, there shall not have occurred (i) any change, or any development or event involving a prospective change, in the condition (financial or other), business, properties or results of operations of the Company and its subsidiaries taken as one enterprise which, in the judgment of a majority in interest of the Underwriters including the Representatives, is material and adverse and makes it impractical or inadvisable to proceed with completion of the public offering or the sale of and payment for the Offered Securities; (ii) any downgrading in the rating of any debt securities or preferred stock of the Company by any "nationally recognized statistical rating organization" (as defined for purposes of Rule 436(g) under the Act), or any public announcement that any such organization has under surveillance or review its rating of any debt securities or preferred stock of the Company (other than an announcement with positive implications of a possible upgrading, and no implication of a possible downgrading, of such rating); (iii) any material suspension or material limitation of trading in securities generally on the New York Stock Exchange, or any setting of minimum prices for trading on such exchange, or any suspension of trading of any securities of the Company on any exchange or in the over-the-counter market; (iv) any banking moratorium declared by U.S. Federal or New York authorities; or (v) any outbreak or escalation of major hostilities in which the United States is involved, any declaration of war by Congress or any other substantial national or international calamity or emergency if, in the judgment of a majority in interest of the Underwriters including the Representatives, the effect of any such outbreak, escalation, declaration, calamity or emergency makes it impractical or inadvisable to proceed with completion of the public offering or the sale of and payment for the Offered Securities. 12
(d) The Representatives shall have received an opinion, dated such Closing Date, of Morrill Thomas Nooney & Braun, LLP, South Dakota, counsel for the Company, to the effect that: (i) The Company has been duly incorporated and is an existing corporation in good standing under the laws of the State of South Dakota, with corporate power and authority to own its properties and conduct its business as described in the Prospectus; and the Company is duly qualified to do business as a foreign corporation in good standing in all other jurisdictions in which its ownership or lease of property or the conduct of its business requires such qualification; (ii) The Offered Securities delivered on such Closing Date and all other outstanding shares of the Common Stock of the Company have been duly authorized and validly issued, are fully paid and nonassessable and conform to the description thereof contained in the Prospectus; and the stockholders of the Company have no preemptive rights with respect to the Securities; (iii) The Company has full corporate power and authority to authorize, issue and sell the Offered Securities as contemplated by this Agreement; (iv) This Agreement has been duly authorized, executed and delivered by the Company; (v) Except as disclosed in the Prospectus, there are no contracts, agreements or understandings known to such counsel between the Company and any person granting such person the right to require the Company to file a registration statement under the Act with respect to any securities of the Company owned or to be owned by such person or to require the Company to include such securities in the securities registered pursuant to the Registration Statement or in any securities being registered pursuant to any other registration statement filed by the Company under the Act; (vi) The Company and each of its subsidiaries possess adequate certificates, authorities, licenses or permits issued by appropriate governmental agencies or bodies necessary to conduct the business as now operated by them as described in the Prospectus and such counsel is not aware of the receipt of any notice of proceedings relating to the revocation or modification of any such certificate, authority, license or permit that, if determined adversely to the Company or any of its subsidiaries, would individually or in the aggregate have a Material Adverse Effect; (vii) No consent, approval, authorization or order of, or filing with, any governmental agency or body or any court is required under South Dakota law, PUHCA or the Federal Power Act, as amended ("FPA"), for the consummation of the transactions contemplated by this Agreement in connection with the 13
issuance and sale of the Offered Securities by the Company, except such as may be required under state securities laws; (viii) The execution, delivery and performance of this Agreement and the issuance and sale of the Offered Securities will not result in a breach or violation of any of the terms and provisions of, or constitute a default under, PUHCA or FPA, any rule, regulation or, to such counsel's knowledge, order of any governmental agency or body relating to PUHCA or FPA or any court having jurisdiction over the Company or any subsidiary of the Company or any of their properties in a proceeding relating to PUHCA or FPA; (ix) The descriptions under the headings "Risk Factors," Management's Discussion and Analysis of Financial Condition and Results of Operations - Rate Regulation" and "Business" in the Registration Statements and Prospectus of statutes, legal and governmental proceedings and contracts and other documents are accurate in all material respects and fairly present the information required to be shown; (x) Such counsel is of the opinion that the Company and each subsidiary of the Company (i) is in compliance with any and all applicable environmental laws, (ii) has received all permits, licenses or other approvals required of it under applicable environmental laws to conduct its business and (iii) is in compliance with all terms and conditions of any such permit, license or approval, except where such noncompliance with environmental laws, failure to receive required permits, licenses or other approvals or failure to comply with the terms and conditions of such permits, licenses or approvals would not individually or in the aggregate have a Material Adverse Effect; and (xi) The Company is a public utility holding company that is exempt from regulation under PUHCA (except for Sections 9(a)(2) and 10 thereof) pursuant to Section 3(a) of PUHCA. In rendering such opinion, such counsel may state that their opinion is limited to matters governed by the laws of the State of South Dakota, PUHCA and FPA. (e) The Representatives shall have received an opinion, dated such Closing Date, of Conner & Winters, A Professional Corporation, special counsel for the Company, to the effect that: (i) The Company is not and, after giving effect to the offering and sale of the Offered Securities and the application of the proceeds thereof as described in the Prospectus, will not be an "investment company" as defined in the Investment Company Act of 1940; (ii) No consent, approval, authorization or order of, or filing with, any governmental agency or body or any court is required for the consummation of the transactions contemplated by this Agreement in connection with the issuance and sale of the Offered Securities by the Company, except such as have been 14
obtained and made under the Act and such as may be required under state securities laws; (iii) The execution, delivery and performance of this Agreement and the issuance and sale of the Offered Securities will not result in a breach or violation of any of the terms and provisions of, or constitute a default under, (A) any statute, any rule, regulation or, to such counsel's knowledge, order of any governmental agency or body or any court having jurisdiction over the Company or any subsidiary of the Company or any of their properties, (B) any agreement or instrument to which the Company or any such subsidiary is a party or by which the Company or any such subsidiary is bound or to which any of the properties of the Company or any such subsidiary is subject, or (C) the charter or by-laws of the Company, except in the case of clause (B) for such breaches, violations or defaults that would not individually or in the aggregate have a Material Adverse Effect; (iv) The Initial Registration Statement was declared effective under the Act as of the date and time specified in such opinion (based solely upon a telephonic confirmation from a representative of the Commission), the Additional Registration Statement (if any) was filed and became effective under the Act as of the date and time (if determinable) specified in such opinion, the Prospectus either was filed with the Commission pursuant to the subparagraph of Rule 424(b) specified in such opinion on the date specified therein or was included in the Initial Registration Statement or the Additional Registration Statement (as the case may be), and, to the knowledge of such counsel, no stop order suspending the effectiveness of a Registration Statement or any part thereof has been issued and no proceedings for that purpose have been instituted or are pending or contemplated under the Act, and each Registration Statement and the Prospectus, and each amendment or supplement thereto, as of their respective effective or issue dates, complied as to form in all material respects with the requirements of the Act and the Rules and Regulations; the descriptions under the headings "Management - Executive Compensation - Retirement Plans," "Management - Executive Compensation - Severance Agreements," "Principal Shareholders," "Description of Capital Stock," "United States Federal Tax Considerations for Non-U.S. Holders" and "Underwriting" in the Registration Statements and Prospectus of statutes, legal and governmental proceedings and contracts and other documents are accurate in all material respects and fairly present the information required to be shown; and such counsel do not know of any legal or governmental proceedings required to be described in a Registration Statement or the Prospectus which are not described as required or of any contracts or documents of a character required to be described in a Registration Statement or the Prospectus or to be filed as exhibits to a Registration Statement which are not described and filed as required; it being understood that such counsel need express no opinion as to the financial statements or other financial data contained in the Registration Statements or the Prospectus. 15
In addition, such counsel shall state that such counsel has participated in conferences with officers and other representatives of the Company, counsel for the Company, representatives of the independent accountants of the Company, and representatives of the Underwriters at which the contents of the Registration Statements and Prospectus were discussed, and, although such counsel is not passing upon and does not assume responsibility for the accuracy, completeness or fairness of the statements contained in any Registration Statement or Prospectus (except and to the extent stated in subparagraph (iv) of this Section 6(e)), on the basis of the foregoing, nothing has come to the attention of such counsel that cause them to believe that any part of a Registration Statement or any amendment thereto, as of its effective date or as of such Closing Date, contained any untrue statement of a material fact or omitted to state any material fact required to be stated therein or necessary to make the statements therein not misleading or that the Prospectus or any amendment or supplement thereto, as of its issue date or as of such Closing Date, contained any untrue statement of a material fact or omitted to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading; it being understood that such counsel need express no opinion as to the financial statements or other financial data contained in the Registration Statements or the Prospectus. In rendering such opinion, such counsel may state that their opinion is limited to matters governed by the federal laws of the Unites States of America (other than PUHCA and FPA) and the laws of the State of Oklahoma. (f) The Representatives shall have received from Skadden, Arps, Slate, Meagher & Flom LLP, counsel for the Underwriters, such opinion or opinions, dated such Closing Date, with respect to the incorporation of the Company, the validity of the Offered Securities delivered on such Closing Date, the Registration Statements, the Prospectus and other related matters as the Representatives may require, and the Company shall have furnished to such counsel such documents as they request for the purpose of enabling them to pass upon such matters. In rendering such opinion, Skadden, Arps, Slate, Meagher & Flom LLP may rely as to the incorporation of the Company and all other matters governed by South Dakota law upon the opinion of Morrill Thomas Nooney & Braun, LLP, referred to above. (g) The Representatives shall have received a certificate, dated such Closing Date, of the President or any Vice President and a principal financial or accounting 16
officer of the Company in which such officers, to the best of their knowledge after reasonable investigation, shall state that: the representations and warranties of the Company in this Agreement are true and correct; the Company has complied with all agreements and satisfied all conditions on its part to be performed or satisfied hereunder at or prior to such Closing Date; no stop order suspending the effectiveness of any Registration Statement has been issued and no proceedings for that purpose have been instituted or are contemplated by the Commission; the Additional Registration Statement (if any) satisfying the requirements of subparagraphs (1) and (3) of Rule 462(b) was filed pursuant to Rule 462(b), including payment of the applicable filing fee in accordance with Rule 111(a) or (b) under the Act, prior to the time the Prospectus was printed and distributed to any Underwriter; and, subsequent to the date of the most recent financial statements of the Company in the Prospectus, there has been no material adverse change, nor any development or event involving a prospective material adverse change, in the condition (financial or other), business, properties or results of operations of the Company and its subsidiaries taken as a whole except as set forth in or contemplated by the Prospectus or as described in such certificate. (h) The Representatives shall have received a letter, dated such Closing Date, of Arthur Andersen LLP which meets the requirements of subsection (a) of this Section, except that the specified date referred to in such subsection will be a date not more than three days prior to such Closing Date for the purposes of this subsection. (i) On or prior to the date of this Agreement, the Representatives shall have received lockup letters from each of the executive officers and directors of the Company substantially to the effect described in the Prospectus. The Company will furnish the Representatives with such conformed copies of such opinions, certificates, letters and documents as the Representatives reasonably request. CSFBC may in its sole discretion waive on behalf of the Underwriters compliance with any conditions to the obligations of the Underwriters hereunder, whether in respect of an Optional Closing Date or otherwise. 7. INDEMNIFICATION AND CONTRIBUTION. (a) The Company will indemnify and hold harmless each Underwriter, its partners, directors and officers and each person, if any, who controls such Underwriter within the meaning of Section 15 of the Act, against any losses, claims, damages or liabilities, joint or several, to which such Underwriter may become subject, under the Act or otherwise, insofar as such losses, claims, damages or liabilities (or actions in respect thereof) arise out of or are based upon any untrue statement or alleged untrue statement of any material fact contained in any Registration Statement, the Prospectus, or any amendment or supplement thereto, or any related preliminary prospectus, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, and will reimburse each Underwriter for any legal or other expenses reasonably incurred by such Underwriter in connection with investigating or defending any such loss, claim, damage, liability or action as such expenses are incurred; provided, however, that the Company will not be liable in any such case to the extent that any such loss, claim, damage or liability arises out of or is based upon an untrue statement or alleged untrue statement in or omission or alleged omission from any of such documents in 17
reliance upon and in conformity with written information furnished to the Company by any Underwriter through the Representatives specifically for use therein, it being understood and agreed that the only such information furnished by any Underwriter consists of the information described as such in subsection (b) below; and provided, further, that with respect to any untrue statement or alleged untrue statement in or omission or alleged omission from any preliminary prospectus the indemnity agreement contained in this subsection (a) shall not inure to the benefit of any Underwriter from whom the person asserting any such losses, claims, damages or liabilities purchased the Offered Securities concerned, to the extent that a prospectus relating to such Offered Securities was required to be delivered by such Underwriter under the Act in connection with such purchase and any such loss, claim, damage or liability of such Underwriter results from the fact that there was not sent or given to such person, at or prior to the written confirmation of the sale of such Offered Securities to such person, a copy of the Prospectus if the Company had previously furnished copies thereof to such Underwriter. (b) Each Underwriter will severally and not jointly indemnify and hold harmless the Company, its directors and officers and each person, if any who controls the Company within the meaning of Section 15 of the Act, against any losses, claims, damages or liabilities to which the Company may become subject, under the Act or otherwise, insofar as such losses, claims, damages or liabilities (or actions in respect thereof) arise out of or are based upon any untrue statement or alleged untrue statement of any material fact contained in any Registration Statement, the Prospectus, or any amendment or supplement thereto, or any related preliminary prospectus, or arise out of or are based upon the omission or the alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, in each case to the extent, but only to the extent, that such untrue statement or alleged untrue statement or omission or alleged omission was made in reliance upon and in conformity with written information furnished to the Company by such Underwriter through the Representatives specifically for use therein, and will reimburse any legal or other expenses reasonably incurred by the Company in connection with investigating or defending any such loss, claim, damage, liability or action as such expenses are incurred, it being understood and agreed that the only such information furnished by any Underwriter consists of (i) the following information in the Prospectus furnished on behalf of each Underwriter: the concession and reallowance figures appearing in the fourth paragraph under the caption "Underwriting"; and (ii) the following information in the Prospectus furnished on behalf of CSFBC: the information concerning CSFBDIRECT, Inc. appearing in the third sentence in the penultimate paragraph under the heading "Underwriting". (c) Promptly after receipt by an indemnified party under this Section of notice of the commencement of any action, such indemnified party will, if a claim in respect thereof is to be made against the indemnifying party under subsection (a) or (b) above, notify the indemnifying party in writing of the commencement thereof; but the omission so to notify the indemnifying party will not relieve it from any liability which it may have to any indemnified party otherwise than under subsection (a) or (b) above. In case any such action is brought against any indemnified party and it notifies the indemnifying party of the commencement thereof, the indemnifying party will be entitled to participate therein and, to the extent that it may wish, jointly with any other indemnifying party similarly notified, to assume the defense thereof, with counsel satisfactory to such indemnified party (who shall not, except with the consent of the indemnified party, be counsel to the indemnifying party), and after notice from the indemnifying party to such indemnified party of its election so to assume the defense thereof, the indemnifying party will not be liable to such indemnified party under this Section for any legal or other 18
expenses subsequently incurred by such indemnified party in connection with the defense thereof other than reasonable costs of investigation. No indemnifying party shall, without the prior written consent of the indemnified party, effect any settlement of any pending or threatened action in respect of which any indemnified party is or could have been a party and indemnity could have been sought hereunder by such indemnified party unless such settlement (i) includes an unconditional release of such indemnified party from all liability on any claims that are the subject matter of such action and (ii) does not include a statement as to, or an admission of, fault, culpability or a failure to act by or on behalf of an indemnified party. (d) If the indemnification provided for in this Section is unavailable or insufficient to hold harmless an indemnified party under subsection (a) or (b) above, then each indemnifying party shall contribute to the amount paid or payable by such indemnified party as a result of the losses, claims, damages or liabilities referred to in subsection (a) or (b) above (i) in such proportion as is appropriate to reflect the relative benefits received by the Company on the one hand and the Underwriters on the other from the offering of the Securities or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits referred to in clause (i) above but also the relative fault of the Company on the one hand and the Underwriters on the other in connection with the statements or omissions which resulted in such losses, claims, damages or liabilities as well as any other relevant equitable considerations. The relative benefits received by the Company on the one hand and the Underwriters on the other shall be deemed to be in the same proportion as the total net proceeds from the offering (before deducting expenses) received by the Company bear to the total underwriting discounts and commissions received by the Underwriters. The relative fault shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Company or the Underwriters and the parties' relative intent, knowledge, access to information and opportunity to correct or prevent such untrue statement or omission. The amount paid by an indemnified party as a result of the losses, claims, damages or liabilities referred to in the first sentence of this subsection (d) shall be deemed to include any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any action or claim which is the subject of this subsection (d). Notwithstanding the provisions of this subsection (d), no Underwriter shall be required to contribute any amount in excess of the amount by which the total price at which the Securities underwritten by it and distributed to the public were offered to the public exceeds the amount of any damages which such Underwriter has otherwise been required to pay by reason of such untrue or alleged untrue statement or omission or alleged omission. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation. The Underwriters' obligations in this subsection (d) to contribute are several in proportion to their respective underwriting obligations and not joint. (e) The obligations of the Company under this Section shall be in addition to any liability which the Company may otherwise have and shall extend, upon the same terms and conditions, to each person, if any, who controls any Underwriter within the meaning of the Act; and the obligations of the Underwriters under this Section shall be in addition to any liability which the respective Underwriters may otherwise have and shall extend, upon the same terms and conditions, to each director of the Company, to each officer of the Company who has signed a Registration Statement and to each person, if any, who controls the Company within the meaning of the Act. 19
8. DEFAULT OF UNDERWRITERS. If any Underwriter or Underwriters default in their obligations to purchase Offered Securities hereunder on either the First or any Optional Closing Date and the aggregate number of shares of Offered Securities that such defaulting Underwriter or Underwriters agreed but failed to purchase does not exceed 10% of the total number of shares of Offered Securities that the Underwriters are obligated to purchase on such Closing Date, CSFBC may make arrangements satisfactory to the Company for the purchase of such Offered Securities by other persons, including any of the Underwriters, but if no such arrangements are made by such Closing Date, the non-defaulting Underwriters shall be obligated severally, in proportion to their respective commitments hereunder, to purchase the Offered Securities that such defaulting Underwriters agreed but failed to purchase on such Closing Date. If any Underwriter or Underwriters so default and the aggregate number of shares of Offered Securities with respect to which such default or defaults occur exceeds 10% of the total number of shares of Offered Securities that the Underwriters are obligated to purchase on such Closing Date and arrangements satisfactory to CSFBC and the Company for the purchase of such Offered Securities by other persons are not made within 36 hours after such default, this Agreement will terminate without liability on the part of any non-defaulting Underwriter or the Company, except as provided in Section 9 (provided that if such default occurs with respect to Optional Securities after the First Closing Date, this Agreement will not terminate as to the Firm Securities or any Optional Securities purchased prior to such termination). As used in this Agreement, the term "Underwriter" includes any person substituted for an Underwriter under this Section. Nothing herein will relieve a defaulting Underwriter from liability for its default. 9. SURVIVAL OF CERTAIN REPRESENTATIONS AND OBLIGATIONS. The respective indemnities, agreements, representations, warranties and other statements of the Company or its officers and of the several Underwriters set forth in or made pursuant to this Agreement will remain in full force and effect, regardless of any investigation, or statement as to the results thereof, made by or on behalf of any Underwriter, the Company or any of their respective representatives, officers or directors or any controlling person, and will survive delivery of and payment for the Offered Securities. If this Agreement is terminated pursuant to Section 8 or if for any reason the purchase of the Offered Securities by the Underwriters is not consummated, the Company shall remain responsible for the expenses to be paid or reimbursed by it pursuant to Section 5 and the respective obligations of the Company and the Underwriters pursuant to Section 7 shall remain in effect, and if any Offered Securities have been purchased hereunder the representations and warranties in Section 2 and all obligations under Section 5 shall also remain in effect. If the purchase of the Offered Securities by the Underwriters is not consummated for any reason other than solely because of the termination of this Agreement pursuant to Section 8 or the occurrence of any event specified in clause (iii), (iv) or (v) of Section 6(c), the Company will reimburse the Underwriters for all out-of-pocket expenses (including fees and disbursements of counsel) reasonably incurred by them in connection with the offering of the Offered Securities. 10. NOTICES. All communications hereunder will be in writing and, if sent to the Underwriters, will be mailed, delivered or telegraphed and confirmed to the Representatives, c/o Credit Suisse First Boston Corporation, Eleven Madison Avenue, New York, New York 10010-3629, Attention: Transactions Advisory Group, or, if sent to the Company, will be mailed, delivered or telegraphed and confirmed to it at P.O. Box 1400, 625 Ninth Street, Rapid City, South Dakota 57709, Attention: Steven J. Helmers, Esq., General Counsel; provided, however, that any notice to an 20
Underwriter pursuant to Section 7 will be mailed, delivered or telegraphed and confirmed to such Underwriter. 11. SUCCESSORS. This Agreement will inure to the benefit of and be binding upon the parties hereto and their respective successors and the officers and directors and controlling persons referred to in Section 7, and no other person will have any right or obligation hereunder. 12. REPRESENTATION OF UNDERWRITERS. The Representatives will act for the several Underwriters in connection with the transactions contemplated by this Agreement, and any action under this Agreement taken by the Representatives jointly or by CSFBC will be binding upon all the Underwriters. 13. COUNTERPARTS. This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original, but all such counterparts shall together constitute one and the same Agreement. 14. APPLICABLE LAW. THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. 15. CONSENT TO JURISDICTION. The Company hereby submits to the non-exclusive jurisdiction of the Federal and state courts in the Borough of Manhattan in The City of New York in any suit or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby. If the foregoing is in accordance with the Representatives' understanding of our agreement, kindly sign and return to the Company one of the counterparts hereof, whereupon it will become a binding agreement between the Company and the several Underwriters in accordance with its terms. Very truly yours, BLACK HILLS CORPORATION By: ----------------------------------- Name: Title: The foregoing Underwriting Agreement is hereby confirmed and accepted as of the date first above written. CREDIT SUISSE FIRST BOSTON CORPORATION LEHMAN BROTHERS INC. CIBC WORLD MARKETS CORP. UBS WARBURG LLC, 21
Acting on behalf of themselves and as the Representatives of the several Underwriters By: CREDIT SUISSE FIRST BOSTON CORPORATION By: ------------------------------- Name: Title: SCHEDULE A NUMBER OF FIRM UNDERWRITER SECURITIES - ----------- -------------- Credit Suisse First Boston Corporation........................... Lehman Brothers Inc.............................................. CIBC World Markets Corp.......................................... UBS Warburg LLC.................................................. --------- Total....................................................... 3,000,000 ========= 22
EXHIBIT 10.4 NEW RESTATED AND AMENDED COAL SUPPLY AGREEMENT dated as of January 1, 2001 between WYODAK RESOURCES DEVELOPMENT CORP. and PACIFICORP Coal-Fired Steam Electric Generating Facility at Wyodak, Wyoming
NEW RESTATED AND AMENDED COAL SUPPLY AGREEMENT NEW RESTATED AND AMENDED COAL SUPPLY AGREEMENT ("Agreement"), dated as of January 1, 2001 by and among WYODAK RESOURCES DEVELOPMENT CORP., a Delaware corporation ("Seller") and PACIFICORP, an Oregon corporation ("Buyer"). WHEREAS, Seller mines coal at a coal mine consisting of the existing Wyodak Mine and the adjacent Clovis Point Mine (the "Mine") in Campbell County, Wyoming, pursuant to leases described in Annex A attached hereto (the "Coal Leases," or the "United States Coal Leases," when referring to items 1,2,3 and 5 of Annex A, or the "State Coal Lease" when referring to item 6 of Annex A), and owns coal properties in land described in Annex B, and may in the future add (by lease or purchase) additional coal properties adjacent to the Mine but part of a logical mining unit with the existing Coal Leases, all of which Coal Leases and coal properties contain certain coal reserves (collectively, the "Coal Reserves"); WHEREAS, Buyer owns an 80% interest in, and operates, a coal-fired steam electric generating facility having a name-plate rating of 335 megawatts (the "Facility") located adjacent to the Coal Reserves; WHEREAS, the parties intend that Seller will mine and deliver all of Buyer's coal requirements for the Facility during the Term of this Agreement; WHEREAS, Seller, Buyer and Black Hills Corporation are parties to a Further Restated and Amended Coal Supply Agreement dated May 5, 1987, as amended, which Agreement was substituted, as of the date of its execution, for the Restated and Amended Coal Supply Agreement dated June 8, 1978 as amended by the Coal Supply Agreement for Wyodak Unit #2 and the Ancillary Agreement to Coal Supply Agreement for Wyodak Unit #2, both dated February 3, 1982, all of such agreements being hereinafter collectively referred to as the "Prior Agreement"; and WHEREAS, the parties have agreed to settle all disputes relating to the Prior Agreement pursuant to a Settlement Agreement effective January 1, 2001, and the Parties have agreed to terminate the Prior Agreement, as between Buyer and Seller, as of the effective date of this Agreement pursuant to the terms of the Settlement Agreement and enter into this Agreement for the supply of Buyer's coal requirements for the Facility. NOW, THEREFORE, Seller agrees to sell and deliver and Buyer agrees to accept and buy coal, as hereinafter provided, upon the following terms and conditions: SECTION 1. TERM OF AGREEMENT. The term of this Agreement (the "Term") shall commence on January 1, 2001 and shall terminate on December 31, 2022.
SECTION 2. REPRESENTATIONS, ETC. OF SELLER; DEDICATION OF COAL RESERVES; SECURITY INTEREST AND MORTGAGE; SUBSTITUTION AND RELEASE OF COAL RESERVES, ETC. (a) CERTAIN REPRESENTATIONS, WARRANTIES AND COVENANTS OF SELLER. The source of the coal to be sold and purchased shall be the Coal Reserves. Seller shall have no right to substitute coal mined from reserves other than the Coal Reserves. Seller represents and warrants to Buyer that: (1) The Coal Reserves contained approximately 297,000,000 tons of mineable coal as of January 1, 2001; (2) Seller has valid and existing leasehold rights under the Coal Leases; (3) Seller has title to the Coal Reserves under the real property described in Annex B, but its right to mine such coal may be subject to obtaining the consent of the owner of the surface rights to said property; (4) Seller has certain valid and existing rights (as described in Annex C hereto) to use the surface of the land under which the Dedicated Reserves, as hereinafter defined in this Section 2, are located (such rights to the extent they relate to the Dedicated Reserves being herein referred to as "Surface Rights"); and (5) Seller holds the following permits, licenses and approvals (the "Governmental Approvals") to mine the Dedicated Reserves: Permit No. 232C-T4 issued by The Department of Environmental Quality of the State of Wyoming permitting the surface mining (pursuant to the mine plan filed by Seller with said Department) of coal in the Dedicated Reserves and other portions of the Coal Reserves. Permit No. 581-T3 issued by The Department of Environmental Quality of the State of Wyoming permitting the surface mining (pursuant to the mine plan filed by Seller with said Department) of coal in the Dedicated Reserves and other portions of the Coal Reserves. License No. 232-T1-L1 issued by the Department of Environmental Quality of the State of Wyoming authorizing Seller to surface mine (pursuant to the mine plan referred to above) coal in the Dedicated Reserves and other portions of the Coal Reserve. Approval by the Geological Survey of the United States Department of the Interior of the mining plan of Seller to mine the Dedicated Reserves and other portions of the Coal Reserves; and (6) The rights of Seller under the Coal Leases (such rights to the extent they relate to the Dedicated Reserves being referred to herein as "Lease Rights"), the Surface Rights and the Governmental Approvals are sufficient to permit Seller to mine the Dedicated Reserves, 2
subject to the claims and rights of others and applicable mining and reclamation requirements and governmental approvals as are set forth in Exhibit A to the Security Agreement and Real Estate Mortgage (the "Security Agreement and Mortgage") being executed and delivered effective with the execution and delivery of this Agreement. Seller shall use its best efforts to maintain the Coal Leases, the Surface Rights and the Governmental Approvals in full force and effect during the Term, to obtain all necessary renewals thereof, and to obtain all mining permits and other governmental approvals or authorizations and any consents from others as may be necessary in order to permit Seller to perform its obligations hereunder and under the Security Agreement and Mortgage. (b) DEDICATION OF COAL RESERVES; SECURITY INTEREST AND MORTGAGE; ACCESS TO DEDICATED RESERVES. Seller does hereby dedicate to the Facility all coal (constituting at least 40,000,000 tons of mineable coal meeting the quality requirements set forth in Section 6) from the Coal Reserves under the following described real property: TOWNSHIP 50 NORTH, RANGE 71 WEST OF THE 6TH PRINCIPAL MERIDIAN, CAMPBELL COUNTY, WYOMING: Section 8: The Southwest Quarter; and Section 17: The Northwest Quarter and the North Half of the Southwest Quarter. (The afore-described portion of the Coal Reserves is herein referred to as the "Dedicated Reserves".) Seller shall not mine, sell or use coal from the Dedicated Reserves for any purpose other than fulfilling its obligations under this Agreement, unless otherwise permitted under this Agreement. Seller shall, effective with the execution and delivery of this Agreement, execute and deliver the Security Agreement and Mortgage. As contemplated by the Access Easement to Dedicated Reserves, substantially in the form of Annex D hereto, Buyer shall have the right to enter upon Seller's premises for the purpose of transporting coal from the Dedicated Reserves to the Facility. (c) SUBSTITUTION AND RELEASE OF COAL RESERVES, ETC. Other Coal Reserves and the lease rights and surface rights associated therewith shall be substituted for the Dedicated Reserves. Coal Reserves shall be released from the Dedicated Reserves, and Coal Reserves, Lease Rights and Surface Rights may be released from the lien of the Security Agreement and Mortgage under certain conditions as follows: (1) If for any reason any Coal Lease which includes the right to mine the Dedicated Reserves terminates or expires and is not renewed, Seller shall dedicate to the Facility other portions of the Coal Reserves containing coal sufficient to satisfy the quality specifications in Section 6 and as readily recoverable, both legally and physically, in substitution for those which have been lost to the extent, if any, that Seller at the time of the loss has such quality of Coal Reserves which have not been sold, committed or dedicated to others. Such substituted 3
Coal Reserves and the lease rights and surface rights associated therewith shall be subjected to the lien of the Security Agreement and Mortgage subject only to the exceptions referred to therein and, to the extent Seller only has Coal Reserves, lease rights and surface rights subject to liens or security interests granted to others prior to the date of such substitution, to such prior liens or security interests, PROVIDED that such substituted Coal Reserves, lease rights and surface rights shall not be subjected to the lien of the Security Agreement and Mortgage to the extent such subjection would be a breach of the terms of any prior lien or security interest and the consent to such subjection cannot be obtained by Seller from the holder(s) of such lien or security interest. (2) Subject to the quality requirements set forth in Section 6, Seller may from time to time, at its option, supply coal to the Facility in fulfilling its obligations under this Agreement from the Coal Reserves but from sources other than the Dedicated Reserves, and in such event Buyer shall (from time to time upon Seller's written request) release equivalent quantities of the Dedicated Reserves from the dedication thereof pursuant to this Agreement and shall release such quantities of the Dedicated Reserves and the Lease Rights and Surface Rights associated therewith from the lien of the Security Agreement and Mortgage, but only if after giving effect to such release the Dedicated Reserves shall contain a quantity of mineable coal of a quality required by Section 6 in an amount which, when added to all of the coal sold by Seller to Buyer under this Agreement up to the date of such release, equals at least 40,000,000 tons. (3) Seller shall have the option from time to time to cause Buyer to release quantities of the Dedicated Reserves from the dedication thereof pursuant to this Agreement and to release such quantities of the Dedicated Reserves and the Lease Rights and Surface Rights associated therewith from the lien of the Security Agreement and Mortgage, but only if after giving effect to such release the Dedicated Reserves shall contain a quantity of mineable coal of a quality required by Section 6 in an amount which, when added to all of the coal sold by Seller to Buyer under this Agreement up to the date of such release, equals at least 40,000,000 tons. (4) Seller shall further have the option to dedicate other equivalent reserves from the Coal Reserves in substitution for all or any part of the Coal Reserves dedicated pursuant to this Agreement and to cause Buyer to release an equivalent quantity of the Dedicated Reserves (at the location to be designated by Buyer) from the dedication thereof pursuant to this Agreement and to release such quantity of Dedicated Reserves and the Lease Rights and Surface Rights associated therewith from the lien of the Security Agreement and Mortgage, but only if after giving effect to such release (i) the Dedicated Reserves shall contain a quantity of mineable coal of a quality required by Section 6 in an amount which, when added to all of the coal sold by Seller to Buyer under this Agreement up to the date of such release, equals at least 40,000,000 tons, (ii) such substituted reserves are of the same quality and are as readily recoverable, both legally and physically, as the portion of the Dedicated Reserves to be released, and (iii) the reserves so substituted and the lease rights and surface rights associated therewith shall be subjected to the lien of the Security Agreement and Mortgage, subject only to the exceptions set forth in Exhibit A thereto. (5) Any part of the Coal Reserves substituted in accordance with this Section 2(c) shall be coal under surface either owned by Seller or in which Seller has all necessary surface rights to surface mine such coal. 4
(6) The quantities of the Dedicated Reserves to be released pursuant to clauses (2) and (3) of this Section 2(c) shall be released in the parcels designated in the Plat of the Dedicated Reserves (the "Plat") attached as Annex K hereto. Each parcel shall be released in the numerical order set forth in the Plat upon delivery by Seller from sources other than the Dedicated Reserves of the amount of coal described in the Plat as being contained in such parcel and upon fulfillment of the other terms and conditions applicable to release of quantities of the Dedicated Reserves set forth in this Section 2(c). (7) In the event compliance with this Section 2 requires Seller to subject additional Coal Reserves to the lien of the Security Agreement and Mortgage, such subjection shall be evidenced by an agreement supplemental to the Security Agreement and Mortgage, or by such other agreement as may be necessary, in view of applicable law at the time of such subjection, to grant Buyer substantially the same rights in such additional Coal Reserves as Buyer had with respect to the Dedicated Reserves pursuant to the Security Agreement and Mortgage, subject, however, to the provisions of clause (1) of this Section 2(c). (8) At the time Seller substitutes other Coal Reserves for Dedicated Reserves under clause (1) or (4) of this Section 2(c), and in order for Seller to obtain a release of Coal Reserves from the Dedicated Reserves under such clause (4), Seller shall (at its expense) deliver to Buyer a certificate executed by an engineer satisfactory to Buyer certifying that the Coal Reserves to be substituted contain coal of the quality and quantity, and are as physically recoverable, as required by such clause (1) or (4) and an opinion of counsel satisfactory to Buyer to the effect that Seller has all permits, licenses, consents and approvals from governmental bodies and other parties legally necessary for Seller to mine the Coal Reserves being substituted (subject to amending the mine plan of Seller to allow the mining of the Coal Reserves being substituted at an earlier time than may be contemplated by Seller's mine plan at the time of the substitution), that such substituted reserves and the lease rights and surface rights associated therewith have been duly subjected to the lien of the Security Agreement and Mortgage to the full extent required hereby, and that all recordations or filings required to perfect the rights of Buyer under such Security Agreement and Mortgage, as then supplemented, have been duly made and are in full force and effect. Such substituted Coal Reserves, lease rights and surface rights shall thereupon be considered Dedicated Reserves, Lease Rights and Surface Rights for the purposes of this Agreement and the Security Agreement and Mortgage and, as such, shall be subject to release or substitution in accordance with the terms of this Section 2(c). In order to obtain a release of Coal Reserves from the Dedicated Reserves under clause (2) or (3) of this Section 2(c), Seller shall (at its expense) deliver to Buyer a certificate executed by an engineer satisfactory to Buyer certifying that the Dedicated Reserves which are to remain after such release contain the quantity of coal required by such clause (2) or (3), as the case may be. (9) Upon satisfaction of all applicable conditions as set forth above for the release or substitution of Coal Reserves from the dedication hereunder and for the release of Coal Reserves, Lease Rights and Surface Rights from the lien of the Security Agreement and Mortgage, Buyer shall execute and deliver to Seller appropriate instruments for effecting such release. At the time of the completion of Seller's obligations under this Agreement, Buyer shall release any remaining unmined coal from the dedication of Coal Reserves pursuant to this 5
Agreement and shall release such coal and the lease rights and surface rights associated therewith from the lien of the Security Agreement and Mortgage. The lien of the Security Agreement and Mortgage shall not in any way alter Seller's rights granted in any of the Coal Leases to mine and remove the coal therefrom, except to the extent Seller's rights may be affected by the exercise of Buyer's rights in the event of Seller's default pursuant to the terms of the Security Agreement and Mortgage. SECTION 3. QUANTITIES OF COAL TO BE SOLD AND PURCHASED; SCHEDULING. Seller agrees to sell and Buyer agrees to buy all of the coal which is necessary to fuel Buyer's portion of the Facility during the Term. Buyer shall notify Seller at least twenty days prior to the beginning of each month of the quantities of coal to be delivered to Buyer during such month and shall provide a schedule for delivery. In addition, Buyer will furnish Seller an estimate of the quantities to be ordered in each of the two months following such month. Buyer may at any time increase or decrease the amount of the coal to be delivered at a rate necessary to properly fuel the Facility, but the amount of coal to be delivered shall not exceed 41,000 tons for any one week or 1,800,000 tons for any one year. SECTION 4. BUYER MINIMUM PURCHASE OBLIGATION. To fuel its 80 percent share of the Facility, Buyer shall purchase from Seller a minimum of the lesser of (a) 1,500,000 tons of coal during each calendar year of the Term in which no planned outage is contemplated (as of April 1 of such year) by Buyer for the Facility, or (b) that number of tons of coal during each calendar year during the Term in which a planned outage is contemplated (as of April 1 of such year) by Buyer for the Facility either (i) for any calendar year ending on or before December 31, 2013, equal to the greater of 1,280,000 tons or the number determined by multiplying 1,500,000 by a fraction, the numerator of which equals 365 minus the number of days of the planned outage, and the denominator of which equals 365, or (ii) for any calendar year commencing on or after January 1, 2014, the number determined by multiplying 1,500,000 by a fraction, the numerator of which equals 365 minus the number of days of the planned outage, and the denominator of which equals 365. This minimum amount of coal shall be purchased by Buyer regardless of the quantity of coal purchased by it during prior years. Seller's sole remedy for Buyer's failure to purchase this minimum amount of coal shall be the Short-Fall Payment provided for in Section 15. SECTION 5. PLACE OF DELIVERY AND SALE. Delivery shall be made to Buyer at the inlet of the secondary crusher at the location specified on Annex E. Title to the coal delivered at the inlet of the secondary crusher by Seller in fulfillment of its obligations under this Agreement shall thereupon pass to Buyer and Buyer shall be responsible for transporting said coal from such inlet to the Facility. Risk of loss for such coal shall pass from Seller to Buyer after the coal is weighed on the scales referenced in Section 7; provided, however, in the event scales for the weighing of coal are ever relocated to a point at or adjacent to the inlet to the secondary crusher, then risk of loss for all coal weighed on such scales shall pass from Seller to Buyer at the inlet to the secondary crusher. In the event of emergencies of Buyer preventing the delivery or acceptance of the coal at the inlet of the 6
secondary crusher, the coal shall be delivered at such different location as may be designated by Buyer, and in that event Seller shall be compensated by Buyer for any additional cost to Seller resulting from the delivery of said coal at a different location. SECTION 6. QUALITY OF COAL. The coal furnished hereunder shall be raw, run-of-mine coal and substantially free of magnetic material and other foreign material impurities including, but not limited to, mining debris, bone, slate, scrapped iron, steel, petroleum coke, earth, rock, pyrite, wood and blasting wire. Seller warrants that coal as delivered shall meet the typical and maximum and minimum specifications (all on a 30-day rolling average basis) as follows: Coal Size-raw, pit run coal nominally sized to six-inch minus Coal Quality Typical Minimum Maximum ------------ ------- ------- ------- Btu/lb. 8000 7700 Moisture 30.7% 32.0% Sulfur 0.55% 0.70% Ash 6.0% 9.0% Fusion Temperatures Typical Minimum ------------------- ------- ------- Initial 2050 2000 Softening 2070 2050 Fluid 2150 2100 Notwithstanding the foregoing, if the Facility experiences significant performance or handling difficulties as a result of coal quality, the parties shall cooperate in good faith to resolve such difficulties and Seller shall take all reasonable steps to meet any revised quality parameters agreed upon at such time as the solution or partial solution to such difficulties. The quality of the coal delivered shall be determined from the daily composite coal sample analysis taken by Buyer pursuant to Section 8 hereof. Seller may deliver and sell coal having a sulfur content in excess of the sulfur limitation herein during any time that Buyer is able to utilize such coal in the Facility as then equipped and operating and meet all applicable federal and state emission standards, PROVIDED that, if such excess sulfur content increases the costs of Buyer in any way, including but not limited to increased operating costs and taxes, Seller shall reimburse Buyer for all of said increased costs. SECTION 7. WEIGHING. The weights of the coal delivered to Buyer shall be determined from weights taken by Buyer on Buyer's scales located at such places as the parties hereto may agree. The aggregate weights of such delivered coal shall be accepted as the quantity of coal delivered for which invoices are to be rendered and payments to be made. Seller shall have the right to have a representative present at any and all times to observe the weighing of coal delivered hereunder, and if Seller shall, at any time, question the accuracy of the weights thus determined, Seller shall 7
so advise Buyer and Buyer shall permit Seller's representative to test Buyer's scales. If any such tests show the scales being used are in error, such scales shall be adjusted to an accurate condition, PROVIDED that if Seller and Buyer are unable to agree upon such test and adjustments or the method thereof, the scales shall be tested and adjusted to a condition of accuracy within manufacturer's tolerances by a qualified third party, mutually chosen by Seller and Buyer, and the cost of the testing and adjusting by such third party shall be shared one-half by Seller and one-half by Buyer. The sole remedy for inaccurate scales shall be to adjust the scales to an accurate condition so as to provide proper measurement of quantities of coal delivered thereafter. SECTION 8. SAMPLING AND ANALYSIS. Analysis of calorific value, ash, sulfur, moisture and, if requested by Buyer, ash softening temperature, shall be made by Seller or at its direction for each day's deliveries of coal. Analysis shall be performed in accordance with the latest methods approved by the American Society for Testing and Materials (ASTM) or such other methods as the parties may agree upon. Samples shall be taken by Buyer on a regular basis in accordance with ASTM standards utilizing the automated sampler located in the secondary crusher at the point of delivery. Other sampling methods and locations may be used from time to time upon mutual agreement of the parties. All samples shall be divided into three parts and put in suitable airtight containers. One part shall be taken and analyzed by Seller, one part shall be retained by Buyer and may be analyzed by Buyer at its discretion and the third part shall be retained by Seller for not less than one month in one of the aforesaid containers properly sealed and labeled to be analyzed if a dispute arises due to any differences between Seller's analysis and Buyer's analysis. The results of Seller's analysis for each day's deliveries of coal during a calendar month shall be communicated to Buyer as soon as practicable after the end of such calendar month so that Buyer can perform the calculations described in Section 9. Seller shall pay for the cost of the analysis of the samples to be analyzed by it. Buyer shall bear the cost of any analysis it should decide to make of the samples it retains. The analysis of the third part of each sample, should its analysis be found necessary, shall be made by an independent commercial testing laboratory mutually chosen, and the results of such commercial laboratory analysis shall be made available and accepted by all parties hereto as the quality of the coal represented by such sample. The costs thereof shall be shared one-half by Seller and one-half by Buyer. SECTION 9. DETERMINING OF WEIGHTED AVERAGE HEAT CONTENT. As soon as practicable after the end of each month, the weighted average heat content, in B.T.U.'s per pound, of coal delivered hereunder during such month shall be computed by Buyer from the daily coal delivered weight readings from the coal scales and from the analysis made by Seller from the daily composite coal samples taken by Seller pursuant to Section 8. Computations made by Buyer shall be communicated to Seller. SECTION 10. PURCHASE PRICE. (a) The Purchase Price per ton of coal to be paid by Buyer to Seller for each ton of coal delivered under this Agreement from January 1, 2001 through June 30, 2014, shall be the sum of (i) in the case of the first 1,160,000 tons of coal sold hereunder , $8.527, and in the case of all coal sold hereunder other than the first 1,160,000 tons, $6.207 (said $8.527 being the "Base 8
Price" for the first 1,160,000 tons of coal sold hereunder for purposes of the Btu adjustment in Section 13, and said $6.207 being the "Base Price" for all purposes after the first 1,160,000 tons of coal have been sold hereunder), plus or minus (ii) in the case of all coal sold hereunder other than the first 1,160,000 tons, the adjustments provided in Section 11 applicable to such delivery, plus (iii) the Government Impositions determined in accordance with Section 12 applicable to such delivery. The Base Price is based on coal having a BTU content of 8,000 BTU per pound and shall be further subject to adjustment for BTU variations as provided in Section 13. Annex F attached hereto is a sample computation of the Purchase Price based upon assumed facts to illustrate the application of Sections 10, 11, 12 and 13. (b) The Purchase Price per ton of coal to be paid by Buyer to Seller for each ton of coal delivered under this Agreement from July 1, 2014 through June 30, 2019, shall be determined by the parties as follows: (i) The Purchase Price for each ton of coal delivered under this Agreement in July 2014 shall equal the product of (A) the sum of (1) the 8400 BTU PRB Market Price (as hereinafter defined), (2) the Transportation Market Price (as hereinafter defined) and (3) the Levelized Fixed Charge (as hereinafter defined), and (B) a fraction, the numerator of which is 8,000 and the denominator of which is 8,400. The Purchase Price so determined is based on coal having a BTU content of 8,000 BTU per pound and shall be further subject to adjustment for BTU variations as provided in Section 13. (ii) The 8400 BTU PRB Market Price shall equal the average spot coal price (FOB loaded into railcars at the mine) for 8400 BTU per pound coal sold from mines located in the Powder River Basin in Wyoming during the 12 months ending March 31, 2014, as reported in COAL DAILY. If COAL DAILY has ceased publication or ceases to publish spot market price data on a monthly or more frequent basis, the parties shall substitute such publication as may exist in March 2014 that most accurately reports the spot market price for such coal. If no such publication exists, the parties shall negotiate in good faith to determine such average market price, and if such negotiation does not produce agreement on such average market price by June 1, 2014, either Seller or Buyer may on or before July 1, 2014, invoke the arbitration procedure described in Section 24 below to determine the average spot market coal price (FOB loaded into railcars at the mine) for 8400 BTU per pound coal sold from mines located in the Powder River Basin in Wyoming during the 12 months ending March 31, 2014. Notwithstanding the foregoing, if COAL DAILY (or another comparable publication similar in standing in the coal industry) publishes a market price index for 8400 BTU Wyoming PRB coal sold on a 1-year or longer contract basis (FOB loaded into railcars at the mine) for contracts incepted during the 24 months ending March 31, 2014, and having escalation/de-escalation provisions reasonably comparable to those contained in Section 11 and other terms and conditions reasonably comparable to those set forth in this Agreement, the 8400 BTU PRB Market Price shall equal the average contract price for such 8400 BTU coal as set forth in such index during the 24-month period ended March 31, 2014. (iii) The Transportation Market Price shall equal the average per ton market price for the transportation of coal at the rate of approximately 36,000 tons per week by rail commencing on July 1, 2014, in railroad supplied railcars from the two Powder River Basin 9
mines (other than the Coal Reserves) in closest proximity to the Facility that then produce coal having a quality reasonably comparable to the quality of coal produced by the mines in the Powder River Basin that produce the coal the market price of which is reflected in the index used in clause (ii). The parties shall designate a mutually acceptable engineering firm on or before April 1, 2014 to perform the analysis and determination of the Transportation Market Price. If the parties are unable to agree on the engineering firm by April 1, 2014, or if any party disagrees with the determination made by the engineering firm within 30 days after the final determination by such firm of the Transportation Market Price, then either party may on or before October 1, 2014, invoke the arbitration procedure described in Section 24 below to determine the Transportation Market Price. (iv) The Levelized Fixed Charge shall equal the hypothetical per ton fully-loaded and levelized pre-income tax cost that Buyer would incur if it constructed a permanent rail unloading facility at the Facility and operated it for a period of 20 years commencing July 1, 2014, for the receipt of coal deliveries via rail at the rate of approximately 36,000 tons per week. To determine the Levelized Fixed Charge, the parties shall designate a mutually acceptable engineering firm on or before April 1, 2014 to perform an evaluation of the capital costs required to construct the unloading facility, including an unloading hopper capable of unloading a unit train within 6 hours, a reasonable and prudent track configuration, necessary track siding/switching devices to connect with the mainline of the railroad entity then most proximate to and economically capable of serving the Facility, construction of any required roads and underpasses, requisite supporting structures, acquisition of required rights-of-way at then fair market value, and environmental and engineering costs associated with the design and construction of the unloading facility. Buyer shall have the right, but not the obligation, prior to April 1, 2014, to seek bids from not less than two reputable contractors for either the design and/or the construction of the unloading facility, to assist in establishing the cost of the design and/or construction of such facility, the lower of which bids shall be deemed conclusive evidence of such cost if the bids are within 10% of each other. The engineering firm shall also estimate the levelized cost to operate the unloading facility (including but not limited to all costs for property taxes, insurance, maintenance, labor, materials, supplies and power associated with the unloading facility) in a reasonable and prudent manner at a rate of approximately 36,000 tons per week over the 20-year expected life of the facility using an assumed inflation rate equal to the average of the annual change (on a calendar year basis) in the index referenced in Section 11(c) for the three consecutive calendar years ending December 31, 2013. In determining return and interest expense associated with the capital cost of the unloading facility, the engineering firm shall assume that the capital (net of the residual value, after reclamation, of the unloading facility at the end of the 20-year life) is fully-amortized on a straight line basis over 20 years and financed, 50% with equity and 50% with debt, with the debt amortizing on a levelized basis over 20 years. The return on equity shall be assumed to be the average return on equity then allowed in all jurisdictions within the United States regulating the electricity distribution assets of Buyer, and the cost of debt shall be assumed to be the average per annum interest rate on Buyer's long-term mortgage bond indebtedness with respect to the funding of electricity distribution assets of Buyer. If Buyer does not own electricity distribution assets on April 1, 2014, but a United States based affiliate of Buyer owns such assets on April 1, 2014, then the return on equity and cost of indebtedness shall be determined by reference to the average return on equity allowed in all jurisdictions within the United States regulating the electricity distribution assets of the affiliate 10
of Buyer and the per annum interest rate on such entity's long-term mortgage bond indebtedness. If Buyer (or an affiliate of Buyer) does not own and operate electricity distribution assets regulated by a public utility commission on April 1, 2014, then the return on equity and cost of indebtedness shall be determined by reference to the average return on equity allowed in all jurisdictions regulating the electricity distribution assets of Black Hills Power, Inc. ("Black Hills") and the average per annum interest rate on Black Hills' long-term mortgage bond indebtedness with respect to Black Hills' electricity distribution assets. If neither Buyer nor Black Hills nor any affiliate of either owns electricity distribution assets on April 1, 2014, then the parties shall mutually agree upon the average return on equity allowed in all jurisdictions for a western United States electricity distribution company, and on the average per annum interest rate on such company's long-term mortgage indebtedness with respect to its electricity distribution assets. The calculation of return on equity shall gross up the aforesaid average return on equity based on then applicable federal and state income tax rates. The engineering firm computing the Levelized Fixed Charge shall assume that the amortization of the capital, the interest expense, the return and the operating costs as calculated on a levelized basis for each of the 20 years of the assumed life of the facility is to be allocated on a per ton basis based on the assumption of a number of tons per year determined by taking the average of PacifiCorp's annual tonnage purchases hereunder for calendar years 2009 through 2013, normalized to exclude all periods of uncontrollable force (as set forth in Section 22), if any, during such five-year period, and multiplying such average by a fraction, the numerator of which is the weighted average calorific value (expressed as BTU/lb.) of the coal purchased by PacifiCorp hereunder during such five-year period, and the denominator of which is 8400. For example, if the foregoing computation results in 1,600,000 tons as PacifiCorp's annual average purchases for the five-year period, adjusted to 8400 BTU/lb., and if the engineering firm determines a levelized amortization of capital with interest expense and return of $1,000,000 per year and a levelized operating cost for the facility of $40,000 per year, then the total levelized annual cost of $1,040,000 will be converted to a per ton Levelized Fixed Charge of $0.65 per ton ($1,040,000 divided by 1,600,000 tons). If the parties are unable to agree on the engineering firm by April 1, 2014, or if any party disagrees with the determination made by the engineering firm within 30 days after the final determination by such firm of the Levelized Fixed Charge, then either party may on or before October 1, 2014, invoke the arbitration procedure described in Section 24 below to determine the Levelized Fixed Charge. (v) The parties shall use their respective best efforts to cause the engineering firm or firms used to determine the new purchase price to complete its/their work product and render a final opinion on or before July 1, 2014. Seller and Buyer shall each bear one-half of the fees and costs for the engineering firm(s). If the purchase price has not been agreed upon by July 1, 2014, the parties shall continue to use the per ton Purchase Price from coal delivered during June 2014 until the new purchase price is finally determined, at which point Seller shall issue an invoice or credit truing up the difference between the invoiced price and the ultimately agreed upon or determined new purchase price. (vi) Once the new purchase price per ton for coal delivered during July 2014 has been finally determined in accordance with this subsection (b), the parties shall also promptly agree on the portion of such new purchase price that constitutes Government Impositions and on the allocation of the remaining portion of the new purchase price (the 11
"Netback Portion" which shall also be the new Base Price effective July 1, 2014) amongst the several components described in Section 11. Section 11 below shall also be deemed amended to bring forward to dates in 2014 reasonably comparable to the dates in 2000 the base values of the respective indices from which future escalation/de-escalation shall be measured, and to make Section 11 as so revised applicable to adjustments to the Netback Portion from July 1, 2014 through December 31, 2022 (subject to further revision as set forth in subsection (c) (vi) below). If the parties are unable to agree on the portion of the new purchase price that constitutes Government Impositions or on the allocations or base values for escalating/de-escalating the Netback Portion, then either party may at any time after October 1, 2014 invoke the arbitration procedure described in Section 24 below to determine the portion of the new purchase price that constitutes Government Impositions or the allocations or base values for escalating/de-escalating the Netback Portion. (vii) The Purchase Price for coal delivered after July 2014 and prior to July 1, 2019 shall be the sum of (i) the Netback Portion, plus or minus (ii) the adjustments provided in the revised Section 11 applicable to such delivery, plus (iii) the Government Impositions determined in accordance with Section 12 applicable to such delivery. The Purchase Price so determined is based on coal having a BTU content of 8,000 BTU per pound and shall be further subject to adjustment for BTU variations as provided in Section 13. (c) Either Seller or Buyer shall have the right, exercisable by written notice delivered to the parties on or before January 1, 2019, to renegotiate the Purchase Price effective July 1, 2019. If neither Seller nor Buyer exercises this right, then the Purchase Price shall be as specified for June 2019 without regard to this subsection (c) and with continued escalation/de-escalation pursuant to Section 11 (as amended in 2014 pursuant to subsection (b) above) and continued adjustments pursuant to Sections 12 and 13. If either Seller or Buyer exercises this right, then the Purchase Price per ton of coal to be paid by Buyer to Seller for each ton of coal delivered under this Agreement from July 1, 2019 through December 31, 2022, shall be determined by the parties as follows: (i) The Purchase Price for each ton of coal delivered under this Agreement in July 2019 shall equal the product of (A) the sum of (1) the 8400 BTU PRB 2019 Market Price (as hereinafter defined), (2) the Transportation 2019 Market Price (as hereinafter defined) and (3) the Levelized Fixed Charge (as defined above), and (B) a fraction, the numerator of which is 8,000 and the denominator of which is 8,400. The Purchase Price so determined is based on coal having a BTU content of 8,000 BTU per pound and shall be further subject to adjustment for BTU variations as provided in Section 13. (ii) The 8400 BTU PRB 2019 Market Price shall equal the average spot coal price (FOB loaded into railcars at the mine) for 8400 BTU per pound coal sold from mines located in the Powder River Basin in Wyoming during the 12 months ending March 31, 2019, as reported in COAL DAILY. If COAL DAILY has ceased publication or ceases to publish spot market price data on a monthly or more frequent basis, the parties shall substitute such publication as may exist in March 2019 that most accurately reports the spot market price for such coal. If no such publication exists, the parties shall negotiate in good faith to determine such average market price, and if such negotiation does not produce agreement on such average market price by June 12
1, 2019, either Seller or Buyer may on or before July 1, 2019, invoke the arbitration procedure described in Section 24 below to determine the average spot market coal price (FOB loaded into railcars at the mine) for 8400 BTU per pound coal sold from mines located in the Powder River Basin in Wyoming during the 12 months ending March 31, 2019. Notwithstanding the foregoing, if COAL DAILY (or another comparable publication similar in standing in the coal industry) publishes a market price index for 8400 BTU Wyoming PRB coal sold on a 1-year or longer contract basis (FOB loaded into railcars at the mine) for contracts incepted during the 24 months ending March 31, 2019, and having escalation/de-escalation provisions reasonably comparable to those contained in Section 11 and other terms and conditions reasonably comparable to those set forth in this Agreement, the 8400 BTU PRB Market Price shall equal the average contract price for such 8400 BTU coal as set forth in such index during the 24-month period ended March 31, 2019. (iii) The Transportation 2019 Market Price shall equal the average per ton market price for the transportation of coal at the rate of approximately 36,000 tons per week by rail commencing on July 1, 2019, in railroad supplied railcars from the two Powder River Basin mines (other than the Coal Reserves) in closest proximity to the Facility that then produce coal having a quality reasonably comparable to the quality of coal produced by the mines in the Powder River Basin that produce the coal the market price of which is reflected in the index used in clause (ii). The parties shall designate a mutually acceptable engineering firm on or before April 1, 2019 to perform the analysis and determination of the Transportation Market Price. If the parties are unable to agree on the engineering firm by April 1, 2019, or if any party disagrees with the determination made by the engineering firm within 30 days after the final determination by such firm of the Transportation Market Price, then either party may on or before October 1, 2019, invoke the arbitration procedure described in Section 24 below to determine the Transportation 2019 Market Price. (iv) The Levelized Fixed Charge shall be the same as the Levelized Fixed Charge determined in accordance with subsection (b)(iv) above, subject to the following adjustment. In the event of a change in law or regulation or interpretation of law or regulation after July 1, 2014 and before June 30, 2019, and the effect of that change is to increase or decrease the capital cost of the rail unloading facility or the annual operating cost of the facility above or below the levels specified in subsection (b)(iv) by more than 10% on a levelized basis, then the Levelized Fixed Charge shall be adjusted to reflect such increase or decrease, computed on the same basis as set forth in subsection (b)(iv) with a change in the assumed inflation rate to equal the average of the annual change (on a calendar year basis) in the index referenced in Section 11(c) for the three consecutive calendar years beginning January 1, 2016 and ending December 31, 2018. If the parties are unable to agree on whether a change in law or regulation or interpretation of law or regulation has occurred or on the adjustment to the Levelized Fixed Charge resulting therefrom, then either party may on or before October 1, 2019, invoke the arbitration procedure described in Section 24 below to determine the adjustment, if any, to the Levelized Fixed Charge. (v) The parties shall use their respective best efforts to cause the engineering firm or firms used to determine the new purchase price to complete its/their work product and render a final opinion on or before July 1, 2019. Seller and Buyer shall each bear one-half of the 13
fees and costs for the engineering firm(s). If the purchase price has not been agreed upon by July 1, 2019, the parties shall continue to use the per ton Purchase Price from coal delivered during June 2019 until the new purchase price is finally determined, at which point Seller shall issue an invoice or credit truing up the difference between the invoiced price and the ultimately agreed upon or determined new purchase price. (vi) Once the new purchase price per ton for coal delivered during July 2019 has been finally determined in accordance with this subsection (c), the parties shall also promptly agree on the portion of such new purchase price that constitutes Government Impositions and on the allocation of the remaining portion of the new purchase price (the "2019 Netback Portion" which 2019 Netback Portion shall also be the new Base Price effective July 1, 2019) amongst the several components described in Section 11. Section 11 below shall also be deemed amended to bring forward to dates in 2019 reasonably comparable to the dates in 2000 the base values of the respective indices from which future escalation/de-escalation shall be measured, and to make Section 11 as so revised applicable to adjustments to the 2019 Netback Portion from July 1, 2019 through December 31, 2022. If the parties are unable to agree on the portion of the new purchase price that constitutes Government Impositions or on the allocations or base values for escalating/de-escalating the 2019 Netback Portion, then either party may at any time after October 1, 2019 invoke the arbitration procedure described in Section 24 below to determine the portion of the new purchase price that constitutes Government Impositions or the allocations or base values for escalating/de-escalating the 2019 Netback Portion. (vii) The Purchase Price for coal delivered hereunder after July 2019 shall be the sum of (i) the 2019 Netback Portion, plus or minus (ii) the adjustments provided in the revised Section 11 applicable to such delivery, plus (iii) the Government Impositions determined in accordance with Section 12 applicable to such delivery. The Purchase Price so determined is based on coal having a BTU content of 8,000 BTU per pound and shall be further subject to adjustment for BTU variations as provided in Section 13. SECTION 11. PRICE ADJUSTMENTS. Following the first full month occurring after the initial 1,160,000 tons of coal have been delivered hereunder, the Base Price shall be subject to adjustment each calendar month through June 30, 2014 (and thereafter through December 31, 2022, as provided in Subsections 10 (b) (vi) and 10 (c) (vi) above), based on the following: (a) LABOR INDEX COMPONENT. The Base Price shall be adjusted monthly on the first day of each calendar month to cover changes in labor costs by an amount determined by multiplying 140.0 cents per ton by the percentage change in the Average Hourly Earnings Index EEU10122006 published by the United States Bureau of Labor Statistics from the Base Value of such index (the term "Base Value" being defined in Subsection (d) (i) of this Section 11). (b) MATERIALS AND SUPPLIES. The Base Price shall be adjusted monthly on the first day of each calendar month to cover changes in the costs of materials and supplies: 14
(i) TIRES. The Base Price shall be adjusted by an amount determined by multiplying 8.0 cents per ton by the percentage change in the Producer Price Index, Rubber and Rubber Products, BLS WPU071, published by the United States Bureau of Labor Statistics from the Base Value of such index. (ii) FUEL. The Base Price shall be adjusted by an amount determined by multiplying 25.0 cents per ton by the percentage change in the Producer Price Index, Fuel #2 Diesel, Direct Sales to End Users, BLS PCU2911#4132, published by the United States Bureau of Labor Statistics from the Base Value of such index. (iii) CAPITAL. The Base Price shall be adjusted by an amount determined by multiplying 80.0 cents per ton by the percentage change in the Producer Price Index, Construction Machinery and Equipment, BLS WPU112, published by the United States Bureau of Labor Statistics from the Base Value of such index. (iv) EXPLOSIVES. The Base Price shall be adjusted by an amount determined by multiplying 17.0 cents per ton by the percentage change in the Producer Price Index, Chemicals and Allied Products, BLS WPU067, published by the United States Bureau of Labor Statistics from the Base Value of such index. (v) POWER. The Base Price shall be adjusted by an amount determined by multiplying 28.0 cents per ton by the percentage change in the Producer Price Index, Power-Mtn Region, BLS PCU4981#13831, published by the United States Bureau of Labor Statistics for the month then ended from the Base Value of such index. (vi) MATERIALS AND SUPPLIES-MISC. The Base Price shall be adjusted by an amount determined by multiplying 47.0 cents per ton by the percentage change in the Producer Price Index, Mining Machinery Parts, BLS WPU11925301, published by the United States Bureau of Labor Statistics from the Base Value of such index. (c) UNDIFFERENTIATED CAPITAL, RETURN AND PROFIT. The Base Price shall be adjusted quarterly on the first day of each calendar quarter to cover the effects of inflation/deflation on Seller's capital costs, return and profit by an amount determined by multiplying 275.7 cents per ton by the percentage change in the Gross Domestic Product Implicit Price Deflator published by the United States Department of Commerce, Bureau of Economic Analysis from the Base Value of such index. (d) INDEX ADJUSTMENTS. The following procedures shall be used to calculate adjustments to the Base Price based on changes in published indices: 15
(i) Base values ("Base Values") used for determining adjustments to the Base Price in any month shall, in the case of indices published monthly, be the published value for the month that is two months in advance of the first month that the Base Price was subject to adjustment and in the case of indices published quarterly, the index value for the quarter that is two quarters in advance of the first month that the Base Price was subject to adjustment. Index values which are compared to Base Values used for determining adjustments to the Base Price in any month shall, in the case of indices published monthly, be the latest published values for the second preceding month, and in the case of indices published quarterly, be the latest published values for the second preceding quarter (ie., the December 2001 index value is to be used for the February 2002 adjustment for monthly indices, and the December 31, 2001 index value is to be used for the April 2002 adjustment for quarterly indices). (ii) If any of the foregoing indices or any revision or equivalent ceases to be published by any federal agency, such indices shall be replaced by a substantially equivalent index that, after necessary adjustment, if any, provides the most reasonable substitute for such index and which is mutually agreeable to the parties. (iii) All calculations of individual adjustments to the Base Price shall be rounded to the nearest mill or, if there is no nearest mill, to the nearest cent. SECTION 12. GOVERNMENT IMPOSITIONS. The Purchase Price for the first 1,160,000 tons of coal sold hereunder includes an estimated $3.973 representing the following governmental taxes, fees, royalties, costs and impositions (collectively, "Government Impositions"): GOVERNMENT IMPOSITION EST. COST PER TON ON 1/1/01 Property Tax $0.063 Black Lung Tax $0.527 Reclamation Fee $0.350 Royalties $1.618 Severance Tax $0.762 Extraction Tax $0.653 The Purchase Price for all coal sold hereunder after the first 1,160,000 tons of coal have been sold hereunder, includes an estimated $3.063 representing the following governmental taxes, fees, royalties, costs and impositions (collectively, "Government Impositions"): GOVERNMENT IMPOSITION EST. COST PER TON ON OR ABOUT 9/1/01 Property Tax $0.063 Black Lung Tax $0.391 Reclamation Fee $0.350 Royalties $1.215 Severance Tax $0.564 Extraction Tax $0.483 16
(a) ITEMS SUBJECT TO REIMBURSEMENT AS GOVERNMENT IMPOSITIONS. Buyer shall reimburse Seller, as provided in this Section 12, for only the following Government Impositions: (i) TAXES. Buyer shall reimburse Seller only for those federal, state and local taxes paid by Seller which are imposed directly on, or measured by (or in the case of property tax or future taxes similarly levied, are properly allocated to) the coal being sold and delivered to Buyer pursuant to this Agreement, or upon the mining, ownership, possession, sale and delivery of such coal to the Buyer. These taxes may include, but are not limited to, property taxes, taxes on coal production, extraction and severance, (including without limitation any severance or extraction tax measured in whole or in part by the value of coal sold to Buyer plus any value added as mandated by law), ad valorem taxes whether on coal mined or in place, personal property taxes, black lung taxes, sales taxes, transfer taxes, excise taxes and occupation taxes. Property Taxes payable by Seller shall be allocated on a per ton basis pro rata to all tons of coal sold by Seller from the Coal Reserves during the period covered by the tax charge. Buyer shall not be responsible for any other taxes paid by or imposed upon Seller, including, but not limited to, those taxes levied or measured by, in whole or in part, net income, capital or retained earnings, and any business privilege, business activity, general franchise or other similar taxes imposed on Seller's general business activity in the jurisdiction that seeks to impose the tax. For purposes of determining Taxes in which a transportation or other deduction is allowed or certain mining costs are excluded, the Taxes shall be computed each period based on the specific deduction or exclusion for all tons delivered by Seller to Buyer pursuant to this Agreement from the Coal Reserves during that period. (ii) FEDERAL RECLAMATION FEE. Buyer shall reimburse Seller for the Abandoned Mine Reclamation Fee actually attributable to tons of coal sold to Buyer pursuant to this Agreement. The Abandoned Mine Reclamation Fee is assessed by the United States as $0.35 per ton as of January 1, 2001, less an allowed moisture credit. If the fee is ever levied on or measured by, in whole or in part, the purchase price of coal delivered hereunder, then Buyer shall pay Seller an amount that is equal to the applicable statutory rate of such fee multiplied by the value or the purchase price, as applicable, of the coal actually sold hereunder during the subject period, after taking into account all applicable exclusions, deductions, credits or other reductions authorized by law. No adjustment to the Base Price shall be made to recover final reclamation costs except for changes in such costs resulting from changes in law after January 1, 2001 which are to be reimbursed pursuant to subsection (iv) below. (iii) ROYALTIES. Buyer shall reimburse Seller for the per ton royalties actually incurred by Seller on the portion of the Coal Reserves consisting of United States Leases and directly attributable to the sale by Seller of coal to Buyer under this Agreement. The royalty rate as of January 1, 2001 is 12.5% of the Purchase Price, plus any additional value added as mandated by law, minus any allowable deductions. In addition, if Seller mines coal from the State Lease for sale to Buyer hereunder, Buyer shall reimburse Seller for royalties on the portion of the Coal Reserves consisting of the State Lease as though the royalty on the State Lease was equal to the then average royalty rate on United States Leases. In no event shall Seller seek reimbursement from Buyer for any overriding royalty, rental, bonus payment or other 17
comparable payment paid to any third party for the right to mine coal from, or arising as a result of mining coal from, any of the Coal Reserves. (iv) OTHER GOVERNMENT IMPOSITIONS. Whenever any federal, state or local laws, rules, regulations or requirements, whether due to change in, additions to or difference of interpretation or enforcement by any governmental authority of existing laws, rules, regulations or requirements after January 1, 2001 (a "New Government Imposition"), should cause an increase or decrease in the cost to Seller of mining coal in compliance with such laws, rules, regulations or requirements, Buyer shall reimburse Seller (in the case of an increase) or Seller shall issue a credit to Buyer (in the case of a decrease) for the actual additional cost (or savings) per ton of coal to Seller on account thereof. With respect to a New Government Imposition effective prior to January 1, 2014, payment for these additional costs shall be made on an accrual basis so that payment is made at the time Seller incurs the obligation even though Seller may not fulfill the obligation until some time later. With respect to a New Government Imposition effective after December 31, 2013, any such adjustment shall be effective from the date Seller is required to accrue the additional cost under GAAP. In no event shall this subsection (iv) be applied in such a fashion as to result in double recovery by Seller of any such costs. Seller shall use its best efforts to minimize or eliminate any cost that would otherwise be recoverable under this subsection (iv). To the extent a prudent miner operating the Mine in a competitive market would comply with the New Government Imposition by using its own labor and equipment, Seller shall utilize its labor and equipment to fulfill the New Government Imposition mandate and Buyer shall reimburse Seller for Buyer's pro rata portion of the actual cost of such labor and equipment (net of any cost savings or benefit received by Seller as a result of complying with such New Government Imposition mandate). To the extent a prudent miner operating the Mine in a competitive market would modify its mine plan to reduce the cost of complying with the New Government Imposition mandate, Seller shall take all reasonable steps to minimize costs by so modifying the mine plan for the Mine. The parties agree that Buyer shall reimburse Seller for all costs, expense and reasonable attorneys fees relating to legal or regulatory proceedings based upon the first audit, with respect to coal delivered hereunder, by any responsible agency after January 1, 2001, of each of the Government Impositions set forth in the beginning of SECTION 12. Buyer shall be notified of all hearings or other proceedings, including settlement negotiations and at its own expense, shall be entitled to have its legal representative present at all proceedings in a non-participating role. Seller shall consult, however, with legal representatives of Buyer. Buyer's privilege to attend regulatory proceedings shall not authorize Buyer to receive, or gain access to, Seller's privileged attorney-client communications or attorney work product. In the event Seller deems any business information confidential and proprietary and the disclosure thereof to Buyer a potential harm to Seller, Buyer shall upon request from Seller and as a condition to receipt of such information, execute a commercially reasonable form of confidentiality agreement covering such information, and limiting the use of such information to the applicable proceeding, and dissemination within Buyer to those employees of Buyer with a need to know and those consultant's, attorneys or accountants of Buyer who are assisting Buyer in such proceedings. Buyer agrees that at the close of such proceedings, all confidential and proprietary information, including all copies thereof, shall be returned to Seller. 18
(b) PARTIES' INTENT; LIMITATION. It is the parties' intent that the Buyer reimburse Seller for all of the Government Impositions actually attributable to coal sold to Buyer under this Agreement, and in an amount that reflects no duplication and is not greater than the amount actually paid by Seller to the governmental authorities or incurred by Seller (as a proper accrual in accordance with prudent mining practices) as a result thereof. It is also the parties' intent that, with respect to Government Impositions that are levied on or measured by the purchase price of coal, Buyer shall reimburse Seller for the actual amount of Government Imposition attributable to coal sold to Buyer under this Agreement without regard to revenues received by Seller from sales to other customers of coal mined from the Coal Reserves. (c) ESTIMATES AND TRUE-UPS OF GOVERNMENT IMPOSITIONS. The parties recognize that at the time each monthly invoice for coal is prepared, it may not be possible for Seller to calculate definitively the Government Impositions actually attributable to coal sold during such calendar month. Each monthly invoice will, therefore, be based on the most current data reasonably available to Seller at the time of invoicing. Within a reasonable time after receipt of information permitting determination of actual Government Impositions attributable to coal sold to Buyer in any such calendar month, Seller shall prepare and furnish to Buyer a hard copy of a supplemental invoice sent by overnight delivery reflecting a true-up of the actual against the estimate used in preparing the original invoice. SECTION 13. PRICE ADJUSTMENTS-CALORIFIC QUALITY. For coal delivered in each month hereunder, the Base Price, adjusted pursuant to the application of Sections 10 and 11 shall be further adjusted monthly for calorific quality by multiplying the Base Price by a fraction, the numerator of which is the actual weighted average BTU per pound of coal delivered (as determined in Section 9) for the period for which the calculation is being made, and the denominator of which is 8000. SECTION 14. SPECIAL ONE-TIME PAYMENT. On or before September 1, 2001, Buyer shall pay Seller a one-time payment of $7,374,000. Seller shall be responsible for any Government Impositions measured by or levied with respect to such one-time payment by Buyer. This provision shall in no event be deemed to affect either party's right to make any claim with respect to the Prior Agreements if such claim is allowable under the terms of the Settlement Agreement. SECTION 15. SHORTFALL PAYMENT. (a) For any year during the Term in which no planned outage is contemplated (as of April 1 of such year) by Buyer for the Facility, Buyer shall pay a Short-Fall Payment if it purchases fewer than 1,500,000 tons of coal for its own account. For any year during the Term in which a planned outage is contemplated (as of April 1 of such year) by the Buyer for the Facility, Buyer shall pay a Short-Fall Payment if it purchases fewer tons than either (i) for any calendar year ending on or before December 31, 2013, the greater of 1,280,000 tons, or the amount determined by multiplying 1,500,000 by a fraction, the numerator of which equals 365 minus the number of days of the planned outage, and the denominator of which equals 365, or 19
(ii) for any calendar year commencing on or after January 1, 2014, the amount determined by multiplying 1,500,000 by a fraction, the numerator of which equals 365 minus the number of days of the planned outage, and the denominator of which equals 365. This Short-Fall Payment shall be equal to the result of the following equation: (MT - P) (B - C) Where: MT = 1,500,000 tons if there is no planned outage, or the lesser tonnage specified above if there is a planned outage contemplated by Buyer for the Facility as of April 1 of the year in question; P = number of tons purchased by Buyer during the year; B = the Purchase Price as of the date of payment of the Short-Fall Payment; and C = per ton costs for Government Impositions as of the payment of the Short-Fall Payment that Seller need not pay until coal is mined. (b) Buyer shall be excused from paying the Short-Fall Payment for any calendar year if failure to purchase the minimum tons of coal for its account was caused by a partial or total suspension of deliveries pursuant to Section 22, provided that the effect of such uncontrollable force is eliminated insofar as possible with all reasonable dispatch. Notwithstanding the foregoing, until June 8, 2013, Buyer's lack of need for the power generated by the Facility or its inability to economically market the power generated by the Facility, shall not be considered an uncontrollable force under Section 22. (c) If Buyer incurs a Short-Fall Payment, during any subsequent year in which Buyer's purchases exceed 1,500,000 tons, Seller shall afford Buyer a dollar-for-dollar credit for any previously paid Short-Fall Payment, against amounts otherwise owing by Buyer for its annual purchases in excess of 1,500,000 tons. Any accrued Short-Fall Payments existing at the end of the Term, for which credit has not been given, shall be forfeited by Buyer. (d) Any Short-Fall Payment owing shall be paid no later than January 31 of the year following the year giving rise to it. (e) For purposes of this Section 15, whether a planned outage is contemplated (as of April 1 of any year) by the Buyer for the Facility, shall be determined based on prudent utility practice. (f) If Buyer has reason to believe it will incur a Short-Fall Payment for any year, or if Buyer actually incurs a Short-Fall Payment for such year, Buyer shall have the right, upon reasonable prior notice to Seller, to divert coal purchased hereunder to other generation facilities owned or controlled by Buyer or any affiliate of Buyer until such time as the Short-Fall Payment 20
has been eliminated or recouped in accordance with the provisions of this Section 15. At Buyer's request with respect to any such coal, Seller shall deliver the coal to Buyer at the Clovis Point loadout facility (for railcars) or the Mine's truck loadout (for trucks), and Buyer shall reimburse Seller for any incremental cost incurred by Seller in delivering the coal to the alternate delivery point and loading it into Buyer supplied railcars or trucks, net of any cost savings Seller incurs by delivering the coal to the alternate delivery point and not having to transport the coal from the face of the Mine to the place of delivery specified in Section 5. SECTION 16. INVOICES AND PAYMENTS. (a) Seller shall invoice Buyer by delivering a hard copy invoice to Buyer by the fifth day of each month for (i) the coal ordered to be delivered for that calendar month per Section 3 at an amount estimated under the provisions of Sections 10, 11, 12 and 13 together with (ii) an adjustment, credit or debit, for actual coal sold the previous calendar month based upon the actual Purchase Price for that month (including adjustments contemplated in Sections 12 and 13, if any, for prior months' coal deliveries). For the purposes of determining the estimated price for the current month in (i) above, Seller shall use the actual Purchase Price for the prior month as described in (ii). Buyer shall pay each invoice to Seller by the fifteenth day after receipt of a hard copy of the invoice. In the event Buyer fails to pay the undisputed portion of any invoice when due, or in the event Seller fails to issue an undisputed credit to Buyer in a timely manner, then Buyer or Seller, as the case may be, shall pay interest on the undisputed amount until paid/credited at a per annum rate equal to the from time to time "prime rate" as published in THE WALL STREET JOURNAL plus two percent. (b) It is understood that some costs which are to be included in the Government Impositions portion of the Purchase Price may not be known or determinable on the date billings are made for the coal for which such costs are incurred; and in that event retroactive adjustments and appropriate billings and credit statements shall be made at such time that such costs become known and determinable. If Seller fails to make an adjustment in billings or notify Buyer in writing of the potential for an adjustment in billings related to Government Impositions within two years from the date information is reasonably available to Seller to fully determine the actual amount of the adjustment, Seller shall be barred from making that adjustment. If Buyer fails to protest to Seller in writing within two years of a date when information is reasonably available to Buyer to determine that an adjustment included in a billing received prior to that date is incorrect, Buyer shall be barred from contesting that adjustment even if the adjustment was incorrect. (c) If at any time Buyer desires to receive assurances of the accuracy of Seller's records affecting the price adjustments provided for herein, Buyer may request Seller to authorize a nationally recognized independent certified public accounting firm doing Seller's auditing work at the time of the request to audit Seller's records and certify the accuracy to Buyer of certain information so requested. If Seller does not have a nationally recognized accounting firm retained at the time of the request, a nationally recognized accounting firm shall be selected upon mutual agreement of the parties hereto. The information requested must be relevant to the amount of any price adjustment herein. The accounting firm's charges for any work requested of it under this provision shall be paid by Buyer. Notwithstanding the foregoing, 21
not more often than once in each calendar year, Buyer shall have the right to examine and audit Seller's records with respect to all price adjustments made or required to be made pursuant to Sections 10, 11, 12 and 13. SECTION 17. NO RESTRICTION ON COAL RESERVES OTHER THAN DEDICATED RESERVES. This Agreement shall not restrict Seller from mining, selling, using, committing, dedicating, mortgaging or encumbering in any manner the Coal Reserves other than the Dedicated Reserves for any purpose. SECTION 18. INSPECTION. Each party shall at all reasonable times have the right to enter upon the premises of the other to inspect the coal receiving equipment and the weighing, measuring and testing facilities. Buyer shall at all reasonable times have the right to inspect the Mine, maps and operating records of Seller relating to the operation of the Mine. SECTION 19. NORTH CONVEYOR SYSTEM. Seller is the owner and operator of the North Conveyor System, which is defined as the truck hopper, the primary crusher conveyor linking the primary crusher to the secondary crusher, the secondary crusher and all related facilities being located in the north pit of the Mine. (a) During the Term, Seller shall make the North Conveyor System available to Buyer as a backup, standby system for the delivery of coal to the Facility in common with the Seller's use of the North Conveyor System for its own purpose. (b) As long as Seller owns the North Conveyor System, all operations and maintenance expenses of the North Conveyor System and capital additions and replacements shall be borne 57.6% by Buyer and 42.4% by Seller commencing January 1, 1978; provided, however, capital additions or replacements to such System made by Seller without the prior written consent of Buyer shall be borne by Seller; and further provided that all costs of operation and maintenance shall be bone by Seller during such period that the North Conveyor system is used exclusively by Seller. (c) Seller reserves the right to dismantle and dispose of or abandon the North Conveyor System at any time, but in such event, Seller shall give written notice of such intent to Buyer. Within 60 days of receipt of such notice, Buyer shall have the option to purchase the North Conveyor System for a consideration to be determined by mutual agreement of the parties or, absent such agreement, by appraisers mutually selected by the parties. In the event Buyer exercises the option to purchase the North conveyor System by giving written notice thereof to Seller during said 60-day period, Seller shall convey the North Conveyor System to Buyer upon payment by Buyer to Seller of the agreed upon or appraised price. If such option is not exercised within the 60-day period, Buyer shall have no further right or interest in the North Conveyor System. 22
SECTION 20. ASH DISPOSAL. Seller shall furnish a site without improvements on Seller's property at its Mine for the disposal of fly ash and bottom ash from the Facility during the Term at no additional cost to Buyer but subject to the terms and conditions set forth in that certain Amended and Restated Waste Disposal Agreement for Wyodak Unit No. 1 and the Neil Simpson Plant dated as of June 15, 1995, among Seller, Buyer and Black Hills Corporation. Seller reserves the right from time to time to designate and to change the designation of the particular location and method for such disposal so that the disposal of such ash will conform to Seller's mining and reclamation program. Seller shall furnish Buyer reasonable access to and from the disposal sites, but shall not be required to provide road maintenance. Seller shall not be responsible for the cost of transporting such ash from the Facility to the site designated from time to time for disposal. SECTION 21. INTENTIONALLY OMITTED. SECTION 22. UNCONTROLLABLE FORCE. If, because of uncontrollable force, either party hereto is unable to carry out any part or all of its obligations under this Agreement, and if such party promptly gives to the other party hereof notice of such uncontrollable force, then the obligations of the party giving such notice shall be suspended to the extent made necessary by such uncontrollable force and during its continuance, provided the effect of such uncontrollable force is eliminated insofar as possible with all reasonable dispatch. The term "uncontrollable force" as used herein shall mean any cause beyond the control of the party and which, by the exercise of reasonable diligence, the party is unable to overcome and shall include but not be limited to acts of God, acts of the public enemy, insurrection, riot, strike, labor dispute, labor or material shortage, fire, explosion, flood, breakdown of or damage to a plant, equipment or facilities, interruption of transportation, embargo, orders or injunctions of a federal, state or local court, agency or governmental body having jurisdiction, acts of civil or military authority, failure of equipment, or inability to obtain materials, supplies, or equipment from others because of similar causes. It shall be considered an uncontrollable force and shall relieve Seller from performing its obligations under this Agreement if valid state or federal legislation is enacted which prohibits the strip mining of the federal coal which has been leased by Seller. SECTION 23. BUYER'S RIGHTS TO MINE COAL FROM DEDICATED RESERVES DURING PERIOD OF UNCONTROLLABLE FORCE. During any time and from time to time that Seller is not delivering coal as required by this Agreement due to uncontrollable force as provided in Section 22, Buyer shall have the right, after giving Seller at least two months' notice of their intent to do so, to mine coal for the Facility from the Dedicated Reserves (or, upon mutual agreement of the parties, other Coal Reserves in closer proximity to or at the face of the existing Mine works). The exercise of such right shall be subject to obtaining all necessary governmental approvals therefor, and any such mining shall be conducted in conformance with all governmental laws and regulations applicable thereto. Buyer shall pay Seller the Purchase Price for the coal mined by Buyer under this Section less the actual costs incurred by Buyer in obtaining the right to and in mining and delivering such coal 23
including all Government Impositions due as a result of such mining. Subject to Buyer incurring all of the expense thereof, Seller shall use its best efforts to assist Buyer to obtain such governmental approvals as it may need for the exercise of its rights under this Section 23. Buyer shall assume all obligations to pay all costs relating to such mining of the Dedicated Reserves which may exceed the Purchase Price. The rights granted in this Section shall terminate at such time that Seller has restored the deliveries of coal in the fulfillment of this Agreement. SECTION 24. DISPUTE RESOLUTION. If any dispute arises under this Agreement, such dispute shall be resolved pursuant to the provisions of this paragraph 24. a. The parties shall meet through authorized officers (or representatives with full authority to resolve issues on behalf of the parties) of the companies in a good faith attempt to resolve the dispute. Prior to such meeting, the parties shall prepare short summaries of their respective positions with respect to each of the disputes, which summaries shall be exchanged with the other parties not less than 48 hours prior to the meeting. With respect to any unresolved dispute that remains after this first meeting, the parties agree that officers of the respective companies shall meet in person within 15 days after the first meeting in an effort to resolve the remaining disputes; and if, after the meeting among the officers of the respective parties has occurred, there remain outstanding any unresolved disputes, each party shall prepare a short summary of each remaining claim (the "Submitted Issues") for submission to binding arbitration pursuant to subparagraph (b) hereof. b. Within 10 days after the determination that the parties are unable to resolve any of the Submitted Issues pursuant to subparagraph (a) above, the parties shall jointly select an independent, third-party to act as arbitrator for the Submitted Issues. The arbitrator shall be a certified public accountant, mining engineer or other qualified professional with nationally recognized expertise in matters relevant to the resolution of the Submitted Issues and shall have no past or current relationship with any of the parties hereto including any affiliates of such parties (the "Arbitrator"). If the parties are unable to agree on the selection of the Arbitrator, then the Arbitrator shall be selected by the American Arbitration Association, using the criteria set forth herein. (i) Within 10 days after selection of the Arbitrator, Seller and Buyer shall each submit to the Arbitrator a written position statement with respect to each of the Submitted Issues. Such statements shall include a short summary of the party's position along with a statement of such party's last best offer with respect to the issue of the required adjustment. Any applicable accounting guidelines or other materials may be included with the submission. The Arbitrator may thereafter decide whether a meeting will be called in which each party may present orally the position stated in its submission and the Arbitrator may make such inquiries as he or she deems appropriate. Any such meeting shall be held, if at all, in Denver, Colorado within 20 days of the submission of the materials to the Arbitrator. (ii) Thereafter, within 15 days of the meeting (or, if no meeting is called by the Arbitrator, within 30 days after the submission of the materials to the Arbitrator), the Arbitrator shall issue his or her award. The award shall set forth the resolution of each of the Submitted 24
Issues, it being understood that the Arbitrator shall select either the last best offer made by Seller or the last best offer made by Buyer with respect to a particular Submitted Issue and that the Arbitrator shall have no discretion to award any other relief. The Arbitrator shall resolve each of the Submitted Issues separately and shall issue a written award (the "Award"). (iii) The Award issued by the Arbitrator shall be final and binding upon the parties with respect to the Submitted Issues unless the Arbitrator fails to comply with the requirement to select a last best offer as required by subsection (b)(ii). If the Arbitrator fails to select a last best offer submitted by one of the parties, then any award entered shall be invalid and the matter shall be resubmitted to arbitration. All such amounts shall be either credited against or for the account of Buyer or Seller as the case may be. The fees and expenses of the Arbitrator shall be divided equally between Seller and Buyer. Any other fees and costs shall be the responsibility of the party incurring them. SECTION 25. NOTICES. Unless otherwise expressly provided herein, all notices required to be given by the provisions of this Agreement shall be deemed to be duly served if given in writing sent by United States mail, postage prepaid, or by telecopy or other electronic mail media and to the addresses set forth below: If to Seller: Mailing Address: Wyodak Resources Development Corp. P.O. Box 1400 Rapid City, SD 57709 Street Address: 625 9th Street Rapid City, SD 57701 Attn: David R. Emery Vice President-Fuel Resources Phone Number: (605) 721-1700 Fax Number: (605) 721-2549 If to Buyer: PacifiCorp 201 S. Main Street, Suite 2100 Salt Lake City, Utah 84140-0021 Attn: Neil L. Getzelman General Manager - Fuel Resources Phone Number: (801) 220-4608 Fax Number: (801) 220-4578 SECTION 26. APPLICABLE LAW. 25
This Agreement shall be considered to have been entered into and shall be interpreted under the laws of the State of Wyoming. SECTION 27. AMENDMENT. No provision of this Agreement may be amended, modified, supplemented or waived except by an instrument in writing signed by Seller and Buyer. SECTION 28. SUCCESSORS AND ASSIGNS. This Agreement and all the terms and provisions hereof shall be binding upon and inure to the benefit of the respective successors and assigns of the parties hereto. This Agreement and any interests, rights or obligations under this Agreement may not be assigned by any party without the prior written consent of the other parties, which consent shall not be unreasonably withheld or delayed. SECTION 29. COMPLETE AGREEMENT. Except as expressly set forth in the Settlement Agreement, this Agreement supersedes and cancels the Prior Agreement and constitutes the complete agreement of the parties. SECTION 30. EXECUTION IN COUNTERPARTS. This Agreement may be executed by the parties hereto on separate counterparts, each of which when so executed and delivered shall be an original, but all such counterparts shall together constitute but one and the same instrument. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective officers thereunto duly authorized as of the date first above written. WYODAK RESOURCES DEVELOPMENT CORP. By /s/ DAVID R. EMERY -------------------------------- Attest: /S/ STEVEN J. HELMERS - ------------------------- (Corporate Sea1) PACIFICORP By /s/ TERRY F. HUTCHINSON -------------------------------- Attest: /S/ ILLEGIBLE - ------------------------- (Corporate Sea1) 26
The undersigned hereby consents to the termination of the Prior Agreements as to Seller and Buyer as set forth herein and in the Settlement Agreement referenced herein. BLACK HILLS POWER, INC. By /s/ THOMAS M. OLMACHER -------------------------------- Attest: /S/ STEPHEN J. HELMERS - ------------------------- (Corporate Sea1) All annexes to the new restated and amended coal supply agreement are omitted from this Exhibit 10.4. These annexes provide details of coal leases, surface rights, access easements, point of delivery drawings, sample calculations and a reserve plat and are immaterial to an investment decision. The Registrant will furnish supplementally a copy of any omitted annex to the Commission upon request. 27
EXHIBIT 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the use of our report and to all references to our Firm included in or made a part of this registration statement. Arthur Andersen LLP Minneapolis, Minnesota, April 13, 2001
EXHIBIT 23.1 (CONTINUED) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the inclusion in this registration statement of Black Hills Corporation on Form S-1 of our following reports: Report dated February 11, 2000 (except for Note 5, as to which the date is February 28, 2000), on our audit of the consolidated financial statements of EIF Management Holdings, LLC and its subsidiaries as of and for the year ended December 31, 1999; Report dated February 11, 2000, on our audit of the financial statements of EIF Group Management Company as of and for the years ended December 31, 1999 and 1998; Report dated April 21, 2000, on our audit of the financial statements of Project Finance Partners, L.P. as of and for the years ended December 31, 1999 and 1998; Report dated April 21, 2000, on our audit of the financial statements of Project Finance Fund III, L.P. as of and for the years ended December 31, 1999 and 1998; Report dated February 11, 2000, on our audit of the financial statements of Energy Investors Management Company as of and for the years ended December 31, 1999 and 1998; Report dated April 21, 2000, on our audit of the financial statements of Energy Investors Partners II, L.P. as of and for the years ended December 31, 1999 and 1998; Report dated April 21, 2000, on our audit of the financial statements of Energy Investors Fund II, L.P. as of and for the years ended December 31, 1999 and 1998; Report dated February 11, 2000, on our audit of the financial statements of Energy Investors Management, Inc. as of and for the years ended December 31, 1999 and 1998; Report dated April 21, 2000, on our audit of the financial statements of Energy Investors Partners, L.P. as of and for the years ended December 31, 1999 and 1998; and Report dated April 21, 2000, on our audit of the financial statements of Energy Investors Fund, L.P. as of and for the years ended December 31, 1999 and 1998; Arthur Andersen LLP Boston, Massachusetts April 13, 2001
EXHIBIT 23.2 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the use in this Registration Statement on Form S-1 of our reports relating to the financial statements listed below, which appear in such Registration Statement. Our reports referred to above are as follows: - Report dated June 9, 2000, except for information in Note 11, for which the date is August 30, 2000, relating to the consolidated financial statements of Indeck Capital, Inc. and Subsidiaries - Report dated February 25, 2000, relating to the consolidated financial statements of Indeck North American Power Fund, L.P. - Report dated February 25, 2000, relating to the financial statements of Indeck North American Power Partners, L.P. - Report dated February 25, 2000, relating to the financial statements of Northern Electric Power Co., L.P. - Report dated February 25, 2000, relating to the financial statements of South Glens Falls Limited Partnership We also consent to the reference to us under the heading "Experts" in such Registration Statement. PricewaterhouseCoopers LLP Milwaukee, Wisconsin April 13, 2001