SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
X ACT OF 1934
For the fiscal year ended December 31, 1998
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ___________________ to __________________
Commission File Number 1-7978
BLACK HILLS CORPORATION
Incorporated in South Dakota IRS Identification Number 46-0111677
625 Ninth Street
Rapid City, South Dakota 57701
Registrant's telephone number, including area code
(605) 348-1700
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -------------------
Common stock of $1.00 par value New York Stock Exchange
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES X NO______
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
State the aggregate market value of the voting stock held by non-affiliates of
the Registrant.
At February 26, 1999 $461,115,553
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date.
Class Outstanding at February 26, 1999
----- --------------------------------
Common stock, $1.00 par value 21,447,235 shares
Documents Incorporated by Reference
1. Definitive Proxy Statement of the Registrant filed pursuant to Regulation
14A for the 1999 Annual Meeting of Stockholders to be held on May 11, 1999,
is incorporated by reference in Part III. TABLE OF CONTENTS Page
ITEM 1. BUSINESS.............................................................4
GENERAL..........................................................4
ELECTRIC POWER SUPPLY............................................5
ELECTRIC SERVICE TERRITORY AND SALES.............................6
COMPETITION IN THE ELECTRIC UTILITY BUSINESS.....................7
ENERGY EXTRACTION AND PRODUCTION.................................7
ENERGY MARKETING OPERATIONS......................................9
COMMUNICATIONS OPERATIONS........................................9
ENVIRONMENTAL REGULATION........................................10
EMPLOYEES.......................................................12
ITEM 2. PROPERTIES..........................................................13
UTILITY PROPERTIES..............................................13
ENERGY EXTRACTION AND PRODUCTION PROPERTIES.....................13
ITEM 3. LEGAL PROCEEDINGS...................................................14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................15
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.................................................16
ITEM 6. SELECTED FINANCIAL DATA.............................................16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................................17
LIQUIDITY AND CAPITAL RESOURCES.................................17
MARKET RISK DISCLOSURES.........................................19
RATE REGULATION.................................................21
COMPETITION IN ELECTRIC UTILITY BUSINESS........................21
RESULTS OF OPERATIONS...........................................24
BUSINESS OUTLOOK STATEMENTS.....................................33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................37
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE..............................59
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..................59
ITEM 11. EXECUTIVE COMPENSATION..............................................60
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT......60
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......................60
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.....60
SIGNATURES..........................................................63
DEFINITIONS
When the following terms are used in the text they will have the meanings
indicated.
Term Meaning
BlackHills Power.............Black Hills Power and LightCompany, the assumed
business name of the Company under which its
electric operations are conducted
Basin Electric................Basin Electric Power Cooperative, Inc., a rural
electric cooperative engaged in generating and
transmitting electric power to its member RECs
Black Hills Capital Group.....Black Hills Capital Group, Inc., a wholly owned
subsidiary of Wyodak Resources
Black Hills Exploration and Production......Black Hills Exploration and
Production, Inc., (formerly Western
Production Company) a wholly owned
subsidiary of Wyodak Resources
Clovis Point Mine.............Clovis Point Mine refers to
coal properties Wyodak Resources acquired from
Kerr-McGee Coal Corporation consisting of a
federal coal lease, a state coal lease and real
property interests including coal processing and
rail loading
facilities.
Company.......................Black Hills Corporation
DEQ...........................Department of Environmental Quality of the State
of Wyoming
FERC..........................Federal Energy Regulatory Commission
MDU...........................Montana-Dakota Utilities Co., a division of MDU
Resources Group, Inc.
NS #1.........................Neil Simpson Unit #1, a 20 megawatt coal-fired
electric generating plant owned by the Company and
located adjacent to the Wyodak Plant and Neil
Simpson Unit #2
NS #2.........................Neil Simpson Unit #2, an 80 megawatt coal-fired
electric generating plant owned by the Company and
located adjacent to the Wyodak Plant and Neil
Simpson Unit #1
Pacific Power.................PacifiCorp, which operates its electric utility
operations under the assumed names of Pacific
Power and Utah Power
RECs..........................Rural electric cooperatives, which are owned by
their customers and which rely primarily on the
United States for their financing needs
SDPUC.........................The South Dakota Public Utilities Commission
WAPA..........................Western Area Power Administration, an agency of
the Department of Energy of the United States of
America
WPSC..........................The Wyoming Public Service Commission
Wyodak Resources..............Wyodak Resources Development Corp., a wholly owned
subsidiary of the Company
Wyodak Plant..................A 330 megawatt coal-fired electric generating
plant which is owned 20 percent by the Company and
80 percent by Pacific Power and located near
Gillette, Wyoming
4
PART I
ITEM 1. BUSINESS
GENERAL
Incorporated under the laws of South Dakota in 1941, the Company is an energy
and communications company primarily consisting of four principal businesses:
electric, energy extraction and production, energy marketing, and
communications. The Company's mission statement is to provide quality service
and energy and communications products at competitive prices in targeted markets
in order to build value for customers and shareholders and create opportunities
for employees. The Company operates its public utility electric operations under
the assumed name of Black Hills Power and Light Company, operates its energy
extraction and production businesses through its subsidiary Wyodak Resources
related to coal, and Black Hills Exploration and Production (formerly Western
Production Company) related to oil and natural gas, and its energy marketing and
communication operations through Black Hills Capital Group and its affiliates.
Black Hills Power is engaged in the generation, purchase, transmission,
distribution and sale of electric power and energy to approximately 56,900
customers in 11 counties in western South Dakota, northeastern Wyoming and
southeastern Montana, an area with a population estimated at 165,000. The
largest community served is Rapid City, South Dakota, a major retail, wholesale
and health care center, with a population, including environs, estimated at
75,000. Agriculture, tourism, small stakes gambling, mining, lumbering, small
item manufacturing, service and support businesses and government support
through Ellsworth Air Force Base are the primary influences on the economic
well-being of the region.
Wyodak Resources, incorporated under the laws of Delaware in 1956, is engaged in
the mining and sale of low sulfur sub-bituminous coal and is located
approximately five miles east of Gillette, Wyoming, in the Powder River Basin.
Black Hills Exploration and Production is an oil and gas exploration and
production company with interests located in the Rocky Mountain region, Texas,
California and various other locations.
Black Hills Capital Group, incorporated under the laws of South Dakota in 1997,
holds the Company's investments in Black Hills Energy Resources, Inc., Enserco
Energy, Inc., and Black Hills Coal Network, Inc. The energy marketing companies
noted above market natural gas, crude oil, coal, and/or related energy services
to customers in the East Coast, Midwest, Southwest, Rocky Mountain, Northwest
and West Coast regions.
Black Hills Capital Group also holds the Company's investments in Black Hills
FiberCom, Inc. and Daksoft, Inc. The communications companies noted above
represent start-up operations formed to provide local and long-distance
telephone, cable, internet and data services in the Black Hills of South Dakota,
and development and marketing of software products for the utility industry.
In addition to the energy marketing companies and communications' operations,
Black Hills Capital Group directs the Company's corporate development efforts in
the energy and communication areas.
Information as to the continuing lines of business of the Company for the
calendar years 1996-1998 is as follows:
1998 1997 1996
---- ---- ----
(in thousands)
Revenue from sales to unaffiliated customers:
Electric ........................ $128,834 $126,194 $118,508
Coal mining ..................... 21,157 19,991 20,931
Oil and gas ..................... 12,562 13,295 12,555
Energy marketing................. 506,043 142,790 --
Revenue from inter-company sales:
Electric ....................... $ 402 $ 303 $ 210
Coal mining ........................ 10,256 11,089 10,384
For additional information relating to the Company's operations by business line
see Note 11 of "NOTES TO CONSOLIDATED FINANCIAL STATEMENTS".
ELECTRIC POWER SUPPLY
General
- -------
Black Hills Power has been able to meet the needs of its customers for electric
power and energy through its owned generating capacity and by contract
purchases. Black Hills Power's peak load of 348 megawatts was reached in July
1998. Approximately 45 megawatts of additional load commenced January 1, 1997,
when Black Hills Power began providing wholesale electricity to MDU for its
Sheridan, Wyoming electric service territory. (See ITEM 1. BUSINESS-ELECTRIC
SERVICE TERRITORY AND SALES - Wholesale to MDU.) Black Hills Power estimated its
1998 required reserves at 82 megawatts. Black Hills Power is not presently a
member of a power pool, but in 1998 Black Hills Power joined the Rocky Mountain
Reserve Group. Rocky Mountain Reserve Group was approved by FERC in 1998 and
becomes active January 1, 1999. Black Hills Power's 1999 reserve requirement is
estimated to be 22 megawatts, consisting of 11 megawatts of spinning reserves
and 11 megawatts of secondary reserves.
Black Hills Power owns coal-fired generating units having a summer capability
rating of 214 megawatts and 77 megawatts of oil-fired diesel and natural
gas-fired combustion turbines for peaking and standby use. Black Hills Power
purchases additional resources under three contracts with Pacific Power: the
Power Sales Agreement, under which it purchases 75 megawatts of baseload power
declining to 50 megawatts from 2000 to 2004; the Reserve Capacity Integration
Agreement, under which 33 megawatts of additional reserve capacity are
available; and the Capacity Contract, under which Black Hills Power has options
to be exercised seasonally to purchase up to 60 megawatts of capacity.
Pacific Power's Power Sales Agreement
- -------------------------------------
This agreement obligates Black Hills Power to purchase from Pacific Power 75
megawatts of electric power plus energy at a load factor varying from a minimum
of 41 percent to a maximum of 80 percent as scheduled by Black Hills Power. In
October 1997, Black Hills Power entered into a second Restated and Amended Power
Sales Agreement with Pacific Power. The Amended Agreement reduces the contract
capacity by 25 megawatts (5 megawatts per year beginning in 2000). The contract
terminates December 31, 2023. The power and energy delivered is power from
Pacific Power's system and does not depend on any one unit, but the price is
generally based on Pacific Power's costs in Units 3 and 4 of the Colstrip
coal-fired generating plant near Colstrip, Montana. Black Hills Power contracts
for transmission service from Pacific Power under Pacific Power's FERC approved
transmission rates. The Company has incurred capacity charges of $15,700 per
megawatt month and an average energy charge of $11.90 per megawatt hour over the
last three years of this agreement with a 60 percent load factor. (See ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)
Pacific Power's Reserve Capacity Integration Agreement
- ------------------------------------------------------
This agreement obligates Pacific Power until the end of the contract in 2012 to
make available to Black Hills Power 100 megawatts of reserve capacity to be
acquired by Black Hills Power only at such time under prudent utility practice
Black Hills Power would have operated its combustion turbines. In return,
Pacific Power has the right to utilize Black Hills Power's four 25 megawatt
combustion turbines (with a summer rating of 67 megawatts), but Black Hills
Power has a prior right to use said turbines to support the transmission system.
The price for any energy Black Hills Power acquires under this agreement is
based upon the lower of Pacific Power's incremental costs of generation of its
highest price coal-fired plant or the cost of fuel to operate the combustion
turbines. Pacific Power also pays certain operating and maintenance expenses of
the combustion turbines, together with a $50,000 payment per month for the
remaining life of the contract.
Pacific Power's Capacity Contract
- ---------------------------------
Under this contract, Pacific Power granted Black Hills Power an option to be
exercised for each six-month season for a period commencing October 1, 1996 and
ending March 31, 2007 to purchase up to 60 megawatts of peaking capacity at
established prices. Black Hills Power may schedule the energy at a rate up to
100 percent per hour at a load factor up to 15 percent per season. Other than to
give preference to purchasing peaking capacity from Pacific Power, Black Hills
Power is under no obligation to exercise any of the six-month seasonal options.
In addition to granting Black Hills Power options to purchase peaking capacity,
the Pacific Power Capacity Contract also obligates Black Hills Power to sell to
Pacific Power until December 31, 2000, all surplus energy which is defined as
the difference in Black Hills' Resources (all energy from Black Hills Power's
generating resources and energy entitlement under Pacific Power's Power Sales
Agreement) and Black Hills' Loads (non-end user contracts of five months or
longer and all retail customers as they exist from time to time). The selling
prices are based upon economy energy spot price indices determined daily in the
western part of the United States with a sharing between Pacific Power and Black
Hills Power of prices above certain levels. Black Hills Power is not obligated
to sell any energy below its marginal production cost. The contract also
provides Black Hills Power an option to store energy with Pacific Power and to
take that energy back for the purpose of replacing energy from a forced or
scheduled outage of NS #2 or Black Hills Power's share of the Wyodak Plant.
To the extent of the excess capacity and energy available to Black Hills Power
from its generating resources and the Pacific Power purchased power contracts,
Black Hills Power at this time has the flexibility to serve the expected growth
of its loads in its service territory and as opportunities arise in the
meantime, to increase sales of its energy and capacity.
ELECTRIC SERVICE TERRITORY AND SALES
Retail Service Territory
- ------------------------
Black Hills Power's service territory is currently protected by assigned service
area and franchises that generally grant to Black Hills Power the exclusive
right to sell all electric power consumed therein, subject to providing adequate
service. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS - COMPETITION IN ELECTRIC UTILITY BUSINESS.)
As evidenced by a 1 percent increase in customers in both 1998 and 1997, the
economy in and around Black Hills Power's service territory is believed by
management to be stable. Small businesses and regional plant expansions are
continually being attracted to the region along with retirees who have
discovered the Black Hills region with its scenery, recreational activities and
medical services to be an attractive place to live. Management anticipates that
the economy will continue to experience modest growth but can give no assurances
as many economic factors will greatly influence any economy. Ellsworth Air Force
Base, a B-1 bomber military base near Rapid City, survived the fourth round of
base closures in 1995 but may be subject to future base closures that are beyond
the Company's control. The Company does not serve the air base, but it impacts
the surrounding economy. In January 1998, Homestake Mining Company (Homestake),
the Company's third largest customer at 4.6 percent of 1998 electric revenues,
announced a reorganization and restructuring plan at its gold mine in Lead,
South Dakota. Load reductions at Homestake were mitigated by additional
off-system sales. Other major industries in and around Black Hills Power's
service territory have been economically stable.
Wholesale to City of Gillette
- -----------------------------
Black Hills Power sells electric power and energy to the municipal electric
system at Gillette, Wyoming. Service is rendered under a long-term contract,
recently amended, and expiring July 1, 2012, wherein Black Hills Power sells to
the City of Gillette its first 23 megawatts of capacity requirements and the
associated energy. In 1997, as part of a contract amendment, the transmission
service component was unbundled from the power supply agreement, and
transmission service will be provided at FERC approved rates. In the amended
contract, the City of Gillette has agreed not to apply to FERC for any rate
change to be effective prior to January 1, 2003, unless and in the event that
Black Hills Power files for a rate change with FERC, which rate filing cannot be
effective prior to January 1, 2002, except under extraordinary events as defined
in the contract. In addition, Black Hills Power agreed to phase in price
reductions for the power purchased by the City of Gillette. The most recent
average annual capacity factor for this 23 megawatt demand has been
approximately 90 percent. Sales to Gillette represented 9.5 percent and 9.3
percent of total firm energy sales and 6.1 percent and 6.6 percent of revenue
from total firm electric sales in 1998 and 1997, respectively.
Wholesale to MDU
- ----------------
Black Hills Power and MDU entered into a Power Integration Agreement, dated as
of September 9, 1994, providing for the sale to MDU of up to 55 megawatts of
power and associated energy to serve MDU's Sheridan, Wyoming, electric service
territory for a period of 10 years which commenced January 1, 1997. The MDU
Sheridan service territory has experienced a 47 megawatt winter peak and
operates at a 57 percent load factor.
The agreement provides for fixed rates for capacity and energy to be paid by MDU
during the 10-year contract term. Black Hills Power and MDU have agreed not to
apply to FERC for any rate changes in the contract for the entire 10-year term
other than increases caused by governmental direct taxes on electric generation
fired by hydrocarbons. The agreement further provides for Black Hills Power and
MDU to equally share the costs of constructing a combustion turbine of
approximately 70 megawatts at such time during the 10-year term that Black Hills
Power determines in its sole discretion that such turbine is required.
Additional Off-System Sales
- ---------------------------
Black Hills Power sold 371,100, 279,600, and 249,100 megawatt hours of non-firm
energy in 1998, 1997, and 1996, respectively. The selling price is based on spot
market prices which have generated only a small profit margin on the sales. (See
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)
Transmission Service Sales
- --------------------------
Black Hills Power furnishes long-term transmission services under two contracts:
(i) the transmission contract terminating December 31, 2020 (1986 Agreement),
among Black Hills Power and Basin Electric and the other distribution
cooperatives as it concerns the transmission contract (the Cooperatives) and
(ii) the agreement with the City of Gillette terminating July 1, 2012 (described
under Wholesale to City of Gillette above), under which Black Hills Power has
agreed to deliver all of the City of Gillette's electric requirements. The rates
charged under the transmission contract with the Cooperatives are fixed formula
rates, and the transmission rates under the Gillette contract are established by
FERC under Black Hills Power's open access transmission tariff. (See ITEM 3.
LEGAL PROCEEDINGS - Transmission Rates - FERC Proceedings and ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -COMPETITION IN ELECTRIC UTILITY BUSINESS.)
COMPETITION IN THE ELECTRIC UTILITY BUSINESS
For information relating to competition in the electric utility business, see
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS -COMPETITION IN ELECTRIC UTILITY BUSINESS.
ENERGY EXTRACTION AND PRODUCTION
Coal Sales to Black Hills Power's Plants
- ----------------------------------------
Wyodak Resources sells coal to Black Hills Power for all of its requirements
under an agreement that limits earnings from all coal sales to Black Hills Power
(including the 20 percent share on the Wyodak Plant and all sales to Black Hills
Power's other plants) to a return on Wyodak Resources' original cost,
depreciated investment base. The return is 4 percent (400 basis points) above
A-rated utility bonds to be applied to Wyodak Resources' coal mining investment
base as determined each year. Black Hills Power made a commitment to the SDPUC,
the WPSC and the City of Gillette that coal would be furnished and priced as
provided by this agreement for the life of NS #2. Earnings from the intercompany
sales of coal at this time represent 5.9 percent of the Company's consolidated
earnings.
Sales and production statistics for the last three calendar years comparing
sales to Black Hills Power to others are as follows:
% Revenue
Revenue Derived
from Sale from Black Tons of
Year of Coal Hills Power Coal Sold
---- ------- ----------- ---------
(in thousands, except % revenue)
1998 $31,413 33 3,280
1997 31,080 36 3,251
1996 31,315 33 3,243
Coal Sales to the Wyodak Plant
- ------------------------------
Wyodak Resources furnishes all of the fuel supply for the Wyodak Plant in which
Black Hills Power owns a 20 percent interest and Pacific Power an 80 percent
interest. (See Note 6 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.) The price
for unprocessed coal sold to Pacific Power for its 80 percent interest in the
Wyodak Plant is determined by a coal supply agreement entered into by Black
Hills Power, Pacific Power and Wyodak Resources in 1978 and terminating in the
year 2013. This agreement was amended and restated in 1987. Revenue from coal
sales to the Wyodak Plant totaled $23,228,000 in 1998 or 74 percent of revenue
for all coal sold by Wyodak Resources. The quantity of coal sold in 1998 for the
Wyodak Plant was 2,120,000 tons, as compared to 2,155,000 tons sold in 1997.
Barring unusual periods of maintenance, the quantity of coal for the maximum
consumption capability of the Wyodak Plant for one year is approximately
2,100,000 tons and the average yearly consumption is 1,900,000 tons. The average
consumption is expected to continue during the remaining 15 years of the coal
agreement. However, from time to time, the plant's physical operating
capabilities will affect the quantity of coal burned.
Of the 3,280,000 tons of coal sold by Wyodak Resources in 1998, 1,463,000 tons
were sold to Black Hills Power, 1,697,000 tons were sold to Pacific Power and
120,000 tons were sold to others.
Wyodak Resources' revenue from sales of coal to Pacific Power and Black Hills
Power as compared to its revenue from all sales to total unaffiliated customers
for the last three years was as follows:
1998 1997 1996
---- ---- ----
(in thousands)
Sales to:
Pacific Power $20,263 $19,240 $19,189
Black Hills 10,256 11,089 10,384
Power
All unaffiliated
Customers 21,157 19,991 20,931
(See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS-BUSINESS OUTLOOK STATEMENTS--Future Coal Sales.)
Oil and Gas Operations
- ----------------------
The oil and gas industry is highly competitive. Black Hills Exploration and
Production (formerly Western Production Company) encounters strong competition
from many oil and gas producers in acquiring drilling prospects and producing
properties.
The Company's oil and gas production is sold at or near the wellhead, generally
at prevailing posted prices. Black Hills Exploration and Production has been
able to market all of its oil and gas production. Oil and natural gas revenues
are subject to market price volatility. Operating revenue by source for the last
three years was as follows:
Oil and Gas Gas Plant Field
Year Sales Revenue Services
- ---- ----- ------- --------
(in thousands)
1998 $9,204 $613 $2,745
1997 9,763 755 2,777
1996 9,050 875 2,630
Black Hills Exploration and Production sold approximately 687,000 equivalent
barrels of oil in 1998 comprised of 50 percent oil and 50 percent gas. (See ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-BUSINESS OUTLOOK STATEMENTS--Future Oil and Gas Sales.)
ENERGY MARKETING OPERATIONS
The Company's energy marketing operations market natural gas, crude oil, and/or
coal to customers in the East Coast, Midwest, Southwest, Rocky Mountain, West
Coast and Northwest regions of the United States. Natural gas marketing
operations are located in Houston, Texas, and Lakewood, Colorado, with sales
offices in Allentown, Pennsylvania, Chicago, Illinois and Calgary, Alberta,
Canada. Crude oil marketing operations are headquartered in Houston, Texas with
sales offices in Tulsa, Oklahoma and Midland, Texas. Coal marketing operations
are headquartered in Mason, Ohio.
In October 1998, Enserco Energy, Inc. reacquired the other shareholder interests
becoming a wholly-owned subsidiary of Black Hills Capital Group. In September
1998, Black Hills Capital Group formed Black Hills Coal Network which acquired
the assets and hired the operational management of Coal Network, Inc. and Coal
Niche, Inc. based in Mason, Ohio.
In July 1997, Black Hills Capital Group acquired, through Wickford Energy
Marketing, Inc., the assets and hired the operational management of Jomax
Partners, L.P. as successor and survivor of Wickford Energy Marketing, L.C. and
Wickford Energy Marketing Canada Company. In March 1998, Wickford Energy
Marketing, Inc. changed its name to Black Hills Energy Resources, Inc.
Revenues and marketed daily volumes by energy product for the last two years are
as follows:
1998 1997
---- ----
(in thousands)
Revenues:
Natural gas $375,934 $95,980*
Crude oil 117,185 46,810*
Coal 12,924* -
Daily Volumes:
Natural gas (mmbtus) 487,000 231,000*
Crude oil (barrels) 19,000 12,600*
Coal (tons) 4,400* -
*Since date of acquisition
The marketing operations are high volume, low margin businesses whose
contribution to consolidated earnings has not been significant. (See ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -RESULTS OF OPERATIONS - Energy Marketing Operations.)
COMMUNICATIONS OPERATIONS
In September 1998, Black Hills Capital Group formed Black Hills FiberCom, Inc.
to provide facilities-based communication services for Rapid City and the
Northern Black Hills of South Dakota .
The newly formed company is expected to invest more than $50,000,000 over the
next three years in state-of-the-art technology that will offer local and long
distance telephone service, expanded cable television service, Internet access,
and high-speed data and video services. System engineering and acquisition of
equipment began in the fourth quarter of 1998. The network is expected to take
two to three years to build out the complete system. The Company plans to market
the communications services to schools, hospitals, cities, economic development
groups, and business and residential customers.
The hybrid fiber coaxial cable link will enable customers to receive telephone,
cable television, internet, and high-speed data and video services all through
one cable coming into their businesses and homes. The network is designed to
provide greater reliability because there will be redundancy built into the
system. Compared with the present telecommunications network in the Black Hills,
connections to homes and businesses are expected to have significantly greater
capacity.
The Company is partnering with an international telecommunications firm, GLA
International, of St. Louis, Missouri, to build a 200 mile fiber optic backbone
and a 500-mile hybrid fiber coaxial network in Rapid City and the Northern Black
Hills. Black Hills FiberCom's assets and net income are expected to comprise
less than 10 percent of consolidated assets and earnings when fully implemented.
DAKSOFT, Inc. develops and markets internally generated computer software
associated with the Company's business segments and the utility industry.
ENVIRONMENTAL REGULATION
The Company is subject to extensive federal, state and local laws and
regulations governing discharges to the air and water, as well as the handling
and disposal of solid and hazardous wastes, including without limitation the
federal Clean Air Act (as amended in 1990), the federal Water Pollution Control
Act ("Clean Water Act"), the federal Toxic Substances Control Act and various
state laws, including solid waste disposal laws (collectively "Environmental
Regulatory Laws"). Governmental authorities have the power to enforce compliance
with Environmental Regulatory Laws, and violators may be subject to civil or
criminal penalties, injunctions or both. Third parties also may have the right
to sue to enforce compliance.
Air Quality
- -----------
Under the federal Clean Air Act, the federal Environmental Protection Agency
("EPA") has promulgated national air quality standards for certain air
pollutants, including sulfur oxides, particulate matter and nitrogen oxides. The
Company was granted a prevention of significant deterioration ("PSD")
construction permit by the DEQ for NS #2. The PSD construction permit set
emission rate limitations on particulate, sulfur dioxide, nitrogen oxides and
opacity. Black Hills Power has been in substantial compliance with its PSD
construction permit in its operations of NS #2 since its completion in August of
1995. Black Hills Power expects to receive an operational PSD construction
permit from DEQ in 1999.
Amendments to the Clean Air Act in 1990 will require a significant reduction in
nationwide sulfur oxide emissions by fossil fuel-fired generating units to a
permanent total emissions cap in the year 2000. This reduction is to be achieved
by the allotment of allowances to emit sulfur dioxide measured in tons per year
to each owner of a unit and requiring the owner to hold sufficient allowances
each year to cover the emissions of sulfur oxide from the unit during that year.
Black Hills Power holds sufficient allowances credited to it as a result of
sulfur removal equipment previously installed on the Wyodak Plant to apply to
the operation of NS #2 and its interest in the Wyodak Plant in the year 2000
without requiring the purchase of any additional allowances. Current law does
not require allowances for Black Hills Power's other plants.
All existing generating units of the Company are required to obtain operating
source permits under the Clean Air Act amendments. The operating permit
applications for the Osage and NS #1 generating units were submitted in 1995 and
received in 1997. Air quality permits for the Ben French Station were renewed in
1995 by the Department of Environment and Natural Resources of South Dakota.
Black Hills Power expects to receive a renewed permit in 1999.
Because the 1990 amendments to the Clean Air Act are scheduled to be implemented
and interpreted throughout the 1990s, compliance with yet-to-be promulgated and
interpreted regulations may require additional capital and operational
expenditures in the future, most likely from enhanced monitoring costs. Due to
the political sensitivity and volatility of environmental issues and how they
may be implemented, management can give no assurances that unexpected additional
capital and operating costs may be required in the future that would have a
material impact on financial results.
Water Quality
- -------------
The federal Clean Water Act requires permits for discharges of effluent and that
all discharges of pollutants comply with federally approved state water quality
standards. Black Hills Power currently has in place all required permits under
the Clean Water Act for discharges from all of the power plants in which Black
Hills Power has an interest. While management believes that it is in full
compliance with all federal and state clean water laws and regulations, for all
the same reasons as stated in the previous paragraph, no assurances can be given
of the extent of costs to comply with clean water requirements in the future.
Land Quality - Solid Waste Disposal
- -----------------------------------
Black Hills Power disposes all solid wastes collected as a result of burning
coal at its 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 Plant and NS #2 are
deposited in Wyodak Resources' 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 water quality. While management does not believe that any substances from
the solid waste disposal will pollute underground water, they can give no
assurances that over a long period of time such could never happen. In such
event, the Company could experience material costs in mitigating any damages
from such pollution. Agreements in place require Pacific Power to be responsible
for any such costs that would be related to the solid waste from its 80 percent
interest in the Wyodak Plant.
Additional unexpected material costs could also result in the future from either
the federal or state government determining that solid waste from the burning of
coal does contain some hazardous material that requires some special treatment,
including solid waste previously disposed of, and holding those entities who
disposed of such waste responsible for such treatment. Such unexpected
governmental requirements are beyond the control of the Company.
Reclamation
- -----------
Under federal and state laws and regulations, Wyodak Resources is required to
submit to and receive approval from the DEQ for a mining and reclamation plan
which provides for orderly mining, reclaiming and restoring of all land in
conformity with all laws and regulations. Wyodak Resources has an approved
mining permit and is otherwise in compliance with other land quality permitting
programs.
One condition that could result in substantial unexpected increases in costs of
the reclamation permit relates to three depressions, the existing south
depression, the Peerless depression and the North Pit depression, which have or
will result from Wyodak Resources' mining. Because of the thick coal seam and
relatively shallow overburden, the present plan for restoration leaves areas of
the mine that will have limited reclamation potential because of their location
in depressions with interior drainage only. While the DEQ has allowed these
depressions in the present plan, the DEQ has reserved the right to review and
evaluate future mining plans proposed by Wyodak Resources. Such plans are
reviewed for the feasibility and desirability of causing Wyodak Resources to
place additional overburden generated elsewhere for the purpose of reducing the
depressions if the DEQ finds that the placement is necessary to prevent
degradation of more areas than expected. The DEQ has allowed the depressions at
the maximum acres specified and subject to maintenance of water quality at the
sites. Exceedence of acreage limitations or degradation of water quality could
result in material additional requirements placed upon Wyodak Resources,
including the placement of additional quantities of overburden in the
depressions and restoring water quality. Based on extensive reclamation studies,
accruals are maintained to comply with all reclamation requirements. However, no
assurances can be given that additional requirements in the future may be
imposed that cause unexpected material increases in reclamation costs.
Ben French Oil Spill
- --------------------
In 1990 and 1991, Black Hills Power discovered extensive underground fuel oil
contamination at the Ben French Plant site. With the help of expert consultants,
the Company engaged in assessment and remediation and has worked closely with
the South Dakota Department of Environment and Natural Resources. Assessment and
remediation efforts are continuing up to the present time. All 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. Black Hills Power continues to monitor the site. Soil borings and
monitoring wells on the perimeters of Black Hills Power's Ben French Plant
property are showing 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 $438,000, of which amount
$354,000 has been reimbursed from the South Dakota Petroleum Release
Compensation Fund. To date, no penalties, claims or actions have been taken or
threatened against the Company because of this oil spill.
PCBs
- ----
Under the federal Toxic Substances Control Act, the EPA has issued regulations
that control the use and disposal of polychlorinated biphenyls (PCBs). PCBs had
been widely used as insulating fluids in many electric utility transformers and
capacitors manufactured before the Toxic Substances Control Act prohibited any
further manufacture of such PCB equipment. Black Hills Power removes and
disposes of PCB-contaminated equipment in compliance with law as it is
discovered.
Several years ago, Black Hills Power began a testing program of possible
PCB-contaminated transformers, and in 1997 completed testing of all transformers
and capacitators which are not located in Black Hills Power's electric
substations. Black Hills Power has not completed the testing of sealed potential
transformers and bushings located in its electric substations as the testing of
such equipment will require the destruction of the equipment. While release of
PCB-contaminated fluid, if present, from such equipment is unlikely and the
volume of fluid in such equipment is generally less than one gallon, any release
of such fluid would be confined to Black Hills Power's substation site.
Release of PCB-contaminated fluids, especially any involving a fire or a release
into a waterway, could result in substantial cleanup costs. As the result of the
September 18, 1996 inspection by the Environmental Protection Agency of Black
Hills Power's Deadwood Avenue facility located in Rapid City, South Dakota, the
United States Environmental Protection Agency Region VIII filed a complaint
dated September 30, 1998, alleging three counts of violations of PCB regulations
and proposing a civil penalty of $13,600. Black Hills Power filed an answer
contesting the complaint. Based on Black Hills' answer and subsequent facts and
information, the EPA withdrew their complaint and an order was entered by an
administrative law judge dismissing the complaint on December 1, 1998.
Electromagnetic Fields
- ----------------------
A number of studies have examined the possibility of adverse health effects such
as cancer from electromagnetic fields (EMF) which are caused by electric
transmission and distribution facilities. Certain states have enacted
regulations to limit the strength of magnetic fields at the edge of transmission
line rights-of-way. None of the jurisdictions in which Black Hills Power
operates has adopted formal rules or programs with respect to EMF or EMF
considerations in the siting of electric facilities. Black Hills Power expects
that public concerns will make it more difficult and costly to site and
construct new power lines and substations in the future. It is uncertain whether
Black Hills Power's operations may be adversely affected in other ways as a
result of EMF concerns. Black Hills Power is designing all new transmission
lines under EMF standards adopted by the State of Florida so as to minimize the
EMF effect. The Company is unable to predict the future costs to the electric
utility industry, including the Company, if a determination is made in the
future, either based on facts or perception, that EMF causes adverse health
effects.
The Company makes ongoing efforts to comply with new as well as existing
environmental laws and regulations to which it is subject. It is unable to
estimate the ultimate effect of existing and future environmental requirements
upon its operations.
EMPLOYEES
At December 31, 1998, the number of employees of the Company (including Black
Hills Power), Wyodak Resources, Black Hills Exploration and Production, energy
marketing companies and communication companies, were 291, 44, 32, 60 and 27,
respectively, for a total of 454 employees.
Approximately 48 percent of the employees of Black Hills Power are covered by
union contracts with the International Brotherhood of Electrical Workers. In the
Company's opinion employee relations are satisfactory.
- --------------------------------------------------------------------------------
ITEM 2. PROPERTIES
UTILITY PROPERTIES
The following table provides information on the generating plants of Black Hills
Power. During 1998, 98 percent of the fuel used in electric generation, measured
in Btus (British thermal units), was coal. Generating Units
Name Plate
Year of Rating Principal
Installation (Kilowatts) Fuel
------------ ----------- ----
Osage Plant - Osage, Wyoming 1948-1952 34,500 Coal
Ben French Station-Rapid City, South 1960 25,000 Coal
Dakota
1965 10,000 Oil
1977-1979(a) 100,000 Oil or gas
Neil Simpson Station - Gillette, 1969 21,760 Coal
Wyoming
1995(b) 88,900 Coal
Wyodak Plant - Gillette, Wyoming 1978(c) 72,400 Coal
-------
Total 352,560
=======
(a) These combustion turbines are those referenced by ITEM 1. BUSINESS ELECTRIC
POWER SUPPLY - Pacific Power's Reserve Capacity Integration
Agreement.
(b) NS #2 was placed into commercial operation in August 1995. The plant's
total production may, at times, exceed its name plate rating by 11 MWs.
(c) Black Hills Power's 20 percent interest. See Note 6 of "NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS".
Black Hills Power owns transmission lines and distribution systems in and
adjoining the communities served consisting of 447 miles of 230 kV, 527 miles of
69 kV, 8 miles of 47 kV and numerous distribution lines of less voltage. Black
Hills Power owns a service center in Rapid City, several district office
buildings at various locations within its service area and an eight-story home
office building at Rapid City, South Dakota, housing its home office on four
floors, with the balance of the building rented to others.
- --------------------------------------------------------------------------------
ENERGY EXTRACTION AND PRODUCTION PROPERTIES
Coal Mining Properties
- ----------------------
Wyodak Resources is engaged in mining and processing sub-bituminous coal near
Gillette in Campbell County, Wyoming, and owns or has user rights in the
necessary mining, processing and delivery equipment to fulfill its sales
contracts. The coal averages 8,000 Btus per pound. Mining rights to the coal are
based upon four federal leases and one state lease. The estimated recoverable
coal from the leases as of December 31, 1998 is 280,895,000 tons, of which
22,012,000 tons are committed to be sold to the Wyodak Plant and approximately
25,125,000 tons to Black Hills Power's other plants.
Each federal lease grants Wyodak Resources the right to mine all of the coal in
the land described therein, but the government has the right at the end of 20
years from the date of the lease to readjust royalty payments and other terms
and conditions. All of the federal leases provide for a royalty of 12.5 percent
of the selling price of the coal. The state lease provides for a royalty to be
determined every five years. Currently, the royalty on the state lease, approved
in 1998, is 9% of the selling price of the coal. Each federal lease and state
lease requires diligent development to produce at least one percent of all
recoverable reserves within either 10 years from the respective dates of the
1983 leases or 10 years from the date of adjustment of the other leases. Each
lease further requires a continuing obligation to mine, thereafter, at an
average annual rate of at least one percent of the recoverable reserves. All of
the federal leases and the state lease constitute one logical mining unit which
is treated as one lease for the purpose of determining diligent development and
continuing operation requirements. All coal is to be mined within 40 years from
December 31, 1991, the date of the logical mining unit. Even if federal and
state coal leases are not mined out in 40 years, the federal coal is likely to
be available for further lease after the 40 years. Wyodak Resources' current
coal agreements require production which should be sufficient to satisfy the
diligent development and continual operation requirements of present law absent
any unexpected event. Wyodak Resources will require additional coal sales in
order to mine all of its state and federal coal within the 40 year requirement.
The law, which requires that an owner of land that is primarily devoted to
agriculture must approve a reclamation plan before the state will approve a
permit for open pit mining, affects approximately 3,100,000 tons of the
recoverable coal. Wyodak Resources has excluded these tons of coal from its mine
plan and will not mine such coal until a surface consent has been negotiated or
the right to mine has been settled by litigation.
In 1996, Wyodak Resources purchased the Clovis Point Mine properties from Kerr
McGee Coal Corporation. Acquisition of the property increased Wyodak Resources'
1996 recoverable reserves to approximately 288 million tons and included a train
loadout facility, maintenance and processing facilities and a developed open
pit. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES - Acquisition of
Clovis Point Mine Properties.)
Oil and Natural Gas Properties
- ------------------------------
Black Hills Exploration and Production operates 297 wells as of December 31,
1998. The majority of these wells are in the Finn Shurley Field, located in
Weston and Niobrara Counties, Wyoming. Black Hills Exploration and Production
does not operate, but owns a working interest in 275 producing properties
located in the western and southern United States. Black Hills Exploration and
Production also owns a 44.7 percent non-operating interest in a natural gas
processing plant also located at the Finn Shurley Field.
Black Hills Exploration and Production participated in the drilling of 43
exploratory and development wells in 1998. Black Hills Exploration and
Production's average working interest in such wells was 15 percent, or 6 net
wells. A development well is a well drilled within the presently proved
productive area of an oil and gas reservoir, as indicated by reasonable
interpretation of available data, with the objective of completing in that
reservoir. An exploratory well is a well drilled in search of a new, as yet
undiscovered oil or gas reservoir or to greatly extend the known limits of a
previously discovered reservoir. Twenty-three out of the 43 wells drilled in
1998 were completed as producing wells for an overall drilling success rate of
53 percent.
See the table in Note 10 of "NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS" for
Black Hills Exploration and Production's estimated quantities of proved
developed and undeveloped oil and natural gas reserves at December 31, 1998,
1997 and 1996, and a reconciliation of the changes between these dates using
constant product prices for the respective years.
ITEM 3. LEGAL PROCEEDINGS
Transmission Rates - FERC Proceedings
- -------------------------------------
The FERC approved a settlement in Black Hills' Order 888 open access
transmission tariff filing. This settlement allows Black Hills to use the
revenues received under the long-term transmission agreement between the Company
and the Cooperatives which terminates on December 31, 2020 (SEE ITEM 1. BUSINESS
- -ELECTRIC SERVICE TERRITORY AND SALES-Transmission Service Sales) as being equal
to the cost of providing service to the Cooperatives. The Cooperatives'
transmission loads are not considered when calculating Black Hills' open access
transmission tariff rates; and as such, the Cooperatives are paying less than
their fully allocated cost for use of the transmission system. But as a result
of allowing the revenue credit methodology, the open access transmission rates
still allow Black Hills to earn a just and reasonable rate on its transmission
facilities. The settlement with the FERC is consistent with past actions of the
SDPUC and WPSC, which similarly have allowed Black Hills to use the revenue
credit methodology in determining bundled rates for retail customers.
In the settlement, Black Hills has agreed to file for new open access
transmission tariff rates in the event that: (1) either the South Dakota or the
Wyoming legislatures adopt retail access which would allow alternative
electricity suppliers to have access to existing franchised retail service
territories; (2) an entity other than Black Hills Power or the Cooperatives
establishes generation tied to a Cooperative's transmission line as identified
in the 1986 Black Hills Power-Basin Electric Transmission Agreement for service
to that entity's existing retail customers within the joint transmission area;
(3) an AC/DC/AC tie is established near Rapid City, South Dakota, to connect the
western electric transmission and eastern electric transmission grids of the
United States; or (4) the FERC revises the rates Black Hills Power charges the
Cooperatives. Finally, to the extent that a transmission customer (other than
Black Hills Power or the Cooperatives) arranges for transmission service on the
Cooperatives' transmission facilities as defined in the 1986 Agreement for the
purposes of serving the transmission customer's retail customers within the
joint transmission area as defined within the 1986 Agreement, Black Hills Power
shall provide a credit, not to exceed its tariff rate, against their rates for
transmission service it charges to such transmission customer for its use of the
Cooperatives' transmission facilities to serve the transmission customer's
retail customers within the joint transmission area.
Because Order 888 now gives the cooperatives the full use of the transmission
system, Black Hills Power had filed a complaint against the Cooperatives. In its
complaint, Black Hills Power had requested that the FERC modify the transmission
contract between Black Hills Power and the Cooperatives, so that the
Cooperatives would be obligated to pay a just and reasonable rate that would
fairly allocate the capital cost of the transmission system to reflect the
Cooperatives' use. Black Hills Power withdrew its complaint, without prejudice,
against the Cooperatives.
Black Hills Power does not anticipate any material use of its transmission
system by third-parties until such time that retail wheeling may be instituted.
It is uncertain at this date as to what extent the FERC or the state regulatory
jurisdictions will have jurisdiction over determining retail wheeling rates.
(See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - COMPETITION IN ELECTRIC UTILITY BUSINESS.)
Other Legal Proceedings
- -----------------------
The Company and its subsidiaries are involved in minor routine administrative
proceedings and litigation incidental to the businesses, none of which, in the
opinion of management, are expected to have a material effect on the
consolidated financial statements of the Company. .
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter
of 1998.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock ($1 par value) is traded on The New York Stock
Exchange. Quotations for the Common Stock are reported under the symbol BKH. At
year-end, the Company had 6,315 common shareholders of record. All 50 states and
the District of Columbia plus 11 foreign countries are represented.
The Company has declared Common Stock dividends payable in cash in each year
since its incorporation in 1941. At its January 1999 meeting, the Board of
Directors raised the quarterly dividend to 26.0 cents per share, equivalent to
an annual increase of 4.0 cents per share. This regular quarterly dividend is
payable March 1, 1999. Dividend payment dates are normally March 1, June 1,
September 1, and December 1.
Quarterly dividends paid and the high and low Common Stock prices for the last
two years reflecting the 3-for-2 Common Stock split in March 1998 were as
follows:
Year ended December 31, 1998
1st 2nd 3rd 4th
Dividends paid
per share $0.25 $0.25 $0.25 $0.25
Common stock
prices
High $25.56 $24.25 $26.88 $27.94
Low $21.00 $20.69 $22.31 $24.13
Year ended December 31, 1998
1st 2nd 3rd 4th
Dividends paid
per share $0.237 $0.237 $0.237 $0.237
Common stock
prices
High $19.25 $19.67 $19.75 $24.29
Low $17.50 $17.58 $17.92 $19.50
- --------------------------------------------------------------------------------
ITEM 6. SELECTED FINANCIAL DATA
The following data was derived from the Company's audited financial statements.
Years ended December 31 1998 1997 1996 1995 1994
- ----------------------- ---- ---- ---- ---- ----
(in thousands, except per share amounts)
Operating revenues $679,254 $313,662 $162,588 $149,817 $145,402
Net income 25,808* 32,359 30,252 25,590 23,805
Per share of common stock:
Earnings - basic and diluted 1.19* 1.49 1.40 1.19 1.11
Dividends paid 1.00 0.95 0.92 0.89 0.88
Total assets 559,417 508,741 467,354 448,830 436,877
Long-term debt 162,030 163,360 164,691 166,069 128,925
Quarterly financial data for the years indicated (are summarized in thousands,
except per share amounts) as follows:
1st 2nd 3rd 4th
--- --- --- ---
Year ended December 31, 1998
Operating revenues $153,837 $161,334 $170,158 $193,925
Operating income 14,875 13,915 17,603 2,840*
Net income 8,544 7,497 9,616 151*
Earnings per share .39 .35 .45 .01*
Year Ended December 31, 1997
Operating revenues $43,879 $40,259 $98,182 $131,342
Operating income 15,629 12,742 15,573 14,495
Net income 8,586 6,762 8,644 8,367
Earnings per share 0.39 0.31 0.40 0.39
*Includes $8.8 million, or 41 cents per share, non-cash writedown of certain oil
and gas properties.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
The Company generated cash from operations sufficient to meet operating needs,
pay dividends on common stock and finance its capital requirements. Property
additions from 1996 through 1998 were primarily for the replacement of
equipment, modernization of facilities, oil and gas investment and expansion of
energy marketing operations. The primary capital requirements of the Company for
the past three years were as follows:
1998 1997 1996
---- ---- ----
(in thousands)
Property additions $25,265 $21,087 $24,388
Common stock dividends 21,737 20,540 19,930
Energy marketing assets 1,960 7,232 -
Maturities/redemptions of
long-term debt 1,331 1,534 1,405
----- ----- -----
$50,293 $50,393 $45,723
======= ======= =======
Capital requirements for projected construction, capital improvements, oil and
gas investments, communications network construction and corporate development
activities for the next three years are estimated to be as follows:
1999 2000 2001
---- ---- ----
(in thousands)
Electric:
Production $3,316 $ 1,291 $1,415
Transmission 3,956 2,479 2,807
Distribution 8,731 7,937 8,008
General 1,804 2,414 1,749
----- ----- -----
17,807 14,121 13,979
Energy Extraction and
Production:
Coal mining 4,245 5,211 1,233
Oil and gas 9,700 10,000 10,000
----- ------ ------
13,945 15,211 11,233
Communications 38,556 5,389 6,644
Corporate development 20,000 10,000 10,000
------ ------ ------
$90,308 $44,721 $41,856
======= ======= =======
- -------------------------------------------------------------------------------
The electric and coal mining operations' forecasted expenditures include the
replacement of equipment and modernization of facilities. Forecasted
expenditures for the oil and gas operations are dependent upon future cash flows
and include an active development and exploratory drilling program and
acquisition of existing producing properties. Forecasted investment in
communications infrastructure represents the communications network build-out in
Rapid City and the Northern Black Hills. Forecasted investment in corporate
development activities are dependent on market conditions at the time and the
Company's ability to identify opportunities consistent with its corporate
strategy. Black Hills Generation, Inc. (formerly WYGEN, Inc.) and the energy
marketing companies do not have any forecasted capital expenditures that are
significant. The energy marketing companies are generally not capital intensive
businesses. Black Hills Generation was formed as an exempt wholesale generator
and will not incur substantial costs until and unless long-term power sale
contracts are obtained. If long term sales agreements are reached requiring
capital expenditures, such expenditures will be evaluated at that time.
Electric operations is the only segment of the Company's business with long-term
debt. Long-term debt sinking fund requirements are: $1,330,000 in 1999,
$1,330,000 in 2000, and $3,029,000 in 2001. 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 $700,000
is charged to operations as reclamation expense annually. As of December 31,
1998, accrued reclamation costs were approximately $17,000,000 which includes
$7,957,000 for the 1996 Clovis Point Mine Acquisition. (See Acquisition of
Clovis Point Mine Properties following this section.)
The Company has a Dividend Reinvestment and Stock Purchase Plan, under which
shareholders may purchase additional shares of Common Stock through dividend
reinvestment 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 used the open market purchase option for
all of 1998, 1997 and 1996.
The debt component of the Company's capital structure at December 31, 1998 and
1997, was 44 percent. The Company does not anticipate any additional long-term
debt financings in the next three years and would expect the debt ratio to
decrease to approximately 40 percent over the next 3 to 5 year period unless a
Black Hills Generation project is constructed or significant other development
opportunities are consummated. The Company anticipates financing the
communications construction through operating cash flow and short-term debt.
(See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS-RESULTS OF OPERATIONS-Independent Power Business; and
BUSINESS OUTLOOK STATEMENTS - Future Corporate Development Activities.)
The Company had $12,000,000 of unsecured short-term lines of credit at December
31, 1998 and 1997, which provide for interim borrowings and the opportunity for
timing of permanent financing. There was $3,850,000 outstanding under these
lines of credit as of December 31, 1998. There are no compensating balance
requirements associated with these lines of credit.
In addition to the above lines of credit, Black Hills Energy Resources has a
$65,000,000 uncommitted line of credit with a national bank ($50,000,000 for
letters of credit and $15,000,000 for working capital) to provide credit support
for purchases and sales of natural gas and crude oil. The Company does not
provide credit support for this agreement. At December 31, 1998, there were
outstanding letters of credit totaling approximately $28,000,000, which reduced
the available credit to $37,000,000.
In addition to the above lines of credit, Wyodak Resources has guaranteed a
$15,000,000 line of credit for Enserco to use to guarantee letters of credit.
Enserco pays a 0.125 percent facility fee on this line of credit. At December
31, 1998, there were no balances outstanding on this line of credit.
In the past, the Company has relied upon internally generated funds, issuance of
short and long-term debt and sales of common stock to finance its activities.
The Company expects an appropriate mix of financing options will be used to
finance future activities.
Credit ratings for the Company's First Mortgage Bonds are at an A1 level at
Moody's Investors Service, Inc. and at an A+ at Standard & Poor's. These ratings
reflect the respective agencies' opinions of the credit quality of the Company's
first mortgage bonds.
Acquisition of Clovis Point Mine Properties
- -------------------------------------------
In September 1996, Wyodak Resources purchased the Clovis Point Mine properties
from Kerr-McGee Coal Corporation. The Clovis Point Mine properties are located
adjacent to Wyodak Resource's current reserves in Campbell County, Wyoming, and
consist of State of Wyoming and federal leased coal reserves.
Acquisition of the property increased the Company's 1996 recoverable reserves
from 170 million tons to approximately 288 million tons and included a train
loadout facility, maintenance and processing facilities and a developed open
pit. (See NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 7 - Commitments and
Contingent Liabilities - Acquisition of Clovis Point Mine Properties.)
MARKET RISK DISCLOSURES
Commodity Risk
- --------------
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.
The Company has adopted a Risk Management Policies and Procedures, approved by
the Board of Directors, which include, but are not limited to, risk tolerance
levels relating to authorized derivative financial instruments, position limits,
authorization of transactions and credit exposure.
Trading Activities
- ------------------
The Company, through its energy marketing companies, utilizes derivatives for
its energy marketing services. These financial instruments include fixed price
swap agreements, variable price swap agreements, exchange-traded energy futures
contracts, and swaps and collars traded in the over-the-counter financial
markets.
The majority of derivatives have been designated for hedging purposes and are
not held for speculative purposes. For trading transactions that do not qualify
for hedge accounting, the Company utilizes marked-to-market accounting, and such
financial instruments are recorded at fair value with realized and unrealized
gains (losses) recorded as a component of income. The quantities and maximum
terms of derivative financial instruments held for trading purposes at December
31, 1998 and 1997 are not significant to the Company's financial position or
results of operations.
Non-trading activities
- ----------------------
To reduce risk from fluctuations in the price of oil and natural gas, the
Company enters into futures and swap transactions. The transactions are used to
hedge price risk from sales of the Company's crude oil and natural gas
production, and from fixed price sales from the Company's retail gas marketing
activities. For such transactions, the Company utilizes hedge accounting. (See
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 1 - BUSINESS DESCRIPTION AND
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Price Risk Management Activities).
The notional quantities and maximum terms of derivative financial instruments
held for non-trading activities at December 31, 1998 are presented below:
Volume Max.
Purchased Term Fair Value
(MMBtu's) (Years) (in thousands)
--------- ------- --------------
Natural gas futures
contracts purchased 1,470,000 2 $(409)
Natural gas swap
contracts purchased 7,989,096 3 $(2,601)
Natural gas swap
contracts sold 1,473,000 1 $432
Because these contracts are entered into for hedging purposes, the Company
expects that the gains/(losses) will be offset by gains (losses) on the
underlying physical transactions; Such physical transactions are subject to
weather trends, transportation and delivery risks and other factors that the
Company monitors on a regular basis. The notional amounts detailed above are
intended to be indicative of the Company's level of activity in such
derivatives.
At December 31, 1998, the Company did not have material crude oil derivatives in
its non-trading activities. At December 31, 1997, the company had price collars
and fixed rate for floating rate price swaps to hedge crude oil price risk for
15,000 barrels of oil per month, resulting in the recognition of $939,000 of
gains during 1998. In addition, the Company had fixed rate for floating rate
price swaps on 3.9 bcf of natural gas to hedge fixed price sales commitments in
a similar quantity.
Trading and Non-trading--General Policy
- ---------------------------------------
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.
Interest Rate Risk
- ------------------
The Company's exposure to market risk for changes in interest rates relates
primarily to the Company's short-term investments and long-term debt
obligations. The Company does not use derivative financial instruments in its
available for sale securities. As stated in its policy, the Company is averse to
principal loss and ensures the safety and preservation of its investments by
limiting default risk, market risk, and reinvestment risk. The Company mitigates
default risk by investing in high credit quality securities consisting primarily
of tax-exempt Federal, state and local agency obligations and by constantly
monitoring the credit rating of any investment issuer or guarantor and by
limiting the amount of exposure to any one issuer. The portfolio includes only
securities with active secondary or resale markets to ensure portfolio
liquidity. All short-term investments mature, by policy, in three years or less.
The effect of a 100 basis point increase in interest rates would not have a
material effect to the Company's results of operations or financial condition,
due to the short-term duration of the investment portfolio.
The Company has no cash flow exposure due to rate changes for long-term debt
obligations. The Company primarily enters into debt obligations to support
general corporate purposes including capital expenditures and working capital
needs.
- -------------------------------------------------------------------------------
The table below presents principal (or notional) amounts and related weighted
average interest rates by year of maturity for the Company's short-term
investments and long-term debt obligations, including current maturities (in
thousands).
1999 2000 2001 2002 2003 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
Cash equivalents
Fixed rate $14,764 $ -- $ -- $ -- $ -- $ -- $ 14,764
Average interest rate 3.40% -- -- -- -- -- 3.40%
Available for sale securities
Fixed rate 11,834 9,006 1,835 -- -- -- 22,675
Average interest rate 4.18% 4.14% 4.26% -- -- -- 4.17%
Total investment securities 26,598 9,006 1,835 -- -- -- 37,439
Average interest rate 3.75 4.14 4.26% -- -- -- 3.87%
Long-term debt
Fixed rate 1,330 1,330 3,029 18,018 3,068 136,585 163,360
Average interest rate 9.11% 9.11% 9.24% 6.96% 9.24% 8.2% 8.2%
RATE REGULATION
Existing Rate Regulation
- ------------------------
In 1995, Black Hills Power and the South Dakota and Wyoming regulatory bodies
reached settlement relating to the inclusion of NS #2 into rate base.
The South Dakota and Wyoming settlements further provide that unless an
extraordinary event occurs, Black Hills Power will not file for any increase in
rates or invoke any fuel and purchased power automatic adjustment tariff to take
effect during a freeze period ending January 1, 2000. The specified
extraordinary events are: new governmental impositions increasing annual costs
in South Dakota above $1,000,000 or $325,000 in Wyoming, forced outages of both
the Wyodak Plant and NS #2 projected to continue at least 60 days in South
Dakota and three months in Wyoming, forced outages occurring to either plant
which are continued for a period of three months or projected to last at least
nine months and an increase in the Consumer Price Index at a monthly rate for
six consecutive months which would result in a 10 percent or more annual
inflation rate.
During the freeze period, Black Hills Power is undertaking the risks of
machinery failure, load loss caused by either an economic downturn or changes in
regulation, increased costs under existing power purchase contracts over which
the Company has no control, government interferences, acts of nature and other
unexpected events that could cause material losses of income or increases in
costs of doing business. However, the settlements anticipate that Black Hills
Power will retain during that period of time earnings realized from more
efficient operations, sales from load growth, and off-system sales of power and
energy, including the sale to MDU. (See ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS OUTLOOK
STATEMENTS.)
Long-Term Contracts
- -------------------
As a result of rate negotiations, Black Hills Power has been successful in
entering into long-term contracts with most of its industrial and large
commercial customers. The all requirements electric service agreement with
Homestake Mining Company expires September 9, 2002, and the other contracts have
terms of five years that begin to expire in 2000. However, each of the contracts
provides options for the customer to keep the term of the contract extended for
at least three years, with the proviso that if the customer allows the term to
reduce to less than two years, Black Hills Power may invoke a planning surcharge
on that customer. If deregulation in retail electric sales occurs, the contracts
give Black Hills Power notice to allow for planning to make the transition to
full competition, guard against stranded investment and protect other customers
from rate impacts of unexpected load loss. However, management cannot predict if
the notice period would be sufficient to fully adapt for competition. These
industrial and large commercial customers, together with the wholesale power
sales agreements to the City of Gillette and MDU, result in approximately 40
percent of Black Hills Power's firm load under these term contracts.
Business Development Rates
- --------------------------
Both the SDPUC and the WPSC authorized Black Hills Power to negotiate rates
above its marginal costs but below full cost with any customer with a load of
over 250 KVA if that customer has a legal choice of its electric supplier. Black
Hills Power expects to utilize this tariff in those instances where a new
business would have a choice of locating in the service territory of either
Black Hills Power or a competing REC or enticing a new business to locate or
relocate in Black Hills Power's service territory. Black Hills Power has
available resources to compete for new large load customers through this new
tariff.
COMPETITION IN ELECTRIC UTILITY BUSINESS
Current Status of Competition for Service at Retail
- ---------------------------------------------------
In addition to Black Hills Power, RECs and the federal government through WAPA
provide electric service in and around the service territory of Black Hills
Power. Black Hills Power's transmission system is interconnected to Pacific
Power's transmission system near Gillette, Wyoming, and to WAPA's system near
Scottsbluff, Nebraska. Pacific Power provides electric service at retail to
large portions of Wyoming. Black Hills Power and the RECs serve in territories
which are protected by state laws or regulations which generally give each
entity the exclusive right to serve retail customers in its respective
territory; however, these laws or regulations are subject to change and there
are certain exceptions. In South Dakota, the SDPUC may allow a new customer with
a load of over 2,000 kilowatts to choose to be served by a utility other than
the utility in whose territory the new customer locates. In Wyoming, public
utilities operate in service territories assigned by the WPSC, and a franchise
granted by the municipality's governing body is required to serve within a
municipality. Black Hills Power may apply for and obtain the right to serve in
another utility's electric service territory if it is found to be in the public
interest to do so, but such applications are rarely granted.
The respective service territories of Black Hills Power and the RECs were
originally assigned based on where each was serving at the time of assignment.
Since the RECs were serving in rural areas (the purpose for which they were
formed), a large portion of the rural area surrounding the municipalities in
which Black Hills Power serves constitutes REC service territory. Although Black
Hills Power has traditionally served considerable territory outside of
municipalities and, therefore, has been assigned a large amount of such
territory, the RECs have the largest portion of such area and, if the laws are
not changed, will over a long period of time tend to receive a larger portion of
the growth of the population centers.
Every municipality in Black Hills Power's service territory has the right, upon
meeting certain conditions, to acquire or construct a municipally owned electric
system and to serve customers within its city. As a wholesaler of electric power
and energy, such municipality would have the power to demand and receive
transmission access over Black Hills Power's transmission system consistent with
its open access transmission tariff. The FERC has recognized the principle that
a city, which establishes a municipal electric system and buys power from a
supplier other than its former electric utility, should compensate the former
supplier for any stranded costs caused by the change in the power supplier.
However, the Company can give no assurances to what extent the stranded cost
provisions will be administered or how they would be applied to Black Hills
Power. Black Hills Power is not aware of any movement by any municipality in its
service territory which does not already have a municipally owned electric
system to establish one.
The primary competing fuel in Black Hills Power's territory is natural gas which
is available to approximately 80 percent of its customers.
Competition in Electric Generation
- ----------------------------------
The business of electric generation is no longer reserved exclusively for the
traditional public utility such as Black Hills Power. The Energy Policy Act of
1992 exempted independent power producers engaged exclusively in the sale of
power at wholesale from the onerous restrictions of the Public Utility Holding
Company Act. The Public Utility Regulatory Policies Act of 1978 (PURPA)
authorizes entities generating electricity from waste fuel and renewable fuel or
utilizing steam for both generation and other purposes to force a public utility
to purchase the energy at an avoided cost. These laws, together with the FERC
mandating all public utilities under its jurisdiction to file tariffs providing
transmission access for sales of energy at wholesale, have caused electric
generation and the marketing of electric energy at wholesale to become extremely
competitive. While independent power producers, other than qualifying facilities
under PURPA, are regulated by the FERC, the FERC is allowing rates for the sale
of generation to be determined by the market rather than by costs if the
producer or marketer can demonstrate no market power. As a result of these
changes in the law and regulations, the traditional public utility, such as
Black Hills Power, is more likely to purchase energy required for its franchised
service territories through competitive bidding and either not expand its rate
base generating capabilities or engage in the electric generation business
through independent power producers by selling to other utilities. (See ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -RESULTS OF OPERATIONS - Independent Power Business.)
Future generation, whether constructed by a public utility or an independent
power producer, is likely to be justified strictly on the basis of the
marketability of the capacity and energy from the new source in a competitive
market.
Black Hills Power could face the competition of industrial and public customers
constructing self-generation facilities using alternative fuels, such as waste
material, natural gas or oil. To date, Black Hills Power has not faced any
material competition from such sources and management does not believe that such
sources are cost effective and the company believes its rate design allows
flexibility in rates should competition become a threat, but no assurances can
be given that material competition from these sources will not occur.
Transmission Access
- -------------------
In 1996, the FERC adopted Order 888 that requires each public utility under its
jurisdiction to file open access transmission tariffs that provide rates which
are comparable to the same transmission costs of the public utility to transmit
power over its system. The rates provide for various transmission services to be
provided for any competitor but apply to the transmission of electric power for
wholesale purposes only. FERC has established Black Hills Power's open access
transmission tariffs (See ITEM 3. LEGAL PROCEEDINGS - Transmission Rates - FERC
Proceedings). The regulations further require the public utility to keep posted
for public access, on an electronic bulletin board, all current information
concerning the availability and rates for these transmission services. Black
Hills Power was granted an extension by FERC to delay establishing an electronic
bulletin board until WAPA, which operates the control area in which Black Hills
Power is located, establishes or participates in an electronic bulletin board.
The public utilities are further required by FERC to adopt standards of conduct
which require the functional separation of those persons who operate and market
the transmission system from those persons who buy and sell power for the same
utility; however, the FERC granted a waiver to Black Hills Power from the
requirement to adopt the standards of conduct in view of Black Hills Power's
small transmission system and lack of significant market control. The
regulations are designed to attempt to eliminate any market advantage of the
utility owning transmission over others engaged in the sale of electric power at
wholesale.
The new FERC regulations requiring the filing of open access tariffs does not
apply to the nonjurisdictional utilities such as the RECs and publicly owned
electric utilities. However, these nonjurisdictional utilities are subject to
the law that allows the FERC to force them to provide transmission services upon
application, and the FERC has adopted reciprocity regulations that would
authorize a jurisdictional utility to deny transmission access to a
nonjurisdictional utility which has denied access.
Black Hills Power currently furnishes transmission service for competing RECs
through contract. As long as the states in which Black Hills Power operates
continue to grant exclusive service territories, the federal government does not
preempt this state jurisdiction and municipalities in Black Hills Power's
service territory do not establish municipal electric systems, the increase in
transmission access for wholesale purposes through Black Hills Power's
transmission system is not likely to have any material adverse effect upon Black
Hills Power. Such open access may have a beneficial effect by opening
opportunities for the Company to further the marketing of coal-fired energy
outside of its service territory.
Retail Wheeling
- ---------------
Legislative proposals requiring a public utility to allow its competitors to
utilize the utility's electric distribution system to serve end-use customers
who are located in service areas assigned to that public utility, commonly
referred to as retail wheeling, are getting serious consideration in Congress
and in many states. Since the duplication of electric transmission and
distribution systems would neither be efficient nor tolerable by the public, the
transmission and distribution portion of the business is likely to continue to
be regulated with rates based on costs. The Company cannot predict when and if
mandated retail wheeling will come to the areas where it now provides exclusive
retail electric service. Major problems should be resolved first, such as the
preservation of reliable service, compensation to a utility for investment
incurred to fulfill its duty to serve but stranded because of competition,
fairness of market pricing between large industrial users and small business and
residential users and assurances that all utilities, including the RECs, are
bound to operate under the same rules.
The SDPUC and WPSC continue to monitor the potential impacts of electric utility
industry restructuring and retail competition in South Dakota and Wyoming. At
this time, South Dakota does not have any legislative activity regarding retail
wheeling. During the 1999 legislative session, the Wyoming State Senate rejected
a bill which would have required the WPSC to hold formal hearings and provide a
report regarding the effects of retail wheeling in Wyoming. Several credible
studies, including a study for the US Department of Energy, have indicated that
electric rates for residential customers in South Dakota and Wyoming may
increase if there is national retail competition. The Company is unable to
predict whether Congress or the states may in the future require electric retail
competition and, if they do, whether the ground rules for competition will be
fair to all participants including its related impacts on customers rates.
Management is unable to predict the effect of full electric retail competition
on the Company's earnings. Management does anticipate that a transition period
of at least five years will be required to achieve a fully competitive electric
energy retail market. During that five years, Black Hills Power will endeavor to
increase its earnings through additional sales and cost management. Based upon
the FERC's expressed positions concerning open access transmission regulations,
electric utilities which will lose revenues due to competition should be allowed
recovery of stranded costs. The market price of electric energy in a fully
competitive market is expected to be based upon a much wider geographical area
than just Black Hills Power's service territory. Because energy providers are
likely to seek the markets where the highest profit margins can be realized,
today's rates designed to serve exclusive service territories may be
substantially different for service to a fully competitive market. Lower rates
today are partially caused by excess generation capacity which allows providers
to sell energy above their marginal costs but below full costs.
However, the Company is unable to predict future markets and economic conditions
and government actions or inaction that could have a materially adverse affect
on Black Hills Power's ability to compete in a fully competitive electric power
market and to maintain its equity return on investment. (See ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)
Regulatory Accounting
- ---------------------
Black Hills Power follows Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation," 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 recent regulatory activity, a 50-year depreciable life
for NS #2 is used for financial reporting purposes. If Black Hills Power were
not following SFAS 71, a 35 to 40 year life would probably be more appropriate
which would increase depreciation expense by approximately $600,000 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 noncash 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.
RESULTS OF OPERATIONS
Consolidated Results
- --------------------
The Company reported record earnings for 1998 (before a special non-cash
charge), due to sales growth in electric operations and record coal and oil and
gas production, partially offset by lower oil and natural gas prices.
Consolidated net income for 1998 was $25,808,000 compared to $32,359,000 in 1997
and $30,252,000 in 1996 or $1.19 per average common share in 1998, compared to
$1.49 and $1.40 per averaged common share in 1997 and 1996, respectively. This
equates to a 12.5 percent return on year-end common equity in 1998, 15.8 percent
return on year-end common equity in 1997, and 15.7 percent in 1996.
In 1998, the Company recorded an $8.8 million (net-of-tax) charge to earnings
related to a write down of oil and natural gas properties. Absent this charge,
the Company's earnings per average common share for 1998 would have been $1.60,
a 7 percent increase as compared to 1997, and a return on year-end common equity
of 16.1 percent.
Consolidated revenue and net income (loss) provided by the four business
segments as a percentage of the total were as follows:
1998 1997 1996
---- ---- ----
Revenue:
Electric 19% 40% 73%
Energy extraction
and production:
Coal mining 5 10 19
Oil and gas 2 4 8
Energy Marketing 74 46 -
-- -- --
100% 100% 100%
=== === ===
1998 1997 1996
---- ---- ----
Net Income (Loss):
Electric 96% 68% 61%
Energy extraction
and production:
Coal mining 37 28 32
Oil and gas (31) 7 7
Energy marketing (1) (2) -
Communications
and other (1) (1) -
-- -- --
100% 100% 100%
=== === ===
Dividends paid on common stock totaled $1.00 per share in 1998. This reflected
increases approved by the Board of Directors from $0.95 per share in 1997 and
$0.92 per share in 1996. All dividends were paid out of current earnings. The
Company's dividend objective is to increase the dividend at or above the
electric utility average and reduce the Company's payout ratio to the low 60's.
Management believes this objective is attainable through earnings growth. The
Company's three year dividend growth rate was 4.0 percent and the payout ratio
for 1998 was 63 percent, excluding the effect of the special non-cash charge.
In January 1999 the Board of Directors increased the quarterly dividend 4.0
percent to 26 cents per share. If this dividend is maintained during 1999, it
will be equivalent to $1.04 per share, an annual increase of 4 cents per share.
Electric Operations
- -------------------
1998 1997 1996
---- ---- ----
(in thousands)
Revenue $129,236 $126,497 $118,718
Operating
expenses 79,340 81,886 79,628
-------- -------- --------
Operating income $ 49,896 $ 44,611 $ 39,090
======== ======== ========
Net income $ 24,825 $ 22,106 $ 18,333
======== ======== ========
Electric revenue increased 2.2 percent in 1998 compared to a 6.6 percent
increase in 1997 and a 9.1 percent increase in 1996. Firm kilowatthour sales
decreased 0.4 percent in 1998 compared to a 13 percent increase in 1997 and a
3.9 percent increase in 1996 and have averaged an annual 5.5 percent growth rate
over the last three years.
The increase in electric revenue in 1998 was primarily due to a 60 percent
increase in non-firm sales and a 2 percent increase in commercial sales
partially offset by 4 percent decrease in industrial sales primarily due to
Homestake's restructuring. Firm kilowatthour sales declined slightly due to
Homestake but total kilowatthour sales increased 4 percent primarily due to a 33
percent increase in off-system sales. Degree days, a measure of weather trends,
were 2 percent below 1997 and 4 percent below normal.
The increase in electric revenue and firm kilowatthour sales in 1997 was
primarily due to the additional load to serve MDU's energy requirements for its
customers in the Sheridan, Wyoming area. Partially offsetting the increase,
residential sales declined 3 percent primarily due to milder weather. Degree
days were 15 percent below 1996 and 2 percent below normal.
The increase in electric revenue in 1996 was due to strong sales growth in all
sectors of the Company's electric business, including the industrial sector and
the inclusion of NS #2 in the Company's rate base (See ITEM 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - RATE
REGULATION).
Revenue per kilowatthour sold was 5.4 cents in 1998 compared to 5.5 cents in
1997 and 5.8 cents in 1996. The number of customers in the service area
increased to 56,856 in 1998 from 56,269 in 1997 and 55,601 in 1996. The revenue
per kilowatthour sold in 1998 reflects the 33 percent increase in wholesale
non-firm sales to 371,100 megawatthours. The revenue per kilowatthour sold in
1997 reflects the increased wholesale sales to MDU's Sheridan, Wyoming customers
and 279,600 megawatthours of wholesale non-firm sales. The revenue per
kilowatthour sold in 1996 reflects the increase in electric rates and the strong
growth in the higher margin sectors of Black Hills Power's business offset by
the impact of 249,100 megawatt hours of wholesale non-firm sales in 1996.
Operating expenses have remained fairly stable over the last three years.
Operating expenses decreased in 1998, primarily due to lower purchased power
costs and strong operating cost management, partially offset by increased
property taxes and fuel expense. Purchased power costs declined due to the
renegotiated Pacific Power Sales Agreement (SEE ITEM 1. BUSINESS - ELECTRIC
POWER SUPPLY - Pacific Power's Power Sales Agreement). The increase in operating
expenses in 1997 are primarily due to the increased load requirements to serve
MDU's Sheridan, Wyoming energy needs. The increase in operating expenses and
depreciation associated in 1996 with the commercial operation of NS #2 were
offset by a decrease in fuel and purchased power costs.
Depreciation expense decreased 9 percent in 1997 as a result of the 1996
accelerated depreciation of the Kirk Power Plant.
Firm energy sales are forecasted to increase over the next 10 years at an annual
compound growth rate of approximately 1 percent with the system demand
forecasted to increase 2 percent. The Company currently has a winter peak of 344
MWs established in December 1998 and a summer peak of 348 MWs established in
July 1998. These forecasts are from studies conducted by the Company with the
help of outside consultants whereby Black Hills Power's service territory is
examined and analyzed 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. However, in the past
the forecasts tracked actual sales within a band of reasonableness over a period
of several years. Weather deviations can adversely effect energy sales when
compared to forecasts based on normal weather.
Coal Mining Operations
- ----------------------
1998 1997 1996
---- ---- ----
(in thousands)
Revenue $31,413 $31,080 $31,315
Expenses 18,690 18,863 19,081
------ ------ ------
Operating income $12,723 $12,217 $12,234
======= ======= =======
Net income $ 9,585 $ 9,073 $ 9,934
======= ======= =======
Revenue and operating expenses have been fairly stable over the last three years
reflecting stable production and long-term coal contracts. Wyodak Resources had
record coal production of 3,280,000 tons in 1998 compared to 3,251,000 tons in
1997 and 3,243,000 tons in 1996.
Non-operating income was $1,063,000 in 1998 and $1,066,000 in 1997 compared to
$2,725,000 in 1996. Non-operating income includes gains or losses on sale or
disposal of property and equipment and interest income from investments.
Non-operating income in 1996 included a $700,000 gain realized on the disposal
of equipment and an increase in cash available for investment.
Wyodak Resources expects relatively stable sales in 1999 absent unplanned
outages at the Wyodak Plant or Black Hills Power's plants.
Oil and Gas Operations
- ----------------------
1998 1997 1996
---- ---- ----
(in thousands)
Revenue $12,562 $13,295 $12,555
Expenses 11,356 10,388 9,574
------ ------ -----
Operating income
before non-cash
charge 1,206 2,907 2,981
Ceiling test write down 13,546 - -
------ ------ ------
Operating income
(loss) $(12,340) $ 2,907 $ 2,981
======== ======= =======
Net income (loss) $ (7,976) $ 2,147 $ 2,198
======== ======= =======
In 1998, Western Production Company changed its name to Black Hills Exploration
and Production, Inc. to more closely identify it's activities with the Company.
Net income before the special non-cash charge and assets related to oil and gas
operations have been 7 percent or less of the Company's consolidated amounts
over the last three years.
Black Hills Exploration and Production's product sales and product prices for
the last three years were as follows: 1998 1997 1996 Barrels of oil 344,000
299,000 286,000 sold Mcf of natural 2,056,000 1,747,000 1,718,000 gas sold
Equivalent barrels 687,000 590,000 572,000 of oil sold Price per barrel $12.19
$19.05 $21.09 of oil Price per mcf of natural gas $1.97 $2.42 $2.05
Revenue decreased 5.5 percent in 1998 primarily due to 36 percent and 19 percent
lower oil and natural gas prices, respectively, partially offset by 15 percent
and 18 percent increases in oil and natural gas sales, respectively. In
addition, to mitigate the risk of declining product prices, the company hedged
certain oil production in Wyoming (excluded from the product prices noted above)
and recognized $939,000 in hedging gain (See NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS - Note 7 - Commitments and Contingent Liabilities - Price Risk
Management Activities).
Black Hills Exploration and Production's production expenses increased 9.3
percent in 1998, 8.5 percent in 1997, and 1.1 percent in 1996. Production
expenses increased in 1998 and 1997 due to increased depletion as a result of
increased oil and gas production and lower crude oil prices. Black Hills
Exploration and Production recognized $4,850,000, $3,920,000, and $3,434,000 of
depletion expense in 1998, 1997, and 1996, respectively. Low oil and gas prices
reduce the cash flow and value of the Company's oil and gas assets and cause the
Company to increase its depletion expense.
Black Hills Exploration and Production accounts for its oil and gas activities
using the full cost method of accounting (See NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS - Note 1 - Business Description and Summary of Significant
Accounting Policies - Oil and Gas Operations).
In December 1998, Black Hills Exploration and Production recognized a
$13,546,000 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. Absent other
factors impacting depletion expense, the Company expects future depletion
expense per unit of production to be reduced because of this write down.
Black Hills Exploration and Production's proved reserves and the revenues
generated from production decline as production occurs, except to the extent
successful exploration, development, and production enhancement activities are
conducted or additional proved reserves are acquired. Black Hills Exploration
and Production has been active in exploration and development drilling during
the past three years.
Black Hills Exploration and Production's drilling results were as follows:
1998 1997 1996
---------------------------------
Gross Net Gross Net Gross Net
Wells drilled 43 6.4 37 7.1 52 7.0
Producing 23 2.3 22 3.5 35 4.7
Success rate 53% 59% 67%
In April 1998, Black Hills Exploration and Production acquired approximately 3.7
billion cubic feet of natural gas in Wyoming for $1,836,000. In 1998, the
Company also acquired 88,000 barrels of oil and 0.1 billion cubic feet of
natural gas in the Finn Shurley Field for $404,000.
In 1997, Black Hills Exploration and Production acquired approximately 121,000
barrels of oil and 0.2 bcf of natural gas in the Finn Shurley Field for
$455,000.
In 1997 and 1996, Black Hills Exploration and Production sold certain interest
in natural gas properties for $165,000 and $380,000, respectively. Such sales
are not expected to materially impact future production.
Black Hills Exploration and Production intends to increase its net proved
reserves by selectively increasing its oil and gas exploration and development
activities and by acquiring producing properties primarily with the use of
internally generated funds and short-term borrowings.
Black Hills Exploration and Production's reserves are based on reports prepared
by Ralph E. Davis Associates, Inc. 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. Black Hills Exploration and Production's
unaudited reserves, principally proved developed and proved undeveloped
properties, were estimated to be 2.4, 2.5, and 2.4 million barrels of oil and
16.0, 9.1, and 11.0 billion cubic feet of natural gas as of December 31, 1998,
1997 and 1996, respectively. The increase in reserves at December 31, 1998, was
due to natural gas acquisitions and drilling results despite lower product
prices. The decrease in reserves at December 31, 1997 was due to lower oil and
gas prices and reductions in engineering estimates of recoverable reserves for
certain natural gas properties.
Independent Power Business
- --------------------------
In 1998, WYGEN, Inc. changed its name to Black Hills Generation, Inc.,
reflecting its alignment with the Company and its stated mission to build or
acquire electric generating assets. Black Hills Generation was formed in 1994
for the sole purpose of engaging in the generating and selling of electric power
and energy at wholesale and has exempt wholesale generator status under Section
32 of the Public Utility Holding Company Act. At this time Black Hills
Generation is proposing to build an 80 megawatt coal-fired electric generating
plant to be known as the WYGEN project adjacent to NS #2. In 1996, Black Hills
Generation received a prevention of significant deterioration air quality
construction permit from the DEQ. In addition, Black Hills Generation renewed
its prevention of significant deterioration air quality construction permit for
the WYGEN project with the DEQ in September 1998. Construction must commence
within one year of the renewal of the permit or Black Hills Generation will be
required to reapply. As an independent power project, the air quality permit is
the only major permit required. Viable markets for the electric power and energy
from the WYGEN project will depend partially upon the cost of transmission
rights to deliver the electric power and energy to higher priced energy markets.
While the FERC's open access transmission regulations should make such
transmission legally available, physical transmission constraints or the
perception of such constraints may require Black Hills Generation's
participation in transmission improvements which, together with transmission
rates for access across transmission systems, could make the WYGEN project less
economical. The economics of delivering power over multiple-owned transmission
systems will depend upon how successful the FERC is in bringing about regional
transmission systems operated independently of the interest of any one provider,
with mechanisms to pool costs and cause transmission system improvements to be
constructed, on a timely basis, with broad participation.
In addition to the WYGEN project, the Company is exploring opportunities for
participating in the acquisition of existing or new independent power projects
fueled by coal or natural gas and located at Wyodak Resources' mine or at other
locations in the United States. To date, such efforts have not resulted in
successful bids for such projects.
Energy Marketing Operations
- ---------------------------
1998 1997
---- ----
Revenue $506,043 $142,790
Expenses 506,002 143,615
-------- --------
Operating income $ 41 $ (825)
======== ========
Net loss $ (346) $ (749)
======== ========
The substantial increase in revenues and operating expenses and related
increases in accounts receivable and accounts payable balances is primarily due
to recording twelve months of operations for Black Hills Energy Resources in
1998. Black Hills Energy Resources was acquired in July 1997. Enserco Energy,
Inc.'s revenues and operating expenses were recorded using the equity method in
1997 and due to the acquisition of the shareholder interests in 1998 (discussed
below), include all 1998 revenues and operating expenses and related increases
in accounts receivable and accounts payable balances. Net income was adjusted
for the other shareholder interests prior to the reacquisition. Black Hills Coal
Network was formed in September 1998 (discussed below) and reflects activity
from the acquisition's effective date.
Energy marketing operations revenues and daily volumes by energy product for the
last two years are as follows:
1998 1997
---- ----
(in thousands)
Revenues:
Natural gas 375,934 95,980*
Crude oil 117,185 46,810*
Coal 12,924* -
Daily Volumes:
Natural gas (mmbtus) 487,000 231,000*
Crude oil (barrels) 19,000 12,600*
Coal (tons) 4,400* -
*Since the acquisition date.
The marketing operations are high volume, low margin businesses whose
contribution to consolidated earnings has not been significant.
Within the context of this report, an energy marketing company is a company that
sells and buys natural gas, crude oil, coal, and electric power at market prices
and ordinarily does not participate in the production of energy.
Black Hills Capital Group, Inc. was incorporated by the Company to hold the
Company's equity and debt investments in Black Hills Energy Resources, Inc.
VariFuel, Inc., Enserco Energy, Inc., and Black Hills Coal Network, Inc. In
addition to the energy marketing companies, Black Hills Capital Group will be
the primary vehicle for future corporate development activities outside of the
internal company specific activities.
Energy marketing operations expanded considerably in 1998 in terms of products,
customers, and volume. In September Black Hills Coal Network acquired Coal
Network and Coal Niche, Mason, Ohio-based coal marketing companies with customer
and supplier relationships east of the Mississippi. Enserco Energy, our Rocky
Mountain, Northwest and West Coast regions' natural gas marketing company,
reacquired the shares not owned by the company and expanded its Rocky Mountain
region service to retail customers with an acquisition of Platte River
Solutions' retail operations. Black Hills Energy Resources expanded its crude
oil marketing operations with additional sales from its 1997 expansion in Tulsa,
Oklahoma and Midland, Texas, and East Coast region retail gas sales with the
opening of an Allentown, Pennsylvania office.
Cost of natural gas, crude oil and coal sold (included in Fuel and Purchased
Power in the CONSOLIDATED STATEMENTS OF INCOME) relating to the above revenues
totaled $498,580,000 in 1998 and $141,726,000 in 1997. The increase in cost of
sales is primarily due to increased volumes as described in the revenue increase
above.
In 1998, the energy marketing companies incurred a net loss of $346,000 due to
mild weather conditions in certain markets and additional administrative
expenses incurred to expand its operations.
In 1997, the energy marketing companies incurred a net loss of $(749,000)
primarily due to mild weather conditions in its target markets, start-up
expenses and additional administrative expenses to expand its energy marketing
operations.
In July 1997, Black Hills Capital Group acquired the assets and hired the
operational management of Jomax Partners, L.P. as successor and survivor of
Wickford Energy Marketing, L.C. and Wickford Energy Marketing Canada Company.
Black Hills Energy Resources, Inc., is headquartered in Houston, Texas with a
natural gas sales office in Calgary, Alberta, Canada and crude oil sales offices
in Tulsa, Oklahoma, and Midland, Texas. Black Hills Energy Resources is a
"niche" wholesale natural gas and crude oil marketing company with expertise in
Gulf Coast and Canadian supply, targeting natural gas markets in the East Coast
and Midwest and crude oil markets primarily in the Southwest.
Black Hills Energy Resources has a $65,000,000 uncommitted line of credit with a
national bank ($50,000,000 for letters of credit and $15,000,000 for working
capital) to provide credit support for purchases and sales of natural gas and
crude oil. The Company does not provide credit support for this agreement.
In November 1997, Black Hills Capital Group, Inc. acquired the assets and hired
the operational management of VariFuel, Inc. (VariFuel). VariFuel targets
commercial and industrial natural gas customers located primarily in the
Chicago, Illinois and northern Indiana area. VariFuel is headquartered in
Houston, Texas with a sales office in Chicago, Illinois.
In 1996, Wyodak Resources, with the participation of three individuals, formed
an energy marketing startup company under the name of Enserco Energy, Inc.
(Enserco), headquartered in Lakewood, Colorado. Wyodak Resources also acquired a
convertible debenture from Enserco.
To provide Enserco with the financial backing to participate in the purchase and
sale of natural gas and electric power, Wyodak Resources has agreed to guarantee
up to $15,000,000 of letters of credit to be issued by banks to guarantee
purchases and sales of natural gas.
Enserco has acquired the approval from the FERC of a tariff which allows Enserco
to sell electric power at market prices. With the reacquisition of shares,
Enserco's FERC approval to market electric power needs recertification of FERC.
The company has not actively pursued the electricity market to date. Should
wholesale electricity market conditions stabilize, the company will review its
options at that time. Enserco is also qualified to purchase and sell natural gas
at market prices.
Although the energy marketing business is highly competitive, management is of
the opinion that due to the increasing competition in the energy business, it is
essential for many reasons to be active with the energy marketing business,
including the knowledge the Company gains in the marketing of energy, which is
required for the Company to effectively compete in all aspects of its energy
business.
The energy marketing companies generate large amounts of revenue and
corresponding expense related to buying and selling energy products. Associated
with the purchase and sale of energy products, the energy marketing companies
use derivatives (exchange traded and over-the-counter energy financial
instruments) to manage risk associated with the buying and selling of energy
products whose prices can be extremely volatile. The use of derivatives helps
mitigate risk in the trading of energy products but does not eliminate the risk.
Black Hills Capital Group and the energy marketing companies have adopted risk
management policies and established risk management committees to further
mitigate risk associated with the sale and purchase of energy products. Some
purchasers and sellers with whom the energy marketing companies transact
business require the utilization of letters of credit to assure the underlying
performance of the obligations between the parties. The failure of a party to
perform may result in a significant risk of loss to the energy marketing
companies and corresponding loss to Wyodak Resources as it concerns the
outstanding letters of credit to Enserco.
Communication and Technology Operations
- ---------------------------------------
In September 1998, Black Hills Capital Group formed Black Hills FiberCom, Inc.
to provide facilities-based communication services for Rapid City, and the
Northern Black Hills of South Dakota .
The newly formed company is expected to invest more than $50,000,000 over the
next three years in state-of-the-art technology that will offer local and long
distance telephone service, expanded cable television service, Internet access,
and high-speed data and video services. Construction began in the fourth quarter
of 1998 and will take two to three years to build out the complete fiber optics
system. The Company expects to begin serving customers by the summer of 1999.
The company plans to market the communications services to schools, hospitals,
cities, economic development groups, and business and residential customers.
Black Hills FiberCom is partnering with an international telecommunications
firm, GLA International, of St. Louis, Missouri, to build 200 mile fiber optic
backbone and a 500-mile hybrid fiber coaxial network in Rapid City and the
Northern Black Hills. GLA was the firm that helped develop the fiber networks
for Brooks Fiber Properties which was recently purchased by WorldCom. Black
Hills FiberCom is expected to have positive cash flow from operating activities
in its second year of operation and assets and net income are expected to
comprise less than 10 percent of consolidated assets and earnings when fully
implemented.
DAKSOFT, Inc. was incorporated by the Company in 1994, to develop and market
internally generated computer software associated with the Company's business
segments. Additionally, DAKSOFT has developed internet/intranet products which
are currently being used internally and marketed to third parties. In 1998 and
1997, DAKSOFT entered into agreements for the customized installation of its
Customer Information System (CIS) product. DAKSOFT's assets and net income are
expected to comprise less than 3 percent of consolidated assets and earnings.
Other Segments of Business
- --------------------------
Landrica was incorporated by the Company in March 1984, and holds minor
interests in real estate.
The financial position and results of operations of Black Hills Generation and
Landrica are not material to the Company.
Year 2000 Issues
- ----------------
What is referred to as the Year 2000 problem ("Year 2000 problem") is the result
of computer programs being written using two digits rather than four to define
the applicable year. Any of the Company's computer systems and products that
have date-sensitive software may recognize a date using "00" as the Year 1900
rather than the Year 2000. This could result in a system failure or
miscalculations causing disruptions of operations, including, among other
things, a temporary inability to process transactions, send invoices, or engage
in similar normal business activities.
Management has formed a Year 2000 Committee to establish and ensure the
Company's compliance with what is commonly known as the "Year 2000 problem". In
addition, consultants have been engaged in certain areas to assist with a
comprehensive review of the Company's state of readiness and to assist with any
necessary remedial plans for the Year 2000 date change. The Company's review
encompassed supporting information technology systems, product generation and
distribution systems, and business supply chain systems and infrastructure.
Management presently believes that with the modifications it is making to the
Company's existing software and conversions to new software, the Year 2000
problem can be mitigated. However, if such modifications and conversions are not
made, or are not completed on a timely basis, the Year 2000 problem could have a
material adverse effect on the Company's business, financial condition and
results of operations.
Management further believes that the cost of either repairing or replacing
certain business systems to ensure business continuance beyond Year 2000 should
not have a significant impact on the results of operations. The cost of the Year
2000 project is currently estimated at less than $1 million and is being funded
through operating cash flows. These costs are primarily attributable to the
purchase of new software and equipment which are expensed or capitalized on a
basis consistent with the Company's accounting policies for capital assets.
Other than seeking representations and assurances from third parties, the
Company has not made an assessment as to whether any of its customers, suppliers
or service providers will be affected by the date change. The Company's
business, financial condition and results of operations may be adversely
impacted should the efforts of customers, suppliers or service providers for the
Company to address the Year 2000 issue prove to be inadequate. The Company's
risk management program includes emergency backup and recovery procedures to be
followed in the event of failure of a business-critical system. These procedures
are being expanded to include specific procedures for potential Year 2000
issues. Contingency plans to protect the business from Year 2000-related
interruptions are being developed. These plans will be complete by June 1999 and
will include, for example, development of backup procedures, identification of
alternate suppliers and possible increases in safety inventory levels.
Accounting Pronouncements
- -------------------------
FASB Statement No. 130, "Reporting Comprehensive Income," adopted in 1998,
establishes standards of disclosure and financial statement display for
reporting total comprehensive income and the individual components thereof.
Adoption of Statement No. 130 did not impact the Company's financial position or
results of operations in 1998.
FASB Statement No. 131 "Disclosures about Segments of an Enterprise and Related
Information" requires that a publicly-held company report financial and
descriptive information about its operating segments in financial statements
issued to shareholders for interim and annual periods. The Statement also
requires additional disclosures with respect to products and services,
geographic areas of operation, and major customers. The Company adopted this
Statement in the fourth quarter of 1998. (See NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS - Note 11 - Summary of Information Relating to Segments of the
Company's Business.)
FASB Statement No. 132 "Employers' Disclosures about Pensions and Other
Postretirement Benefits - an amendment of FASB Statements No. 87, 88, and 106"
requires revised disclosures about pension and other postretirement benefit
plans. The Company adopted this Statement in the fourth quarter of 1998. (See
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 8 - Employee Benefit Plans.)
In March 1998, the Accounting Standards Executive Committee issued Statement of
Position 98-1, "Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use." The Statement is effective for fiscal years
beginning after December 15, 1998. Earlier application is encouraged in fiscal
years for which annual financial statements have not been issued. The Statement
defines which costs of computer software developed or obtained for internal use
are capitalized and which costs are expensed. The Company will adopt the new
Statement in 1999. The effect of adoption is not expected to materially affect
the Company's financial position or results of operations.
In May 1998, the Accounting Standards Executive Committee issued Statement of
Position 98-5, "Reporting on the Costs of Start-Up Activities." The Statement is
effective for fiscal years beginning after December 15, 1998. The Statement
defines one-time start up costs and requires such costs to be expensed as
incurred. The Company will adopt the new Statement in 1999. The effect of
adoption is not expected to materially affect the Company's financial position
or results of operations.
As a result of recent pronouncements issued by the Financial Accounting
Standards Board and the Emerging Issues Task Force, the Company's comprehensive
method of accounting for energy-related contracts and/or derivative instruments
and hedging transactions is changing effective January 1, 1999. The Company does
not anticipate that its current mark-to-market accounting for certain
fixed-price natural gas contracts will be significantly affected by the adoption
of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("Statement No. 133") or by the Emerging Issues Task
Force's conclusions in EITF 98-10, "Accounting for Energy Trading and Risk
Management Activities" ("EITF 98-10"). However, provisions in Statement No. 133
and in EITF 98-10 will affect the accounting for other trading and marketing
operations that are currently accounted for under the accrual method. Further,
provisions in Statement No. 133 will affect the accounting for and disclosure of
other contractual arrangements and operations of the Company.
The Company is required to adopt the provisions of EITF 98-10 effective January
1, 1999, while the transition rules under Statement No. 133 provide for early
adoption as of the beginning of any fiscal quarter subsequent to June 15, 1998.
Management anticipates that implementation of the provisions of these standards
will not have a material impact on the Company's financial position at January
1, 1999. However, management believes that the adoption of the provisions of
these standards may affect the variability of future periodic results reported
by the Company, as well as its competitors. Such earnings variability, if any,
will likely result principally from valuation issues arising from imbalances
between supply and demand created by illiquidity in certain commodity markets
resulting from, among other things, the lack of mature trading and price
discovery mechanisms, transmission and/or transportation constraints resulting
from regulation or other issues in certain markets and the need for a
representative number of market participants maintaining the financial liquidity
and other resources necessary to compete effectively. Management will continue
to monitor exposure to these and other market and business risks and will adjust
valuation reserves accordingly as indicated by changing circumstances.
BUSINESS OUTLOOK STATEMENTS
The following statements are based on current expectations. The statements under
this Business Outlook Statements section are forward-looking, and actual results
may differ materially.
Pacific Power's Power Sales Agreement
- -------------------------------------
Pacific Power's Power Sales Agreement represents Black Hills Power's
highest-cost electric power resource. Black Hills Power has been able to utilize
the 75 MW resource from Pacific Power's Power Sales Agreement at a load factor
of only 60 percent. Black Hills Power expects to reduce these costs in the
future through better utilization of the resource through a marketing program
and as a result of the Second Restated and Amended Power Sales Agreement
executed between Pacific Power and Black Hills Power. This marketing program
will include the use of the Pacific Power's Power Sales Agreement under which
Black Hills Power has the right to cause the power and energy to be delivered at
any point on Pacific Power's transmission system (defined as both Pacific
Power's owned and contracted transmission paths) where capacity is available.
This Second Restated and Amended Power Sales Agreement, effective August 1,
1997, and terminating December 31, 2023, supersedes the Restated Agreement,
which was intended to be effective January 1, 2000.
The Second Restated Agreement provides (i) that 25 megawatts of the contract
capacity amount and the charges thereof will be deleted, 5 megawatts each year
commencing in the year 2000, (ii) Black Hills Power shall pay no levelized
annual charges for Colstrip Plants' additions and replacements which are
completed after January 1, 1997, (iii) that commencing January 1, 1997, the
company's fixed cost components of the Variable Costs shall be based on an
assumption that the Colstrip Plants operated at an 80 percent load factor, (iv)
beginning August 1, 1997 and continuing until December 31, 1999, Black Hills
Power shall pay Pacific Power annual fixed cost of $164.59 per kW-yr multiplied
by the capacity purchased, (v) commencing January 2000 and continuing until
December 2018, Black Hills Power shall pay Pacific Power's initial investment in
Colstrip Units 3 and 4 using Pacific Power's then most current applicable cost
of capital consisting of Pacific Power's then current FERC approved capital
structure, Pacific Power's then current weighted average cost of long-term debt
and preferred stock using FERC approved methods and Pacific Power's then current
FERC approved cost of common equity, (vi) that the monthly invoices for the
fixed amount calculated above shall be reduced by $95,564 for the years 2000
through 2009, and (vii) unbundling of the transmission charge in the contract to
Pacific Power's FERC-filed rates. Future cost reductions or increases related to
these amendments will depend on Pacific Power's future capital structure and
cost of capital and the cost of replacement power starting in the year 2000.
However, the Company believes the reduction of the 25 MWs of capacity which
begins in the year 2000 at a rate of 5 MW a year is positive as the Company
enters a deregulated electricity market and believes Pacific Power's future cost
of capital under the FERC approved capital structure will be lower than the cost
of capital formulas embedded in the existing contract.
Future Electric Sales
- ---------------------
Future earnings from all power sales are dependent on many economic and
political factors, including the move toward competition at the retail level,
the market price of electricity, the ability of Black Hills Power to generate
and deliver electric power at a cost that will allow a profit margin and the
regulatory treatment of electric utilities during the transition period toward
competition.
In order to realize a higher margin of profit than from sales on the spot
market, Black Hills Power continues to look for opportunities to sell power
off-system . The highly competitive wholesale electric power market, the lack of
an open retail market at this time, the cost of transmission to deliver the
power to markets where prices are higher, the current low natural gas prices and
the availability of surplus capacity and energy are the current competitive
conditions that make it difficult to find new markets. However, management
believes that Black Hills Power's marginal production costs are low enough and
the quantity of power Black Hills Power has available high enough that new
opportunities for off-system sales are feasible.
Future Retail Wheeling
- ----------------------
Management is unable to predict the effect of full electric retail competition
(if it comes about) on the Company's earnings. Management does anticipate that a
transition period of at least five years will be required to achieve a fully
competitive electric energy retail market. Black Hills Power continues to
endeavor to increase its earnings through additional sales and cost containment.
Based upon the FERC's expressed positions concerning open access transmission
regulations, electric utilities which will lose revenue due to competition
should be allowed to recover stranded costs. The market price of electric energy
in a fully competitive market is expected to be based upon a much wider
geographical area than just Black Hills Power's service territory. Because the
energy providers are likely to seek the markets where the highest profit margin
can be realized, today's rates designed to serve exclusive service territories
may be substantially different for service to a fully competitive market. Based
upon industry predictions, management believes that the industry's excess
capacity will be more fully utilized in the future. Management believes that
coal-fired plants will become more competitive with natural gas-fired plants in
the future as natural gas prices increase.
However, the Company is unable to predict future markets and economic conditions
and government actions or inactions that could have a materially adverse effect
on Black Hills Power's ability to compete in a fully competitive electric power
market and to maintain its equity return on investment.
Rate Regulation
- ---------------
Management's expectation is that the rate settlements made with the South Dakota
and Wyoming Commissions in 1995 are beneficial in that (i) management has
confidence in the operational capability of Black Hills Power's power plants;
(ii) management does not anticipate purchasing any substantial amount of
capacity and energy during the freeze period except for its existing purchase
power agreements; and (iii) Wyodak Resources' mining costs are not expected to
materially increase. Absent unplanned state or Federal requirements to
deregulate the electric utility industry in South Dakota or Wyoming, the Company
expects its electric operations to be regulated by the SDPUC and WPSC.
Future Coal Sales
- -----------------
Many factors can significantly affect sales of coal and revenue under the
existing contracts. Examples include the seller's or buyer's inability to
perform due to machinery breakdown, damage to equipment, governmental
impositions, labor strikes, coal quality problems, transportation problems and
other unexpected events, including a material breach of an obligation under
existing contracts.
The coal mining industry is highly competitive and significant new sales
opportunities are limited. Wyodak Resources operates in an area with many other
mining companies which have substantial unused capacity. They, like Wyodak
Resources, have the permits and capability for large increases in production.
Currently, Wyodak Resources' coal sales are confined to sales for consumption at
or near the mine. Wyodak Resources is a relatively small coal mine in relation
to others in the area and its current production costs exceed the current spot
market price for coal.
Because of an acquisition of unit train load-out facilities with the Clovis
Point Mine Properties, Wyodak Resources expects to increase its market
opportunities. However, the heating value (approximately 8,000 Btu per pound) of
the coal at Wyodak Resources' mine and the Clovis Point Mine Properties is
approximately 400 to 800 Btus less than Powder River Basin coal available at
other locations. This difference in the Btu value combined with relatively high
mining costs due to low production volumes makes Wyodak Resources' coal
noncompetitive in the current market for coal to be shipped by rail over long
distances because of higher freight rates per Btu. Notwithstanding this
limitation, the acquisition of a unit train loadout facility has led management
to investigate opportunities for Wyodak Resources to ship coal by rail at closer
distances where the Btu difference would not be a major factor, to ship coal
that is enhanced at the coal mine site by various processes, one of the results
of which would remove some of the moisture content of the coal and thereby
increase the Btu per pound content and to the acquisition of the coal marketing
companies to enhance future coal sale opportunities.
Processes for the enhancement of Powder River Basin coal are being developed and
seriously considered for commercial operations by the coal industry. Wyodak
Resources continues to investigate several coal enhancement opportunities but
has not invested significant capital in any of the processes. Management can
give no assurances at this time that any coal enhancement process will be
economically viable at Wyodak Resources' mine due to several factors including:
the current low spot market price of Powder River Basin coal, technical
limitations of many of the coal enhancement processes developed to date, and an
uncertain market demand for enhanced Powder River Basin coal.
Freight rates to ship coal by rail are also a material factor in determining the
economic feasibility of selling either raw run-of-the-mine coal or enhanced coal
products. At this time only one rail carrier, the Burlington Northern, is
available to Wyodak Resources for such sales. Reasonable freight rates are a
requirement for any rail transported sales from Wyodak Resources' mine.
Future Oil and Gas Sales
- ------------------------
Many factors can significantly affect sales of oil and natural gas and the
corresponding revenues under existing or future agreements. Such factors
include, but are not limited to, the seller's or buyer's inability to perform
due to equipment malfunctions, damage to equipment, and transportation problems
which could result from the Company or third party providers of such services,
governmental impositions, labor problems, weather problems, economic factors,
and other unexpected events.
The oil and natural gas industry is highly competitive and the Company's ability
to obtain rights to drill future oil and natural gas wells and/or acquire such
properties is subject to the Company's availability to obtain such opportunities
on an economic basis.
The Company is unable to predict future markets, technological advancements, and
economic conditions that could effect the profitability and probability of
success of the oil and natural gas operations.
Future Energy Marketing Sales
- -----------------------------
The profitability of the Company's energy marketing operations depends in large
part on management's ability to assess and respond to changing market
conditions. Such conditions include, but are not limited to, availability of
supply, availability of transportation capacity from supply area to markets
served, operating margins on sales and market demand. In addition, such
operations are highly sensitive to weather conditions in the markets served. The
Company is unable to predict future markets and economic conditions that could
effect the profitability of the energy marketing operations.
Future Communication and Technology Activities
- ----------------------------------------------
The Company's start-up communications operations are expected to have operating
losses for two to four years. The recovery of capital investment and future
profitability are dependent primarily on the ability of the Company to attract
new customers and customers from incumbent providers including U.S. West
Communications and Telecommunications, Inc. (TCI) the incumbent telephone and
cable television providers. Although the Company does not anticipate being
regulated in the local markets it is unable to predict future markets, future
government impositions, and future economic conditions that could effect the
profitability of the communication and technology operations.
Future Corporate Development Activities
- ---------------------------------------
The Company's corporate development activities are accomplished through Black
Hills Capital Group. Black Hills Capital Group's focus is to increase the
Company's earnings and assets through energy and communication related
investments that position the Company to earn multiple revenue streams.
Potential investments could be comprised of independent power projects, coal
reserves, oil and gas reserves, energy transportation assets, energy marketing
assets, communication assets or other related assets. The success of Black Hills
Capital Group acquiring such assets will depend on future market conditions. The
market for such assets is very competitive. The Company is unable to predict
future markets and economic conditions that could effect the profitability and
probability of the success of corporate development activities.
Risks and Uncertainties
- -----------------------
The forward looking statements contained in the Management's Discussion and
Analysis of Financial Condition and Results of Operations involve a number of
risks and uncertainties. In addition to factors discussed above, other factors
that could cause actual results to differ materially are the following: the
extent to which the federal government or the state governments, or both,
institute competition in the electric utility business; the market value of
electric power at the time of full competition, of including any competitor's
delivery costs to Black Hills Power's current markets and Black Hills Power's
ability to produce and deliver power at those market prices; the extent to which
the surplus electric generation continues; the extent that any electric
generating surplus is exhausted and customers are again entering into
longer-term purchased power contracts with prices relating more to the full cost
of generating and delivering electric power than to spot market energy prices;
the future market prices of crude oil, natural gas and coal; the Company's
ability to produce coal, oil and natural gas at costs maintaining historical
profit margins consistent with contractual sales obligations; government
regulations of the environment, especially to the extent to which further
financial burdens may be placed upon coal versus natural gas and additional
governmental burdens that may be placed upon the burning of all fossil fuels;
the extent to which competition will be fairly administered for participants in
the electric utility business and whether it will be applied equally to
investor-owned companies, rural electric cooperatives, public power agencies and
municipalities; technological advances in the generation and delivery of
electric power; the general economy as it affects the use of electric power; the
market price of competing fuels to electricity, such as natural gas; the extent
to which coal beneficiation programs are efficiently developed and the extent to
which the new coal products will be accepted by the market; the Company's
ability and success in implementing its communications strategy; technological
advances in communications delivery equipment; the general economy of Black
Hills Power's retail service territory; and other risk factors which are
referenced in this report and other SEC reports filed prior hereto.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants 37
Consolidated Statements of Income and Retained Earnings
for the three years ended December 31, 1998 38
Consolidated Statements of Cash Flows for
the three years ended December 31, 1998 39
Consolidated Balance Sheets as of December 31, 1998 and 1997 40
Consolidated Statements of Capitalization as of
December 31, 1998 and 1997 41
Notes to Consolidated Financial Statements 42
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Black Hills Corporation:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Black Hills Corporation and Subsidiaries as of December 31,
1998 and 1997, and the related consolidated statements of income, retained
earnings and cash flows for each of the three years in the period ended December
31, 1998. 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 Black Hills Corporation and
Subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota,
January 27, 1999
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31 1998 1997 1996
- ----------------------- ---- ---- ----
(in thousands, except per share amounts)
Operating revenues:
Electric $129,236 $126,497 $118,718
Coal mining 31,413 31,080 31,315
Oil and gas 12,562 13,295 12,555
Energy marketing 506,043 142,790 -
------- ------- -------
679,254 313,662 162,588
------- ------- -------
Operating expenses:
Fuel and purchased power 531,518 177,071 34,195
Operations and maintenance 32,701 31,743 30,343
Administrative and general 15,747 12,113 8,491
Depreciation, depletion and amortization 24,037 22,311 22,794
Oil and gas ceilings test write down 13,546 - -
Taxes, other than income taxes 12,472 11,985 12,460
------ ------ ------
630,021 255,223 108,283
------- ------- -------
Operating income 49,233 58,439 54,305
------ ------ ------
Other income (expense):
Interest expense (14,707) (14,123) (13,942)
Investment income 2,861 2,136 1,373
Other, net 129 233 2,094
------- ------- -------
(11,717) (11,754) (10,475)
------- ------- -------
Income before income taxes 37,516 46,685 43,830
Income taxes (11,708) (14,326) (13,578)
------- ------- -------
Net income $ 25,808 $ 32,359 $ 30,252
======== ======== ========
Earnings per share of common stock:
Basic and diluted $1.19 $1.49 $1.40
===== ===== =====
Weighted average common shares outstanding:
Basic 21,623 21,692 21,660
====== ====== ======
Diluted 21,665 21,706 21,660
====== ====== ======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years ended December 31 1998 1997 1996
- ----------------------- ---- ---- ----
(in thousands)
Balance, beginning of year $143,703 $131,884 $121,562
Net income 25,808 32,359 30,252
Cash dividends on common stock ($1.00,
$0.95 and$0.92 per share, respectively) (21,737) (20,540) (19,930)
------- ------- -------
Balance, end of year $147,774 $143,703 $131,884
======== ======== ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31 1998 1997 1996
---- ---- ----
(in thousands)
Operating activities:
Net income $25,808 $32,359 $30,252
Principal non-cash items-
Depreciation, depletion and amortization 24,037 22,311 22,794
Oil and gas ceilings test write down 13,546 - -
Deferred income taxes and investment tax
credits (2,535) 2,457 1,872
Increase in receivables, inventories and
other current assets (49,775) (27,067) (373)
Increase (decrease) in current liabilities 43,709 26,015 (1,412)
Other, net (60) (26) 2,264
------ ------ ------
54,730 56,049 55,397
------ ------ ------
Investing activities:
Property additions, excluding allowance
for other funds used during construction (25,265) (21,087) (24,388)
Energy marketing assets (1,960) (7,232) -
Available for sale securities purchased (22,361) (31,944) (40,894)
Available for sale securities sold 13,655 29,433 36,189
(35,931) (30,830) (29,093)
Financing activities:
Dividends paid (21,737) (20,540) (19,930)
Treasury stock, net (3,081) - -
Common stock issued 273 409 511
Increase (decrease) in short-term borrowings 5,067 (120) (475)
Long-term debt issued - - 156
Long-term debt retired (1,331) (1,534) (1,405)
------- ------- -------
(20,809) (21,785) (21,143)
------- ------- -------
Increase (decrease) in cash and cash
equivalents (2,010) 3,434 5,161
Cash and cash equivalents:
Beginning of year 16,774 13,340 8,179
------ ------ -----
End of year $14,764 $16,774 $13,340
======= ======= =======
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $14,742 $14,167 $13,996
Income taxes $13,135 $11,840 $12,616
Assumption of reclamation liability in
acquisition of Clovis Point properties $ - $ - $ 7,957
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
At December 31, 1998 1997
- --------------- ---- ----
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 14,764 $ 16,774
Securities available for sale 22,675 13,969
Receivables, net
Customers 87,068 39,639
Other 2,919 3,414
Materials, supplies and fuel 9,733 8,642
Prepaid expenses 3,321 1,571
------- ------
140,480 84,009
------- ------
Property and equipment:
Electric 496,883 487,424
Coal mining 51,889 52,804
Oil and gas 62,581 52,412
Other 8,196 5,666
619,549 598,306
Less accumulated depreciation and depletion (229,942) (197,179)
-------- --------
389,607 401,127
-------- --------
Deferred charges:
Federal income taxes 12,347 8,061
Regulatory asset 3,978 3,776
Other 13,005 11,768
-------- --------
29,330 23,605
-------- --------
$559,417 $508,741
======== ========
LIABILITIES AND CAPITALIZATION
Current liabilities:
Current maturities of long-term debt $ 1,330 $ 1,331
Notes payable 5,090 23
Accounts payable 74,087 32,622
Accrued liabilities-
Taxes 9,950 8,040
Interest 3,956 3,991
Other 8,169 7,800
------- ------
102,582 53,807
------- ------
Deferred credits:
Federal income taxes 55,107 53,010
Investment tax credits 3,514 4,014
Reclamation liability 17,000 16,664
Regulatory liability 5,661 6,152
Other 6,857 6,331
------ ------
88,139 8,171
------ ------
Commitments and contingent liabilities (Notes 6, 7 and 8)
Capitalization, per accompanying statements:
Common stock equity 206,666 205,403
Long-term debt 162,030 163,360
-------- --------
368,696 368,763
-------- --------
$559,417 $508,741
======== ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1998 1997
- --------------- ---- ----
(in thousands)
Common stock equity:
Common stock $1 par value; 50,000,000 shares
authorized; 21,719,465 and 21,704,592 shares
outstanding, respectively $ 21,719 $ 21,705
Additional paid-in capital 40,254 39,995
Retained earnings 147,774 143,703
Treasury stock (3,081) -
------- -------
Total common stock equity 206,666 205,403
------- -------
Long-term debt:
First mortgage bonds-
6.50% due 2002 15,000 15,000
9.00% due 2003 5,295 6,336
8.06% due 2010 30,000 30,000
9.49% due 2018 5,710 6,000
9.35% due 2021 35,000 35,000
8.30% due 2024 45,000 45,000
------- -------
136,005 137,336
------- -------
Other-
6.7% pollution control revenue bonds, due 2010 12,300 12,300
7.5% pollution control revenue bonds, due 2024 12,200 12,200
Other long-term obligations 2,855 2,855
------ ------
27,355 27,355
------ ------
Total long-term debt 163,360 164,691
Current maturities (1,330) (1,331)
------ ------
Net long-term debt 162,030 163,360
------- -------
Total capitalization $368,696 $368,763
======== ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
1
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1998, 1997 and 1996
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation and its subsidiaries operate in four primary business
segments: electric, energy extraction and production (includes coal mining and
oil and natural gas operations), energy marketing, and communications. The
Company's electric utility operation is engaged in the generation, purchase,
transmission, distribution and sale of electric power and energy in western
South Dakota, northeastern Wyoming and southeastern Montana. Sales of electric
power to the three largest electric customers represented 17 percent of the
Company's electric revenue in 1998, 18 percent in 1997 and 17 percent in 1996.
The coal mining operation of the Company, located in northeastern Wyoming, mines
and sells sub-bituminous coal primarily under long-term coal supply agreements.
As discussed in Note 6, approximately 74 percent of the coal mining operation's
sales are to the Wyodak Plant. Sales of coal to the Company and to PacifiCorp,
herein referred to as Pacific Power, represent 97 percent of total coal sales in
1998. The Company's oil and gas exploration and production business operates and
has working interests in properties located in the western and southern United
States. The Company's energy marketing businesses market natural gas, crude oil
and coal and provide related energy services to customers in the West Coast,
Northwest, Rocky Mountain, Southwest, Midwest and East Coast markets. The
Company's communication operations represent a start-up business to provide
communication services to Rapid City and the Northern Black Hills of South
Dakota and a software development and marketing company.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills
Corporation and its wholly owned subsidiaries. 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 $10,256,000, $11,089,000, and $10,384,000 in
1998, 1997, and 1996, respectively.
In 1998, Enserco Energy, Inc. ("Enserco") reacquired the other shareholders
interests effectively becoming a wholly-owned subsidiary. For the 1998 financial
statements, the Company consolidated Enserco as if it was wholly owned for the
entire year and reported a minority interest for the portion of net income due
the other shareholders. Investments in Enserco, in which in 1997 and 1996 the
Company had a 50 percent ownership interest, were accounted for on the equity
method of accounting.
The Company uses the proportionate consolidation method to account for its
working interests in oil and gas properties.
Regulatory Accounting
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 NS #2 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 $600,000 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.
Property
Property is recorded at cost which includes an allowance for funds used during
construction where applicable. The cost of electric property retired, together
with removal cost less salvage, is charged to accumulated depreciation. Repairs
and maintenance of property are charged to operations as incurred.
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 imposes a stricter criterion for assets by requiring that such assets be
probable of future recovery at each balance sheet date.
Depreciation and Depletion
Depreciation is computed using the straight-line method over the estimated
useful lives of the related assets. Depreciation provisions for the electric
property were equivalent to annual composite rates of 3.0 percent in 1998, and
1997 and 3.4 percent in 1996. Composite depreciation rates for other property
were 7.9 percent, 8.1 percent, and 7.7 percent in 1998, 1997 and 1996,
respectively. Depletion of coal and oil and gas properties is computed using the
cost method for financial reporting.
Available for Sale Securities
The Company has investments in marketable securities which are classified as
available-for-sale securities and are carried at fair value. The difference
between the securities' fair value and cost basis and the realized gains and
losses on sales of the securities were not significant for the periods
presented.
Revenue Recognition
Revenue from sales of electric energy is based on rates filed with applicable
regulatory authorities. Electric revenue includes an accrual for estimated
unbilled revenue for services provided through year-end. Revenue from other
business segments is recognized at the time the products are delivered or the
services are rendered.
Fuel and Purchased Power Adjustment Tariffs
The Company's Montana Retail Tariffs contain a clause that allow recovery of
certain fuel and purchased power costs in excess of the level of such costs
included in base rates. The cost adjustment tariff is revised periodically for
any difference between the total amount collected under the clause and the
recoverable costs incurred. The adjustments are recognized as current assets or
current liabilities until adjusted through future billings to customers.
The Company's South Dakota, Wyoming and wholesale tariffs do not include an
automatic fuel and purchased power adjustment tariff.
Use of Estimates
The preparation of 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
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.
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. Under the full cost method, net capitalized costs
may not exceed the present value of proved reserves.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFDC) represents the approximate
composite cost of borrowed funds and a return on capital used to finance
construction expenditures and is capitalized as a component of the electric
property. The AFDC was computed at an annual composite rate of 10.1 percent in
1998 and 10.0 percent in 1997 and 1996.
Income Taxes
The Company follows the provisions of SFAS No. 109, "Accounting for Income
Taxes," which requires the use of 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.
Price Risk Management
The Company utilizes deferral (hedge) accounting in conjunction with such
financial instruments; gains or losses from changes in the market value of the
financial instruments are deferred until the gain or loss on the hedged item is
recognized.
Financial instruments are classified as being used for a hedge only if the
instrument reduces the risk of the underlying hedged item and is designated at
the inception as a hedge with respect to the hedged item.
Accounting Pronouncements
FASB Statement No. 130, "Reporting Comprehensive Income," adopted in 1998,
establishes standards of disclosure and financial statement display for
reporting total comprehensive income and the individual components thereof.
Adoption of Statement No. 130 did not impact the Company's financial position or
results of operations in 1998.
In March, 1998, the Accounting Standards Executive Committee issued Statement of
Position 98-1, "Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use." The Statement is effective for fiscal years
beginning after December 15, 1998. Earlier application is encouraged in fiscal
years for which annual financial statements have not been issued. The statement
defines which costs of computer software developed or obtained for internal use
are capitalized and which costs are expensed. The Company will adopt the new
Statement in 1999. The effect of adoption is not expected to materially affect
the Company's financial position or results of operations.
In May 1998, the Accounting Standards Executive Committee issued Statement of
Position 98-5, "Reporting on the Costs of Start-Up Activities." The Statement is
effective for fiscal years beginning after December 15, 1998. The Statement
defines one-time start up costs and requires such costs to be expensed as
incurred. The Company will adopt the new statement in 1999. The effect of
adoption is not expected to materially affect the Company's financial position
or results of operations.
As a result of recent pronouncements issued by the Financial Accounting
Standards Board and the Emerging Issues Task Force, the Company's comprehensive
method of accounting for energy-related contracts and/or derivative instruments
and hedging transactions is changing effective January 1, 1999. The Company does
not anticipate that its current mark-to-market accounting for fixed-price
natural gas contracts will be significantly affected by the adoption of
Financial Accounting Standard No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("Statement No. 133") or by the Emerging Issues Task
Force's conclusions in EITF 98-10, "Accounting for Energy Trading and Risk
Management Activities" (EITF 98-10"). However, provisions in Statement No. 133
and in EITF 98-10 will affect the accounting for other trading and marketing
operations that are currently accounted for under the accrual method. Further,
provisions in Statement No. 133 will affect the accounting for and disclosure of
other contractual arrangements and operations of the company. The Company is
required to adopt the provisions of EITF 98-10 effective January 1, 1999, while
the transition rules under Statement No. 133 provide for early adoption as of
the beginning of any fiscal quarter subsequent to June 15, 1998. Management
anticipates that implementation of the provisions of these standards will not
have a material impact on the Company's financial position at January 1, 1999.
Reclassifications
Certain 1997 and 1996 amounts in the financial statements have been reclassified
to conform to the 1998 presentation. These reclassifications did not have a
material effect on the Company's stockholders' investment or results of
operations.
(2) CAPITAL STOCK
In January, 1998, the Board of Directors declared a 3-for-2 Common Stock Split
effected in the form of a stock dividend. The stock dividend was paid March 10,
1998 to shareholders of record on February 13, 1998. The common stock share and
per share information in the accompanying consolidated financial statements and
notes reflect the stock distribution.
Net Income Per Share
The Company follows SFAS No. 128 "Earnings Per Share", which requires the
presentation of basic and diluted earnings per share. 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.
A reconciliation of these amounts is as follows (in thousands, except per share
data):
1998 1997 1996
---- ---- ----
Net income $25,808 $32,359 $30,252
======= ======= =======
Weighted average
common shares
outstanding-basic 21,623 21,692 21,660
Dilutive effect of
option plan 14 42 -
------ ------ ------
Common and
potential common
shares outstanding-
diluted 21,665 21,706 21,660
====== ====== ======
Basic and diluted net
income per share $1.19 $1.49 $1.40
===== ===== =====
Common Stock
The Company has a stock option plan ("the 1996 Stock Option Plan") which allows
for the granting of stock options with exercise prices equal to the stocks'
market value on the date of grant and an employee stock purchase plan ("the ESPP
Plan"). The Company accounts for such plans under Accounting Principles Board
Opinion No. 25, under which no compensation cost has been recognized.
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 proforma amounts:
1998 1997 1996
---- ---- ----
(in thousands)
Net income:
As reported $25,808 $32,359 $30,252
Proforma $25,717 $32,308 $30,215
Earnings per share (basic and diluted):
As reported $1.19 $1.49 $1.40
Performa $1.19 $1.49 $1.39
The Company may grant options for up to 300,000 shares of common stock under the
Stock Option Plans. The Company has granted options on 292,700 shares and
182,700 shares through December 31, 1998 and 1997, respectively. The option
exercise price equals the fair market value of the stock on the day of the
grant. The options granted have an exercise price range of $16.67 to $25.00. The
options granted vest one-third a year for three years and all expire after ten
years from the grant date. At December 31, 1998, 84,800 options were available
for exercise at an exercise price range of $16.67 to $22.50. At December 31,
1997, 27,900 options were available for exercise at an exercise price of $16.67.
There were no options available for exercise at December 31, 1996.
The fair value of each option grant is estimated on the date of grant using the
Black Scholes option pricing model with the following weighted-average
assumptions used for the grants:
1998 1997 1996
---- ---- ----
(in thousands)
Risk free interest rate 5.50% 6.09% 6.15%
Expected dividend yield 4.20% 5.00% 5.50%
Expected life 10 years 10 years 10 years
Expected volatility 16.67% 16.71% 17.66%
Weighted average fair value $0.61 $1.09 $0.49
The Company issued 12,824 and 29,294 shares of common stock under the ESPP Plan
in 1998 and 1997, respectively. At December 31, 1998, 267,135 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 1998 was $19.38.
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
1998, 1997 and 1996. At December 31, 1998, 1,290,797 shares of unissued common
stock were available for future offerings under the Plan.
Additional Paid-in Capital
Changes in additional paid-in capital for the years indicated were:
1998 1997 1996
---- ---- ----
(in thousands)
Balance, beginning
of year $39,995 $46,841 $46,355
Stock Dividend for 3-for-2
Common Stock split - (7,235) -
Premium, net of expenses
from sales of stock 259 389 486
------- ------- -------
Balance, end of year $40,254 $39,995 $46,841
======= ======= =======
Treasury Stock
In 1998, a subsidiary of the Company was authorized to repurchase up to 300,000
shares of common stock to be used for acquisitions, development and other
corporate purposes. At December 31, 1998, the Company had reacquired 141,251
shares at an average price of $22.50 per share.
(3) LONG-TERM DEBT
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. Scheduled maturities of long-term debt
for the next five years are: $1,330,000 in 1999, $1,330,000 in 2000, $3,029,000
in 2001, $18,018,000 in 2002, and $3,068,000 in 2003.
(4) NOTES PAYABLE
The Company had $12,000,000 of unsecured short-term lines of credit at December
31, 1998 and 1997. There was $3,850,000 outstanding under these lines of credit
at December 31, 1998. There were no outstanding borrowings at December 31, 1997.
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 1998, Black Hills Coal Network acquired the assets of Coal Network, Inc. and
Coal Niche, Inc. The Company issued a $1,240,000 note payable to partially
finance the purchase. Black Hills Capital Group provided credit support for the
1999 and 2000 principal and interest payments due under this note payable
totaling $1,100,000.
In addition to the above lines of credit, Black Hills Energy Resources, Inc.
(formerly Wickford Energy Marketing, Inc.), has a $65,000,000, uncommitted,
discretionary credit facility consisting of a $50,000,000 transactional line of
credit and a $15,000,000 overdraft line of credit. The transactional line of
credit provides credit support for the purchases of natural gas and crude oil of
Black Hills Energy Resources. The Company and its subsidiaries provide no
guarantee to the Lender. At December 31, 1998, and 1997, Black Hills Energy
Resources had letters of credit outstanding of $27,990,000 and $29,000,000,
respectively, and no balance outstanding on the overdraft line of credit.
In addition to the above lines of credit, Wyodak Resources has guaranteed a
$15,000,000 line of credit for Enserco to use to guarantee letters of credit.
Enserco pays a 0.125 percent facility fee on this line of credit. At December
31, 1998 and 1997, there were no balances outstanding on this line of credit.
(5) 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 Company considers all highly liquid investments
with an original maturity of three months or less to be cash equivalents. 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.
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, 1998 and 1997, and the fair
value approximates 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:
1998
(in thousands)
Carrying Fair
Amount Value
------ -----
Cash and cash equivalents $ 14,764 $ 14,764
Securities available for sale:
Corporate debt securities 1,997 1,997
Federal, state and local
agency obligations 20,678 20,678
Long-term debt 163,360 189,767
1997
(in thousands)
Carrying Fair
Amount Value
------ -----
Cash and cash equivalents $16,774 $16,774
Securities available for sale:
Corporate debt securities 997 997
Federal, state and local
agency obligations 12,972 12,972
Long-term debt 164,691 189,649
(6) WYODAK PLANT
The Company owns a 20 percent interest and Pacific Power 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, 1998, the Company's investment in the
Plant included $72,979,000 in electric plant and $28,121,000 in accumulated
depreciation. The Company's share of direct expenses of the Plant was
$5,835,000, $5,934,000, and $6,458,000 for the years ended December 31, 1998,
1997 and 1996, 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 for 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, 1998, approximately 22,012,000 tons
were covered under this agreement. Wyodak Resources' sales to the Plant were
$23,228,000, $22,688,000, and $22,643,000 for the years ended December 31, 1998,
1997 and 1996, respectively.
(7) COMMITMENTS AND CONTINGENT LIABILITIES
MDU Power Sale
On January 1, 1997, the Company began service under a ten year contract to
supply up to 55 megawatts of electric power and associated energy required by
MDU for its Sheridan, Wyoming, service territory. In both 1998 and 1997, MDU's
Sheridan service area experienced a 47 megawatt peak, and had a load factor of
approximately 57 percent.
Coal Obligations
In addition to the 22,012,000 tons of coal reserved under the agreement to
supply coal to the Wyodak Plant, Wyodak Resources has reserved 25,125,000 tons
of coal under existing contracts.
Coal Leases
Wyodak Resources' mining rights to its coal are based upon four federal leases
and one state lease. The federal leases provide for a royalty of 12.5 percent of
the selling price of the coal. The state lease provides for a royalty, approved
in 1998, currently at 9 percent. Wyodak Resources paid royalties in the amount
of $4,009,000, $3,969,000, and $3,995,000 in 1998, 1997, and 1996, respectively.
Each federal lease requires diligent development to produce at least one percent
of all recoverable reserves within either 10 years from the respective dates of
the leases or 10 years from the date of adjustment of the leases. Each lease
further requires a continuing obligation to mine, thereafter, at an average
annual rate of at least one percent of the recoverable reserves. All of the
federal leases constitute one logical mining unit which is treated as one lease
for the purpose of determining diligent development and continuing operation
requirements.
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. 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
$17,458,000, $20,251,000, and $19,777,000 in 1998, 1997 and 1996, respectively.
Acquisition of Clovis Point Mine Properties
In 1996, Wyodak Resources purchased a portion of the Clovis Point and East
Gillette Mine properties from Kerr-McGee Coal Corporation. The Clovis Point Mine
properties are located adjacent to Wyodak Resources' current reserves in
Campbell County, Wyoming, and consist of State of Wyoming and federal leased
coal reserves.
Acquisition of the property in 1996 increased Wyodak Resources' reserves from
170 million tons to approximately 288 million tons and included a train loadout
facility, maintenance and processing facilities and a developed open pit.
The purchase price consisted of the assumption of the responsibility to reclaim
the existing Clovis Point open pit of which the Company recorded a liability of
$7,957,000 and the payment of overriding royalties to Kerr McGee if and when
coal is produced from the acquired properties. Wyodak Resources is not obligated
to mine the coal.
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 $700,000 is charged to operations as reclamation expense annually.
As of December 31, 1998, accrued reclamation costs were approximately
$17,000,000 which includes $7,957,000 for the Clovis Point Mine Acquisition.
Price Risk Management Activities
The Company utilizes a variety of financial instruments to hedge the impact of
price fluctuations on its oil and gas production and energy marketing
operations. The Company does not hold or issue derivative financial instruments
for trading purposes.
The primary financial instruments the Company uses in managing its price risk
exposure are exchange traded natural gas futures contracts, over-the-counter
natural gas and crude oil swaps, collar and option contracts. The Company would
be exposed to credit losses in the event of nonperformance by the counterparties
that have issued the financial instruments. The Company does not expect that the
counterparties will fail to meet their obligations, based on the Company's
review of the financial condition of the counterparties and/or their credit
ratings.
The notional quantities and maximum terms of derivative financial instruments
held for non-trading activities at December 31, 1998 are presented below:
Volume Max.
Purchased Term Fair Value
(MMBtu's) (Years) (in thousands)
--------- ------- --------------
Natural gas futures
contracts purchased 1,470,000 2 $(409)
Natural gas swap
contracts purchased 7,989,096 3 $(2,601)
Natural gas swap
contracts sold 1,473,000 1 $432
Because these contracts are entered into for hedging purposes, the Company
expects that the gains/(losses) will be largely offset by gains (losses) on the
underlying physical transactions. The notional amounts detailed above are
intended to be indicative of the Company's level of activity in such
derivatives.
At December 31, 1997, the Company had fixed rate for floating rate price swaps
to hedge crude oil price risk for 15,000 barrels of oil per month at prices
ranging from $19.00 per barrel to $20.93 per barrel which expired December 31,
1998. In addition, the Company had fixed rate for floating rate price swaps on
3.9 bcf of natural gas to hedge fixed price sales commitments in a similar
quantity.
Other
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.
(8) EMPLOYEE BENEFIT PLANS
The Company has a defined benefit pension plan (the Plan) covering substantially
all employees. 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 consist primarily of equity
securities and cash equivalents.
In December 1998, the Company adopted FASB Statement No. 132 "Employers'
Disclosures about Pensions and Other Postretirement Benefits - an amendment of
FASB Statements No. 87, 88, and 106" which requires revised disclosures about
pension and other postretirement benefit plans.
Net pension (income) expense for the Plan was as follows:
1998 1997 1996
---- ---- ----
(in thousands)
Service cost $ 895 $ 931 $ 874
Interest cost 2,406 2,383 2,239
Return on assets:
Actual (2,007) (10,278) (4,477)
Deferred (2,412) 7,022 1,502
------ ----- -----
Net pension (income)
expense $(1,118) $ 58 $ 138
======= ======= =======
Actuarial assumptions:
Discount rate 7.5% 7.5% 7.5%
Expected long-term rate
of return on assets 10.5% 10.5% 10.5%
Rate of increase in
compensationn levels 5% 5% 5%
Funding information for the Plan as of October 1 each year was as follows (the
discount rate assumption for obligations at 1998 was 6.75% and at 1997 was
7.5%):
1998 1997
---- ----
(in thousands)
Fair value of plan assets $40,638 $40,435
Projected benefit obligation (39,490) (33,025)
------- -------
1,148 7,410
Unrecognized:
Net gain (200) (7,579)
Prior service cost 528 618
Transition asset (180) (271)
------- -------
Prepaid pension cost $ 1,296 $ 178
======= =======
Accumulated benefit obligation $31,323 $27,133
======= =======
Vested benefit obligation $29,829 $25,995
======= =======
A reconciliation of the beginning and ending balances of the projected benefit
obligation is as follows:
1998 1997 1996
---- ---- ----
(in thousands)
Beginning projected
benefit obligation $33,025 $32,722 $30,714
Service cost 895 931 874
Interest cost 2,406 2,383 2,239
Actuarial gains (losses) 4,968 (1,215) 603
Benefits paid (1,804) (1,796) (1,708)
------ ------ ------
Net increase 6,465 303 2,008
------ ------ ------
Ending projected
benefit obligation $39,490 $33,025 $32,722
======= ======= =======
A reconciliation of the fair value of plan assets as of October 1 of each year
is as follows:
1998 1997
---- ----
(in thousands)
Beginning market value
of plan assets $40,435 $31,953
Benefits paid (1,804) (1,796)
Investment income 2,007 10,278
------- -------
Ending market value
of plan assets $40,638 $40,435
======= =======
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 $395,000, $94,000 and $498,000 in 1998,
1997, and 1996, respectively.
The Company follows the provisions of SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." The standard requires that the
expected cost of these benefits must be charged to expense during the years that
the employees render service. Prior to adopting the standard in 1993, the
Company expensed these benefits as they were paid. The Company is amortizing the
transition obligation of $2,996,000 over a 20 year period.
Employees retiring from the Company on or after attaining age 55 who have
rendered 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 for the Company was as follows:
1998 1997 1996
---- ---- ----
(in thousands)
Service cost $135 $168 $166
Interest cost 290 329 304
Amortization of
transition 150 150 150
obligation
Amortization of gain (42) (5) (1)
--- -- --
$533 $642 $619
==== ==== ====
Funding information as of October 1 was as follows:
1998 1997
(in thousands)
Accumulated postretirement benefit
obligation:
Retirees $1,821 $1,588
Fully eligible active participants 1,033 671
Other active participants 2,576 1,668
----- -----
Unfunded accumulated postretirement
benefit obligation 5,430 3,927
Unrecognized net gain (loss) (301) 1,067
Unrecognized transition
obligation (2,097) (2,247)
------ ------
$3,032 $2,747
====== ======
For measurement purposes, a 9.0 percent annual rate of increase in healthcare
benefits was assumed for 1998; 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 $95,000 or 22.2% and the net periodic postretirement cost $129,000
or 24.1%. A one percent decrease would reduce the service and interest cost by
$73,000 or 17.1% and decrease the net periodic postretirement cost $112,000 or
21.0%. The weighted-average discount rate used in determining the accumulated
postretirement benefit obligation was 6.75 percent.
(9) INCOME TAXES
Income tax expense for the years indicated was:
1998 1997 1996
---- ---- ----
(in thousands)
Current $14,243 $11,869 $11,706
Deferred (1,886) 3,107 2,533
Tax credits, net (649) (650) (661)
------- ------- -------
$11,708 $14,326 $13,578
======= ======= =======
The temporary differences which gave rise to the net deferred tax liability at
December 31, 1998 and 1997 were as follows:
Net Deferred
Income
Tax Asset
December 31, 1998 Assets Liabilities (Liability)
- ----------------- ------ ----------- -----------
(in thousands)
Accelerated depreciation and other
plant-related differences $ - $47,095 $(47,095)
Regulatory asset 1,963 - 1,963
Regulatory liability - 1,392 (1,392)
Unamortized investment tax credits 1,230 - 1,230
Mining development and oil exploration 5,481 5,746 (265)
Employee benefits 2,623 494 2,129
Other 1,050 380 670
------- ------- --------
$12,347 $55,107 $(42,760)
======= ======= ========
Net Deferred
Income
Tax Asset
December 31, 1997 Assets Liabilities (Liability)
- ----------------- ------ ----------- -----------
(in thousands)
Accelerated depreciation and other
plant-related differences $ - $45,508 $(45,508)
Regulatory asset 2,136 - 2,136
Regulatory liability - 1,415 (1,415)
Unamortized investment tax credits 1,405 - 1,405
Mining development and oil exploration 1,417 5,342 (3,925)
Employee benefits 2,426 103 2,323
Other 677 642 35
-------- ------- --------
$ 8,061 $53,010 $(44,949)
======== ======= ========
The effective tax rate differs from the federal statutory rate for the years
ended December 31, as follows:
1998 1997 1996
---- ---- ----
Federal statutory rate 35.0% 35.0% 35.0%
Regulatory asset recognition (0.7) (1.3) (1.7)
Amortization of investment tax credits (1.3) (1.1) (1.5)
Tax-exempt interest income (1.1) (0.9) (0.6)
Percentage depletion in excess of cost (1.7) (0.7) (0.5)
Other 1 .0 (0.3) 0.2
---- ---- ---
31.2% 30.7% 30.9%
==== ==== ====
(10) OIL AND GAS RESERVES (Unaudited)
Black Hills Exploration and Production has interests in 572 producing oil and
gas properties in seven states. Black Hills Exploration and Production also
holds leases on approximately 38,825 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, 1998, 1997
and 1996, 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.
1998 1997 1996
Oil Gas Oil Gas Oil Gas
--- --- --- --- --- ---
(in thousands of barrels of oil and MCF of gas)
Proved developed and
undeveloped
Reserves:
Balance at beginning of year 2,495 9,052 2,386 10,972 1,612 7,658
Production (353) (2,068) (299) (1,747) (286) (1,718)
Additions 1,149 10,721 1,146 3,498 404 5,098
Property sales - - (10) (393) (9) (312)
Revisions to previous estimates (923) (1,753) (728) (3,278) 665 246
---- ------ ---- ------ --- ---
Balance at end of year 2,368 15,952 2,495 9,052 2,386 10,972
===== ====== ===== ===== ===== ======
Proved developed reserves at
end of Year included above 1,463 10,041 2,035 6,821 2,376 9,633
===== ====== ===== ===== ===== =====
Year-end prices $9.16 $1.93 $16.34 $2.32 $24.04 $3.20
===== ===== ====== ===== ====== =====
In December 1998, Black Hills Exploration and Production recognized a
$13,546,000 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.
(11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS
Effective December 31, 1998 the Company adopted FASB Statement No. 131,
"Disclosure About Segments of an Enterprise and Related Information." Black
Hills Corporation's business segments include: Electric which supplies electric
utility service to western South Dakota, northeastern Wyoming and southeastern
Montana; 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; Energy 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 and Technology and Others which
primarily markets communications and software development services.
Financial data for the business segments are as follows (in thousands):
Oil Energy Technology
Electric Mining and Gas Marketing & Others Eliminations Total
-------- ------ ------- --------- -------- ------------ -----
1998
- -------------------
Operating revenues $129,236 $31,413 $12,562 $506,043 $2,437 $(2,437) $679,254
Depreciation,
depletion & amort. 14,881 3,252 18,760* 690 - - 37,583*
Operating income
(loss) 49,896 12,723 (12,340) 41 (1,087) - 49,233
Interest expense 13,572 9 355 731 40 - 14,707
Income taxes 12,612 4,092 (4,689) (116) (191) - 11,708
Net income (loss) 24,825 9,585 (7,976) (346) (280) - 25,808
Current assets 43,760 25,538 1,335 77,401 6,406 (13,960) 140,480
Total assets 451,404 93,140 26,666 86,300 18,838 (116,931) 559,417
Property additions 11,451 1,447 10,169 424 1,774 - 25,265
Increase in goodwill - - - 1,960 - - 1,960
* Includes the impact of a $13,546 pretax write down of certain oil and natural
gas properties.
Oil Energy Technology
Electric Mining and Gas Marketing & Others Eliminations Total
-------- ------ ------- --------- -------- ------------ -----
1997
- -------------------
Operating revenues $126,497 $31,080 $13,295 $142,790 $685 $(685) $313,662
Depreciation,
depletion & amort. 14,608 3,188 4,275 240 - - 22,311
Operating income
(loss) 44,611 12,217 2,907 (825) (471) - 58,439
Interest expense 13,676 5 203 203 36 - 14,123
Income taxes 9,929 4,205 629 (347) (90) - 14,326
Net income (loss) 22,106 9,073 2,147 (749) (218) - 32,359
Current assets 35,987 17,227 2,009 34,403 6,116 (11,733) 84,009
Total assets 445,840 89,665 31,449 41,211 15,888 (115,312) 508,741
Property additions 12,484 1,336 7,076 - 191 - 21,087
Increase in goodwill - - - 7,232 - - 7,232
Oil Energy Technology
Electric Mining and Gas Marketing & Others Eliminations Total
-------- ------ ------- --------- -------- ------------ -----
1996
- -------------------
Operating revenues $118,718 $31,315 $12,555 - $685 $(685) $162,588
Depreciation,
depletion & amort. 16,104 2,981 3,709 - 24 (24) 22,794
Operating income
(loss) 39,090 12,234 2,981 - (237) 237 54,305
Interest expense 13,814 1 98 - 29 - 13,942
Income taxes 7,887 5,024 715 - (48) - 13,578
Net income (loss) 18,333 9,934 2,198 (126) (87) - 30,252
Current assets 30,345 20,325 3,796 - 385 (3,854) 50,997
Total assets 432,667 77,671 29,131 (123) 604 (72,596) 467,354
Property additions 12,634 2,118 9,585 - 51 - 24,388
Detailed revenues by product sold and business segment are as follows (in
thousands):
Oil Energy Technology
Electric Mining and Gas Marketing & Others Eliminations Total
-------- ------ ------- --------- -------- ------------ -----
1998
- -------------------
Electric revenues $129,236 $ - $ - $ - $ - $ - $129,236
Coal revenues - 31,413 - 12,924 - - 44,337
Gas revenues - - 4,073 375,136 - - 379,209
Oil revenues - - 5,131 117,185 - - 122,316
Other revenues - - 3,358 798 2,437 (2,437) 4,156
-------- ------- ------- -------- ------ ------- --------
Total $129,236 $31,413 $12,562 $506,043 $2,437 $(2,437) $679,254
======== ======= ======= ======== ====== ======= ========
Oil Energy Technology
Electric Mining and Gas Marketing & Others Eliminations Total
1997
- -------------------
Electric revenues $126,497 $ - $ - $ - $ - $ - $126,497
Coal revenues - 31,080 - - - - 31,080
Gas revenues - - 4,223 94,295 - - 98,518
Oil revenues - - 5,540 48,495 - - 54,035
Other revenues - - 3,532 - 685 (685) 3,532
-------- ------- ------- -------- ---- ----- --------
Total $126,497 $31,080 $13,295 $142,790 $685 $(685) $313,662
======== ======= ======= ======== ==== ===== ========
Oil Energy Technology
Electric Mining and Gas Marketing & Others Eliminations Total
1996
- -------------------
Electric revenues $118,718 $ - $ - $ - $ - $ - $118,718
- -
Coal revenues - 31,315 - - - - 31,315
Gas revenues - - 3,523 - - - 3,523
Oil revenues - - 5,527 - - - 5,527
Other revenues - - 3,505 - - - 3,505
-------- ------- -------- ------- ------- ------ --------
Total $118,718 $31,315 $ 12,555 $ - $ - $ - $162,588
======== ======= ======== ======= ======= ====== ========
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
Taxes Other than Income Taxes
1998 1997 1996
---- ---- ----
(in thousands)
Property $ 4,993 $ 4,326 $ 4,368
Production and severance 3,437 3,654 4,105
Payroll 1,348 1,332 1,307
Black lung 1,324 1,310 1,320
Federal reclamation 1,148 1,138 1,135
Other 222 225 225
------- ------- -------
$12,472 $11,985 $12,460
======= ======= =======
FINANCIAL STATISTICS
Years ended December 31, 1998 1997 1996 1995 1994
- ------------------------ ---- ---- ---- ---- ----
TOTAL ASSETS (in thousands) $559,417 $508,741 $467,354 $448,830 $436,877
PROPERTY AND INVESTMENTS
(in thousands)
Total property and investments $619,549 $598,306 $581,537 $557,642 $519,296
Accumulated depreciation and depletion 229,942 197,179 181,103 164,383 156,046
Capital expenditures (includes AFDC) 27,225 28,319 24,388 51,895 103,059
CAPITALIZATION (in thousands)
Long-term debt $162,030 $163,360 $164,691 $166,069 $128,925
Common stock equity 206,666 205,403 193,175 182,342 175,410
------- ------- ------- ------- -------
Total capitalization $368,696 $368,763 $357,866 $348,411 $304,335
======== ======== ======== ======== ========
CAPITALIZATION RATIOS
Long-term debt 43.9% 44.3% 46.0% 47.7% 42.4%
Common stock equity 56.1 55.7 54.0 52.3 57.6
---- ---- ---- ---- ----
Total 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
AVERAGE INTEREST RATE ON LONG-
TERM DEBT 8.1% 8.1% 8.1% 8.1% 8.5%
NET INCOME AVAILABLE FOR
COMMON STOCK (in thousands) $25,808* $32,359 $30,252 $25,590 $23,805
DIVIDENDS PAID IN COMMON STOCK
(in thousands) $21,737 $20,540 $19,930 $19,312 $18,920
COMMON STOCK DATA (in thousands)**
Shares outstanding, average 21,623 21,692 21,660 21,614 21,509
Shares outstanding, end of year 21,578 21,705 21,675 21,638 21,579
Earnings per average share, in dollars $1.19* $1.49 $1.40 $1.19 $1.11
Dividends paid per share, in dollars $1.00 $0.95 $0.92 $0.89 $0.88
Book value per share, end of year, in dollars $9.58 $9.46 $8.91 $8.43 $8.13
RETURN ON COMMON STOCK
EQUITY (year-end) 12.5%* 15.8% 15.7% 14.0% 13.6%
ALLOWANCE FOR FUNDS USED
DURING CONSTRUCTION AS
PERCENT OF NET INCOME 0.9% 0.6% 1.2% 22.9% 16.7%
* Includes impact of $8.8 million, or 41 cents per average share, write down
of certain oil and gas properties.
**Common Stock Data reflects the 3-for-2 stock split on March 10, 1998.
ELECTRIC OPERATION STATISTICS
Years ended December 31, 1998 1997 1996 1995 1994
- ------------------------ ---- ---- ---- ---- ----
ELECTRIC ENERGY GENERATED AND
PURCHASED (megawatt hours)
Generated, net station output 1,870,247 1,803,350 1,659,671 1,320,630 1,108,530
Purchased and net interchange 500,319 503,242 380,106 473,175 595,872
--------- --------- --------- --------- ---------
Total generated and purchased 2,370,566 2,306,592 2,039,777 1,793,805 1,704,402
Company use and losses (76,131) (94,633) (80,106) (87,512) (65,651)
---------------------- --------- --------- --------- --------- ---------
Total electric energy sales 2,294,435 2,211,959 1,959,671 1,706,293 1,638,751
========= ========= ========= ========= =========
ELECTRIC ENERGY SALES
(megawatt hours)
Residential 392,637 392,059 406,658 383,929 368,953
General and commercial 561,292 547,624 541,463 513,854 495,909
Industrial 527,157 556,554 555,601 552,829 583,258
Public authorities 24,356 22,583 25,083 23,164 23,051
Sales for resale 417,889 413,527 181,766 171,942 166,580
--------- --------- --------- --------- ---------
Total firm electric energy sales 1,923,331 1,932,347 1,710,571 1,645,718 1,637,751
Non-firm sales 371,104 279,612 249,100 60,575 1,000
--------- --------- --------- --------- ---------
Total electric energy sales 2,294,435 2,211,959 1,959,671 1,706,293 1,638,751
========= ========= ========= ========= =========
ELECTRIC REVENUE (in thousands)
Residential 32,336 32,178 33,230 30,433 28,574
General and commercial 42,221 41,452 41,307 37,663 35,390
Industrial 25,713 26,802 26,915 26,495 27,318
Public authorities 1,944 1,843 1,970 1,775 1,718
Sales for resale 15,782 16,181 8,189 7,625 7,460
------- ------- ------- ------- -------
Total firm electric revenue 117,996 118,456 111,611 103,991 100,460
Non-firm electric revenue 6,002 3,760 2,985 741 -
Other electric revenue 5,238 4,281 4,122 4,051 4,296
-------- -------- -------- -------- --------
Total electric revenue $129,236 $126,497 $118,718 $108,783 $104,756
======== ======== ======== ======== ========
ELECTRIC CUSTOMERS (end of year)
Residential 46,967 46,656 46,146 45,886 45,060
General and commercial 9,703 9,431 9,280 8,958 8,732
Industrial 44 39 37 35 36
Public authorities 140 141 137 138 130
Other electric utilities 2 2 1 1 1
------ ------ ------ ------ ------
Total electric customers 56,856 56,269 55,601 55,018 53,959
====== ====== ====== ====== ======
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No change of accountants or disagreements on any matter of accounting principles
or practices or financial statement disclosure have occurred.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of the Company is incorporated herein by
reference to the Proxy Statement for the Annual Shareholders' Meeting to be held
May 11, 1999.
EXECUTIVE OFFICERS OF THE COMPANY
The following is a list of all executive officers of the Company. There are no
family relationships among them. Officers are normally elected annually.
Daniel P. Landguth, 52, Chairman, President and Chief Executive Officer of Black
Hills Corporation Mr. Landguth was elected to his present position in January
1991.
Roxann R. Basham, 37, Vice President - Finance and Secretary/Treasurer
Ms. Basham was elected to her present position in December 1997. She had served
as Secretary/Treasurer since 1993.
David R. Emery, 36, Vice President - Fuel Resources
Mr. Emery was elected to his present position in January 1997. He had served as
General Manager of Black Hills Exploration and Production (formerly Western
Production Company) since June 1993.
Gary R. Fish, 40, Vice President - Corporate Development
Mr. Fish was elected to his present position in October 1996. He had served as
Controller since 1988.
Everett E. Hoyt, 59, President and Chief Operating Officer of Black Hills Power
Mr. Hoyt was elected to his present position in October 1989.
James M. Mattern, 44, Vice President - Corporate Administration and Assistant to
the CEO
Mr. Mattern was elected to his present position in September 1997. He had served
as Vice President - Corporate Administration since January 1994 and had served
as Director of Human Resources since 1991.
Thomas M. Ohlmacher, 47, Vice President - Power Supply
Mr. Ohlmacher was elected to his present position in August 1994. He had served
as Director of Power Generation since 1993.
Mark T. Thies, 35, Controller
Mr. Thies was elected to his present position in May 1997. Previously, Mr. Thies
had served in a number of accounting positions, most recently as Assistant
Controller, at InterCoast Energy Company, a wholly owned subsidiary of
MidAmerican Energy Holdings Company since 1990.
Kyle D. White, 39, Vice President - Marketing and Regulatory Affairs
Mr. White was elected to his present position in July 1998. He had served as
Vice President - Energy Services since January 1998 and had served as Director
of Strategic Marketing and Sales since 1993.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding management remuneration and transactions is incorporated
herein by reference to the Proxy Statement for the Annual Shareholders' Meeting
to be held May 11, 1999.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the security ownership of certain beneficial owners and
management is incorporated herein by reference to the Proxy statement for the
Annual Shareholders' Meeting to be held May 11, 1999.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions is
incorporated herein by reference to the Proxy Statement for the Annual
Shareholders' Meeting to be held May 11, 1999.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements
Financial statements required by Item 14 are listed in the index included
in Item 8 of Part II.
2. Schedules
All schedules have been omitted because of the absence of the conditions
under which they are required or because the required information is included
elsewhere in the financial statements incorporated by reference in the Form
10-K.
3. Exhibits
*3(a) Restated Articles of Incorporation dated May 24, 1984
(Exhibit 3(I) to Form 8-K dated June 7, 1994, File No.
1-7978).
*3(b) Bylaws dated January 30, 1997. (Exhibit 3(b) to Form 10-K
for 1997.)
*4(a) Reference is made to Article Fourth (7) of the Restated
Articles of Incorporation of the Company (Exhibit 3(a)
hereto).
*4(b) Indemnification Agreement and Company and Directors' and
Officers' indemnification insurance (Exhibit 4(b) to Form
10-K for 1987).
*4(c) Indenture of Mortgage and Deed of Trust, dated September 1,
1941, and as amended by supplemental indentures (Exhibit B
to Form A-2, File No. 2-4832); (Exhibit 7-B to Form S-1,
File No. 2-6576); (Exhibit 7-C to Form S-1, File No.
2-7695); (Exhibit 7-D to Form S-1, File No. 2-8157);
(Exhibit 4.05(e) to Form S-3, File No. 33-54329); (Exhibit
4-I to Form S-1, File No. 2-9433); (Exhibit 4-H to Form S-1,
File No. 2-13140); (Exhibit 4-I to Form S-1, File No.
2-14829); (Exhibits 4-J and 4-K to Form S-1, File No.
2-16756); (Exhibits 4-L, 4-M, and 4-N to Form S-1, File No.
2-21024); (Exhibits 2(q), 2(r), 2(s), 2(t), 2(u), and 2(v)
to Form S-7, File No. 2-57661); (Exhibit 4.05(t), 4.05(u)
and 4.05(v) to Form S-3, File No. 33-54329); (Exhibit 4(b)
to Form S-3, File No. 2-81643); (Exhibit 4.05(x), 4.05(y),
and 4.05(z) to Form S-3, File No. 33-54329); (Exhibit 4(d)
and 4(e) to Post-Effective Amendment No. 1 to Form S-8, File
No. 33-15868); and (Exhibit 4.05(ac), 4.05(ad), and 4.05(ae)
to Form S-3, File No. 33-54329).
*4(d) Indentures of Trust dated as of June 1, 1992, City of
Gillette, Campbell County, Wyoming; Lawrence County, South
Dakota; Pennington County, South Dakota; Weston County
Wyoming; and Campbell County, Wyoming; to Norwest Bank
Minnesota, National Association, as Trustee (Exhibits 10(n),
10(q), 10(s), 10(u), and 10(w), to Form 10-K for 1992).
*10(a) Agreement for Transmission Service and The Common Use of
Transmission Systems dated January 1, 1986, among the
Company, Basin Electric Power Cooperative, Rushmore Electric
Power Cooperative, Inc., Tri-County Electric Association,
Inc., Black Hills Electric Cooperative, Inc. and Butte
Electric Cooperative, Inc. (Exhibit 10(d) to Form 10-K for
1987).
*10(b) Restated and Amended Coal Supply Agreement for NS #2 dated
February 12, 1993 (Exhibit 10(c) to Form 10-K for 1992).
*10(c) Coal Leases between Wyodak Resources Development Corp. and
the Federal Government -Dated May 1, 1959, (Exhibit 5(i) to
Form S-7, File No. 2-60755) -Modified January 22, 1990
(Exhibit 10(h) to Form 10-K for 1989) -Dated April 1, 1961
(Exhibit 5(j) to Form S-7, File No. 2-60755) -Modified
January 22, 1990 (Exhibit 10(i) to Form 10-K for 1989)
-Dated October 1, 1965 (Exhibit 5(k) to Form S-7, File No.
2-60755) -Modified January 22, 1990 (Exhibit 10(j) to Form
10-K for 1989)
*10(d) Further Restated and Amended Coal Supply Agreement dated
May 5, 1987 between Wyodak Resources Development Corp. and
Pacific Power & Light Company (Exhibit 10(k) to Form 10-K
for 1987).
*10(e) Second Restated and Amended Power Sales Agreement dated
September 29, 1997, between PacifiCorp and the Company
(Exhibit 10(e) to Form 10-K for 1997).
*10(f) Coal Supply Agreement for Wyodak Unit #2 dated February 3,
1983, and Ancillary Agreement dated February 3, 1982,
between Wyodak Resources Development Corp. and Pacific Power
& Light Company and the Company (Exhibit 10(o) to Form 10-K
for 1983). Amendment to Agreement for Coal Supply for Wyodak
#2 dated May 5, 1987 (Exhibit 10(o) to Form 10-K for 1987).
*10(g) Third Restated Electric Power and Energy Supply and
Transmission Agreement dated January 1, 1998, by and between
the Company and the City of Gillette, Wyoming (Exhibit 10(g)
to Form 10-K for 1997).
*10(h) Reserve Capacity Integration Agreement dated May 5, 1987,
between Pacific Power & Light Company and the Company
(Exhibit 10(u) to Form 10-K for 1987).
*10(i) Compensation Plan for Outside Directors (Exhibit 10(bb) to
Form 10-K for 1992).
*10(j) The Amended and Restated Pension Equalization Plan of Black
Hills Corporation dated January 27, 1995 (Exhibit 10 (ad) to
Form 10-K for 1994).
*10(k) The Amended and Restated Pension Plan of Black Hills
Corporation (Exhibit 10 (ad) to Form 10-K for 1994).
*10(l) Agreement for Supplemental Pension Benefit for Everett E.
Hoyt dated January 20, 1992 (Exhibit 10(gg) to Form 10-K for
1992).
*10(m) Power Integration Agreement, dated September 9, 1994,
between the Company and Montana-Dakota Utilities Co., a
Division of MDU Resources Group, Inc. (Exhibit 10(gg) to
Form 8-K dated September 12, 1994, File No. 1-7978).
*10(n) Change in Control Agreements dated January 30, 1996 for
Daniel P. Landguth, Everett E. Hoyt, Thomas M. Ohlmacher,
James M. Mattern, Roxann R. Basham and Gary R. Fish (Exhibit
10(af) to Form 10-K for 1995). Change in Control Agreement
dated February 1, 1997 for David R. Emery (Exhibit 10(p) to
Form 10-K for 1997). Change in Control Agreement dated May
1, 1997 for Mark T. Thies (Exhibit 10(q) to Form 10-K for
1997). Change in Control Agreement dated December 31, 1997
for Kyle D. White (Exhibit 10(r) to Form 10-K for 1997).
*10(o) Marketing, Capacity and Storage Service Agreement between
Black Hills Corporation and PacifiCorp dated September 1,
1995 (Exhibit 10(ag) to Form 10-K for 1995).
*10(p) Black Hills Corporation 1996 Stock Option Plan (Exhibit
10(s) to Form 10-K for 1997).
*10(q) The Outside Directors Stock Based Compensation Plan
(Exhibit 10(t) to Form 10-K for 1997).
*10(r) Assignment of Mining Leases and Related Agreement
effective May 27, 1997, between Wyodak Resources Development
Corp. and Kerr-McGee Coal Corporation. Included in this
Agreement are coal leases between Wyodak Resources
Development Corp. and the Federal Government and the State
of Wyoming, as modified by the decision dated May 27, 1997
from the U.S. Department of the Interior - Bureau of Land
Management (Exhibit 10(u) to Form 10-K for 1997).
10(s) Officers 1998 Short-Term Incentive Plan.
21 Subsidiaries of the Registrant.
23a Consent of Independent Public Accountants with respect to Annual
Report on Form 10-K.
23b Consent of Independent Public Accountants with respect to Annual
Report on Form 11-K.
27 Financial Data Schedule.
99 Annual Report on Form 11-K of the Black Hills Corporation Employee
Stock Purchase Plan for the year ended December 31, 1998.
* Exhibits incorporated by reference.
(c) See (a) 3. above.
(d) See (a) 2. above.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BLACK HILLS CORPORATION
By DANIEL P. LANDGUTH
Daniel P. Landguth, Chairman,
President and Chief Executive Officer
Dated: March 9, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
/s/ DANIEL P. LANDGUTH Director and Principal March 9, 1999
Daniel P. Landguth, Chairman, Executive Officer
President, and Chief Executive Officer
/s/ ROXANN R. BASHAM Principal Financial Officer March 9, 1999
Roxann R. Basham, Vice President-Finance,
and Corporate Secretary/Treasurer
/s/ MARK T. THIES Principal Accounting Officer March 9, 1999
Mark T. Thies, Controller
/s/ ADIL M. AMEER Director March 9, 1999
Adil M. Ameer
/s/ GLENN C. BARBER Director March 9, 1999
Glenn C. Barber
/s/ BRUCE B. BRUNDAGE Director March 9, 1999
Bruce B. Brundage
/s/ DAVID C. EBERTZ Director March 9, 1999
David C. Ebertz
/s/ JOHN R. HOWARD Director March 9, 1999
John R. Howard
/s/ EVERETT E. HOYT Director and Officer March 9, 1999
Everett E. Hoyt (President and Chief
Operating Officer of Black Hills Power)
/s/ KAY S. JORGENSEN Director March 9, 1999
Kay S. Jorgensen
/s/ THOMAS J. ZELLER Director March 9, 1999
Thomas J. Zeller
BOARD OF DIRECTORS AND OFFICERS
BOARD OF DIRECTORS OFFICERS
Daniel P. Landguth Daniel P. Landguth
Chairman of the Board, President and Chairman of the Board,President and
Chief Executive Officer of the Compan Chief Executive Officer
Adil M. Ameer Roxann R. Basham
President and Chief Executive Officer Vice President - Finance and
Rapid City Regional Hospital Corporate Secretary/Treasurer
Glenn C. Barber David R. Emery
President and Chief Executive Officer Vice President - Fuel Resources
Glenn C. Barber & Associates, Inc.
Bruce B. Brundage Gary R. Fish
President and Director Vice President-
Brundage & Company Corporate Development
David C. Ebertz Everett E. Hoyt
President President and Chief Operating Officer
Barlow Agency, Inc. Black Hills Power and Light Company
John R. Howard James M. Mattern
President Vice President-Corporate Administration
Industrial Products, Inc. and Assistant to the CEO
Everett E. Hoyt Thomas M. Ohlmacher
President and Chief Operating Officer Vice President-Power Supply
Black Hills Power and Light Company
Kay S. Jorgensen Mark T. Thies
Owner - Jorgensen-Thompson Controller
Creative Broadcast Services
Thomas J. Zeller Kyle D. White
President Vice President-Marketing and
RE/SPEC Inc. Regulatory Affairs