UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K/A
(Amendment No. 1)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
X EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________________ to __________________
Commission File Number 333-52664
BLACK HILLS CORPORATION
Incorporated in South Dakota IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
Registrant's telephone number, including area code
(605) 721-1700
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 28, 2001 $843,247,880
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 28, 2001
----- --------------------------------
Common stock, $1.00 par value 22,951,394 shares
Documents Incorporated by Reference
1. Definitive Proxy Statement of the Registrant filed pursuant to Regulation
14A for the 2001 Annual Meeting of Stockholders to be held on May 30, 2001,
is incorporated by reference in Part III.
FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" as defined by the
Securities and Exchange Commission. These statements concern our plans,
expectations and objectives for future operations. All statements, other than
statements of historical facts, included in this Form 10-K that address
activities, events or developments that we expect, believe or anticipate will or
may occur in the future are forward-looking statements. The words "believe,"
"plan," "intend," "anticipate," "estimate," "project" and similar expressions
are also intended to identify forward-looking statements. These forward-looking
statements include, among others, such things as:
o expansion and growth of our business and operations;
o future financial performance;
o future acquisition and development of power plants;
o future production of coal, oil and natural gas;
o reserve estimates; and
o business strategy.
These forward-looking statements are based on assumptions which we believe
are reasonable based on current expectations and projections about future events
and industry conditions and trends affecting our business. However, whether
actual results and developments will conform to our expectations and predictions
is subject to a number of risks and uncertainties which could cause actual
results to differ materially from those contained in the forward-looking
statements, including the following factors:
o prevailing governmental polices and regulatory actions with
respect to allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power and
other capital investments, and present or prospective wholesale
and retail competition;
o changes in and compliance with environmental and safety laws and
policies;
o weather conditions;
o population growth and demographic patterns;
o competition for retail and wholesale customers;
o pricing and transportation of commodities;
o market demand, including structural market changes;
o changes in tax rates or policies or in rates of inflation;
o changes in project costs;
o unanticipated changes in operating expenses or capital
expenditures;
o capital market conditions;
o technological advances;
o competition for new energy development opportunities; and
o legal and administrative proceedings that influence our business
and profitability.
TABLE OF CONTENTS
Page
ITEMS
1 & 2. BUSINESS AND PROPERTIES.........................................4
General....................................................4
Holding Company Formation..................................5
Industry Overview..........................................5
Strategy...................................................6
Independent Energy.........................................9
Independent Power Plants...............................11
Fuel Production........................................16
Fuel Marketing.........................................17
Electric Utility - Black Hills Power, Inc.................18
Communications............................................21
Competition...............................................21
Risk Management...........................................21
California Markets........................................22
Regulation................................................23
Energy Regulation......................................23
Environmental Regulation...............................24
Exploration and Production.............................27
Other Properties..........................................28
Employees.................................................28
ITEM 3. LEGAL PROCEEDINGS..............................................28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS............................30
RESULTS OF OPERATIONS.....................................30
LIQUIDITY AND CAPITAL RESOURCES...........................36
MARKET RISK DISCLOSURES...................................39
RATE REGULATION...........................................42
BUSINESS OUTLOOK STATEMENTS...............................44
SIGNATURES.....................................................47
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
General
We are a growth oriented, diversified energy holding company operating
principally in the United States. Our regulated and unregulated businesses have
expanded significantly in recent years. Our independent energy group produces
and markets power and fuel. We produce and sell electricity in a number of
markets, with a strong emphasis on the western United States. We also produce
coal, natural gas and crude oil primarily in the Rocky Mountain region and
market fuel products nationwide. We also own Black Hills Power, Inc., an
electric utility serving approximately 58,600 customers in South Dakota, Wyoming
and Montana. Our communications group offers state-of-the-art broadband
communication services to residential and business customers in Rapid City and
the northern Black Hills region of South Dakota. Our predecessor company was
incorporated and began providing electric utility service in 1941 and began
selling and marketing various forms of energy on an unregulated basis in 1956.
As the following table illustrates, we have experienced significant growth over
the last five years, primarily as a result of the expansion of our independent
energy business and increases in wholesale electric sales.
- ----------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------
Net income (in thousands):
Electric utility $ 37,105 $ 27,286 $ 24,825 $ 22,106 $ 18,333
Independent energy 28,946 11,882 10,068 10,471 12,132
Communications and other (13,203) (2,101) (280) (218) (213)
Oil and gas write-down -- -- (8,805) -- --
-------- -------- -------- -------- --------
$ 52,848 $ 37,067 $ 25,808 $ 32,359 $ 30,252
======== ======== ======== ======== ========
Earnings per share $2.37 $1.73 $1.60(2) $1.49 $1.40
Assets (in thousands) $1,320,320 $668,492 $559,417 $508,741 $467,354
Capital expenditures (in thousands) $177,189(1) $154,609 $27,225 $28,319 $24,388
Electric sales (megawatthours):
Regulated utility
Firm electric sales 1,973,066 1,920,005 1,923,331 1,932,347 1,710,571
Wholesale off-system 684,378 445,712 371,104 279,612 249,100
----------- ---------- ---------- ---------- ----------
Total utility 2,657,444 2,365,717 2,294,435 2,211,959 1,959,671
Non-regulated sales 236,279 - - - -
----------- ---------- ---------- ---------- ----------
Total electric sales 2,893,723 2,365,717 2,294,435 2,211,959 1,959,671
=========== ========== ========== ========== ==========
Average daily marketing volumes:
Natural gas (MMbtus) 860,800 635,500 524,800 231,000 28,200(3)
Crude oil (barrels) 44,300 19,270 19,000 12,600(3) -
Coal (tons) 4,400 4,500 4,400(3) - -
Generating capacity (megawatts)
Utility (owned generation) 393 353 353 353 353
Utility (purchased capacity) 70 75 75 75 75
Independent power 250 -- -- -- --
----------- ----------- ----------- ----------- ----------
Total generating capacity 713 428 428 428 428
=========== =========== =========== =========== ==========
Oil and gas reserves (MMcfe) 44,882 44,114 30,160 24,022 17,330
- ----------------------------------------------------------------------------------------------------------------------
(1) Excludes the non-cash acquisition of Indeck Capital, Inc.
(2) Excludes impact of $0.41 per share non-cash write-down of oil and gas
properties due to historically low oil prices, lower natural gas prices and
a decline in the value of unevaluated properties.
(3) Since date of inception of marketing operations.
For additional information on our business segments see - "ITEM 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and
Note 13 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS."
Holding Company Formation
At our annual meeting of shareholders on June 20, 2000, our shareholders
approved the formation of a holding company structure through a "plan of
exchange" between Black Hills Corporation and Black Hills Holding Corporation.
The plan of exchange provided that each share of Black Hills Corporation common
stock would be exchanged for one share of common stock of the holding company.
On December 22, 2000, articles of exchange were filed with the South Dakota
Secretary of State. As a result:
o all common shareholders of Black Hills Corporation became shareholders of
Black Hills Holding Corporation, the holding company;
o Black Hills Corporation became a wholly-owned subsidiary of Black Hills
Holding Corporation;
o Black Hills Corporation changed its name to "Black Hills Power, Inc." and
the holding company changed its name to "Black Hills Corporation"; and
o the debt securities and other financial obligations of Black Hills Power,
Inc. continue to be the obligations of Black Hills Power, Inc.
The formation of our holding company structure allows us to pursue, through
separate subsidiaries, business opportunities in both regulated and unregulated
markets.
Industry Overview
In the last decade, many U.S. regulatory bodies have taken steps to transform
the energy sectors which they regulate to encourage competition, introduce
customer choice and, in some cases, to improve the operational performance of
strategic energy assets. In particular, the electric power industry is
undergoing substantial change as a result of regulatory initiatives at the
federal and state levels. As early as the mid-1990's, new regulatory initiatives
to increase competition in the domestic power generation industry had been
adopted or were being considered at the federal level and by many states. The
primary focus of such efforts was to increase competition through the
disaggregation of the traditional utility functions of generation, transmission,
distribution and marketing of electricity into competitive or partially
regulated businesses. This resulted in new investment opportunities to enter
previously non-competitive or closed markets.
In 1992, the Federal Energy Regulatory Commission (FERC) issued Order 636,
followed by Order 888 in 1996, to increase competition by easing entry into
natural gas and electricity markets. These orders require owners and operators
of natural gas and power transmission systems to make transmission service
available on a non-discriminatory basis to energy suppliers. In order to better
assure competitive access to the transmission network on a non-discriminatory
basis, FERC issued Order 2000 in December 1999, which encourages electric
utilities with power transmission assets to voluntarily form regional
transmission organizations to provide regional management and control of
transmission assets independent of firms that sell electricity.
The electric power industry has also witnessed growing consumer demand and
increasingly frequent regional shortages of electricity over the past three
years. The summers of 1998, 1999 and 2000 and the winter of 2000-2001 have all
been characterized by very high peak prices for electricity in a number of
recently created wholesale electricity markets. We believe that substantial
amounts of new electric generating capacity need to be built to relieve
shortages of electricity and to replace inefficient and obsolete facilities.
The oil and gas industry has experienced strong increases in commodity prices
since the historically low levels experienced in 1998. These price increases
have been driven in part by several years of modest drilling activity combined
with strong growth in demand for energy commodities. Continued growth of the
Internet and other high technology industries is contributing to increasing
demand for power. Demand for natural gas is expected to remain strong as an
increasing number of gas-fired power plants are brought into service.
The telecommunications industry is currently undergoing widespread changes
brought about by, among other things, the Telecommunications Act of 1996, the
decisions of federal and state regulators to open the monopoly local telephone
and cable television markets to competition and the need for higher speed,
higher capacity networks to meet the increasing consumer demand for expanded
telecommunications services, including broader video choices and high speed data
and Internet services. The convergence of these trends and the inherent
limitations of most existing networks have created opportunities for new types
of communications companies capable of providing a wide range of voice, video
and data services through new and advanced high speed, high capacity
telecommunications networks.
As a result of historical and anticipated regulatory initiatives and the
increasing demand for electricity, fuel and broadband services, we believe there
are significant opportunities for the development and growth of our independent
energy businesses, our regulated utility and our communications business.
Strategy
Our strategy is to build long-term shareholder value by deploying our
development, operating and marketing expertise in the energy industry. We plan
to operate a mix of unregulated independent energy and regulated utility
businesses, with emphasis on the independent power generation and fuel
production segments. We expect our independent energy businesses to operate
nationwide, with an integrated regional emphasis on the western half of the
United States. Our utility and communications businesses intend to continue
focusing their retail operations primarily on the northern Black Hills region of
South Dakota, with wholesale power sales concentrated primarily in the Rocky
Mountain and West Coast regions.
Our strategy includes the following key elements:
o grow our independent power unit by developing and acquiring power projects
primarily in the western United States;
o expand the generating capacity of our existing sites through a strategy
known as "brownfield development;"
o sell a large percentage of the production from our independent power
projects through long-term contracts in order to secure attractive
investment returns;
o increase our reserves of natural gas and crude oil and expand our coal
production;
o exploit our fuel cost advantages and our operating and marketing expertise
to remain a low-cost power producer;
o exploit our knowledge and market expertise while managing the risks
inherent in fuel marketing;
o build and maintain strong relationships with wholesale energy customers;
and
o capitalize on our utility's established market presence, relationships and
customer loyalty.
Grow our Independent Power Unit by Developing and Acquiring Power Projects
Primarily in the Western United States. Our aim is to continue the development
of power plants in regional markets based on prevailing supply and demand
fundamentals in a manner that complements our existing fuel assets and fuel and
energy marketing capabilities. This approach aims to capitalize on market growth
while managing our fuel procurement needs. Over the next few years, we intend to
grow through a combination of disciplined acquisitions and development of new
power generation facilities primarily in the Rocky Mountain region where we
believe we have the detailed knowledge of market fundamentals and competitive
advantage to achieve attractive returns. We believe the following trends will
provide us with growth opportunities in the future:
o Demand for electricity in the Rocky Mountain and West Coast regions will
continue to grow and new generation capacity will be required over the next
several years.
o New electric generation construction will be predominantly gas-fired, which
may create further competitive cost advantages for new and existing
coal-fired generation assets.
o Transmission construction will significantly lag new generation
development, favoring new development located near load centers or
existing, unconstrained transmission locations.
o Disaggregation of the electric utility industry from traditionally
vertically integrated utilities into separate generation, transmission,
distribution and marketing entities will continue, thereby creating
opportunities for acquisitions and joint ventures.
Expand the Generating Capacity of Our Existing Sites Through a Strategy Known as
"Brownfield Development." We believe that existing sites with opportunities for
brownfield expansion generally offer the potential for greater returns than
development of new sites through a "greenfield" strategy. Brownfield sites
typically offer several competitive advantages over greenfield development,
including:
o proximity to existing transmission systems;
o operating cost advantages related to ownership of shared facilities;
o a less costly and time consuming permitting process; and
o potential ability to share infrastructure with existing facilities at the
same site.
We are currently expanding our capacity with brownfield development underway at
our Arapahoe, Valmont and Wygen sites, and believe that our Fountain Valley and
Wygen sites in particular provide further opportunities for a significant
expansion of our gas- and coal-fired generating capacity over the next several
years.
Sell a Large Percentage of the Production From Our Independent Power Projects
Through Long-Term Contracts in Order to Secure Attractive Investment Returns.
Recent extreme price volatility in the short-term power markets are resulting in
greater demand among our wholesale customers for mid- and long-term power
purchase agreements. By selling the majority of our energy and capacity under
mid- and long-term contracts, we believe that we can satisfy the requirements of
our customers while earning more stable revenues and greater returns over the
long term than we could by selling our energy into the more volatile spot
markets. In recent months, for example, we have entered into long-term tolling
agreements covering nearly all of the gas-fired energy and capacity our
independent power unit is adding through brownfield expansion of the Arapahoe
and Valmont sites and from the Fountain Valley project. See "--Independent
Energy -- Independent Power Plants."
Increase Our Reserves of Natural Gas and Expand Our Coal Production. We aim to
support the fuel requirements of our growing portfolio of power plants as well
as power plants owned by others by emphasizing natural gas and coal production.
Our strategy is to expand our natural gas reserves through a combination of
acquisitions and drilling programs and expand our coal production through the
construction of mine-mouth coal-fired generation plants at our Wyodak mine
location. Our objective is to maintain coal reserves to serve our mine-mouth
coal-fired generation plants directly, and to maintain sufficient natural gas
production either to directly serve or indirectly hedge the fuel cost exposure
of our gas-fired generation plants. Specifically, we plan to:
o substantially increase our natural gas reserves and minimize exploration
risk by focusing on lower-risk exploration and development drilling as well
as acquisitions of proven producing properties;
o exploit our belief that the long-term demand for natural gas will remain
strong by emphasizing natural gas, rather than oil, in our acquisition and
drilling activities;
o add natural gas reserves and increase production by focusing on various
shallow gas plays in the Rocky Mountain region, where the added production
can be integrated with our fuel marketing and/or power generation
activities;
o increase coal production and sales from our Wyodak mine by continuing to
develop additional mine-mouth generating facilities at the site, including
the Wygen I plant, which is scheduled for completion in spring 2003; and
o pursue future sales of coal from the Wyodak mine to rail-served customers
by reducing the moisture content of our coal so that we can ship it greater
distances.
Exploit Our Fuel Cost Advantage and Our Operating and Marketing Expertise to
Remain a Low-Cost Power Producer. We expect to expand our portfolio of power
plants having relatively low marginal costs of producing energy and related
products and services. We intend to utilize a low-cost power production
strategy, together with access to coal and natural gas reserves, to protect our
revenue stream as an increasing number of gas-fired power plants are brought
into operation. Low marginal production costs can result from a variety of
factors, including low fuel costs, efficiency in converting fuel into energy,
and low per unit operation and maintenance costs. We have aggressively managed
each of these factors to achieve very low production costs, especially at our
coal-fired and hydroelectric generating facilities.
Our primary competitive advantage is our coal mine, which is located in close
proximity to our retail service territory. We are exploiting the competitive
advantage of this native fuel source by building additional mine-mouth
coal-fired generating capacity. This strengthens our position as a low-cost
producer since transportation costs often represent the largest component of the
delivered cost of coal.
Exploit Our Knowledge and Market Expertise While Managing the Risks Inherent in
Fuel Marketing. We aim to apply our knowledge of and expertise in the natural
gas transmission system and trading markets in the western and northwestern
regions of the United States and western Canada in order to exploit market
inefficiencies and maximize our profits in our fuel marketing businesses. Our
fuel marketing operations require effective management of price, counterparty
and operational risks. To mitigate these risks, we have implemented risk
management policies and procedures for each of our marketing companies that
prohibit speculative strategies and establish price risk exposure levels,
counterparty credit limits and committees to monitor compliance with our
policies. We also limit exposure to energy marketing risks by maintaining
separate credit facilities for each of our marketing companies and by avoiding
the issuance of parent company performance guarantees to counterparties of our
marketing companies.
Build and Maintain Strong Relationships with Wholesale Energy Customers. We
strive to build strong relationships with utilities, municipalities and other
wholesale customers, who we believe will continue to be the primary providers of
electricity to retail customers in a deregulated environment. We further believe
that these entities will need products, such as capacity, in order to serve
their customers reliably. By providing these products under long-term contracts,
we are able to meet our customers' energy needs. Through this approach, we also
believe we can earn more stable revenues and greater returns over the long term
than we could by selling energy into the more volatile spot markets.
We have been successful in entering into a variety of wholesale contracts based
on the specific needs of our customers. For example, in 1999, Public Service
Company of Colorado approached us to take over ownership and construction of the
120 megawatt Arapahoe and Valmont facilities in Colorado. Public Service Company
of Colorado was subject to regulatory constraints that restricted its ability to
own the facilities and needed the plants completed in an efficient and timely
manner to meet the rapid growth in demand. We completed construction of the
facilities on schedule, and signed tolling agreements with Public Service
Company of Colorado for the capacity and energy generated by the original
facilities. We subsequently signed agreements to expand the projects by 90
megawatts. In addition, we recently acquired 240 megawatts at the Fountain
Valley site in Colorado which we expect to be in service in 2001. We have signed
tolling agreements with Public Service Company of Colorado for the expanded
facilities and the Fountain Valley site.
Capitalize On Our Utility's Established Market Presence, Relationships and
Customer Loyalty. As a result of its firmly established market presence, our
electric utility has built solid brand recognition and customer loyalty in the
Black Hills region. By ensuring a reliable supply of power to retail customers
in our South Dakota and Wyoming service territory at rates below the national
average, we have developed a strong, supportive relationship with our utility
regulators. Our utility provides a solid foundation of support for the expansion
of our independent energy and communications businesses. In addition, industry,
technical and market expertise from our utility supports the growth of our
independent energy businesses, and our strong brand recognition assists us in
achieving rapid customer acceptance of our bundled communications services in
our Black Hills service territory.
Independent Energy
Our independent energy group engages in the production and sale of electric
power through ownership of a diversified portfolio of generating plants, the
production of coal, natural gas and crude oil primarily in the Rocky Mountain
region, and the marketing of fuel products nationwide. The independent energy
group was our primary source of revenue and net income growth in 2000 and the
net income from the independent energy group is expected to exceed net income
from our regulated utility beginning in 2001. The independent energy group
consists of three units: independent power production, fuel production and fuel
marketing.
Independent Power Production. Our independent power production business
acquires, develops and expands unregulated power plants. We hold varying
interests in operating independent power plants in California, New York,
Massachusetts and Colorado with a total net ownership of 210 megawatts, as well
as minority interests in several power-related funds with a net ownership
interest of 40 megawatts.
Project Development Program. In February 2001, we signed a definitive agreement
with Enron Corporation to purchase 100 percent of an independent power project
under construction near Colorado Springs, Colorado and known as the "Fountain
Valley" project. We expect to close this transaction on or about March 31, 2001.
This site will initially house 240 megawatts of gas-fired peaking facilities.
The energy and capacity generated by the Fountain Valley project will be sold to
Public Service Company of Colorado under a tolling contract expiring in July
2012 pursuant to which we assume no fuel cost risk. We expect the plant to be
completed in phases beginning in June 2001 and ending in July 2001 with the
total cost expected to approximate $175 million. In addition to the current
project, we believe that the Fountain Valley site provides us with attractive
expansion and integration opportunities and is well-situated to serve other
markets in the Rocky Mountain and southwest regions.
In addition to Wygen I and the Fountain Valley development, other projects under
construction include:
o Arapahoe CC5, a 50 megawatt combined cycle expansion of our gas-fired
turbines at the Arapahoe site located in the Front Range of Colorado;
o Valmont Unit 8, a 40 megawatt gas-fired turbine addition to our Valmont
site located in the Front Range of Colorado;
o Black Hills Generation Gillette CT, a 40 megawatt gas-fired facility
located at the same site as our Wygen I plant; and
o Harbor Expansion, a 30 megawatt (10 megawatt net ownership interest)
expansion of our Harbor Cogeneration facility located in Wilmington,
California.
We also have an active acquisition and development program through which we are
pursuing a number of additional generation projects in various stages of
development, including the following:
o the Lange project, a 40 megawatt gas-fired turbine to be located either at
the same site as our Wygen I and Black Hills Generation CT plants near
Gillette, Wyoming, or adjacent to our transmission system in Rapid City,
South Dakota, and which we expect to compete in early 2002;
o a coal-fired mine-mouth power plant with generating capacity of up to 500
megawatts, to be located at our Wyodak site near Gillette, Wyoming, which
we expect to complete in 2005;
o three separate projects in early stage development with a total of 1,100
megawatts of generation to be located at sites we currently own in whole or
in part; and
o four additional early stage development projects with a total of 1,340
megawatts of generation at new sites which we do not currently control.
No assurance can be given that we will be successful in completing any or all of
the projects currently under consideration.
How We Manage Our Portfolio. We strive to maintain diversification and balance
in our portfolio of regulated and unregulated power plants. Our portfolio
(including plants currently operating and those under construction) is
diversified in terms of fuel mix and geographic location, with 81 percent of net
unregulated capacity being gas-fired, 13 percent coal-fired, and the remainder
hydroelectric. Our independent power plants are located in California, Wyoming,
South Dakota, Colorado, New York and Massachusetts. In contrast, our electric
utility capacity is approximately 53 percent coal-fired, 33 percent oil or
gas-fired, and 14 percent under purchased power contracts, with plants located
in South Dakota and Wyoming.
We also have a diversified mix of revenue sources. We typically sell two types
of products: energy and capacity, including ancillary services. Although these
are separate products, both are typically sold together. Energy refers to the
actual electricity generated by our facilities for ultimate transmission and
distribution to consumers of electricity. Energy is the only one of our products
that is subsequently distributed to consumers. Capacity refers to the physical
capability of a facility to produce energy. Ancillary services generally are
capacity support products used to ensure the safe and reliable operation of the
electric power supply system. Examples of ancillary services include:
o automatic generation control, which is used to balance energy supply with
energy demand, referred to in our industry as "load," on a real-time basis;
and
o operating reserves, which are used on an hourly or daily basis to generate
additional energy if demand increases or if major generating resources go
off-line or if transmission facilities become unavailable.
Our output is sold under contracts of varying length and subject to merchant
pricing, thereby allowing us to take advantage of current favorable price
trends, while hedging the impact of a potential downturn in prices in the
future. We currently sell energy and capacity under a combination of short- and
long-term contracts as well as direct sales into the merchant energy markets.
Currently, we sell 70 percent to 80 percent of our unregulated generating
capacity in operation under contracts greater than one year in duration. We sell
the remainder of this capacity under short-term contracts or directly into the
merchant markets. The energy and capacity generated by our Arapahoe and Valmont
projects, and the additional energy and capacity expected at these sites and at
our Fountain Valley project upon its completion, are subject to long-term
tolling agreements with Public Service Company of Colorado. Similarly, the
electricity generated by the Adirondack Hydro facilities in New York is under a
combination of short- and long-term agreements with Niagara Mohawk.
How We Develop and Acquire Power Plants. We plan to actively pursue power plant
acquisitions and development opportunities in areas we view as attractive
throughout North America. Our current focus has been, and is likely to remain,
in the North American Reliability Council region known as the Western Systems
Coordinating Council, or "WSCC." Among those factors we consider critical in
evaluating the relative attractiveness of new generation opportunities are the
following:
o electric demand growth potential in the targeted region;
o requirements for permitting and siting;
o proximity of the proposed site to high transmission capacity corridors;
o fuel supply reliability and pricing;
o the local regulatory environment; and
o the potential to exploit market expertise and operating efficiencies
relating to geographic concentration of new generation with our existing
power plant portfolio.
We intend to target both acquisition and development opportunities which provide
a minimum expected return on equity of 12 to 13 percent. We plan to concentrate
on development projects over acquisitions because we believe that development
projects generally offer us opportunities for higher rates of return.
Our goal is to sell approximately 80 percent of the independent power generation
portfolio under long-term contracts, while leaving the remainder available for
merchant, or "spot" sales. We aim to secure long-term power sales contracts in
conjunction with non-recourse plant financing. This enables us to design a debt
repayment schedule to closely match the term of the power sales contracts so
that at the end of the contract term, the debt has typically been repaid.
Independent Power Plants
General. Power facilities are often classified by cost of production. Facilities
that have the lowest costs of production relative to other power plants in the
region are usually the facilities that are first used to provide energy. These
plants are known as "baseload" facilities and typically operate more than 60
percent of the time they are available. Our hydroelectric assets in New York and
the Wygen I coal-fired facility under construction in Wyoming are examples of
low-cost, baseload plants.
As demand for electricity rises during the year or even during the course of a
day, power plants that have higher costs of production are dispatched to supply
additional energy. Facilities that regularly provide additional energy during a
day and that are typically used between 10 percent and 60 percent of the time
are known as "intermediate" facilities.
Power plants with the highest costs of production are called upon only in times
of exceptionally high demand and are known as "peaking units." Peaking units are
generally dispatched less than 10 percent of the time they are available.
Rocky Mountain and West Coast Facilities. We own approximately 151 megawatts of
generating capacity in the WSCC states of California and Colorado, and are in
the process of constructing or acquiring another 470 megawatts in the region.
All of these facilities in operation are gas-fired, with all but our Harbor
Cogeneration facility in California operating under long-term power purchase or
tolling agreements. The Harbor Cogeneration facility currently operates as a
merchant peaking plant selling ancillary services and energy into the California
market.
WSCC Facilities
Total
----------- Net
Capacity Capacity Start
Power Plant Fuel Type State (MWs) Interest (MWs) Date
- ----------- --------- ----- ----------- -------- -------- -----
In Operation:
Arapahoe Unit 5 Gas CO 40.0 100% 40.0 2000
Arapahoe Unit 6 Gas CO 40.0 100% 40.0 2000
Valmont Unit 7 Gas CO 40.0 100% 40.0 2000
Ontario Gas CA 12.0 50% 6.0 1984
Harbor Gas CA 80.0 31.8% 25.4 1989
Total in Operation 212.0 151.4
Under Construction:
Fountain Valley Gas CO 240.0 100% 240.0 2001
Arapahoe CC5 Gas CO 50.0 100% 50.0 2002
Valmont Unit 8 Gas CO 40.0 100% 40.0 2001
Wygen I Coal WY 90.0 100% 90.0 2003
BHG Gillette CT Gas WY 40.0 100% 40.0 2001
Harbor Expansion Gas CA 30.0 31.8% 9.5 2001
------ -------
Total in Construction 490.0 469.5
Total WSCC 702.0 620.9
===== =====
Arapahoe, Valmont and Fountain Valley Facilities
In Operation: Our Arapahoe and Valmont plants are wholly-owned gas-fired peaking
facilities in the Front Range of Colorado, with a total capacity of 120
megawatts. The projects were acquired from Public Service Company of Colorado in
January 2000 jointly by the former Indeck Capital and us, and were put into
service on June 1, 2000. We sell all of the output from these plants to Public
Service Company of Colorado under tolling contracts expiring in May 2012. These
contracts also cover the Fountain Valley project and the Arapahoe and Valmont
expansion projects described below.
Under Construction: We expect to increase our capacity by 40 megawatts at the
Valmont project by June 2001 and by 50 megawatts at the Arapahoe plant by May
2002.
The first phase of our 240 megawatt gas-fired Fountain Valley facility is
scheduled for completion in June 2001, with final completion scheduled for July
2001. The Fountain Valley site, located in Colorado has ample capacity for
subsequent expansion if market conditions prove to be attractive.
Wygen I Facility
The Wygen I facility is a leased mine-month coal-fired plant with a total
capacity of 90 megawatts, which is expected to be completed by spring 2003. The
Wygen I plant will be substantially identical in design to our electric
utility's Neil Simpson II facility, completed in 1995. The two plants will both
run on pulverized low-sulfur coal fed by conveyor from our adjacent Wyodak mine.
The plant will burn approximately 500,000 tons of coal per year, and will use
the latest available environmental control technology. We intend to sell the
majority of the power from the facility under long-term unit contingent capacity
and energy sales contracts, under which delivery is not required during plant
outages. We have entered into a contract to sell 60 megawatts of unit contingent
capacity from this plant to Cheyenne Light, Fuel and Power Company with a term
of 10 years from the date the plant becomes operational. We have also signed a
contract to sell an additional 20 megawatts of unit contingent capacity and
energy to the Municipal Electric Agency of Nebraska for a term of 10 years.
Black Hills Generation Gillette CT
The Black Hills Generation Gillette CT facility, a gas-fired combustion turbine
facility located at the same site as our Wygen I facility, has a total capacity
of 40 megawatts and is scheduled to be completed in May 2001. We plan to utilize
this facility as a merchant plant through summer 2001. Beginning in September
2001, we will sell the energy and capacity from this facility to Cheyenne Light,
Fuel and Power Company under a 10-year unit contingent tolling agreement.
Ontario Cogeneration Facility
Ontario Cogeneration Company is a 12 megawatt, gas-fired power plant in Ontario,
California, which is currently being operated as a baseload plant. Electrical
output from the plant is subject to a 25-year power purchase agreement with
Southern California Edison which expires in January 2010. The project also sells
all of its steam production to Sunkist Growers, Inc. under a five-year agreement
which terminates in November 2002. For a description of certain issues relating
to our operation of this plant, see "--Regulation--Environmental
Regulation--Clean Air Act."
Harbor Cogeneration Facility
In Operation: Harbor Cogeneration, a gas-fired plant located in Wilmington,
California, is currently being operated as a merchant peaking plant selling
ancillary services and energy into the California Independent System Operator,
or "CAISO," market. It formerly operated under a 30-year power purchase
agreement with Edison Mission Energy. This contract was terminated in February
1999 under a settlement agreement with Southern California Edison. Under the
buyout agreement, Harbor Cogeneration will receive payments pursuant to a
termination payment schedule for an amount equal to the total payment under the
original contract due for the 11-year period beginning April 1, 1997 and ending
on October 1, 2008. The facility currently has no long-term debt outstanding.
Under Construction/Expansion: We are currently expanding the Harbor Cogeneration
plant by an additional 30 megawatts (10 megawatt net ownership interest), with a
targeted completion date of May 2001. The plant has sold the peaking capacity
from its expansion to the CAISO for the peak summer periods of 2001 through 2003
under an agreement that provides for payments to us of $1 million per year for
each of 2001, 2002 and 2003. We plan to sell the remaining capacity and all of
the energy from this plant in the California market on a merchant basis.
Lange Project
In March 2001, we placed an order for a 40 megawatt gas-fired combustion turbine
which will be located either adjacent to the Wygen I and our Black Hills
Generation Gillette CT plants near Gillette, Wyoming, or at a new site adjacent
to our transmission system in Rapid City, South Dakota, where we have received
all necessary permits for the construction of two 40 megawatt combustion turbine
facilities. We expect the first 40 megawatt turbine unit to be operational in
early 2002.
Northeast Facilities. We currently own approximately 58 net megawatts of
generation capacity in eight plants in the Northeast region, all of which are
located in New York and Massachusetts. Sixty-seven percent of this generation is
"run-of-river" hydroelectric, with the remainder being gas-fired peaking
capacity.
Total Net
Fuel Capacity Capacity Start
Power Plant Type State (MWs) Interest (MWs) Date
----- ----- -------- -------- -------- -----
Northeast
New York State Dam Hydro NY 11.4 100% 11.4 1990
Middle Falls Hydro NY 2.3 50% 1.2 1989
Sissonville Hydro NY 3.0 100% 3.0 1990
Warrensburg Hydro NY 2.9 100% 2.9 1988
Hudson Falls Hydro NY 41.9 30.2% 12.7 1995
South Glens Falls Hydro NY 13.9 30.2% 4.2 1994
Fourth Branch Hydro NY 3.4 100% 3.4 1988
Pepperell Gas MA 40.0 48.7% 19.5 1990
------ -----
Total (Northeast) 118.8 58.3
Adirondack Hydro Development
The seven "run-of-river" hydroelectric plant interests acquired as a
result of our acquisition of Indeck Capital are:
o New York State Dam, an 11.4 megawatt plant located in Waterford
and Cohoes, New York;
o Middle Falls, a 2.3 megawatt plant located in Easton, New York;
o Sissonville, a 3.0 megawatt plant located in Potsdam, New York;
o Warrensburg, a 2.9 megawatt plant located in Warrensburg, New
York;
o Hudson Falls, a 41.9 megawatt plant located in Moreau, New York;
o South Glens Falls, a 13.9 megawatt plant located in South Glens
Falls, New York; and
o Fourth Branch, a 3.4 megawatt plant located in Waterford, New
York.
We acquired approximately 10 percent of the Hudson Falls and the South Glens
Falls plants as part of the Indeck Capital acquisition and an additional 20
percent of these plants in December 2000. These projects run at a high capacity
factor because the Hudson River is regulated for power generation and flood
control.
The seven projects were initially covered by long-term power purchase contracts
with Niagara Mohawk for all or most of their output. Currently, three projects
have been restructured to allow the power purchase contracts to be bought out
and for us eventually to sell power into the New York Independent System
Operator (NY-ISO). The New York State Dam, Sissonville, Fourth Branch and
Warrensburg facilities are currently subject to short-term transition power
sales agreements expiring in 2002 and 2003, at which point these plants will
sell directly into the market on a merchant basis. The remaining three New York
plants, Hudson Falls, South Glens Falls and Middle Falls, continue to operate
under long-term power purchase agreements with Niagara Mohawk.
Pepperell Facility
The Pepperell facility is a 40 megawatt gas-fired combined-cycle plant located
in Pepperell, Massachusetts. The plant is currently subject to a tolling
agreement with Enron Power and Trading for the sale of a majority of its energy
for the year 2001, and a steam sales agreement with the Pepperell Paper Company
expiring in November 2001.
Power Funds. In addition to our ownership of the power plants described above,
we hold various indirect interests in power plants through our investment in
energy and energy-related funds, both domestic and international, as described
below:
Left to
Total be Number Total Net
Amount Funded of Capacity Capacity
Fund Name ($MM) ($MM) Plants (MWs) Interest (MWs)
--------- ------ ------- ------ -------- -------- --------
Energy Investors Fund I $159.5 $0 7 136.0 12.6% 17.1
Energy Investors Fund II $115.0 $0 6 130.0 6.9% 9.0
Project Finance Fund III $101.0 $0 7 239.0 5.3% 12.7
Caribbean Basin $75.0 $60 1 34.0 3.7% 1.3
----- ----
Total Fund Interests 539.0 40.1
Financing of Our Independent Power Projects. We have financed our principal
independent power generation facilities primarily with non-recourse debt that is
repaid solely from the project's revenues. This type of financing is referred to
as "project financing." These financings generally are secured by the physical
assets, major project contracts and agreements, cash accounts and, in certain
cases, our ownership interest, in the related project. True project financing is
not available for all projects, including some assets purchased out of
bankruptcy, some merchant plants and some purchases of minority stock positions
in publicly-traded companies. Even in those instances, however, we may still be
able to finance a smaller portion of the total cost with project financing, with
the remainder financed with debt that is either raised or supported at the
corporate rather than the project level.
Project financing transactions generally are structured so that all revenues of
a project are deposited directly with a bank or other financial institution
acting as escrow or security deposit agent. These funds then are payable in a
specified order of priority set forth in the financing documents to ensure that,
to the extent available, they are used first to pay operating expenses, senior
debt service and taxes and to fund reserve accounts. Thereafter, subject to
satisfying debt service coverage ratios and certain other conditions, available
funds may be disbursed for management fees or dividends or, where there are
subordinated lenders, to the payment of subordinated debt service.
These project financing structures are designed to prevent the lenders from
relying on us or our other projects for repayment; that is, they are
"non-recourse" to us and our affiliates not involved in the project, unless we
or another affiliate expressly agree to undertake liability. In the event of a
foreclosure after a default, our project affiliate owning the facility would
only retain an interest in the assets, if any, remaining after all debts and
obligations were paid. In addition, the debt of each operating project may
reduce the liquidity of our equity interest in that project because the interest
is typically subject both to a pledge securing the project's debt and to
transfer restrictions set forth in the relevant financing agreements. Also, our
ability to transfer or sell our interest in certain projects or the project's
power is restricted by certain purchase options or rights of first refusal in
favor of our partners and certain change of control restrictions in the project
financing documents.
Fuel Production
Coal
Our coal production segment mines and processes low-sulfur sub-bituminous coal
near Gillette, Wyoming. The Wyodak mine, which we acquired in 1956 from
Homestake Gold Mining Company, is located on top of the Powder River Basin, one
of the largest coal reserves in the United States. We believe the Wyodak mine is
the oldest operating surface coal mine in the nation, with an annual production
of approximately three million tons. Mining rights to the coal are based on four
federal leases and one state lease. We pay royalties of 12.5 percent and 9.0
percent, respectively, of the selling price on all federal and state coal. As of
December 31, 2000, we had coal reserves of 275 million tons, enough to satisfy
present contracts for over 90 years. Substantially all of our coal production is
sold under long-term contracts to Black Hills Power, Inc., our electric utility,
and to PacifiCorp.
Our coal segment's agreement with Black Hills Power limits earnings from all
coal sales to Black Hills Power to a specified return on our original cost
depreciated investment base. Black Hills Power made a commitment to the South
Dakota Public Utilities Commission, the Wyoming Public Service Commission and
the City of Gillette that coal would be furnished and priced as provided by that
agreement for the life of our Neil Simpson II plant.
The price for unprocessed coal sold to PacifiCorp for its 80 percent interest in
the Wyodak Plant is determined by a coal supply agreement terminating in 2013.
For a description of litigation with PacifiCorp relating to this agreement, see
"ITEM 3. LEGAL PROCEEDINGS - PacifiCorp Litigation."
In May 2000, we acquired the K-Fuel plant, a coal enhancement plant located near
our Gillette, Wyoming coal mine. The plant, which transforms high-moisture,
low-heat-value coal into low-moisture, high-heat-value coal, is currently not in
service. We are working in conjunction with Denver-based KFx, Inc. to attract
investors to make the capital improvements necessary to re-start the plant. If
we do not locate suitable investment partners, the plant will not be re-started.
Over the next several years, we expect to increase coal production to supply:
o the Wygen I 90 megawatt mine-mouth power plant, which is scheduled for
completion in 2003; and
o additional mine mouth generating capacity of up to 500 megawatts at the
same site as the Wygen I plant, which is in the early stages of
development.
In addition, if our K-Fuel plant is re-started, we expect to increase production
from the Wyodak mine and market any low-moisture, high-heat content coal we
produce to an expanded customer base.
Natural Gas and Crude Oil
Our oil and gas exploration and production segment operates approximately 298
oil and gas wells, all of which are located in Wyoming. The majority of these
wells are in the Finn-Shurley Field area, located in Weston and Niobrara
Counties in Wyoming. We also own a working interest in, but do not operate, an
additional 341 wells located in California, Montana, North Dakota, Texas,
Wyoming, Oklahoma and offshore in the Gulf of Mexico. In addition, we have
accumulated significant acreage in the Rocky Mountain region, which we plan to
utilize for oil and gas exploration.
We plan to substantially increase our natural gas reserves and minimize
exploration risk by focusing on lower-risk exploration and development drilling
and acquisitions of proven producing properties. A key component of this
strategy is the pursuit of shallow gas opportunities in the Rocky Mountain
region. We also expect to modestly increase our California and offshore
production in the future, but do not plan to serve as the operator for those
production activities.
As of December 31, 2000, we had proved reserves of 4.4 million barrels of oil
and 18.4 billion cubic feet of natural gas, with approximately 62 percent of
current production consisting of natural gas. In 2000, our oil and gas
production increased 12 percent over 1999 levels, with record drilling results
and year-end reserves.
In March 2001, we signed a definitive agreement to purchase certain operating
and non-operating interests in 74 oil and gas wells located primarily in
Colorado and Wyoming. We expect this transaction to close in April 2001. These
properties have proved reserves of approximately 8.7 billion cubic feet of
natural gas and approximately 200,000 barrels of oil, representing an increase
in our existing proved reserves of over 20 percent.
Fuel Marketing. We market natural gas, oil and coal in specific regions of the
United States. We offer physical and financial wholesale fuel marketing and
price risk management products and services to a variety of customers. These
customers include natural gas distribution companies, municipalities, industrial
users, oil and gas producers, electric utilities, coal mines, energy marketers
and retail gas users. Our fuel marketing businesses collectively have 35
employees. Our average daily marketing volumes for the year ended December 31,
2000, were 860,800 million British thermal units of gas, 44,300 barrels of oil
and 4,400 tons of coal.
The following table briefly summarizes the location of our fuel marketing
operations and sales offices:
Marketing
Company Fuel Operations Sales Offices
- ---------------------------------------- ----------- ---------- -------------------------------------
Enserco Energy Natural Gas Golden, CO Chicago, IL; Calgary, Alberta, Canada
Black Hills Energy Resources Crude Oil Houston, TX Tulsa, OK; Midland, TX; Longview, TX
Black Hills Coal Network Coal Mason, OH St. Clairsville, OH
Gas Marketing
Our natural gas marketing operations are headquartered in Golden, Colorado, with
satellite offices in Calgary, Canada and Chicago, Illinois. Our gas marketing
operations focus primarily on wholesale marketing and producer marketing
services. Producer services include providing for direct purchases of wellhead
gas and for risk transfer and hedging products. Our gas marketing efforts are
concentrated in the Rocky Mountain and West Coast regions and in Western Canada,
which are areas in which we believe we have a competitive advantage due to our
knowledge of local markets. We contractually hold natural gas storage capacity
and both long and short-term transportation capacity on several major pipelines
in the western United States and Canada. We utilize this capacity to move
relatively low cost natural gas from the producer regions to more expensive
end-use market areas.
Oil Marketing and Transportation
Our crude oil marketing and transportation operations are concentrated primarily
in Texas, Oklahoma, Louisiana and Arkansas. In July 1999, we acquired a 33
percent ownership interest in a 200-mile pipeline, with a capacity of 67,000
barrels of oil per day, that transports imported crude oil from Beaumont, Texas
to refining and trading markets in northern regions.
Coal Marketing
We market coal to various industrial customers and power plants located
primarily in the midwest and eastern regions of the United States through our
coal marketing subsidiary, Black Hills Coal Network. We formed Black Hills Coal
Network in 1998 to acquire the assets and hire the operational management of
Coal Network and Coal Niche, based in Mason, Ohio. These predecessor companies
were coal brokerage and agency companies with customers located primarily east
of the Mississippi River.
Electric Utility - Black Hills Power, Inc.
Our electric utility, Black Hills Power, is engaged in the generation,
transmission and distribution of electricity. It provides a solid foundation of
revenues, earnings and cash flow that support utility capital expenditures,
dividends, and overall performance and growth.
Distribution and Transmission. Our electric utility distribution and
transmission businesses serve approximately 58,600 electric customers, with an
electric transmission system of 447 miles of high voltage lines and 541 miles of
lower voltage lines. Our utility's service territory covers a 9,300 square mile
area of western South Dakota, eastern Wyoming and southeastern Montana with a
strong and stable economic base. Over 90 percent of our utility's retail
electric revenues are generated in South Dakota.
The following are characteristics of our distribution and transmission
businesses:
o We have a diverse customer and revenue base. Our revenue mix in 2000 is
comprised of 29 percent wholesale off-system sales, 26 percent commercial,
20 percent residential, 14 percent industrial, 10 percent contract
wholesale and 1 percent municipal. Approximately 68 percent of our large
commercial and industrial customers are provided service under long-term
contracts. We have historically optimized the utilization of our power
supply resources by selling wholesale power to other utilities and to power
marketers in the spot market and through short-term sales contracts.
o In 1999, the South Dakota Public Utilities Commission extended our previous
retail rate freeze for another five-years, through January 1, 2005. The
rate freeze preserves our low-cost rate structure at levels below the
national average for our retail customers while allowing us to retain the
benefits from cost savings and from wholesale "off-system" sales, which are
not covered by the rate freeze. This provides us with flexibility in
allocating our generating capacity to maximize returns in changing market
environments.
o Twenty-nine percent of our electric revenues for the year ended December
31, 2000 consisted of off-system sales compared to 8 percent in 1999 and 5
percent in 1998. Further increases in the volume of off-system sales are
expected in the future due to demand growth in the Rocky Mountain region
and the June 2000 addition of 40 megawatts of gas-fired generating
capacity.
o Our system has the capability of connecting to either the midwestern or
western transmission systems, which provides us with access between the
WSCC region and the Mid-Continent Area Power Pool, or "MAPP" region. This
allows us the opportunity to improve system reliability and take advantage
of power price differentials between the two electric grids. We are able to
transmit up to 80 megawatts of our generation into the MAPP. Alternatively,
we can receive up to 20 megawatts of power from MAPP into our WSCC-based
system. We expect to increase this capability to 50 megawatts in 2001
through an upgrade of our facilities at a cost of less than $1 million.
o We have firm transmission access to deliver up to 65 megawatts of power on
PacifiCorp's system to wholesale customers in the western region.
On October 15, 2000, we indicated to FERC our intent to participate in a
regional transmission organization, or RTO. Our transmission system is a part of
the western transmission grid governed by the Western Systems Coordinating
Council, and it interconnects with transmission systems operated by the Western
Area Power Administration, or WAPA, and by PacifiCorp. WAPA is evaluating
participation in the Desert Star RTO which will involve transmission systems in
Colorado and the southwest region, while PacifiCorp is evaluating participation
in the RTO West which will involve transmission systems in Wyoming and the
northwest region. Neither Desert Star RTO nor RTO West has been formally
organized at this time, but we expect that Desert Star RTO and RTO West will be
making their final FERC filings late this year or in early 2002. If FERC
approves these two RTOs, the organizations anticipate being fully operational in
late 2002. We will continue to monitor the development of these two RTOs and
decide in the future which RTO best fits our transmission system and operations.
Power Purchase Agreements. We sell approximately 40 percent of our utility's
current load under long-term contracts. Our key contracts include a 10-year
contract expiring in 2007 with Montana-Dakota Utilities Company for the sale of
up to 55 megawatts of energy and capacity to service the Sheridan, Wyoming
electric service territory, and a contract with the City of Gillette, Wyoming,
expiring in 2012, to provide the city's first 23 megawatts of capacity and
energy. Both contracts are integrated into our control system and are treated as
firm native load. In addition, we recently entered into an agreement with the
Municipal Electric Agency of Nebraska for the sale of 30 megawatts of unit
contingent energy and capacity for a period through the completion of
construction of the Wygen I independent power facility, which is expected in
spring 2003. For the 10-year period beginning with the completion of the Wygen I
facility, our utility and our independent power unit will each provide 20
megawatts of unit contingent energy and capacity to the Municipal Electric
Agency of Nebraska.
Our utility's electric load is served by coal-, oil- and natural gas-fired
generating units providing 393 megawatts of generation capacity and from the
following purchased power and capacity contracts with PacifiCorp:
o a power sales agreement expiring in 2023, involving the purchase by us of
65 megawatts of baseload power in 2001, and scheduled to decline to 50
megawatts by 2004;
o a reserve capacity integration agreement expiring in 2012, which makes
available to us 100 megawatts of reserve capacity in connection with the
utilization of the Ben French CT units; and
o a capacity option call, which gives us an option to purchase up to 60
megawatts of peaking capacity seasonally through March 31, 2007.
Regulated Power Plants. Since 1995, our utility has been a net producer of
energy. Our utility owns 393 megawatts of generating capacity, all of which is
located in the Rocky Mountain region. Our utility's peak system load of 372
megawatts was reached in July 2000. None of our generation is restricted by
hours of operation, thereby providing us with the ability to generate power to
meet demand whenever necessary and feasible.
The following table describes our utility's portfolio of power plants:
Total Net
Fuel Capacity Capacity
Power Plant Type State (MWs) Interest (MWs) Start Date
- ----------- ---- ----- -------- -------- -------- ----------
Ben French Coal SD 25.0 100% 25.0 1960
Ben French Diesels 1-5 Diesel SD 10.0 100% 10.0 1965
Ben French CTs 1-4 Gas/Oil SD 100.0 100% 100.0 1977-1979
Neil Simpson I Coal WY 21.8 100% 21.8 1969
Neil Simpson II Coal WY 88.9 100% 88.9 1995
Osage Coal WY 34.5 100% 34.5 1948
Wyodak Coal WY 362.0 20% 72.4 1978
Neil Simpson CT Gas WY 40.0 100% 40.0 2000
----- -----
Total 682.2 392.6
===== =====
Ben French
Ben French is a wholly-owned coal-fired plant situated in Rapid City, South
Dakota, with a capacity of 25 megawatts. This plant was put into service in 1960
and has since been operating as a baseload plant. Coal for the plant is
purchased from our Wyodak mine and delivered by truck.
Ben French Diesel Units 1-5
The Ben French Diesel Units 1-5 are wholly-owned diesel-fired plants located in
Rapid City, South Dakota, with a capacity of 10 megawatts. These plants were put
into service in 1965, and are being operated as peaking plants.
Ben French CT's 1-4
The Ben French Combustion Turbines 1-4 are wholly-owned gas and oil-fired units
with a capacity of 100 megawatts located in Rapid City, South Dakota. These
facilities were put into service from 1977 to 1979, and are being operated as
peaking units.
Neil Simpson I and II
Neil Simpson I and II are air-cooled, coal-fired wholly-owned facilities located
near Gillette, Wyoming. Neil Simpson I has a capacity of 21.8 megawatts and was
put into service in 1969. Neil Simpson II has a capacity of 88.9 megawatts and
was put into service in 1995. These plants are operated as baseload facilities,
and are mine-mouth coal-supplied plants, receiving their coal directly from the
Wyodak mine.
Osage
The Osage plant is a wholly-owned coal-fired plant in Osage, Wyoming with a
total capacity of 34.5 megawatts and was put into service from 1948 to 1952.
This plant has three turbine generation units, and is being operated as a
baseload plant. Coal for the plant is purchased from our Wyodak mine and
delivered by truck.
Wyodak
Wyodak is a 362 megawatt mine mouth coal-fired plant owned jointly by PacifiCorp
and us and in which we hold a 20 percent (72.4 net megawatt) ownership interest.
Our Wyodak mine furnishes all the coal fuel supply for the Wyodak plant. The
plant was put into service in 1978, and is currently being operated as a
baseload plant.
Neil Simpson CT
The Neil Simpson Combustion Turbine is a wholly-owned gas-fired plant located
near Gillette, Wyoming with a capacity of 40 megawatts. This plant was put into
service in 2000, and was installed to provide peaking capabilities.
Communications
Our communications group, known as Black Hills FiberCom, was formed to provide
state-of-the-art broadband telecommunications services to the underserved
markets of Rapid City and the northern Black Hills of South Dakota. We offer
residential and business customers a full suite of telecommunications services,
including local and long distance telephone service, expanded cable television
service, cable modem Internet access and high speed data and video services. We
have completed a 210-mile inter- and intra-city fiber optic network and
currently operate 588 miles of two-way interactive hybrid fiber coaxial or "HFC"
cable. We believe we are one of the first companies in the United States to
provide video entertainment service, high-speed Internet access, and local and
long distance telephone services over an advanced broadband infrastructure. We
have bundled these services into value packages with a single consolidated bill
for all of these services.
We introduced our broadband communications services to the Rapid City and
northern Black Hills areas in November 1999. As of December 31, 2000, we had
attracted 8,368 residential customers and 646 business customers. Our goal is to
double the number of our customers, and to attain 50 percent residential market
penetration within our service territory while serving 35 percent of all
broadband business customers in that territory.
The construction of our communications network is approximately 75 percent
complete and we expect to substantially complete construction in 2001. We
estimate that completing our network will require approximately $25 million of
capital expenditures in 2001.
Competition
The independent power, fuel production and fuel marketing industries are
characterized by numerous strong and capable competitors, some of which may have
more extensive operating experience, larger staffs or greater financial
resources than us. In particular, the independent power industry in recent years
has been characterized by increased competition for asset purchases and
development opportunities.
In addition, Congress has considered various pieces of legislation to
restructure the electric industry that would require, among other things,
customer choice and/or repeal of the Public Utility Holding Company Act of 1935,
or PUHCA. The debate is likely to continue and perhaps intensify. The effect of
enacting such legislation cannot be predicted with any degree of certainty.
Industry deregulation may encourage the disaggregation of vertically integrated
utilities into separate generation, transmission and distribution businesses. As
a result of these potential regulatory changes, significant additional
competitors could become active in the generation segment of our industry.
Our communications unit faces competition from numerous well established
companies, including Qwest Communications, Rapid City's incumbent local exchange
carrier, Midcontinent Communications, the area's incumbent cable television
provider, as well as long distance providers and Internet service providers. Our
success in this business will depend upon, among other things, the quality of
our customer service, the willingness of residential and business customers to
accept us as an alternative provider of broadband communications services, our
products and services and our ability to offer an attractive package of bundled
products.
Risk Management
Our fuel marketing operations require efficient risk management of price,
counterparty performance and operational risks. Price risk is created through
the volatility of energy prices. Counterparty performance risk is the risk that
a counterparty will fail to satisfy its contractual obligations to us, and
includes credit risk. Operational risk arises from a lack of internal controls.
We have implemented controls to mitigate each of these risks.
Our fuel marketing operations are conducted in accordance with guidelines
established through separate risk management policies and procedures for each
marketing company and through our credit policy. These policies are established
by our board of directors, reviewed on a regular basis and monitored as
described below.
We maintain a working risk management committee for each of our marketing
companies, and a credit committee at the parent company level. The risk
management committees focus on implementation of risk management procedures and
on monitoring compliance with established policies. The credit committee sets
counterparty credit limits, monitors credit exposure levels and reviews
compliance with established credit policies. Additionally, we employ a risk
manager and a credit manager responsible for overseeing these functions.
Our risk management policies and procedures specify maximum price risk exposure
levels within which each respective marketing company must operate. These
policies and procedures establish relatively low exposure levels and prohibit
speculative trading strategies.
As part of our enterprise-wide risk management strategy, we limit our exposure
to energy marketing risks by maintaining separate credit facilities within each
of our fuel marketing companies. These credit facilities have security interests
solely against the assets of the respective marketing company, with the
exception of a $1 million guarantee by our coal mining subsidiary on our coal
marketing unit's credit facility. We do not currently issue parent company
performance guarantees to counterparties of our marketing companies.
A significant potential risk related to power sales is the price risk arising
from the sale of wholesale power that exceeds our generating capacity. Short
positions can arise from unplanned plant outages or from unanticipated load
demands. To control such risks, we restrict wholesale off-system sales to
amounts by which our anticipated generation capabilities exceed our anticipated
load requirements plus a required reserve margin. We further control this risk
by selling only in the day-ahead power market and by entering into longer-term
sales contracts that are made on a "unit contingent" basis, under which delivery
is not required during unplanned outages at specified power plants.
California Markets
In 1996, California enacted legislation restructuring the state's investor-owned
utilities. The legislation instituted a freeze on retail rates that
investor-owned utilities could charge their customers for the duration of a
transition period established by the legislation. The legislation did not make
any provision for a California utility to recover costs of purchased electricity
that exceeded the rates that could be charged under the rate freeze. Due to
inadequate supplies of power and an unanticipated surge in demand, the
California market has experienced rapid increases in electric power and natural
gas prices. As a result, the state's two largest investor-owned utilities,
Pacific Gas & Electric Company (PG&E) and Southern California Edison (SCE), have
incurred costs of procuring power significantly in excess of their ability to
recover those costs through authorized retail rates and have indicated that,
unless the rate freeze is eliminated or other proposed relief is provided, they
are, or shortly will become, insolvent.
We may experience losses related to the potential insolvency of the California
utilities in the event that a utility defaults on its obligations:
o under its agreements with us;
o to the CAISO, which administers the real-time markets for energy and
ancillary services, resulting in non-payment to us under our capacity sales
agreement with the CAISO; or
o to other energy companies, causing those energy companies to default on
their obligations to us.
We have two agreements with SCE involving our California independent power
plants.
o In 1999, we entered into a settlement agreement with SCE involving the
Harbor Cogeneration plant located in Wilmington, California, in which we
own a 31.8 percent interest. The settlement agreement provides for the
termination of a 30-year power purchase agreement, in exchange for payments
of approximately $4 million per year by SCE through October 2008 for our
interest in the plant.
o The cogeneration plant located in Ontario, California is entitled to
receive energy and capacity payments from SCE of approximately $1.7 million
per year, under a long-term contract expiring in 2010.
As of March 1, 2001, SCE owed us past due payments of approximately $1.5
million, with delinquencies ranging from 15 to 75 days in duration. We have no
other material contractual relationships with SCE and no material agreements
with PG&E.
The Harbor Cogeneration plant has sold the peaking capacity from its expansion
to the CAISO for the peak summer periods of 2001 through 2003 under an agreement
that provides for payments to us of $1 million per year for each of 2001, 2002
and 2003. We have no other agreements with the CAISO and do not otherwise sell
capacity and energy directly into the California market either through long-term
contracts or on a merchant basis. All other merchant sales are made to power
marketers who in turn sell into the California market. In addition, our fuel
production and fuel marketing exposure to the California market is primarily
indirect through sales to creditworthy counterparties, including neighboring
utilities and gas and power marketing firms.
In recent months, the Governor of the State of California, representatives of
the state legislature and numerous industry participants have undertaken several
initiatives designed to address market disruptions in California. In February
2001, SCE reached a tentative agreement under which the state would pay $2.76
billion to purchase SCE's high voltage transmission system and SCE would drop a
federal lawsuit in which it has sought authority to bill its customers for past
unrecovered costs. Prior to its implementation, this agreement must be approved
by the California state legislature. There is no assurance that any legislation
will be enacted or that, if enacted, the sale of transmission assets will
provide SCE with sufficient funds to pay any current or future obligations to
us. In addition, there is no assurance that any current or future defaults by
California utilities on obligations owed to others will not result in defaults
by our counterparties. However, we believe that our direct exposure to potential
defaults in the California market is largely limited to the agreements with SCE
and the CAISO described above and that our indirect exposure is minimal.
Regulation
We are subject to a broad range of federal, state and local energy and
environmental laws and regulations applicable to the development, ownership and
operation of our projects. These laws and regulations generally require that a
wide variety of permits and other approvals be obtained before construction or
operation of a power plant commences and that, after completion, the facility
operate in compliance with their requirements. We strive to comply with the
terms of all such laws, regulations, permits and licenses and believe that all
of our operating plans are in material compliance with all such applicable
requirements.
Energy Regulation
Federal Power Act. The Federal Power Act gives FERC exclusive rate-making
jurisdiction over wholesale sales of electricity and the transmission of
electricity in interstate commerce. Pursuant to the Federal Power Act, all
public utilities subject to FERC's jurisdiction are required to file rate
schedules with FERC prior to commencement of wholesale sales or interstate
transmission of electricity. Public utilities with cost-based rate schedules are
also subject to accounting, record-keeping and reporting requirements
administered by FERC.
The Energy Policy Act. The passage of the Energy Policy Act in 1992 further
encouraged independent power production by providing certain exemptions from
regulation for exempt wholesale generators, or EWGs. All of our subsidiaries
that would otherwise be treated as public utilities are currently treated as
EWGs under the Energy Policy Act. An EWG is an entity that is exclusively
engaged, directly or indirectly, in the business of owning or operating
facilities that are exclusively engaged in generation and selling electric
energy at wholesale. An EWG will not be regulated under PUHCA, but is subject to
FERC and state public utility commission regulatory reviews, including rate
approval. Since EWGs are only allowed to sell power at wholesale, their rates
must receive initial approval from FERC rather than the states. All of our EWGs
to date that have sought rate approval from FERC have been granted market-based
rate authority, which allows FERC to waive certain accounting, record-keeping
and reporting requirements imposed on public utilities with cost-based rates.
However, FERC customarily reserves the right to suspend, upon complaint,
market-based rate authority on a prospective basis if it is subsequently
determined that we or any of our EWGs exercised market power. If FERC were to
suspend market-based rate authority, it would most likely be necessary to file,
and obtain FERC acceptance of, cost-based rate schedules for any of our EWGs.
Also, the loss of market-based rate authority would subject the EWGs to the
accounting, record-keeping and reporting requirements that are imposed on public
utilities with cost-based rate schedules.
In addition, if there occurs a "material change" in facts that might affect any
of our subsidiaries' eligibility for EWG status, within 60 days of the material
change, the relevant EWG must (1) file a written explanation of why the material
change does not affect its EWG status, (2) file a new application for EWG
status, or (3) notify FERC that it no longer wishes to maintain EWG status. If
any of our subsidiaries were to lose EWG status, we, along with our affiliates,
would be subject to regulation under PUHCA as a public utility company. Absent a
substantial restructuring of our business, it would be difficult for us to
comply with PUHCA without a material adverse effect on our business.
State Energy Regulation. In areas outside of wholesale rate regulation (such as
financial or organizational regulation), some state utility laws may give their
public utility commissions broad jurisdiction over steam sales or EWGs that sell
power in their service territories. The actual scope of the jurisdiction over
steam or independent power projects depends on state law and varies
significantly from state to state.
Environmental Regulation
The construction and operation of power projects are subject to extensive
environmental protection and land use regulation in the United States. These
laws and regulations often require a lengthy and complex process of obtaining
licenses, permits and approvals from federal, state and local agencies. If such
laws and regulations are changed and our facilities are not grandfathered,
extensive modifications to project technologies and facilities could be
required.
General. Based on current trends, we expect that environmental and land use
regulation will continue to be stringent. Accordingly, we actively review
proposed construction projects that could subject us to stringent pollution
controls imposed on "major modifications," as defined under the Clean Air Act,
and changes in "discharge characteristics," as defined under the Clean Water
Act. The goal of these actions is to achieve compliance with applicable
regulations, administrative consent orders and variances from applicable
air-quality related regulations.
Clean Air Act. Our Neil Simpson II and Wyodak plants located in Gillette,
Wyoming are subject to Title IV of the Clean Air Act, which requires certain
fossil-fuel-fired combustion devices to hold sulfur dioxide "allowances" for
each ton of sulfur dioxide emitted. We currently hold sufficient allowances
credited to us as a result of sulfur removal equipment previously installed at
the Wyodak plant to apply to the operation of the Neil Simpson II plant and our
interest in the Wyodak plant through 2030 without requiring the purchase of any
additional allowances. With respect to any future plants, we plan to comply with
the need for holding the appropriate number of allowances by reducing sulfur
dioxide emissions through the use of low sulfur fuels, installation of "back
end" control technology and the purchase of allowances on the open market. We
expect to integrate the costs of obtaining the required number of allowances
needed for future projects into our overall financial analysis of such projects.
On July 14, 2000, the South Coast Air Quality Management District, known as
SCAQMD, sent a letter to our affiliate, now called Black Hills Ontario, L.L.C.,
the operator of a 12 megawatt natural-gas fired cogeneration facility located in
Ontario, California, stating that the SCAQMD had determined, as a result of a
facility audit completed for the compliance year ended June 1, 1999, that the
facility's nitrogen oxide, or NOx, emissions were 28,958 pounds over the
facility's NOx allocation established by the SCAQMD's RECLAIM emissions trading
program. As a result, the SCAQMD indicated that it would be reducing the
facility's NOx allocation by the same number of allowances for the compliance
year subsequent to a final determination on this issue. If a final determination
is reached prior to June 30, 2001, the NOx allowances would be deducted from the
facility's allocation for the compliance year ended June 30, 2002. Black Hills
Ontario has provided documentation to the SCAQMD disputing this proposed
reduction. In addition to this proposed reduction, which could affect the
facility's compliance with RECLAIM requirements for the 2001-2002 compliance
period, Black Hills Ontario also projects that its NOx emissions for the
compliance year ended June 30, 2001 may be approximately 30,000 pounds over its
current NOx allocation. There is currently significant volatility in the price
and supply of RECLAIM NOx allowances; although the SCAQMD has proposed a
revision to its regulations to stabilize the RECLAIM market, it is unclear
whether these rules will mitigate Black Hills Ontario's potential exposure for
its projected allowance shortfall. Accordingly, no assurance can be given at
this time regarding whether RECLAIM NOx allowances will be available for
purchase to allow Black Hills Ontario to comply with RECLAIM requirements for
the year ended June 30, 2001, or, if allowances are available, as to the cost of
those allowances. Black Hills Ontario may also be subject to administrative or
civil penalties with respect to alleged violations of the SCAQMD's regulation
for the compliance year ended June 30, 1999, although no notice of such
penalties has been issued.
In July 1999, the United States Environmental Protection Agency (EPA) finalized
rules designed to protect and improve visibility impairment resulting from air
emissions. Among other things, the regulations required states to identify
sources of emissions (including certain coal-fired generating units built
between 1962 and 1977) by 2004 that would be subject to "Best Available Retrofit
Technology," known as BART. These sources would be required to implement BART
within five years after the EPA approved state plans adopted to combat
visibility impairment. The submission of these plans is due between 2004 and
2008. In January 2001, the EPA proposed guidance to assist states in determining
which sources should be subject to the BART requirement, but the proposed
guidance has not been published pending a review by the newly appointed
administrator of the EPA. If the proposed rules are adopted, management believes
that the only existing plant which may be required to comply with Clean Air Act
requirements is our Neil Simpson I plant and that any capital expenditures
associated with bringing the plant into compliance would not have a material
adverse effect on our financial condition or results of operations.
Title V of the Clean Air Act imposes federal requirements which dictate that all
of our fossil fuel-fired generation facilities must obtain operating permits.
All of our existing facilities subject to this requirement have submitted timely
Title V permit applications and received permits.
On November 3, 1999, the United States Department of Justice filed suit against
a number of electric utilities for alleged violations of the Clean Air Act's
"new source review" requirements related to modifications of air emissions
sources at electric generating stations located in the southern and midwestern
regions of the United States. Several states have joined these lawsuits. In
addition, the EPA has also issued administrative notices of violation alleging
similar violations at additional power plants owned by some of the same
utilities named as defendants in the Department of Justice lawsuit, and also
issued an administrative order to the Tennessee Valley Authority for similar
violations at some of its power plants. The EPA has also issued requests for
information pursuant to the Clean Air Act to numerous other electric utilities
seeking to determine whether those utilities also engaged in activities that may
have been in violation of the Clean Air Act's new source review requirements. To
date, we are aware of three large utilities that have either settled with the
United States or have reached agreements in principle to resolve these actions.
In each case, the settling party has agreed (or agreed in principle) to incur
over $1 billion in expenditures for the installation of additional pollution
control, the retirement or repowering of coal-fired generating units,
supplemental environmental projects and civil penalties. No such proceedings
have been initiated or requests for information issued with respect to any of
our facilities, but there can be no assurance that we will not be subject to
similar proceedings in the future.
In December 2000, the EPA announced its intention to regulate mercury emissions
from coal-fired and oil-fired electric power plants under Section 112 of the
Clean Air Act. The EPA is committed to proposing a rule to regulate such
emissions by no later than 2003. Because we do not know what the EPA may require
with respect to this issue, we are not able to evaluate the impact of potential
mercury regulations on the operation of our facilities. Since the adoption of
the United Nations Framework on Climate Change in 1992, there has been worldwide
attention with respect to greenhouse gas emissions. In December 1997, the
Clinton administration participated in the Kyoto, Japan negotiations, where the
basis of a climate change treaty was formulated. Under the treaty, known as the
Kyoto Protocol, the United States would be required, between 2008 and 2012 to
reduce its greenhouse gas emissions by 7 percent from 1990 levels. However,
because of opposition to the treaty in the United States Senate, the Kyoto
Protocol has not been submitted to the Senate for ratification. Although
legislative developments on the state level related to controlling greenhouse
gas emissions have occurred, we are not aware of any similar developments in the
states in which we operate. If the United States ratifies the Kyoto Protocol or
we otherwise become subject to limitations on emissions of carbon dioxide from
our plants, these requirements could have a significant impact on our
operations. In March 2001, the Bush administration announced that it would not
seek to impose any limitations on carbon dioxide emissions.
Clean Water Act. Our existing facilities are also subject to a variety of state
and federal regulations governing existing and potential water/wastewater
discharges. Generally, such regulations are promulgated under authority of the
Clean Water Act and govern overall water/wastewater discharges through National
Pollutant Discharge Elimination System, or NPDES, permits. Under current
provisions of the Clean Water Act, existing NPDES permits must be renewed every
five years, at which time permit limits are extensively reviewed and can be
modified to account for changes in regulations or program initiatives. In
addition, the permits have re-opener clauses which allow the permitting
authority (which may be the United States or an authorized state) to attempt to
modify a permit to conform to changes in applicable laws and regulations. Some
of our existing facilities have been operating under NPDES permits for many
years and have gone through one or more NPDES permit renewal cycles. Two of
these facilities are currently in the process of renewing their existing NPDES
permits.
Solid Waste Disposal. We dispose of all solid wastes collected as a result of
burning coal at our power plants in approved solid waste disposal sites. Each
disposal site has been permitted by the state of its location in compliance with
law. Ash and wastes from flue gas and sulfur removal from the Wyodak and Neil
Simpson II plants are deposited in mined areas. These disposal areas are located
below some shallow water aquifers in the mine. None of the solid wastes from the
burning of coal is classified as hazardous material, but the wastes do contain
minute traces of metals that would be perceived as polluting if such metals were
leached into underground water. Recent investigations have concluded that the
wastes are relatively insoluble and will not measurably affect the post-mining
ground water quality. While management does not believe that any substances from
our solid waste disposal activities will pollute underground water, they can
give no assurances that pollution will not occur over time. In this event, we
could experience material costs to mitigate any resulting damages. Agreements in
place require PacifiCorp to be responsible for any such costs that would be
related to the solid waste from its 80 percent interest in the Wyodak plant.
Additional unexpected material costs could also result in the future if the
federal or state government determines that solid waste from the burning of coal
contains some hazardous material that requires special treatment, including
solid waste of which we previously disposed. In that event, the government
regulator could consequently hold those entities that disposed of such waste
responsible for such treatment.
Mine Reclamation. Under federal and state laws and regulations, we are required
to submit to the regulation by, and receive approval from, the Wyoming
Department of Environmental Quality (DEQ) for a mining and reclamation plan
which provides for orderly mining, reclamation and restoration of all of our
Wyodak coal mine in conformity with state laws and regulations. We have an
approved mining permit and are otherwise in compliance with other land quality
permitting programs.
Based on extensive reclamation studies, we currently estimate the cost of
reclamation for our mine at approximately $26 million and have currently accrued
approximately $17.7 million on our balance sheet for these reclamation costs. No
assurance can be given that additional requirements in the future may be imposed
that would cause an unexpected material increase in reclamation costs. One
situation that could result in substantial unexpected increases in costs
relating to our reclamation permit concerns three depressions -- the "south"
depression, the "Peerless" depression and the "North Pit" depression - that have
or will result from our mining activities at the Wyodak mine. Because of the
thick coal seam and relatively shallow overburden, the current restoration plan
would leave these depressions, which have limited reclamation potential, with
interior drainage only. Although the DEQ has accepted the current plan to limit
reclamation of these depressions, it has reserved the right to review and
evaluate future reclamation plans or to reevaluate the existing reclamation
plan. If as a result of our mining activities, additional overburden becomes
available, the DEQ may require us to conduct additional reclamation of the
depressions, particularly if the DEQ finds that the current limited reclamation
is resulting in exceedances in the DEQ's water quality standards.
Ben French Oil Spill. In 1990 and 1991, we discovered extensive underground fuel
oil contamination at the Ben French plant site. With the help of expert
consultants, we worked closely with the South Dakota Department of Environment
and Natural Resources to assess and remediate the site. Our assessment and
remediation efforts continue today and we continue to monitor the site. All of
our underground oil-carrying facilities from which the contamination occurred
are now above ground. There have been no significant recoveries of free fuel oil
product since 1994. Soil borings and monitoring wells on the perimeters of our
Ben French plant property provide no indication of contamination beyond the
property's limits. Management believes that the underground spill has been
sufficiently remedied so as to prevent any oil from migrating off site. However,
due to underground gypsum deposits in this area, the fuel oil has the potential
of migrating to area waterways. In such event, cleanup costs could be greatly
increased. Management believes that sufficient remediation efforts to prevent
such a migration are currently in place, but due to the uncertainties of
underground geology, no assurance can be given.
Cleanup costs recognized to date total approximately $472,000, of which amount
$386,000 has been reimbursed by the South Dakota Petroleum Release Compensation
Fund. To date, no penalties, claims or actions have been taken or threatened
against us because of this oil spill.
PCBs. Under the federal Toxic Substances Control Act, the EPA has issued
regulations that control the use and disposal of polychlorinated biphenyls, or
PCBs. PCBs were widely used as insulating fluids in many electric utility
transformers and capacitors manufactured before the Toxic Substances Control Act
prohibited any further manufacture of PCB equipment. We remove and dispose of
PCB-contaminated equipment in compliance with law as it is discovered.
Release of PCB-contaminated fluids, especially any involving a fire or a release
into a waterway, could result in substantial cleanup costs. Several years ago,
we began a testing program of potential PCB-contaminated transformers, and in
1997 completed testing of all transformers and capacitors which are not located
in our electric substations. We have not completed the testing of sealed
potential transformers and bushings located in our electric substations as the
testing of this equipment requires their destruction. Release of
PCB-contaminated fluid, if present, from our equipment is unlikely and the
volume of fluid in such equipment is generally less than one gallon. Moreover,
any release of this fluid would be confined to our substation site.
Exploration and Production
Our oil and gas exploration and production operations are subject to various
types of regulation at the federal, state and local levels. They include:
o requiring permits for the drilling of wells;
o maintaining bonding requirements in order to drill or operate wells;
o submitting and implementing spill prevention plans;
o submitting notification relating to the presence, use and release of
certain contaminants incidental to oil and gas operations;
o regulating the location of wells, the method of drilling and casing wells,
the use, transportation, storage and disposal of fluids and materials used
in connection with drilling and production activities; and
o regulating surface usage and the restoration of properties upon which wells
have been drilled, the plugging and abandoning of wells and the
transporting of production.
Our operations are also subject to various conservation matters, including the
regulation of the size of drilling and spacing units or proration units, the
number of wells which may be drilled in a unit and the unitization or pooling of
oil and gas properties. In this regard, some states allow the forced pooling or
integration of tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases, which may make it more difficult to
develop oil and gas properties. In addition, state conservation laws establish
maximum rates of production from oil and gas wells, generally prohibit the
venting or flaring of gas and impose certain requirements regarding the ratable
purchase of production. The effect of these regulations is to limit the amounts
of oil and gas we can produce from our wells and to limit the number of wells or
the locations at which we can drill. In addition, various federal, state and
local laws and regulations concerning the discharge of contaminants into the
environment, the generation, storage, transportation and disposal of
contaminants and the protection of public health, natural resources, wildlife
and environment affect our exploration, development and production operations
and our related costs.
Other Properties
In addition to the other properties described herein, we own an eight-story
office building consisting of approximately 47,000 square feet of office space
in Rapid City, South Dakota. We occupy approximately 27,000 square feet in this
building and lease the remainder to others.
Employees
At December 31, 2000, we had 635 employees, approximately 332 of whom are
employed in our utility business, 170 of whom are employed in our independent
energy businesses and 133 of whom are employed in our communications business.
Approximately one-half of our utility employees are covered by collective
bargaining agreements with the International Brotherhood of Electrical Workers
which expire on April 1, 2003. We have experienced no significant labor
stoppages or labor disputes at our facilities.
ITEM 3. LEGAL PROCEEDINGS
PacifiCorp Litigation
In August 2000, we initiated an action in the United States District Court for
the District of Wyoming against PacifiCorp relating to a coal supply agreement
between PacifiCorp and us. We believe that PacifiCorp has failed to make
complete payment to us for coal sold under the coal supply agreement and that
PacifiCorp continues to underpay its monthly coal bill by approximately $100,000
per month. We believe that PacifiCorp's actions constitute a breach of the coal
supply agreement and have asked for relief in the amount of $5.0 million, plus
all underpayments since the commencement of our lawsuit.
PacifiCorp subsequently brought a counterclaim against us, alleging that we had
not properly adjusted upward and downward the components which make up the coal
price under the coal supply agreement, resulting in alleged overbilling to
PacifiCorp of $35.0 million to $40.0 million over an undefined period.
PacifiCorp further alleged that if past practices continue our adjustment
methodology will result in additional overcharges of approximately $150.0
million through the balance of the term of the coal supply agreement, which
expires in June 2013. In its counterclaim, PacifiCorp seeks to cancel and
terminate the contract and to recover monetary damages as proven at trial.
Management believes that we have properly billed PacifiCorp under the terms of
the coal supply agreement and that PacifiCorp's withholding of payment
constitutes a breach of contract on their part. Although it is impossible to
predict whether we will ultimately be successful with our claim or in defending
PacifiCorp's claim or, if not successful, what the impact might be, management
believes that the disposition of this matter will not have a material adverse
effect on our consolidated results of operations or financial condition. In
addition, management believes that the pending litigation has not affected and
will not affect our other agreements with PacifiCorp.
Other Litigation
There are no other material legal proceedings pending, other than ordinary
routine litigation incidental to our business, to which we are a party. There
are no material legal proceedings to which an officer or director is a party or
has a material interest adverse to us or our subsidiaries. There are no material
administrative or judicial proceedings arising under environmental quality or
civil rights statutes pending or known to be contemplated by governmental
agencies to which we are or would be a party other than the SCAQMD RECLAIM
requirements on the Ontario Facility "see ITEMS 1 AND 2. BUSINESS AND PROPERTIES
- - Regulation - Environmental Regulation - Clean Air Act."
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
We are a growth oriented, diversified energy holding company operating
principally in the United States. Our regulated and unregulated businesses have
expanded significantly in recent years. Our independent energy group produces
and markets power and fuel. We produce and sell electricity in a number of
markets, with a strong emphasis in the western United States. We also produce
coal, natural gas and crude oil primarily in the Rocky Mountain region and
market fuel products nationwide. We also own Black Hills Power, Inc., an
electric utility serving approximately 58,600 customers in South Dakota, Wyoming
and Montana. Our communications group offers state-of-the-art broadband
communications services to residential and business customers in Rapid City and
the northern Black Hills region of South Dakota.
Results of Operations
Consolidated Results
Consolidated net income for 2000 was $52.8 million, compared to $37.1 million in
1999 and $25.8 million in 1998 or $2.37 per average common share in 2000,
compared to $1.73 and $1.19 per average common share in 1999 and 1998,
respectively. This equates to a 19.0 percent, 17.1 percent and 12.5 percent
return on year-end common equity in 2000, 1999 and 1998, respectively.
We reported record earnings in 2000, primarily due to strong natural gas
marketing activity, increased fuel production, expanded power generation and
increased wholesale off-system electric utility sales. Strong results in our
independent energy business group in 2000 were partially offset by start-up
losses in our communications business. Unusual energy market conditions stemming
primarily from gas and electricity shortages in California contributed to our
strong financial performance in 2000. There was a $0.40 contribution to 2000
earnings per share due to prevailing prices of gas and electricity and unusually
wide gas trading margins that may not recur in the future.
Earnings in 1999 increased over 1998 due primarily to sales growth in our
electric utility and improved results in our independent energy business group,
partially offset by expected start-up losses in our communications business.
In 1998, we recorded an $8.8 million (after tax) charge to earnings related to a
write-down of certain oil and natural gas properties. Absent this charge, our
earnings per average common share for 1998 would have been $1.60, and our return
on year-end common equity would have been 16.1 percent. The write-down was
primarily due to historically low crude oil prices, lower natural gas prices and
a decline in value of certain unevaluated properties.
Consolidated revenues were $1,623.8 million, $791.9 million and $679.3 million
in 2000, 1999 and 1998, respectively, representing a 105 percent increase in
2000 and a 17 percent increase in 1999.
The growth in revenues in 2000 was a result of high energy commodity prices and
increased volumes of fuel marketed, primarily as a result of extreme price
volatility in the western markets, acquisitions and growth in the independent
energy business group and increases in off-system sales by our electric utility.
Prices of natural gas marketed increased from an average of $1.97-$2.15 per
million British thermal units in 1998 and 1999 to $4.19 per million British
thermal units in 2000. Daily volumes of natural gas marketed increased 35
percent from 635,500 million British thermal units per day in 1999 to 860,800
million British thermal units in 2000.
Revenue increases in 1999 resulted primarily from the acquisitions and growth in
the fuel marketing segment of our independent energy business group and
off-system sales by our electric utility.
Revenue and net income (loss) provided by each business group as a percentage of
our total revenue and net income were as follows:
2000 1999 1998
---- ---- ----
Revenue:
Independent energy 89% 83% 81%
Electric utility 11 17 19
Communications - - -
--- --- ---
100% 100% 100%
=== === ===
Net Income (Loss):
Independent energy 55% 31% 5%
Electric utility 70 74 96
Communications (25) (5) (1)
--- --- ---
100% 100% 100%
=== === ===
Net income from the independent energy group is expected to exceed net income
derived from our utility in 2001. We expect that earnings growth from the
independent energy group over the next few years will be driven primarily by our
continued expansion in the independent power production segment. We also believe
that continued strength in commodity prices and energy markets will provide the
opportunity for strong results in our fuel marketing and oil and gas production
operations.
Our electric utility has continued to produce modest growth in revenue and
earnings from the retail business over the past two years. We believe that this
trend is stable and that, absent unplanned system outages, it will continue for
the next several years due to the extension of our electric utility's rate
freeze until January 1, 2005. (See Rate Regulation.) The share of the utility's
future earnings generated from wholesale off-system sales will depend on many
factors, including native load growth, plant availability and commodity prices
in the western markets.
Although our communications business significantly increased residential and
business customers in 2000, we expect it will sustain approximately $10 million
in net losses in 2001, with annual losses decreasing thereafter and
profitability expected in the next three to four years.
The following business group and segment information includes intercompany
eliminations.
Independent Energy
2000 1999 1998
---- ---- ----
(in thousands)
Revenue:
Fuel marketing $1,353,795 $614,228 $506,043
Coal production 30,530 31,095 31,413
Oil and gas production 19,183 13,052 12,562
Independent power 39,331 - -
---------- -------- --------
Total revenue 1,442,839 658,375 550,018
Expenses 1,381,991 644,196 536,048*
---------- -------- --------
Operating income $ 60,848 $ 14,179 $ 13,970*
========== ======== ========
Net income $ 28,946 $ 11,882 $ 10,068*
========== ======== ========
EBITDA $ 65,184 $ 25,016 $ 22,530
========== ======== ========
- ---------------
* Excludes $13.5 million pre-tax, $8.8 million after tax, non-cash write-down
relating to oil and gas properties due to historically low crude oil prices,
lower natural gas prices and a decline in the value of unevaluated properties.
EBITDA represents earnings before interest, income taxes, depreciation and
amortization and any non-recurring or non-cash items. EBITDA is used by
management and some investors as an indicator of a company's historical ability
to service debt. Management believes that an increase in EBITDA is an indicator
of improved ability to service existing debt, to sustain potential future
increases in debt and to satisfy capital requirements. However, EBITDA is not
intended to represent cash flows for the period, nor has it been presented as an
alternative to either operating income, or as an indicator of operating
performance or cash flows from operating, investing and financing activities, as
determined by generally accepted accounting principles. EBITDA as presented may
not be comparable to other similarly titled measures of other companies.
The following is a summary of sales volumes of our coal, oil and natural gas
production:
2000 1999 1998
---- ---- ----
Tons of coal sold 3,050,000 3,180,000 3,280,000
Barrels of oil sold 334,000 318,000 344,000
Mcf of natural gas sold 3,274,000 2,791,000 2,056,000
Mcf equivalent sales 5,278,000 4,698,000 4,120,000
The following is a summary of average daily fuel marketing volumes:
2000 1999 1998
---- ---- ----
Natural gas - MMBtus 860,800 635,500 524,800
Crude oil - barrels 44,300 19,270 19,000
Coal - tons 4,400 4,500 4,400*
* Since the acquisition date
The independent energy business group's revenues increased 119 percent in 2000
and 20 percent in 1999. The revenue increase in 2000 was a direct result of gas
and electricity shortages in the West Coast markets and the closing of the
Indeck Capital acquisition. The revenue increase in 1999 was primarily the
result of consolidating our three fuel marketing companies' operations from the
time of their acquisitions. Additionally, revenues increased in both years as a
result of increased volumes and increased fuel and power prices. Daily volumes
of natural gas marketed increased 35 percent in 2000 and 21 percent in 1999. The
July 2000 acquisition of Indeck Capital contributed to our strong earnings
growth in 2000. In addition, in December 2000, we sold our ownership interest in
a power fund management company which resulted in a $3.7 million pre-tax gain.
The independent energy business group's total operating expenses, EBITDA and
operating income increased over 115 percent, 160 percent and 329 percent,
respectively, in 2000 compared to 1999. Net income of this group increased 144
percent in 2000. These increases resulted primarily from our gas marketing
operations, which experienced a dramatic increase in both trading volumes and
margins, a significant increase in fuel production volumes, record fuel and
power prices and expanded power generation. The independent energy business
group's 1999 net income improved over 1998 (excluding the non-cash charge in
1998) primarily due to record gas production, improved oil prices, lower
depletion expense and the sale of certain retail gas marketing operations in
1999, partially offset by a non-cash write-down of certain intangible assets
relating to our wholesale gas marketing office in Houston.
Coal Mining
Coal mining results were as follows:
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $30,530 $31,095 $31,413
Operating income 8,800 12,600 12,700
Net income 7,200 9,700 9,750
EBITDA 19,000 15,700 15,600
A planned five-week overhaul of the Wyodak plant resulted in lower coal sales
and earnings in 2000 compared to 1999 and 1998.
Oil and Gas
Oil and gas operating results were as follows:
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $19,183 $13,052 $ 12,562
Operating income 7,900 4,000 1,200*
Net income 5,000 2,500 800*
EBITDA 11,900 6,900 6,400
*Excludes the impact of a $13.5 million pre-tax, $8.8 million after tax,
non-cash write-down relating to oil and gas properties due to historically low
crude oil prices, lower natural gas prices and a decline in the value of
unevaluated properties.
Record net income in 2000 was primarily a result of record natural gas prices,
higher crude oil prices, and a significant increase in production volumes.
Operating results for 1998 decreased primarily as a result of historically low
crude oil prices, which not only reduced revenue but also increased depletion
expense (lower oil and gas prices reduce the economically recoverable reserve
amounts, causing an increase in depletion expense). We recognized approximately
$3.7 million, $2.6 million and $4.9 million of depletion expense (excluding the
write-down in 1998) related to gas and oil production in 2000, 1999 and 1998,
respectively.
The following is a summary of our oil and gas reserves at December 31:
2000 1999 1998
---- ---- ----
Barrels of oil (in millions) 4.41 4.11 2.37
Bcf of natural gas 18.4 19.5 16.0
Total in Bcf equivalents 44.88 44.11 30.16
These reserves are based on reports prepared by Ralph E. Davis Associates, Inc.,
an independent consulting and engineering firm. Reserves were determined using
constant product prices at the end of the respective years. Estimates of
economically recoverable reserves and future net revenues are based on a number
of variables, which may differ from actual results. The increase in oil reserves
at December 31, 2000 was due to improved product prices. The increase in
reserves at December 31, 1999 was due to strong drilling results, reserve
acquisitions and improved product prices. We intend to increase our net proved
reserves by selectively increasing our oil and gas exploration and development
activities and by acquiring producing properties.
Fuel Marketing
Our fuel marketing companies produced the following results:
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $1,353,795 $614,228 $506,043
Operating income (loss) 23,800 (2,200) -
Net income 14,000 (200) (300)
EBITDA 23,700 2,500 600
Record volumes marketed and strong margins contributed to the increase in net
income from fuel marketing in 2000 compared to 1999 and 1998. During 1999, the
fuel marketing companies sold certain of their retail gas marketing operations,
resulting in after-tax gains of approximately $1.8 million. In 1999, revenue and
the related cost of sales increased primarily due to a full year of coal
marketing operations (acquired in September 1998), increased product prices and
increased oil volumes marketed. Operating income in 1999 was reduced by a
non-cash write-down of certain intangible assets relating to the wholesale gas
marketing office in Houston in the amount of approximately $1.2 million (after
tax).
Our fuel marketing companies generate large amounts of revenue and corresponding
expense related to buying and selling energy commodities. Fuel marketing is
extremely competitive, and margins are typically very small. The unusual energy
market conditions stemming primarily from natural gas and electricity shortages
in California contributed to the strong financial performance in 2000 and may
not recur in the future. However, we believe that the continued growth of our
fuel and power production businesses will create opportunities for us to
continue to generate strong fuel marketing operating results in future years.
Independent Power Production
Our independent power segment produced the following results:
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $39,331 $ - $ -
Operating income (loss) 20,400 (160) (160)
Net income 3,200 (110) (120)
EBITDA 10,751 (160) (160)
Results from the independent power production segment were not significant
either in 1999 or 1998. In July 2000, we completed the acquisition of Indeck
Capital, representing a significant advancement of our position in the
independent power production segment. We now own 250 net megawatts in currently
operating plants. Of this 250 net megawatts, approximately 179 megawatts is
under contracts or tolling arrangements with at least one year remaining;
approximately 40 megawatts is owned through minority interests in independent
power investment funds which we do not manage, and the remainder is sold under
short-term market arrangements. An additional 470 megawatts of generating
capacity is currently under construction. We expect to sell substantially all of
this output under long-term contracts. We expect to increase revenues and
earnings in this segment beyond 2001 through future project development.
Electric Utility
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $173,308 $133,222 $129,236
Operating expenses 105,100 80,936 79,340
-------- -------- --------
Operating income $ 68,208 $ 52,286 $ 49,896
======== ======== ========
Net income $ 37,105 $ 27,286 $ 24,825
======== ======== ========
EBITDA $ 88,853 $ 68,299 $ 64,936
======== ======== ========
Electric revenue increased 30.1 percent in 2000 compared to 3.1 percent in 1999.
The increase in electric revenue in 2000 was primarily due to a 54 percent
increase in wholesale off-system sales at an average price that was 3.1 times
higher than the average price in 1999. The increase in off-system sales was
driven by high spot market prices for energy in 2000, which enabled us to
generate more energy from our combustion turbine facilities, including the Neil
Simpson combustion turbine which we placed into commercial operation in June
2000. Megawatthours generated from our oil-fired diesel and natural gas-fired
combustion turbines were 305,767 in 2000, 25,882 in 1999 and 33,082 in 1998.
Historically, market prices were not sufficient to support the economics of
generating from these facilities, except to meet peak demand and as standby use
for native load requirements.
Firm kilowatthour sales increased 2.8 percent in 2000 compared to a decrease of
0.1 percent in 1999. Residential and commercial sales increases of 6 percent and
3 percent, respectively, in 2000 were partially offset by a 2 percent decrease
in industrial sales, primarily due to load reductions at Homestake Gold Mine.
Degree days, a measure of weather trends, were 16 percent above 1999 and 1
percent above normal in 2000. Degree days in 1999 were 9 percent below 1998 and
13 percent below normal. The increase in electric revenue in 1999 was primarily
due to stable firm sales combined with a 20 percent increase in off-system
sales.
Revenue per kilowatthour sold was 6.4 cents in 2000 compared to 5.4 cents in
1999 and 1998. The number of customers in the service area increased to 58,601
from 57,709 in 1999 and from 56,856 in 1998. The revenue per kilowatthour sold
in 2000 reflects a 54 percent increase in wholesale non-firm sales to 684,378
megawatthours and robust wholesale power prices. The revenue per kilowatthour
sold in 1999 reflects the 20 percent increase in wholesale non-firm sales to
445,712 megawatthours. The revenue per kilowatthour sold in 1998 reflects the 33
percent increase in wholesale non-firm sales to 371,104 megawatthours.
Electric utility operating expenses increased by 30 percent in 2000 primarily
due to increased fuel, purchased power, and operating and maintenance expenses,
partially offset by lower depreciation. Fuel expense in 2000 included the cost
associated with the additional combustion turbine generation. Operating expenses
increased 2.0 percent in 1999, primarily due to increased purchase power
expense, operations and maintenance expenses and depreciation, partially offset
by lower fuel expense.
We forecast firm energy sales in our retail service territory to increase over
the next 10 years at an annual compound growth rate of approximately 1 percent,
with the system demand forecasted to increase at a rate of 2 percent. We
currently have a winter peak of 344 megawatts established in December 1998 and a
summer peak of 372 megawatts established in August 2000. These forecasts are
derived from studies conducted by us whereby we examined and analyzed our
service territory to estimate changes in the needs for electrical energy and
demand over a 20-year period. These forecasts are only estimates, and the actual
changes in electric sales may be substantially different. Weather deviations can
also affect energy sales significantly when compared to forecasts based on
normal weather.
Communications
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $ 7,689 $ 278 $ -
Operating expenses 20,175 4,852 1,087
-------- ------- -------
Operating loss $(12,486) $(4,574) $(1,087)
======== ======= =======
Net loss $(12,027) $(1,262) $ (280)
======== ======= =======
EBITDA $(13,144) $(2,626) $ (570)
======== ======= =======
In September 1998, we formed our communications business to provide
facilities-based communications services for Rapid City and the northern Black
Hills of South Dakota. We have invested more than $100 million in
state-of-the-art technology that offers local and long distance telephone
service, expanded cable television service, Internet access, and high-speed data
and video services. The build-out is approximately 75 percent complete and is
expected to be completed in 2001. Further capital expenditures of approximately
$31.3 million are expected over the next two years to complete the build-out of
the fiber optic network and to acquire customer premise equipment for sale to
customers.
We began serving communications customers in late 1999 and market our services
to schools, hospitals, cities, economic development groups, and business and
residential customers. Operating losses in 2000 were attributable to increased
interest, depreciation and operating expenses. Operating losses in 1999 were
primarily due to start-up organizational costs, increased depreciation expense
and increased interest expense associated with the capital deployment. As of
December 31, 2000, we had 8,368 residential customers and 646 business
customers. We expect to more than double the number of customers in 2001. Our
goal is to attain 50 percent residential penetration while serving 35 percent of
all broadband business customers within our service territory. If we are unable
to attract additional customers or technological advances make our network
obsolete, we could have a write-down of our assets which could be material.
Liquidity and Capital Resources
In 2000, we generated sufficient cash flow from operations to meet our operating
needs, to pay dividends on common stock and to pay long-term debt maturities. We
funded property additions primarily related to construction of additional
electric generation facilities for our independent energy business group through
a combination of operating cash flow, increased short-term debt and long-term
non-recourse project financing. Investing and financing activities increased
primarily as a result of the acquisition of Indeck Capital in July 2000 and
construction of several generating facilities. Cash flows from operations
increased $0.7 million, primarily due to increased net income and depreciation
partially offset by increased working capital. We expect increased operating
cash flows resulting from our investing activities to support the additional
indebtedness.
As part of our acquisition of Indeck Capital, we incurred $40.3 million of
additional debt through an increase in borrowings on our short-term credit
facilities, which were used to repay certain obligations of Indeck Capital. In
addition, we issued 1.537 million shares of common stock and 4,000 shares of
convertible preferred stock to the former Indeck Capital shareholders.
In 1999, we generated cash from operations sufficient to meet our operating
needs, to pay dividends on our common stock, to pay long-term debt maturities
and to provide financing for our investment in independent power assets.
Property additions were primarily financed through increased short-term debt and
notes payable. Cash flows from operations increased $19 million primarily due to
increased net income and decreased working capital. Cash flows from investing
activities increased substantially, primarily related to the deployment of our
fiber optic communications network and our investment in the construction of
generating facilities. Cash flows from financing activities increased primarily
due to increased short-term indebtedness to fund our investing activities.
In the past, we have relied upon internally generated funds and the issuance of
short- and long-term debt to finance our activities. We expect that an
appropriate mix of financing options will be used to finance future activities.
Dividends paid on our common stock totaled $1.08 per share in 2000. This
reflected increases approved by our board of directors from $1.04 per share in
1999 and $1.00 per share in 1998. All dividends were paid out of current
earnings. Our three-year annual dividend growth rate was 4.4 percent and our
payout ratio for 2000 was 45 percent. In January 2001, our board of directors
increased the quarterly dividend 3.7 percent to 28 cents per share. If this
dividend is maintained during 2001, it will be equivalent to $1.12 per share, an
annual increase of 4 cents per share. The determination of the amount of future
cash dividends, if any, to be declared and paid will depend upon, among other
things, our financial condition, funds from operations, the level of our capital
expenditures, restrictions under our credit facilities and our future business
prospects.
Capital Requirements
Our primary capital requirements for the three years ended December 31, 2000
were as follows:
2000 1999 1998
---- ---- ----
(in thousands)
Property and investment additions:
Independent energy $130,787 $73,656 $12,040
Electric utility 25,257 31,911 11,451
Communications and other 58,922 49,042 1,774
Common stock dividends 23,527 22,602 21,737
Fuel marketing assets - - 1,960
Maturities/redemptions of long-term debt 1,330 1,330 1,331
-------- -------- -------
$239,823 $178,541 $50,293
======== ======== =======
Our capital additions for 2000 were $215 million. The major capital items for
the year included the following: acquisition of the net assets of Indeck
Capital; completion of construction of the 80 megawatt gas-fired generation
units at the Arapahoe site in Denver, Colorado, which we placed in service in
May 2000; completion of construction of the 40 megawatt gas-fired Valmont
combustion turbine unit located in Boulder, Colorado, which we placed in service
in May 2000; acquisitions of various interests in partnerships in which we
previously held a minority interest; completion of construction of the 40
megawatt gas-fired Neil Simpson combustion turbine unit at our Wyodak site,
which we placed in service in June 2000; and the construction of our
communications fiber optic network.
Forecasted capital requirements for projected plant construction, other
independent energy investments, regulated utility capital improvements and
completion of the communications network are as follows:
2001 2002 2003
---- ---- ----
(in thousands)
Independent energy $ 287,200 $ 208,390 $ 195,540
Electric utility 18,340 18,160 16,450
Communications 25,390 5,920 3,290
--------- --------- ---------
$ 330,930 $ 232,470 $ 215,280
========= ========= =========
Our independent energy business group's forecasted capital requirements include
the following:
o Acquisition of a 240 megawatt Fountain Valley gas-fired turbine generation
facility currently under construction, located near Colorado Springs,
Colorado. Construction is expected to be completed in 2001, with an
expected cost of approximately $175 million.
o Completion of construction of a 40 megawatt gas-fired combustion turbine at
our Wyodak, Wyoming site (expected in mid-2001).
o Completion of construction of a 40 megawatt gas-turbine expansion at our
Valmont, Colorado site (expected in mid-2001).
o Completion of construction of a 50 megawatt combined-cycle expansion at our
Arapahoe, Colorado site (expected in mid-2002).
o Expansion of the Harbor Cogeneration plant in Wilmington, California with a
30 megawatt combined-cycle upgrade. This expansion is currently in
development, with anticipated completion in the second quarter of 2001. We
have a 31.8 percent financial interest in this project.
o Acquisition of operating and non-operating interests in 74 gas and oil
wells from Stewart Petroleum Corporation, which is expected to be completed
in April 2001.
o Construction of a 40 megawatt gas-fired turbine known as the Lange project
(expected in mid-2002).
o Expected development of an additional 400 megawatts of generating capacity
in years 2002-2003.
We expect to finance our independent energy business group's purchase and
construction of electric generating facilities, primarily with long-term,
non-recourse project level debt. We expect that any project-level debt will
contain significant restrictions on distributions of cash from the project to
us.
In addition to the above forecasted capital items we will lease the Wygen I
plant, a 90 megawatt coal-fired plant under construction at our Wyodak, Wyoming
site. Because of the leasing arrangement, the $130 million total construction
costs of the plant are not included in the above three-year capital expenditure
forecast. Wygen I will be similar in design to our Neil Simpson II facility,
which was completed in 1995 at the same site. The plant will run on low-sulfur
coal fed by conveyor from our adjacent Wyodak coal mine and will use the latest
available environmental control technology. We anticipate that the Wygen I plant
will be operational by March of 2003.
Forecasted capital expenditures for our electric utility operations include new
transmission and substation projects, re-build projects on existing transmission
lines, distribution projects in response to customer requests for electric
service, capital projects associated with our utility's existing generation
plants, and other miscellaneous items. We do not expect additional generation
capacity to be added to our utility over the forecast period.
Our communications group's capital requirements forecast primarily consists of
2001 costs related to the completion of our fiber optic network in Rapid City
and the northern Black Hills of South Dakota. We expect construction to be
substantially completed by November 2001, with forecasted capital expenditures
thereafter consisting of capital improvements to the then existing network
infrastructure.
Lines of Credit
We have lines of credit with various banks totaling $290 million at December 31,
2000 and $115 million at December 31, 1999, which are currently available to
support bank borrowings or to provide for letters of credit. There were $211
million of borrowings and $20.6 million of letters of credit issued under these
lines of credit at December 31, 2000, and $96.6 million of borrowings and no
letters of credit issued at December 31, 1999. We had no compensating balance
requirements associated with these lines of credit. The lines of credit are
subject to periodic review and renewal during the year by the banks.
In addition, Enserco Energy, Inc., our gas marketing unit, has a $90 million
uncommitted, discretionary line of credit to provide support for the purchase of
natural gas. We provide no guarantee to the lender under this facility. At
December 31, 2000 and 1999, there were outstanding letters of credit issued
under the facility of $69.8 million and $19.9 million, respectively, with no
borrowing balances on the facility.
Similarly, Black Hills Energy Resources, Inc., our oil marketing unit, has a $25
million uncommitted, discretionary credit facility. This line of credit provides
credit support for the purchases of crude oil by Black Hills Energy Resources.
We provide no guarantee to the lender under this facility. At December 31, 2000
and 1999, Black Hills Energy Resources had letters of credit outstanding of $8.5
million and $13.2 million, respectively, and no balance outstanding on its
overdraft line.
Coal Reclamation Reserves
Under our mining permit, we are required to reclaim all land where we have mined
coal reserves. The cost of reclaiming the land is accrued as the coal is mined.
While the reclamation process takes place on a continual basis, much of the
reclamation occurs over an extended period after we mine the area. Approximately
$0.7 million is charged to operations as reclamation expense annually. As of
December 31, 2000, accrued reclamation costs were approximately $17.7 million.
Long-term Debt/Credit Ratings
The long-term debt component of our capital structure at December 31, 2000 and
1999 was 52 percent and 43 percent, respectively. With expected growth within
the independent energy business group, we anticipate our long-term debt ratio
will increase to 55-60 percent in the next five years.
Our utility's first mortgage bonds are rated "A1" by Moody's Investors Service,
Inc. and "A+" by Standard & Poor's Ratings Services. These ratings reflect the
respective agencies' opinions of the credit quality of our utility and the
security underlying the first mortgage bonds.
Market Risk Disclosures
Price Risk Management
Our operations are exposed to market risk arising from changes in commodity
prices. These changes could cause fluctuations in our earnings and cash flows.
In the normal course of business, we actively manage our exposure to these
market risks by entering into various hedging transactions. Hedging transactions
involve the use of a variety of derivative financial instruments. Our risk
management policies place clear controls on these activities.
We have adopted risk management policies and procedures, approved by our board
of directors, and reviewed routinely by the audit committee of the board of
directors. Our risk management policies and procedures include, but are not
limited to, risk tolerance levels relating to authorized derivative financial
instruments, position limits, authorization of transactions and credit exposure.
Operating margins earned by wholesale gas and crude oil marketing are relatively
insensitive to commodity price fluctuations since most of the purchase and sales
contracts do not contain fixed-price provisions. Generally, prices contained in
these contracts are tied to a current spot or index price and, therefore, adjust
directionally with changes in
overall market conditions. We generally attempt to balance our fixed-price
physical and financial purchase and sales commitments. However, we may at times
have a bias in the market, within established guidelines, resulting from the
management of our portfolio. To the extent a net open position exists,
fluctuating commodity market prices can impact our financial position or results
of operations, either favorably or unfavorably. The net open positions are
actively managed, and the impact of changing prices on our financial condition
at a point in time is not necessarily indicative of the impact of price
movements throughout the year.
Effective January 1, 1999, we adopted the provisions of Emerging Issues Task
Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management
Activities" (EITF 98-10). The resulting effect of adoption of the provisions of
EITF 98-10 was to alter our comprehensive method of accounting for
energy-related contracts, as defined in that statement.
We account for all energy trading activities at fair value as of the balance
sheet date and recognize currently the net gains or losses resulting from the
revaluation of these contracts to fair value in our results of operations. As a
result, substantially all of the energy trading activities of our gas marketing,
crude oil marketing and coal marketing operations are accounted for under fair
value accounting methodology as prescribed in EITF 98-10.
Through our independent energy business group, we utilize financial instruments
for our fuel marketing services. These financial instruments include
fixed-for-float swap financial instruments, basis swap financial instruments,
and costless collars traded in the over-the-counter financial markets.
The derivatives are not held for speculative purposes but rather serve to hedge
our exposure related to commodity purchases or sales commitments. Under EITF
98-10, these transactions qualify as energy trading activities that must be
accounted for at fair value. As such, realized and unrealized gains and losses
are recorded as a component of income. Because we do not speculate with "open"
positions, substantially all of our trading activities are back-to-back
positions where a commitment to buy/(sell) a commodity is matched with a
committed sale/(buy) or financial instrument. The quantities and maximum terms
of derivative financial instruments held for trading purposes at December 31,
2000 and 1999 are as follows:
Max. Term
December 31, 2000 Volume Covered (Years)
- ----------------- -------------- -------
(MMBtus)
Natural gas basis swaps purchased 25,577,894 2
Natural gas basis swaps sold 26,059,621 2
Natural gas fixed-for-float swaps purchased 6,476,222 1
Natural gas fixed-for-float swaps sold 7,360,560 1
(Tons)
Coal tons sold 988,000 1
Coal tons purchased 896,000 1
Max. Term
December 31, 1999 Volume Covered (Years)
- ----------------- -------------- -------
(MMBtus)
Natural gas futures contracts purchased 860,000 1
Natural gas basis swaps purchased 17,741,500 4
Natural gas basis swaps sold 18,390,517 4
Natural gas fixed-for-float swaps purchased 9,490,486 1
Natural gas fixed-for-float swaps sold 10,994,521 1
Natural gas collar transactions; puts purchased, calls sold 408,500 1
Natural gas collar transactions; calls purchased, puts sold 318,500 1
As required under EITF 98-10, energy trading activities were marked to fair
value on December 31, 2000, and the gains and losses recognized in earnings. The
entries for the accompanying consolidated balance sheets and income statement
are as follows (in thousands):
Instrument Asset Liability Gain (loss)
- ---------- ----- --------- ----------
Natural gas basis swaps $13,391 $23,963 $(10,572)
Natural gas fixed-for-float swaps 24,617 27,110 (2,493)
Natural gas physical 23,391 9,427 13,964
Coal transactions 5,370 4,460 910
Crude oil transactions 1,523 1,000 523
------- ------- ---------
Totals $68,292 $65,960 $ 2,332
======= ======= =========
There were no significant differences between the fair values of derivative
assets and liabilities at December 31, 1999.
Non-trading Energy Activities
To reduce risk from fluctuations in the price of oil and natural gas, we enter
into swaps and costless collar transactions. We use these transactions to hedge
price risk from sales of our forecasted crude oil and natural gas production.
For such transactions, we utilize hedge accounting.
At December 31, 2000, we had fixed-for-float swaps for 17,000 barrels of oil per
month for the year 2001 to hedge our crude oil price risk with a fair value of
$34,000. We had fixed-for-float swaps for 10,000 barrels of oil per month for
the year 2002 to hedge our crude oil price risk with a fair value of $416,000.
We also had costless collars (purchased puts-sold calls) for 10,000 barrels of
oil per month for 2001 with a fair value of $323,000. We hedged our forecasted
2001 natural gas production with fixed-for-float swaps. We had fixed-for-float
swaps for 1,581,000 million British thermal units with a fair value of $(3.4)
million. These amounts are not reflected in our December 31, 2000 consolidated
balance sheet, but will be recorded as part of the adoption of Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," on January 1, 2001.
Financing Activities
To reduce risk from fluctuations in interest rates, we enter into interest rate
swap transactions. We use these transactions to hedge interest rate risk for
variable rate debt financing. For such transactions, we utilize hedge
accounting. At December 31, 2000, we had interest rate swaps with a notional
amount of $127.4 million, which have a maximum term of six years and a fair
value of $(7.5) million. These amounts are not reflected in our December 31,
2000 consolidated balance sheet, but will be recorded as part of the adoption of
SFAS No. 133 on January 1, 2001.
Credit Risk
In addition to the risk associated with price movements, credit risk is also
inherent in our risk management activities. Credit risk relates to the risk of
loss resulting from non-performance of contractual obligations by a
counterparty. While we have not experienced significant losses due to the credit
risk associated with these arrangements, we have off-balance sheet risk to the
extent that the counterparties to these transactions fail to perform as required
by the terms of their contracts.
Interest Rate Risk
Our exposure to market risk for changes in interest rates relates primarily to
our short-term investments and long-term debt obligations. As stated in our
policy, we are averse to principal loss and ensure the safety and preservation
of our investments by limiting default risk, market risk and reinvestment risk.
We mitigate default risk on short-term investments by investing in high credit
quality securities consisting primarily of tax-exempt federal, state and local
agency obligations, by periodically monitoring the credit rating of any
investment issuer or guarantor and by limiting the amount of exposure to any one
issuer. Our portfolio includes only securities with active secondary or resale
markets to ensure portfolio liquidity. All short-term investments mature, by
policy, in two years or less. The effect of a 100 basis point (1 percent)
increase in interest rates would not have a material effect to our results of
operations or financial condition, due to the short-term duration of the
investment portfolio.
At December 31, 2000, we had $162.2 million of outstanding floating rate debt of
which $34.8 million was not offset with interest rate swap transactions that
effectively convert the interest on that debt to a fixed rate.
The table below presents principal (or notional) amounts and related weighted
average interest rates by year of maturity for our short-term investments and
long-term debt obligations, including current maturities (in thousands).
2001 2002 2003 2004 2005 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
Cash equivalents
Fixed rate $ 24,913 $ - $ - $ - $ - $ - $ 24,913
Average interest rate 6.23% - - - - - 6.23%
Long-term debt
Fixed rate $ 3,070 $ 18,065 $ 3,122 $ 2,017 $ 2,026 $ 130,602 $ 158,902
Average interest rate 9.30% 6.98% 9.31% 9.50% 9.52% 8.30% 8.22%
Variable rate $ 10,890 $ 11,919 $ 12,968 $ 14,380 $ 15,560 $ 96,433 $ 162,150
Average interest rate 8.20% 8.20% 8.19% 8.19% 8.19% 8.10% 8.14%
Total long-term debt $ 13,960 $ 29,984 $ 16,090 $ 16,397 $ 17,586 $ 227,035 $ 321,052
Average interest rate 8.44% 7.46% 8.41% 8.35% 8.35% 8.22% 8.18%
Rate Regulation
Existing Rate Regulation
In June 1999, the South Dakota Public Utilities Commission approved a
settlement, which extended a rate freeze in effect since 1995 until January 1,
2005.
The South Dakota settlement provides that, absent an extraordinary event, we may
not file for any increase in our rates or invoke any fuel and purchased power
adjustment tariff which would take effect during the freeze period. The
specified extraordinary events are:
o new governmental impositions increasing annual costs for South Dakota
customers by more than $2.0 million;
o simultaneous forced outages of both our Wyodak plant and Neil Simpson II
plant projected to continue at least 60 days;
o forced outages occurring to either plant which continue for a period of
three months and is projected to last at least nine months;
o an increase in the Consumer Price Index at a monthly rate for six months
which would result in a 10 percent or higher annual inflation rate;
o the loss of a South Dakota customer or revenue from an existing South
Dakota customer that would result in a loss of revenue of $2.0 million or
more during any 12-month period;
o the cost of coal to our South Dakota customers increases and is projected
to increase by more than $2.0 million over the cost for the most recent
calendar year; and
o electric deregulation occurs as a result of either federal or state
mandate, which allows any of our customers to choose its provider of
electricity at any time during the freeze period.
During the freeze period, except as identified above, we are undertaking the
risks of:
o machinery failure;
o load loss caused by either an economic downturn or changes in regulation;
o increased costs under power purchase contracts over which we have no
control;
o government interferences; and
o acts of nature and other unexpected events that could cause material losses
of income or increases in costs of doing business.
However, the settlement anticipates that we will retain, during that period of
time, earnings realized from more efficient operations, sales from load growth,
and off-system sales of power and energy.
Over the last three years we have initiated an effort to enter into new
contracts with our largest industrial customers. The new contracts contain "meet
or release" provisions which grant us a five-year right to continue to serve a
customer at market rates in the event of deregulation. Additionally, through our
new General Service Large Optional Combined Account Billing Tariff, we have
allowed general service customers to aggregate their loads. This tariff also
provides us with a five-year right to continue to serve those customers in the
event of deregulation. Our "meet or release" contracts currently total more than
116 megawatts of large commercial and industrial load. These contracts provide
us the assurance of a firm local market for our power resources, in the event
deregulation occurs. These industrial and large commercial customers, together
with our wholesale power sale agreements with the City of Gillette, Wyoming and
Montana-Dakota Utilities Company, equal approximately 48 percent of our
utility's firm load.
Regulatory Accounting
We follow SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation," and our financial statements reflect the effects of the different
ratemaking principles followed by the various jurisdictions in which we operate.
As a result of our regulatory activity, a 50-year depreciable life for the Neil
Simpson II plant is used for financial reporting purposes. If we were not
following SFAS 71, a 35- to 40-year life would probably be more appropriate
which would increase depreciation expense by approximately $0.6 million per
year. If rate recovery of generation-related costs becomes unlikely or
uncertain, due to competition or regulatory action, these accounting standards
may no longer apply
to our generation operations. In the event we determine that we no longer meet
the criteria for following SFAS 71, the accounting impact to us would be an
extraordinary non-cash charge to operations of an amount that could be material.
Criteria that may give rise to the discontinuance of SFAS 71 include increasing
competition that could restrict our ability to establish prices to recover
specific costs and a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation. We
periodically review these criteria to ensure that the continuing application of
SFAS 71 is appropriate.
Business Outlook Statements
Business Strategy
Our strategy is to build long-term shareholder value by deploying our
development, operating and marketing expertise in the energy industry. We plan
to operate a mix of unregulated independent energy and regulated utility
businesses, with emphasis on independent power generation and fuel production
segments.
Our strategy includes the following key elements:
o grow our independent power segment by developing and acquiring power
projects primarily in the western United States;
o expand the generating capacity of our existing sites through a strategy
known as "brownfield development;"
o sell a large percentage of the production from our independent power
projects through long-term contracts in order to secure attractive
investment returns;
o increase our reserves of natural gas and expand our coal production;
o exploit our fuel cost advantages and our operating and marketing expertise
to remain a low-cost power producer;
o exploit our knowledge and market expertise while managing the risk inherent
in fuel marketing;
o build and maintain strong relationships with wholesale energy customers;
and
o capitalize on our utility's established market presence, relationships and
customer loyalty.
Future Communications Activities
Our communications operations are expected to have operating losses for the next
three to four years. The recovery of capital investment and future profitability
are dependent primarily on our ability to attract new customers, including
customers from incumbent providers such as Qwest Communications and Midcontinent
Communications, the incumbent telephone and cable television providers. Although
we do not anticipate being regulated in the local markets we are unable to
predict future markets, future government impositions and future economic
conditions that could affect the profitability of the communications and
technology operations.
Recent Developments and Acquisitions
In March 2001, we signed a definitive agreement to acquire a 240 megawatt
gas-fired turbine generation facility located near Colorado Springs, Colorado
from Enron Corporation. The transaction is expected to close around March 31,
2001.
The Fountain Valley facility features six LM-6000 simple-cycle, gas-fired
turbines, a technology identical to our existing facilities in Colorado and
Wyoming. All necessary permitting has been approved and the plant is expected to
phase in its generation capacity beginning in June 2001. We also announced that
we obtained an 11-year contract with Public Service of Colorado to utilize the
plant for peaking purposes. The contract is a tolling arrangement in which we
assume no fuel costs. The cost of the project is expected to be approximately
$175 million. We expect to finance the project primarily with non-recourse
project level debt, and negotiations are presently under way with certain
lenders.
Risks and Uncertainties
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 (Reform Act), we are hereby filing cautionary
statements identifying important factors that could cause our actual results to
differ materially from those projected in forward-looking statements (as such
term is defined in the Reform Act) made by or on behalf of the Company in our
Annual Report on Form 10-K, Annual Report, Quarterly Report on Form 10-Q, and
presentations, or in response to questions or otherwise. These statements
concern our plans, expectations and objectives for future operations. All
statements, other than statements of historical fact, that address activities,
events or developments that we expect, believe or anticipate will or may occur
in the future are forward-looking statements. The words "anticipate," "believe,"
"estimate," "expect," "intend," "plan," "predicts," "project," "will likely
result," "will continue," or similar expressions are not statements of
historical fact and may be forward-looking. These forward-looking statements
include, among others, such things as:
o expansion and growth of our business and operations
o future financial performance;
o future acquisition and development of power plants;
o future production of coal, oil and natural gas;
o reserve estimates; and
o business strategy.
Forward-looking statements are based on assumptions which we believe are
reasonable based on current expectations and projections about future events and
industry conditions and trends affecting our business. However, whether actual
results and developments will conform to our expectations and predictions is
subject to a number of risks and uncertainties which could cause actual results
to differ materially from those contained in the forward-looking statements,
including the following factors:
o prevailing governmental policies and regulatory actions, with respect to
allowed rates of return, industry and rate structure, acquisition and
disposal of assets and facilities, operation and construction of plant
facilities, recovery of purchased power and other capital investments, and
present or prospective wholesale and resale competition;
o changes in and compliance with environmental and safety laws and policies;
o weather conditions;
o population growth and demographic patterns;
o competition for retail and wholesale customers;
o pricing and transportation of commodities;
o market demand, including structural market changes;
o changes in tax rates or policies or in rates of inflation;
o changes in project costs;
o unanticipated changes in operating expenses or capital expenditures;
o capital market conditions;
o credit-worthiness of counterparties;
o technological advances;
o competition for new energy development opportunities; and
o legal and administrative proceedings that influence our business and
profitability.
Any forward-looking statement speaks only as to the date on which that statement
is made, and we undertake no obligation to update any forward-looking statement
to reflect events or circumstances after the date on which that statement is
made or to reflect the occurrence of an anticipated event. New factors emerge
from time to time, and it is not possible for management to predict all such
factors, nor can it assess the impact of any such factor on the business or the
extent to which factor, or combination of factors, may cause results to differ
materially from those contained in any forward-looking statement.
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
and Chief Executive Officer
Dated: April 3, 2001