# UNITED STATESSECURITIES AND EXCHANGE COMMISSION Washington, DC 20549Form
10-K

X  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For
the fiscal year ended December 31, 2002

   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For
the transition period from ___________________ to __________________

Commission
File Number 1-7978

# BLACK HILLS POWER, INC.

Incorporated in South Dakota        
                   
                       
                      
                      
  IRS Identification Number 46-0111677

625 Ninth StreetRapid City, South Dakota 57701

Registrants telephone
number, including area code (605) 721-1700

Securities registered
pursuant to Section 12(b) of the Act:           None

Securities registered
pursuant to Section 12(g) of the Act:            None

Indicate by check mark whether the
Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period
that the Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

YES X  NO____

Indicate 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.

This
paragraph is not applicable to the Registrant.          
            
            
           X

Indicate by check mark whether the
registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

YES ______NOX

State the aggregate market value of
the voting stock held by non-affiliates of the Registrant.

| | All
outstanding shares are held by the Registrants parent company, Black Hills
Corporation. Accordingly, the aggregate market value of the voting common stock of the
Registrant held by non-affiliates is $0.
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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 March 28, 2003

Common stock, $1.00 par value        
                   
                       
                      
                          23,416,396 shares

Reduced Disclosure

| | 1. |  | The Registrant meets the conditions
set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing
this Form 10-K with the reduced disclosure format.
| | -- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

---

# TABLE OF CONTENTS

|             |  | Page
|------------ |  | ----
|ITEMS 1 &  2 |  |     
|             |  |     
|             |  |     
|             |  |     
|             |  |     
|ITEM 3       |  |     
|ITEM 5       |  |     
|ITEM 7       |  |     
|ITEM 7A      |  |     
|             |  |     
|             |  |     
|             |  |     
|             |  |     
|             |  |     
|ITEM 8       |  |     
|ITEM 9       |  |     
|ITEM 14      |  |     
|ITEM 15      |  |     
|             |  |     
|             |  |     
|             |  |     

---

# PART I

# ITEMS 1 AND 2.   BUSINESS
AND PROPERTIES

# General

We are an electric utility serving
customers in South Dakota, Wyoming and Montana. We are incorporated in South Dakota and
began providing electric utility service in 1941. In 2000, we became a wholly owned
subsidiary of Black Hills Corporation through a plan of exchange between us
and Black Hills Corporation. Our power generation group produces and sells electricity in
a number of markets, with a strong emphasis on the western United States.

Unless the context otherwise
requires, references in this Form 10-K to Black Hills Power, we,
us and our refer to Black Hills Power, Inc. and all of its
subsidiaries collectively.

# Electric Utility

We engage in the generation,
transmission and distribution of electricity. We have a solid foundation of revenues,
earnings and cash flow that support our capital expenditures, dividends, and overall
performance and growth.

Our distribution and transmission
businesses serve approximately 60,000 electric customers, with an electric transmission
system of 447 miles of high voltage lines and 514 miles of lower voltage lines. In
addition, we jointly own 43 miles of high voltage lines with Basin Electric Cooperative.
Our 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 retail electric revenues are generated in South Dakota.

The following are characteristics of
our distribution and transmission businesses:

- We have a diverse customer and revenue base. Our revenue mix for the year ended
December 31, 2002 was comprised of 30 percent commercial, 24 percent residential, 17
percent contract wholesale, 15 percent wholesale off-system, 13 percent industrial and 1
percent municipal sales and other revenue. Approximately 70 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.
- In 1999, the South Dakota Public Utilities Commission extended our previous retail rate
freeze until January 1, 2005. The rate freeze preserves our low-cost rate structure for
our retail customers at levels below the national average 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.
- 15 percent of our electric revenues for the year ended December 31, 2002 consisted of
off-system and short-term contract wholesale sales. Although the demand for power in the
western markets has eased from the record levels seen in the first half of 2001, we expect
increases in the volume of our off-system sales in the future due to demand growth in the
Rocky Mountain region and the availability of 40 megawatts of gas-fired generating
capacity which we added in 2002.

---

- Our
system is capable of connecting to either the eastern or western transmission systems,
which provides us with access between the Western Electricity Coordinating Council, or
WECC region and the Mid-Continent Area Power Pool, or MAPP region.
This allows us the opportunity to improve system reliability by adding voltage support and
take advantage of power price differentials between the two electric grids. We are able to
interconnect up to 80 megawatts of our generation into the MAPP. Alternatively, we can
serve up to 80 megawatts of our load from the MAPP region. The available transmission
capacity of the MAPP transmission system determines how much of this 80 megawatts can be
served from the eastern interconnection. We are proceeding with the construction of an
AC-DC-AC transmission tie which is expected to be completed in late third quarter, or
early fourth quarter of 2003. The transmission tie will provide us with additional load
support for our utility customers and increase our ability to buy or sell electric power.
- We have firm transmission access to deliver up to 55 megawatts of power on
PacifiCorps system to wholesale customers in the western region during 2003,
scheduled to decline to 50 megawatts in 2004.

We sell approximately 46 percent of
our utilitys current load under long-term contracts. Our key contracts include a
contract with Montana-Dakota Utilities Company, expiring in 2007, 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 area and are treated as firm native load. In May 2001, we began selling
30 megawatts of firm capacity and energy to Public Service Company of Colorado for a
period through 2004. For the 10-year period beginning in 2003, we will provide 20
megawatts of unit contingent energy and capacity to the Municipal Energy Agency of
Nebraska.

Our utility electric load is served
by coal-, oil- and natural gas-fired generating units providing 435 megawatts of
generating capacity all of which is located in South Dakota and Wyoming, and from the
following purchased power and capacity contracts with PacifiCorp:

- a power sales agreement expiring in 2023, involving the purchase by us of 55 megawatts of
baseload power in 2003, which is scheduled to decline to 50 megawatts in 2004 and
thereafter; and
- 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.

Since 1995, our utility has been a
net producer of energy. Our utility reached its peak system load of 392 megawatts in
August 2001. 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.

# Independent Power

Our independent power unit acquires,
develops and expands unregulated power plants. We hold varying interests in operating
gas-fired and hydroelectric independent power plants in California, Colorado,
Massachusetts, Nevada and New York. We have a total net ownership interest of 886
megawatts, (including the 224 MW expansion at the Las Vegas cogeneration power plant,
which went into service January 3, 2003) as well as minority interests in several
power-related funds with a net ownership interest of 24 megawatts.

---

# Risk Factors

The following specific risk factors
and other risk factors that we discuss in our periodic reports from time to time should be
considered for a better understanding of our Company. These factors and other matters
discussed herein are important factors that could cause our actual results or outcomes to
differ materially from those discussed in the forward looking statements included
elsewhere in this document.

Our agreements with counterparties
that have recently experienced downgrades in their credit ratings expose us to the risk of
counterparty default, which could adversely affect our cash flow and profitability.

We are exposed to credit risks in our
operations. Credit risk includes the risk that counterparties that owe us money or energy
will breach their obligations. In recent months, a substantial number of energy companies
have experienced downgrades in their credit ratings, some of which serve as our
counterparties from time to time. In particular, the credit ratings of the senior
unsecured debt of Public Service Company of Colorado, Nevada Power Company and Allegheny
Energy Supply Company (AESC), counterparties under power purchase agreements with our
subsidiaries, have recently been downgraded by one or more rating agencies. The credit
ratings of Nevada Power Company and AESC were downgraded to non-investment grade status.
In addition, we have project level financing arrangements in place that provide for the
potential acceleration of payment obligations in the event of nonperformance by a
counterparty under related power purchase agreements. If these or other counterparties
fail to perform their obligations under their respective power purchase agreements, our
financial condition and results of operations may be adversely affected. We may not be
able to enter into replacement power purchase agreements on terms as favorable as our
existing agreements, or at all, in which case we would sell the plants power on a
merchant basis.

We have substantial indebtedness,
much of which is short-term. We will require significant amounts of debt or equity capital
in order to refinance or repay maturing indebtedness as it becomes due and to grow our
business. Our future access to these funds is not certain, and our inability to access
funds in the future could adversely affect our liquidity and our ability to implement our
business strategy.

As of December 31, 2002, we had total
consolidated indebtedness of approximately $1.1 billion, of which approximately $0.1
billion is due before December 31, 2004 and approximately $0.5 billion is due to
affiliates and classified as current liabilities. Our substantial indebtedness may:

- limit our ability to borrow funds or increase the cost to borrow additional funds;
- hinder our ability to pay dividends;
- require us to dedicate a substantial portion of our cash flow from operations to pay our
debt, which would reduce funds available for us to finance our current operations and for
our future business opportunities;
- have a negative impact on our credit ratings;
- increase our vulnerability to adverse economic and industry conditions;
- place us at a competitive disadvantage compared to competitors having less debt; or
- require us to sell assets in order to repay debt.

---

Our credit ratings have recently
been lowered and could be further lowered in the future. If this were to occur, our access
to capital and our cost of capital and other costs would be negatively affected.

Our issuer credit rating was recently
downgraded to Baa2 by Moodys Investor Services, Inc., or Moodys. Any further
reduction in our ratings by Moodys or Standard & Poors Rating Service,
particularly a reduction to a level below investment-grade, could adversely affect our
ability to refinance or repay our existing debt and to complete new financings.

In addition, a further downgrade in
our credit rating would increase our costs of borrowing under some of our existing debt
obligations.

A downgrade could also result in our
business counterparties requiring us to provide additional amounts of collateral under new
transactions.

Geopolitical tensions, including
the armed conflict in Iraq, may impair our ability to raise capital and limit our growth.

An extended conflict with Iraq or an
increase in tensions with the government of North Korea could temporarily disrupt capital
markets and make it more costly or temporarily impossible for us to raise capital, thus
hampering the implementation of our growth strategy. In the past, geopolitical events,
including the uncertainty associated with the Gulf War in 1991 and the terrorist attacks
of September 11, 2001, have been associated with general economic slowdowns. A prolonged
conflict or stalemate arising from current geopolitical tensions or other factors could
retard economic growth and reduce demand for the power and fuel products that we produce
or market, which could adversely affect our earnings.

Our rate freeze agreement with the
South Dakota Public Utilities Commission, which prevents us, absent extraordinary
circumstances, from passing on to our South Dakota retail customers cost increases we may
incur during the rate freeze period, could decrease our operating margins.

Our rate freeze agreement with the
South Dakota Public Utilities Commission is effective until January 1, 2005. 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, except in extraordinary
circumstances. Because we are generally unable to increase our rates, our utilitys
historically stable returns could be threatened by plant outages, machinery failure,
increases in purchased power costs over which we have no control, acts of nature, acts of
terrorism or other unexpected events that could cause our operating costs to increase and
our operating margins to decline. Moreover, in the event of unexpected plant outages or
machinery failures, we may be required to purchase replacement power in wholesale power
markets at prices which exceed the rates we are permitted to charge our retail customers.

Because prices for our products
and services and other operating costs for our business are volatile, our revenues and
expenses may fluctuate.

A substantial portion of our growth
in net income in recent years is attributable to increasing wholesale electricity sales
into a robust market. The prices of energy products in the wholesale power markets have
declined significantly since the first half of 2001. Power prices are influenced by many
factors outside our control, including:

- fuel prices;
- transmission constraints;
- supply and demand;

---

- weather;
- economic conditions; and
- the rules, regulations and actions of the system operators in those markets.

Moreover, unlike most other
commodities, electricity cannot be stored and therefore must be produced concurrently with
its use. As a result, wholesale power markets are subject to significant price
fluctuations over relatively short periods of time and can be unpredictable.

Construction, expansion,
refurbishment and operation of power generating and transmission facilities involve
significant risks which could lead to lost revenues or increased expenses.

The construction, expansion,
refurbishment and operation of power generating and transmission and resource recovery
facilities involve many risks, including:

- the inability to obtain required governmental permits and approvals;
- the unavailability of equipment;
- supply interruptions;
- work stoppages;
- labor disputes;
- social unrest;
- weather interferences;
- unforeseen engineering, environmental and geological problems; and
- unanticipated cost overruns.

The ongoing operation of our
facilities involves all of the risks described above, in addition to risks relating to the
breakdown or failure of equipment or processes and performance below expected levels of
output or efficiency. New plants may employ recently developed and technologically complex
equipment, especially in the case of newer environmental emission control technology. Any
of these risks could cause us to operate below expected capacity levels, which in turn
could result in lost revenues, increased expenses, higher maintenance costs and penalties.
While we maintain insurance, obtain warranties from vendors and obligate contractors to
meet certain performance levels, the proceeds of such insurance and our rights under
warranties or performance guarantees may not be adequate to cover lost revenues, increased
expenses or liquidated damage payments.

---

Our business is subject to
substantial governmental regulation and permitting requirements as well as on-site
environmental liabilities we assumed when we acquired some of our facilities. We may be
adversely affected by any future inability to comply with existing or future regulations
or requirements or the potentially high cost of complying with such requirements.

Our business is subject to extensive
energy, environmental and other laws and regulations of federal, state and local
authorities. We generally are required to obtain and comply with a wide variety of
licenses, permits and other approvals in order to operate our facilities. In the course of
complying with these requirements, we may incur significant additional costs. If we fail
to comply with these requirements, we could be subject to civil or criminal liability and
the imposition of liens or fines. In addition, existing regulations may be revised or
reinterpreted, new laws and regulations may be adopted or become applicable to us or our
facilities, and future changes in laws and regulation may have a detrimental effect on our
business.

In acquiring some of our facilities,
we assumed on-site liabilities associated with the environmental condition of those
facilities, regardless of when such liabilities arose and whether known or unknown, and in
some cases agreed to indemnify the former owners of those facilities for on-site
environmental liabilities. We strive at all times to be in compliance with all applicable
environmental laws and regulations. However, steps to bring our facilities into
compliance, if necessary, could be expensive, and thus could adversely affect our results
of operation and financial condition. Furthermore, with the continuing trends toward
stricter standards, greater regulation, more extensive permitting requirements and an
increase in the assets we operate, we expect our environmental expenditures to be
substantial in the future.

One of our subsidiaries may incur
material liabilities due to a prior owners potential violation of regulations for
qualifying facilities under The Public Utility Regulatory Policies Act of 1978
(PURPA).

In August 2001, we purchased a
partnership interest in the 53 megawatt Las Vegas Cogeneration Facility from an affiliate
of Enron. The partnership is called Las Vegas Cogeneration, L.P. The prior owner certified
to us and to relevant governmental authorities that the facility complied with all
regulations necessary to obtain and maintain qualifying facility status under
PURPA. Qualifying facilities are allowed to sell their output to electric utilities at
avoided cost rates, which are usually higher than prevailing market-based
rates. The prior owner contracted with Nevada Power Company to sell 45 megawatts of the
facilitys output during the periods of peak electricity consumption at avoided cost
rates. In connection with acquiring the facility, we assumed this contract.

Recently the Federal Energy
Regulatory Commission (FERC) issued an order announcing an investigation to determine
whether Enrons ownership of the Las Vegas Cogeneration Facility violated the
qualifying facility regulations under PURPA. In addition, the Securities Exchange
Commission (SEC) recently issued an initial decision concluding that Enron is an electric
utility and is thus not exempt from regulations under the Public Utility Holding Company
Act of 1935 (PUHCA), that, among other things, prohibit electric utilities from owning
more than 50 percent of a qualifying facility. Enron is appealing this decision.

The FERC investigation does not
relate to the 224 megawatt gas-fired facility owned and operated by Las Vegas Cogeneration
II, LLC, and located on the same site in North Las Vegas, Nevada. This facility is not
now, and never was certified as a qualifying facility under PURPA.

If FERC determines that Enron
violated the qualifying facility rules with respect to the Las Vegas Cogeneration
Facility, we, as a partner in the entity that now owns that facility, could be liable for
any refunds, fines or other penalties FERC imposes. We could also be subject to additional
liabilities resulting from third party claims. We have the right to seek indemnification
from the prior owner. While the prior owner does not appear among the Enron subsidiaries
and affiliates currently in bankruptcy, the Enron bankruptcy could impair our ability to
enforce a claim for indemnification. Because FERC has only recently begun its
investigation, we cannot predict the outcome of FERCs investigation.

---

We face potential claims related
to forest fires in South Dakota in 2001 and 2002.

In September 2001 a fire occurred in
the southwestern Black Hills. It is alleged that the fire occurred when a high voltage
electrical span maintained by us broke and electrical arcing from the severed line ignited
dry grass. The fire burned approximately 10,000 acres of land owned by the Black Hills
National Forest, the Oglala Sioux Tribe and other private landowners. The State of South
Dakota initiated litigation against us in the Seventh Judicial Circuit Court, Fall River
County, South Dakota, on or about January 31, 2003. The complaint seeks recovery of
damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim
for treble damages is asserted with respect to the claim for injury to timber. It is
expected that substantially similar claims will be asserted against us by the United
States Forest Service. Our investigation into the cause and origin of the fire is still
pending. The total amount of damages claimed by the State of South Dakota is not specified
in the complaint. We have denied all claims and will vigorously defend this matter.

In June 2002, the Grizzly Gulch
forest fire damaged approximately 11,000 acres of private and governmental land located
near Deadwood and Lead, South Dakota. The fire destroyed approximately 20 structures and
caused the evacuation of the cities of Lead and Deadwood for approximately 48 hours.

The cause of the Grizzly Gulch fire
was investigated by the State of South Dakota. Alleged contact between power lines owned
by our electric utility subsidiary and undergrowth was implicated as the cause. We have
initiated our own investigation into the cause of the fire, including the hiring of expert
fire investigators and that investigation is continuing.

We have been notified of potential
private civil claims for property damage and business loss. In addition, the State of
South Dakota initiated a civil action in the Seventh Judicial Circuit Court, Pennington
County, South Dakota, seeking recovery of damages for fire suppression, reclamation and
remediation costs, and treble damages for injury to trees. The United States government
initiated a civil action in U.S. District Court, District of South Dakota, asserting
similar claims. Neither the State of South Dakota nor the United States specified the
amount of their alleged damages. If it is determined that power line contact was the cause
of the fire and that we were negligent in the maintenance of those power lines, we could
be liable for resultant damages.

Although we cannot predict the
outcome of our investigations or the viability of potential claims based on information
currently available, management believes that any such claims, if determined adversely to
us, will not have a material adverse effect on our financial condition or results of
operations.

Ongoing changes in the United
States utility industry, such as state and federal regulatory changes, a potential
increase in the number of our competitors or the imposition of price limitations to
address market volatility, could adversely affect our profitability.

The United States electric utility
industry is currently experiencing increasing competitive pressures as a result of:

- consumer demands;
- technological advances;
- deregulation;
- greater availability of natural gas-fired power generation; and
- other factors.

---

FERC has implemented and continues to
propose regulatory changes to increase access to the nationwide transmission grid by
utility and non-utility purchasers and sellers of electricity. In addition, a number of
states have implemented or are considering or currently implementing methods to introduce
and promote retail competition. Industry deregulation in some states has led to the
disaggregation of some vertically integrated utilities into separate generation,
transmission and distribution businesses, and deregulation initiatives in a number of
states may encourage further disaggregation. As a result, significant additional
competitors could become active in the generation, transmission and distribution segments
of our industry.

In addition, the independent system
operators who oversee most of the wholesale power markets have in the past imposed, and
may in the future continue to impose, price limitations and other mechanisms to address
some of the volatility in these markets. These types of price limitations and other
mechanisms may adversely affect the profitability of those generating facilities that sell
energy into the wholesale power markets. Given the extreme volatility and lack of
meaningful long-term price history in some of these markets and the imposition of price
limitations by independent system operators, we may not be able to operate profitably in
all wholesale power markets.

# ITEM 3.     LEGAL PROCEEDINGS

Hell Canyon Fire

In September 2001 a fire occurred in
the southwestern Black Hills. It is alleged that the fire occurred when a high voltage
electrical span broke and electrical arcing from the severed line ignited dry grass. The
fire burned approximately 10,000 acres of land owned by the Black Hills National Forest,
the Oglala Sioux Tribe and other private landowners. The State of South Dakota initiated
litigation against us in the Seventh Judicial Circuit Court, Fall River County, South
Dakota, on or about January 31, 2003. The complaint seeks recovery of
damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim
for treble damages is asserted with respect to the claim for injury to timber. It is
expected that substantially similar claims will be asserted against us by the United
States Forest Service. Our investigation into the cause and origin of the fire is still
pending. The total amount of damages claimed by the State of South Dakota is not
specified in the complaint. We have denied all claims and will vigorously defend this
matter, the timing or outcome of which is uncertain.

Although we cannot predict the
outcome of our investigation or the viability of potential claims based on information
currently available, management believes that any such claims, if determined adversely to
us, will not have a material adverse effect on our financial condition or results of
operations.

Grizzly Gulch Fire

On June 29, 2002, a forest fire began
near Deadwood, South Dakota. Before being contained more than eight days later, the fire
consumed approximately 11,000 acres of public and private land, mostly consisting of
rugged forested areas. The fire destroyed approximately 20 structures. There were no
reported personal injuries. In addition, the fire burned to the edge of the City of
Deadwood, forcing the evacuation of the City of Deadwood and the adjacent City of Lead,
South Dakota. These communities are active in the tourist and gaming industries.
Individuals were ordered to leave their homes and businesses were closed for a short
period of time. On July 16, 2002, the State of South Dakota announced the results of its
investigation of the cause and origin of the fire. The State asserted that the fire was
caused by tree encroachment into and contact with a transmission line owned and maintained
by the Company.

On September 6, 2002, the State of
South Dakota commenced litigation against us, in the Seventh Judicial Circuit Court,
Pennington County, South Dakota. The complaint seeks recovery of damages for alleged
injury to timber, fire suppression and rehabilitation costs. A claim for treble damages is
asserted with respect to the claim for injury to timber. The total amount of alleged
damages is not specified.

---

On March 3, 2003, the United States
of America filed a similar suit against us, in the United States District Court, District
of South Dakota, Western Division. The federal government complaint likewise seeks
recovery of damages for alleged injury to timber, fire suppression and rehabilitation
costs. A similar claim for treble damages is asserted with respect to the claim for injury
to timber. The total amount of alleged federal damages is not specified.

We are completing our own
investigation of the fire cause and origin and have requested access to the materials that
form the basis for the assertions of state and federal fire investigators. Our
investigation is not complete, but based on information currently available, we expect to
deny all claims and vigorously defend any and all claims brought by governmental or
private parties.

Although we cannot predict the
outcome of our investigation or the viability of potential claims based on information
currently available, management believes that any such claims, if determined adversely to
us, will not have a material adverse effect on our financial condition or results of
operations.

FERC Investigation

In August 2001, we purchased a
partnership interest in the 53 megawatt Las Vegas I power plant from an affiliate of
Enron. The partnership is called Las Vegas Cogeneration, L.P. The prior owner certified to
us and to relevant governmental authorities that the facility complied with all
regulations necessary to obtain and maintain qualifying facility status under
PURPA. Qualifying facilities are allowed to sell their output to electric utilities at
avoided cost rates, which are usually higher than prevailing market-based
rates. The prior owner contracted with Nevada Power Company to sell 45 megawatts of the
facilitys output during the periods of peak electricity consumption at avoided cost
rates. In connection with acquiring the facility, we assumed this contract.

Recently FERC issued an order
announcing an investigation to determine whether Enrons ownership of the Las Vegas I
plant violated the qualifying facility regulations under PURPA. In addition, the SEC
recently issued an initial decision concluding that Enron is an electric utility and is
thus not exempt from regulations under PUHCA, that, among other things, prohibit electric
utilities from owning more than 50 percent of a qualifying facility. Enron is appealing
this decision.

The FERC investigation does not
relate to the 224 megawatt gas-fired Las Vegas II power plant owned and operated by Las
Vegas Cogeneration II, LLC and located on the same site in North Las Vegas, Nevada. This
plant is not now, and never was certified as a qualifying facility under PURPA.

If FERC determines that Enron
violated the qualifying facility rules with respect to the Las Vegas I plant, we, as a
partner in the entity that now owns that plant, could be liable for any refunds, fines or
other penalties FERC imposes. We could also be subject to additional liabilities resulting
from third party claims. We have the right to seek indemnification from the prior owner.
While the prior owner does not appear among the Enron subsidiaries and affiliates
currently in bankruptcy, the Enron bankruptcy could impair our ability to enforce a claim
for indemnification. Because FERC has only recently begun its investigation, we cannot
predict the outcome of FERCs investigation. However, based upon information
currently available, we do not believe that any refunds, fines or penalties resulting from
the investigation will adversely affect our financial condition or results of operations.

---

Other Proceedings

In addition to the above proceedings,
we are involved in numerous legal proceedings, claims and litigation in the ordinary
course of business. In the opinion of management, the amount of liability, if any, with
respect to these actions would not materially affect our consolidated financial position
or results of operations.

There are currently no pending
material legal proceedings to which an officer or director is a party or has a material
interest, that is adverse to us or our subsidiaries. There are also 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.

# PART II

# ITEM 5.     MARKET FOR
REGISTRANTS COMMON EQUITY AND RELATED     
              STOCKHOLDER MATTERS

All of our common stock is held by
our parent company, Black Hills Corporation. Accordingly, there is no established trading
market for our common stock.

# ITEM 7.     
MANAGEMENTS DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

# Consolidated Results

Overview

Revenue and net income (loss) from
continuing operations provided by each business group as a percentage of our total revenue
and net income were as follows:

|                              | 2002 |  | 2001 |     | 2000 | 
|----------------------------- | ---- |  | ---- | --- | ---- | 
|
|Revenue:                      |      |  |      |     |      | 
|Electric utility              |      |  |      | 56  | %    | 
|Independent power             |      |  |      | 44  |      | 
|                              |      |  |      |     |      | 
|                              |      |  |      | 100 | %    | 
|                              |      |  |      |     |      | 
|                              |      |  |     
|Income (loss) from continuing |      | 
|operations:                   |      | 
|Electric utility              |      |  |      | 75  | %    | 
|Independent power             |      |  |      | 25  |      | 
|                              |      |  |      |     |      | 
|                              |      |  |      | 100 | %    | 
|                              |      |  |      |     |      | 

2002 Compared to 2001

Consolidated income from continuing
operations for 2002 was $40.3 million compared to $43.3 million in 2001. The decrease in
income from continuing operations is due to a substantial decrease in prevailing prices
for wholesale electricity compared to 2001, partially offset by earnings from an increase
in power generation capacity. Unusual energy market conditions existed in the first half
of 2001 stemming primarily from gas and electricity shortages in the West. Average
wholesale electric average peak prices at Mid-Columbia were approximately $143 per
megawatt-hour in 2001 compared to approximately $24 per megawatt-hour in 2002.

In addition, 2001 earnings were
impacted by several non-recurring items including a $4.4 million after-tax charge for a
financial exposure to Enron Corporation and a $2.1 million after-tax charge for the
funding of a non-profit foundation.

---

Consolidated revenues were $287.5
million in 2002 compared to $287.0 million in 2001. Revenues were affected by a $52.9
million decrease in electric wholesale off-system sales partially offset by increased
revenues from expanded power generation capacity.

Operating expenses decreased $9.4
million in 2002 compared to 2001. A decrease in fuel and purchased power of $16.4 million
and operation and maintenance expenses of $6.9 million was offset by an increase of $12.2
million in depreciation expense related to the increase in power generation capacity.

2001 Compared to 2000

Consolidated income from continuing
operations for 2001 was $43.3 million compared to $40.3 million in 2000. Consolidated
revenues, expenses and operating income increased 49 percent, 54 percent and 24 percent,
respectively, in 2001 compared to 2000.

Increased revenues, expenses and
strong earnings in 2001 were primarily due to increased wholesale off-system electric
utility sales and expanded power generation. 2001 was the first full year of operations
for our independent power generation subsidiary. Unusual market conditions stemming from
electricity shortages in the West also contributed to our strong financial performance in
2001.

Earnings in 2001 included a $4.4
million after-tax charge for financial exposure to Enron Corporation and certain of its
subsidiaries now in bankruptcy. The exposure is primarily related to the value of a
long-term swap to provide natural gas to a power plant. Earnings in 2001 also were
impacted by a $2.1 million after-tax charge for the funding of a non-profit foundation to
advance our charitable and philanthropic endeavors.

# Electric Utility

|                   | 2002 |  | 2001 |         | 2000 |  
|------------------ | ---- |  | ---- | ------- | ---- | -
|
|Revenue            |      |  | $    | 162,186 |      | $
|Operating expenses |      |  |      | 104,026 |      |  
|                   |      |  |      |         |      |  
|Operating income   |      |  | $    | 58,160  |      | $
|                   |      |  |      |         |      |  
|Net income         |      |  | $    | 30,217  |      | $
|                   |      |  |      |         |      |  

We currently have a winter peak of
344 megawatts established in December 1998 and a summer peak of 392 megawatts established
in August 2001. We own 435 megawatts of electric utility generating capacity and purchase
an additional 60 megawatts under a long-term agreement (decreasing to 55 megawatts in
2003).

2002 Compared to 2001

Electric revenue decreased 24 percent
in 2002 compared to 2001. The decrease in electric revenue in 2002 was due to a $52.9
million decrease in wholesale off-system sales at an average price that was 63 percent
lower than the average price in 2001.

Firm kilowatt-hour sales decreased 2
percent in 2002. Residential and commercial sales increases of 5 percent and 3 percent,
respectively, in 2002 accounted for a $2.9 million increase in revenue which was partially
offset by a $3.6 million decrease in industrial sales, primarily due to discontinued
operations at two of our largest and oldest customers, Homestake Gold Mine and Federal
Beef Processors. Degree days, a measure of weather trends, were one percent above normal
in 2002 and four percent above 2001.

Revenue per kilowatt-hour sold was
5.3 cents in 2002 compared to 7.0 cents in 2001. The number of customers in the service
area at December 31, 2002 increased to 59,948 from 59,237 in 2001. The decrease in the
revenue per kilowatt-hour sold in 2002 is due to a 63 percent decrease in average
wholesale off-system prices.

---

Electric utility operating expenses
decreased $25.1 million or 19 percent in 2002. The decrease was primarily due to a $22.0
million decrease in fuel and purchased power costs and a $5.0 million decrease in
operations and maintenance expenses partially offset by higher depreciation expense
related to the addition of the Lange combustion turbine in early 2002.

The decrease in fuel and purchased
power costs was primarily due to the high spot market price for gas and electricity in the
first half of 2001. The decrease in operations and maintenance expense was primarily due
to a $3.2 million expense of a temporary generator lease in 2001 and a $3.1 million
decrease in incentive compensation in 2002 offset by a $1.8 million increase in pension
expense in 2002.

Net interest expense increased $2.3
million due to the issuance of $75 million of first mortgage bonds issued in August 2002.

In addition, 2001 earnings included a
$2.0 million after-tax charge related to the formation of a non-profit foundation.

2001 Compared to 2000

Electric revenue increased 23 percent in
2001 compared to 2000. The increase in electric revenue in 2001 was primarily due to a 78
percent increase in wholesale off-system sales at an average price that was 27 percent
higher than the average price in 2000. The increase in off-system sales was driven by high
spot market prices for energy in early 2001, which enabled us to generate more energy from
our combustion turbine facilities, including the Neil Simpson combustion turbine, which we
placed into commercial operation in June 2000. Megawatt-hours generated from our oil-fired
diesel and natural gas-fired combustion turbines were 440,368 in 2001, compared to 305,767
in 2000. Historically, market prices were not sufficient to support the economics of
generating from these facilities, except to meet peak demand and as standby use for native
load requirements.

Firm kilowatt-hour sales increased 2
percent in 2001. Residential and commercial sales increases of 3 percent in 2001 were
partially offset by a slight decrease in industrial sales, primarily due to load
reductions at Homestake Gold Mine. Degree days, a measure of weather trends, were 3
percent below normal in 2001 and 4 percent below 2000.

Revenue per kilowatt-hour sold was
7.0 cents in 2001 compared to 6.4 cents in 2000. The number of customers in the service
area increased to 59,237 from 58,601 in 2000. The increase in the revenue per
kilowatt-hour sold in 2001 is due to a 41 percent increase in wholesale off-system sales
to 965,030 megawatt-hours and strong wholesale power prices.

Electric utility operating expenses
increased 23 percent in 2001 primarily due to a 29 percent increase in purchased power
costs and a 14 percent increase in the average cost of generation. The increase in the
average cost of generation was primarily associated with the operation of certain
gas-fired combustion turbines.

In addition, 2001 results include a
$2.0 million after-tax charge related to a contribution to a newly formed non-profit
foundation. This Foundation was created to enhance our longstanding practice of giving
back to our communities. Through the Foundation, we may strengthen our service to our
valued customers and fellow citizens for generations to come.

---

# Independent Power

|                         | 2002 |  | 2001 |         | 2000* |  
|------------------------ | ---- |  | ---- | ------- | ----- | -
|
|Revenue                  |      |  | $    | 125,267 |       | $
|Expenses                 |      |  |      | 77,628  |       |  
|                         |      |  |      |         |       |  
|                         |      |  |      | 47,639  |       |  
|Equity in unconsolidated |      | 
|subsidiaries             |      |  |      | 4,339   |       |  
|                         |      |  |      |         |       |  
|Operating income         |      |  | $    | 51,978  |       | $
|                         |      |  |      |         |       |  
|Net income (loss)        |      |  | $    | 10,962  |       | $
|                         |      |  |      |         |       |  

_________________

|* |  | Year
2000 results are for the partial period July 7, 2000, the date of our acquisition of
Indeck Capital, Inc., through December 31, 2000.
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------

2002 Compared to 2001

Earnings from the power generation
segment increased $12.9 million primarily due to increased capacity that went into service
during 2002 and the second half of 2001. During 2002, we had 686 net megawatts of
independent power capacity in service, contributing to operations, compared to 577 net
megawatts at December 31, 2001. Approximately 300 megawatts of the 577 megawatts of
capacity at December 31, 2001 were brought on-line during the third quarter of 2001.
Earnings for 2002 also reflect a $1.9 million after-tax benefit relating to the collection
of receivables reserved for in prior periods and a $0.9 million benefit, net of taxes from
a change in accounting principle due to the adoption of Statement of Financial Accounting
Standards (SFAS) No. 142, Goodwill and Other Intangibles (SFAS 142). In
addition, 2001 was impacted by a $4.4 million after-tax charge for an exposure to Enron
Corporation.

Revenue increased 70 percent with a
corresponding 25 percent increase to operating expenses. Approximately 46 percent of the
revenue and 70 percent of the operating expenses increase was attributed to the purchase
of an additional 30 percent interest in the Harbor Cogeneration Facility (Harbor) on March
15, 2002. Harbor is a 98-megawatt gas-fired plant located in Wilmington, California. Our
investment in Harbor prior to this acquisition of an additional 30 percent interest was
accounted for under the equity method of accounting. This acquisition gave us majority
ownership and voting control of Harbor, therefore we now consolidate Harbor into our
financial statements. As a result, this consolidation was partially offset by a $6.4
million decrease in equity in earnings of unconsolidated subsidiaries. The remaining
increase in revenue and operating expenses was due to the additional generating capacity.

Interest expense increased $5.4
million due to approximately a $183.3 million increase in debt outstanding related to the
expansion of our generation portfolio, partially offset by lower interest rates.

2001 Compared to 2000

The year 2001 reflects the first full
year of operations of our power generation group and our continued expansion of generation
facilities. Revenues were over three times higher in 2001 compared to 2000. We owned 577
net megawatts in currently operating plants compared to 250 net megawatts at December 31,
2000. An additional 274 megawatts of generating capacity was under construction.
Substantially all of this output is sold pursuant to existing long-term contracts.

Expenses increased more than three
times in 2001 compared to 2000 due to the expansion of the generating capacity, reserves
taken for exposure to western power markets and a $4.4 million after-tax charge for the
Enron exposure.

Earnings in 2001 decreased $5.1
million in 2001 compared to 2000. The increased production capacity was offset by the
charge taken for the Enron exposure, reserves for exposure to the western power markets
and reduced water flow at hydro power plants in New York.

---

# Discontinued Operations

During the quarter ended March 31,
2001, we distributed a non-cash dividend to our parent company, Black Hills Corporation
(the Parent). The dividend included 50,000 common shares of Wyodak Resources Development
Corporation (Wyodak), which represents 100 percent ownership of Wyodak. We therefore no
longer operate in the coal production segment, oil and natural gas production segment,
energy marketing segment or communications as we had indirectly owned the companies
operating in these segments through our ownership of Wyodak. As a result, our only
subsidiary is Black Hills Energy Capital and its subsidiaries. Our investment in Wyodak at
the time of the distribution was $89.6 million.

The consolidated financial statements
and notes to consolidated financial statements have been restated to reflect our
continuing operations for all periods presented. The net operating results of discontinued
operations are included in the Consolidated Statements of Income under the caption
Discontinued operations, net of income taxes and are summarized as follows:

|                           | 2001* |  | 2000 |        
|-------------------------- | ----- |  | ---- | -------
|
|Revenue                    |       |  | $    | 197,274
|Income before income taxes |       |  |      | 7,849  
|Federal income taxes       |       |  |      | 3,017  
|Net income                 |       |  |      | 4,832  

_________________

*Includes only one month of
operations

# ITEM 7A.     QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

# Market Risk Disclosures

Our activities in the regulated and
unregulated energy sector expose us to a number of risks in the normal operations of our
businesses. Depending on the activity, we are exposed to varying degrees of market risk
and counterparty risk. We have developed policies, processes, systems, and controls to
manage and mitigate these risks.

Market risk is the potential loss
that might occur as a result of an adverse change in market price or rate. We are exposed
to the following market risks:

- commodity price risk associated with our fuel procurement for our gas fired generation assets; and
- interest rate risk associated with our variable rate credit facilities and our project
financing floating rate debt as described in Notes 7 and 8 of our Notes to Consolidated
Financial Statements.

Our exposure to these market risks is
affected by a number of factors including the size, duration, and composition of our
energy portfolio, the absolute and relative levels of interest rates and commodity prices,
the volatility of these prices and rates, and the liquidity of the related interest rate
and commodity markets.

To manage and mitigate these
identified risks, we have adopted the Black Hills Corporation Risk Policies and
Procedures (BHCRPP). These policies have been approved by our Board of Directors and
are routinely reviewed by its Audit Committee. We have a formalized Executive Risk
Committee composed of senior level executives that meets on a regular basis to review our
business and credit activities and to ensure that these activities are conducted within
the authorized policies.

---

# Energy Activities

We have a portfolio of gas-fired
fueled generation assets located throughout several western states. Most of these
generation assets are sold under long-term tolling contracts with third parties whereby
any fuel price risk is transferred to the third party. However, we do have some gas-fired
generation assets under long term contracts and a few merchant plants that do possess
market risk for fuel purchases.

It is our policy that fuel price
risk, to the extent possible, will be hedged.

A potential risk related to power
sales is the risk arising from the sale of wholesale power that exceeds our generating
capacity. These short positions can arise from unplanned plant outages or from
unanticipated load demands. To control such risk, we restrict wholesale off-system sales
to amounts by which our anticipated generating capabilities exceed our anticipated load
requirements plus a required reserve margin.

# Financing Activities

We engage in activities to manage
risks associated with changes in interest rates. We have entered into floating-to-fixed
interest rate swap agreements to reduce our exposure to interest rate fluctuations
associated with our floating rate debt obligations. At December 31, 2002, these hedges met
effectiveness testing criteria and retained their cash flow hedge status. At December 31,
2002, we had $212.3 million of notional amount floating-to-fixed interest rate swaps,
having a maximum term of four years and a fair value of $(17.2) million. These hedges are
substantially effective and any ineffectiveness was immaterial.

On December 31, 2002 and 2001, our
interest rate swaps and related balances were as follows (in thousands):

|                  | Notional | Weighted
Average
Fixed
Interest
Rate | Maximum
Terms in
Years | Current
Assets | Non-
current
Assets | Current
Liabilities | Non-
current
Liabilities | Accumulated
Other
Comprehensive
Income (Loss)
|----------------- | -------- | ------------------------------------ | ---------------------- | -------------- | ------------------- | ------------------- | ------------------------ | ---------------------------------------------
|
|Swaps on project  |          |                                      |                        |                |                     |                     |                          |                                              
|financing         |          |                                      | $                      | 212,256        |                     |                     | 5.98                     | %                                            
|                  |          |                                      |                        |                |                     |                     |                          |                                              
|December 31, 2001 |          |                                     
|Swaps on project  |          |                                      |                        |                |                     |                     |                          |                                              
|financing         |          |                                      | $                      | 316,397        |                     |                     | 5.85                     | %                                            
|                  |          |                                      |                        |                |                     |                     |                          |                                              

We anticipate a portion of unrealized
losses recorded in accumulated other comprehensive income will be realized as increased
interest expense in 2003. Based on December 31, 2002 market interest rates, $9.3 million
will be realized as additional interest expense during 2003. Estimated and realized
amounts will likely change during 2003 as market interest rates change.

At December 31, 2002, we had $871.9
million of outstanding, variable-rate debt of which $454.8 million was due to an affiliate
and $212.3 million was offset with interest rate swap transactions that effectively
convert the debt to a fixed rate. A 100 basis point increase in interest rates would cause
our interest expense to increase by $6.6 million.

---

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).

|                      | 2003 |  | 2004 |        | 2005 |   | 2006   |   | 2007 |        | Thereafter |   | Total  
|--------------------- | ---- |  | ---- | ------ | ---- | - | ------ | - | ---- | ------ | ---------- | - | -------
|
|Cash equivalents      |      |  |      |        |      |   |        |   |      |        |            |   |        
|Fixed rate            |      |  | $    | 45,042 |      | $ | --     |   | $    | --     |            | $ | --     
|Long-term debt        |      | 
|Fixed rate            |      |  | $    | 3,095  |      | $ | 1,986  |   | $    | 1,991  |            | $ | 1,996  
|Average interest rate |      |  |      | 9.28   | %    |   | 9.44   | % |      | 9.45   | %          |   | 9.46   
|Variable rate (a)     |      |  | $    | 19,036 |      | $ | 22,213 |   | $    | 23,631 |            | $ | 136,065
|Average interest rate |      |  |      | 3.21   | %    |   | 3.21   | % |      | 3.21   | %          |   | 3.28   
|Total long-term debt  |      |  | $    | 22,131 |      | $ | 24,199 |   | $    | 25,622 |            | $ | 138,061
|Average interest rate |      |  |      | 4.06   | %    |   | 3.72   | % |      | 3.69   | %          |   | 3.37   

|(a) |  | Approximately
58 percent of the variable rate long-term debt has been hedged                with
interest rate swaps moving the floating rates to fixed rates with an
               average interest rate of 5.98 percent.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

# Credit Risk

Credit risk is the risk of financial
loss resulting from non-performance of contractual obligations by a counterparty. We have
adopted the Black Hills Corporation Credit Policy (BHCCP) that establishes guidelines,
controls, and limits to manage and mitigate credit risk within risk tolerances established
by the Board of Directors. In addition, we have a formalized Executive Credit Committee
composed of senior executives that meets on a regular basis to review the Companys
credit activities and to ensure that these activities are conducted within our policies.

For our generation activities, we
attempt to mitigate our credit risk by conducting a majority of our business with
investment grade companies, setting tenor and credit limits commensurate with counterparty
financial strength, obtaining netting agreements, and securing our credit exposure with
less creditworthy counterparties through parental guarantees, prepayments, letters of
credit, and asset security agreements.

We perform ongoing credit evaluations
of our customers and adjust credit limits based upon payment history and the
customers current creditworthiness, as determined by our review of their current
credit information. We maintain a provision for estimated credit losses based upon our
historical experience and any specific customer collection issue that we have identified.
While most credit losses have historically been within our expectations and provisions
established, we cannot guarantee that we will continue to experience the same credit loss
rates that we have in the past or that an investment grade counterparty will not default
sometime in the future.

# Safe Harbor for Forward
Looking Information

This Form 10-K includes
forward-looking statements as defined by the Securities and Exchange
Commission, or SEC. We make these forward-looking statements in reliance on the safe
harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this Form 10-K that
address activities, events or developments that we expect, believe or anticipate will or
may occur in the future are forward-looking statements. These forward-looking statements
are based on assumptions which we believe are reasonable based on current expectations and
projections about future events and industry conditions and trends affecting our business.
However, whether actual results and developments will conform to our expectations and
predictions is subject to a number of risks and uncertainties that, among other things,
could cause actual results to differ materially from those contained in the
forward-looking statements, including:

---

- the effects on our business resulting from the financial difficulties of other energy
companies, including the effects on liquidity and the perceptions of the energy business;
- the effects on our business resulting from a lowering of our credit rating (or actions we
may take in response to changing credit ratings criteria), including demands for increased
collateral by our current or new counterparties, refusal by our current or potential
counterparties or customers to enter into transactions with us and our inability to obtain
credit or capital in amounts or on terms favorable to us;
- capital market conditions;
- unanticipated developments in the western power markets, including unanticipated
governmental intervention, deterioration in the financial condition of counterparties,
defaults on amounts due from counterparties, adverse changes in current or future
litigation, market disruption and adverse changes in energy and commodity supply, volume
and pricing and interest rates;
- pricing and transportation of commodities;
- population changes and demographic patterns;
- prevailing governmental policies and regulatory actions with respect to allowed rates of
return, industry and rate structure, acquisition and disposal of assets and facilities,
operation and construction of plant facilities, recovery of purchased power and other
capital investments, and present or prospective wholesale and retail competition;
- the continuing efforts by or on behalf of the State of California to restructure its
long-term power purchase contracts and efforts by regulators and private parties in
several western states to recover refunds for alleged price manipulation;
- changes in and compliance with environmental and safety laws and policies;
- weather conditions;
- competition for retail and wholesale customers;
- market demand, including structural market changes;
- changes in tax rates or policies or in rates of inflation;
- changes in project costs;
- unanticipated changes in operating expenses or capital expenditures;
- technological advances by competitors;
- competition for new energy development opportunities;
- the cost and other effects of legal and administrative proceedings that influence our business;

---

- the effects on our business, including the availability of insurance, resulting from terrorist
actions or responses to such actions; and
- other factors discussed from time to time in our filings with the SEC.

New factors that could cause actual
results to differ materially from those described in forward-looking statements emerge
from time to time, and it is not possible for us to predict all such factors, or the
extent to which any such factor or combination of factors may cause actual results to
differ from those contained in any forward-looking statement. We assume no obligation to
update publicly any such forward-looking statements, whether as a result of new
information, future events, or otherwise.

---

# ITEM 8.     FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA

# INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS

|                                                                                | 
|------------------------------------------------------------------------------- | 
|
|Independent Auditors' Report                                                    | 
|Consolidated Statements of Income                                               | 
|for the three years ended December 31, 2002                                     | 
|Consolidated Balance Sheets as of December 31, 2002 and 2001                    | 
|Consolidated Statements of Cash Flows                                           | 
|for the three years ended December 31, 2002                                     | 
|Consolidated Statements of Common Stockholder's Equity and Comprehensive Income | 
|for the three years ended December 31, 2002                                     | 
|Notes to Consolidated Financial Statements                                      | 

# INDEPENDENT
AUDITORS REPORT

To the Stockholder of Black Hills
Power, Inc.:

We have audited the accompanying
consolidated balance sheets of Black Hills Power, Inc. and subsidiaries as of December 31,
2002 and 2001, and the related consolidated statements of income, common
stockholders equity and comprehensive income, and cash flows for each of the three
years in the period ended December 31, 2002. Our audits also included the financial
statement schedule listed in the Table of Contents at Item 15. These financial statements
and financial statement schedule are the responsibility of the Corporations
management. Our responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits.

We conducted our audits in accordance
with auditing standards generally accepted in the United States of America. Those
standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, such consolidated
financial statements present fairly, in all material respects, the financial position of
Black Hills Power, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results
of their operations and their cash flows for each of the three years in the period ended
December 31, 2002, in conformity with accounting principles generally accepted in the
United States of America. Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole, presents fairly
in all material respects the information set forth therein.

As explained in Note 1 to the
consolidated financial statements, effective January 1, 2002, the Corporation adopted
Statement of Financial Accounting Standards No. 142 Goodwill and Other Intangible
Assets and as discussed in Note 1 to the consolidated financial statements,
effective January 1, 2001, the Corporation adopted Statement of Financial Accounting Standards
No. 133, Accounting for Derivative Instruments and Hedging Activities.

DELOITTE & TOUCHE LLP

Minneapolis, MinnesotaMarch
10, 2003

---

# BLACK HILLS POWER, INC.CONSOLIDATED
STATEMENTS OF INCOME

|2002                                              |  | 2001 |   | 2000    |  
|------------------------------------------------- |  | ---- | - | ------- | -
|
|Operating revenues                                |  |      | $ | 287,453 |  
|                                                  |  |      |   |         |  
|Operating expenses:                               |  |     
|Fuel and purchased power                          |  |      |   | 60,620  |  
|Operations and maintenance                        |  |      |   | 35,069  |  
|Administrative and general                        |  |      |   | 31,691  |  
|Depreciation and amortization                     |  |      |   | 43,933  |  
|Taxes, other than income taxes                    |  |      |   | 10,341  |  
|                                                  |  |      |   |         |  
|                                                  |  |      |   | 181,654 |  
|                                                  |  |      |   |         |  
|Equity in earnings of unconsolidated subsidiaries |  |      |   | 4,339   |  
|                                                  |  |      |   |         |  
|Operating income                                  |  |      |   | 110,138 |  
|                                                  |  |      |   |         |  
|Other (expense) income:                           |  |     
|Interest expense                                  |  |      |   | (47,865 | )
|Interest income                                   |  |      |   | 825     |  
|Other expense                                     |  |      |   | (312    | )
|Other income                                      |  |      |   | 2,334   |  
|                                                  |  |      |   |         |  
|                                                  |  |      |   | (45,018 | )
|                                                  |  |      |   |         |  
|Income from continuing operations before minority |  |     
|interest, income taxes and change in accounting   |  |     
|principle                                         |  |      |   | 65,120  |  
|Minority interest                                 |  |      |   | (3,162  | )
|Income taxes                                      |  |      |   | (21,675 | )
|                                                  |  |      |   |         |  
|Income from continuing operations before          |  |     
|change in accounting principle                    |  |      |   | 40,283  |  
|Discontinued operations, net of income taxes      |  |     
|(Note 2)                                          |  |      |   | --      |  
|Change in accounting principle                    |  |      |   | 896     |  
|                                                  |  |      |   |         |  
|                                                  |  |      |  
|Net income                                        |  |      | $ | 41,179  |  
|                                                  |  |      |   |         |  

The accompanying notes to
consolidated financial statements are an integral part of these consolidated financial
statements.

---

# BLACK HILLS POWER, INC.CONSOLIDATED
BALANCE SHEETS

|2002                                                          |  | 2001 |  
|------------------------------------------------------------- |  | ---- | -
|
|ASSETS                                                        |  |      |  
|Current assets:                                               |  |     
|Cash and cash equivalents                                     |  |      | $
|Restricted cash                                               |  |      |  
|Receivables (net of allowance for doubtful accounts of $1,771 |  |     
|and $2,677, respectively) -                                   |  |     
|Customers                                                     |  |      |  
|Affiliates                                                    |  |      |  
|Other                                                         |  |      |  
|Materials, supplies and fuel                                  |  |      |  
|Prepaid expenses                                              |  |      |  
|Deferred income taxes                                         |  |      |  
|Other                                                         |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|Investments                                                   |  |      |  
|                                                              |  |      |  
|Property and equipment                                        |  |      |  
|Less accumulated depreciation                                 |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|Other assets:                                                 |  |     
|Regulatory asset                                              |  |      |  
|Goodwill                                                      |  |      |  
|Intangible assets                                             |  |      |  
|Other                                                         |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|                                                              |  |      | $
|                                                              |  |      |  
|LIABILITIES AND STOCKHOLDER'S EQUITY                          |  |     
|Current liabilities:                                          |  |     
|Current maturities of long-term debt                          |  |      | $
|Notes payable                                                 |  |      |  
|Notes payable - affiliate                                     |  |      |  
|Accounts payable                                              |  |      |  
|Accounts payable - affiliate                                  |  |      |  
|Accrued liabilities                                           |  |      |  
|Derivative liabilities                                        |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|Long-term debt, net of current maturities                     |  |      |  
|                                                              |  |      |  
|Deferred credits and other liabilities:                       |  |     
|Deferred income taxes                                         |  |      |  
|Regulatory liability                                          |  |      |  
|Derivative liabilities                                        |  |      |  
|Other                                                         |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|Minority interest in subsidiaries                             |  |      |  
|                                                              |  |      |  
|Commitments and contingencies (Notes 11, 12 and 16)           |  |     
|Stockholder's equity:                                         |  |     
|Common stock $1 par value; 50,000,000 shares authorized;      |  |     
|Issued: 23,416,396 shares in 2002 and 2001                    |  |      |  
|Additional paid-in capital                                    |  |      |  
|Retained earnings                                             |  |      |  
|Accumulated other comprehensive loss                          |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|                                                              |  |      |  
|                                                              |  |      | $
|                                                              |  |      |  

The accompanying notes to
consolidated financial statements are an integral part of these consolidated financial
statements.

---

# BLACK HILLS POWER, INC.CONSOLIDATED
STATEMENTS OF CASH FLOWS

|2002                                                        |  | 2001 |   | 2000     |  
|----------------------------------------------------------- |  | ---- | - | -------- | -
|
|Operating activities:                                       |  |      |   |          |  
|Net income                                                  |  |      | $ | 41,179   |  
|Income from discontinued operations                         |  |      |   | --       |  
|Adjustments to reconcile net income to net cash             |  |     
|provided by operating activities-                           |  |     
|Depreciation and amortization                               |  |      |   | 43,933   |  
|Provision for valuation allowances                          |  |      |   | (906     | )
|Gain on sales of assets                                     |  |      |   | --       |  
|Deferred income taxes                                       |  |      |   | 22,993   |  
|Undistributed earnings in associated companies              |  |      |   | (3,964   | )
|Minority interest                                           |  |      |   | 3,162    |  
|Accounting change                                           |  |      |   | (896     | )
|Change in operating assets and liabilities-                 |  |     
|Accounts receivable and other current assets                |  |      |   | (55,951  | )
|Accounts payable and other current liabilities              |  |      |   | 46,477   |  
|Other operating activities                                  |  |      |   | 1,854    |  
|                                                            |  |      |   |          |  
|                                                            |  |      |   | 97,881   |  
|                                                            |  |      |   |          |  
|Investing activities:                                       |  |     
|Property, plant and equipment additions                     |  |      |   | (178,981 | )
|Payment for acquisition of net assets, net of cash acquired |  |      |   | (13,243  | )
|Payment for acquisition of minority interest                |  |      |   | (13,800  | )
|Notes receivable from associated companies, net             |  |      |   | --       |  
|Other investing activities                                  |  |      |   | (19      | )
|                                                            |  |      |   |          |  
|                                                            |  |      |   | (206,043 | )
|                                                            |  |      |   |          |  
|Financing activities:                                       |  |     
|Dividends paid on common stock                              |  |      |   | (31,148  | )
|Increase in short-term borrowings, net                      |  |      |   | 49,550   |  
|Long-term debt - issuance                                   |  |      |   | 160,632  |  
|Long-term debt - repayments                                 |  |      |   | (32,501  | )
|Other financing activities                                  |  |      |   | (8,161   | )
|                                                            |  |      |   |          |  
|                                                            |  |      |   | 138,372  |  
|                                                            |  |      |   |          |  
|Increase in cash and cash equivalents                       |  |      |   | 30,210   |  
|Cash and cash equivalents:                                  |  |     
|Beginning of year                                           |  |      |   | 14,832   |  
|                                                            |  |      |   |          |  
|End of year                                                 |  |      | $ | 45,042   |  
|                                                            |  |      |   |          |  
|Supplemental disclosure of cash flow information:           |  |     
|Cash paid during the period for-                            |  |     
|Interest                                                    |  |      | $ | 50,134   |  
|Income taxes paid (refunded)                                |  |      | $ | (23,325  | )
|Non-cash net assets acquired through issuance of common     |  |     
|stock (Note 11)                                             |  |      | $ | 3,826    |  
|Stock dividend distribution to Black Hills Corporation, the |  |     
|parent company of Black Hills Power, Inc. (Note 2)          |  |      | $ | --       |  

The accompanying notes to
consolidated financial statements are an integral part of these consolidated financial
statements.

---

# BLACK HILLS POWER, INC.CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDERS EQUITY AND COMPREHENSIVE
INCOME

|                              |  |  |  |        | Accumulated |   |       
|----------------------------- |  |  |  | ------ | ----------- | - | ------
|
|
|
|
|Balance at December 31, 1999  |  |  |  | 21,739 |             | $ | 21,739
|                              |  |  |  |        |             |   |       
|Comprehensive Income:         |  | 
|Net income                    |  |  |  | --     |             |   | --    
|                              |  |  |  |        |             |   |       
|Total comprehensive income    |  |  |  | --     |             |   | --    
|Dividends on preferred stock  |  |  |  | --     |             |   | --    
|Dividends on common stock     |  |  |  | --     |             |   | --    
|Issuance of common stock      |  |  |  | 140    |             |   | 140   
|Issuance of common stock      |  | 
|for acquisition               |  |  |  | 1,537  |             |   | 1,537 
|                              |  |  |  |        |             |   |       
|Balance at December 31, 2000  |  |  |  | 23,416 |             |   | 23,416
|                              |  |  |  |        |             |   |       
|Comprehensive Income:         |  | 
|Net income                    |  |  |  | --     |             |   | --    
|Unrealized loss on mark to    |  | 
|market interest rate swaps    |  |  |  | --     |             |   | --    
|Initial impact of adoption of |  | 
|SFAS 133, net of minority     |  | 
|interest                      |  |  |  | --     |             |   | --    
|                              |  |  |  |        |             |   |       
|Total comprehensive income    |  |  |  | --     |             |   | --    
|                              |  |  |  |        |             |  
|Dividends on common stock     |  |  |  | --     |             |   | --    
|Earnout consideration on      |  | 
|acquisition                   |  |  |  | --     |             |   | --    
|Stock distribution to parent  |  |  |  | --     |             |   | --    
|                              |  |  |  |        |             |   |       
|Balance at December 31, 2001  |  |  |  | 23,416 |             |   | 23,416
|                              |  |  |  |        |             |   |       
|Comprehensive Income:         |  | 
|Net income                    |  |  |  | --     |             |   | --    
|Other comprehensive loss,     |  | 
|net of tax                    |  |  |  | --     |             |   | --    
|                              |  |  |  |        |             |   |       
|Total comprehensive income    |  |  |  | --     |             |   | --    
|Dividends on common stock     |  |  |  | --     |             |   | --    
|                              |  |  |  |        |             |   |       
|Balance at December 31, 2002  |  |  |  | 23,416 |             | $ | 23,416
|                              |  |  |  |        |             |   |       

The accompanying notes to
consolidated financial statements are an integral part of these consolidated financial
statements.

---

# NOTES TO CONSOLIDATED
FINANCIAL STATEMENTSDecember 31, 2002, 2001 and 2000

# (1)     BUSINESS DESCRIPTION AND
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

# Business Description

Black Hills Power, Inc. and its
subsidiaries (the Company) operate in two primary operating groups: regulated electric
utility and non-regulated power generation. Black Hills Power operates the public utility
operations. The Company operates its power generation business through its direct
subsidiary, Black Hills Energy Capital (BHEC). The Company is a wholly owned subsidiary of
the publicly traded Black Hills Corporation (the Parent).

# Use of Estimates

The preparation of financial
statements in conformity with accounting principles generally accepted in the United
States of America requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. The most significant estimates relate to
allowance for uncollectible accounts receivable, realization of market value of
derivatives due to commodity risk, intangible asset valuations and useful lives,
long-lived asset values and useful lives, employee benefits plans and contingencies.
Actual results could differ from those estimates.

# Principles of
Consolidation

The consolidated financial statements
include the accounts of the Company and its wholly owned and majority-owned subsidiaries
and certain subsidiaries in which the Companys ownership interest may be less than
50 percent but represents voting control. Generally, the Company uses equity method
accounting for investments of which it owns between 20 and 50 percent and investments in
partnerships under 20 percent if the Company exercises significant influence. All
significant intercompany balances and transactions have been eliminated in consolidation.

As discussed in Note 16, Black Hills
Energy Capital made several acquisitions during 2002 and 2001. The Companys
consolidated statements of income include operating activity of these companies beginning
with their acquisition date.

The consolidated financial statements
also include assets, liabilities and income from discontinued operations (see Note 2).

# Minority Interest in
Subsidiaries

Minority interest in the accompanying
Consolidated Statements of Income represents the share of the income or loss of certain
consolidated subsidiaries attributable to the minority shareholders of those subsidiaries.
The minority interest in the accompanying Consolidated Balance Sheets reflect the amount
of the underlying net assets of those certain consolidated subsidiaries attributable to
the minority shareholders of those subsidiaries.

Earnings attributable to minority
ownership in certain subsidiaries are generally shown on the accompanying consolidated
statement of income on a pre-tax basis as the subsidiaries with minority investors are
typically limited liability companies or partnerships which pay no tax at the corporate or
partnership level.

---

# Regulatory Accounting

The Companys regulated electric
operations are subject to regulation by various state and federal agencies. The accounting
policies followed are generally subject to the Uniform System of Accounts of the Federal
Energy Regulatory Commission (FERC). These accounting policies differ in some respects
from those used by the Companys non-regulated businesses.

The Companys electric
operations follow the provisions of Statement of Financial Accounting Standards (SFAS) No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), and
its financial statements reflect the effects of the different ratemaking principles
followed by the various jurisdictions regulating its electric operations. As a result of
the Companys 1995 rate case settlement, a 50-year depreciable life for Neil Simpson
II is used for financial reporting purposes. If the Company were not following SFAS 71, a
35 to 40 year life would be more appropriate, which would increase depreciation expense by
approximately $0.6  $1.0 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 the Companys regulated generation
operations. In the event the Company determines that it no longer meets the criteria for
following SFAS 71, the accounting impact to the Company would be an extraordinary non-cash
charge to operations of an amount that could be material. Criteria that give rise to the
discontinuance of SFAS 71 include increasing competition that could restrict the
Companys ability to establish prices to recover specific costs and a significant
change in the manner in which rates are set by regulators from cost-based regulation to
another form of regulation. The Company periodically reviews these criteria to ensure the
continuing application of SFAS 71 is appropriate.

# Cash Equivalents

The Company considers all highly
liquid investments with an original maturity of three months or less to be cash
equivalents.

# Inventory

Materials, supplies and fuel are
generally stated at the lower of cost or market on a first-in, first-out basis.

# Property, Plant and
Equipment

The components of property, plant and
equipment are as follows, at December 31:

|                  | 2002 |  | 2001 |          
|----------------- | ---- |  | ---- | ---------
|
|Electric utility  |      |  | $    | 613,925  
|Independent power |      |  |      | 890,973  
|                  |      |  |      |          
|                  |      |  | $    | 1,504,898
|                  |      |  |      |          

Additions to property, plant and
equipment are recorded at cost when placed in service. Included in the cost of regulated
construction projects is an allowance for funds used during construction (AFUDC) which
represents the approximate composite cost of borrowed funds and a return on capital used
to finance the project. The AFUDC was computed at an annual composite rate of 9.1, 10.2
and 9.7 percent during 2002, 2001 and 2000, respectively. In addition, the Company
capitalizes interest, when applicable, on certain non-regulated construction projects. The
amount of AFUDC and interest capitalized was $11.4 million, $6.8 million and $0.9 million
in 2002, 2001 and 2000, respectively. The cost of regulated electric property, plant and
equipment retired, or otherwise disposed of in the ordinary course of business, together
with removal cost less salvage, is charged to accumulated depreciation. Retirement or
disposal of all other assets, results in gains or losses recognized as a component of
income. Repairs and maintenance of property are charged to operations as incurred.

Depreciation provisions for regulated
electric property, plant and equipment is computed on a straight-line basis using an
annual composite rate of 3.1 percent in 2002, 3.0 percent in 2001 and 2.8 percent in 2000.
Non-regulated property, plant and equipment is depreciated on a straight-line basis using
estimated useful lives ranging from 3 to 40 years.

---

# Deferred Financing Costs

Deferred financing costs are
amortized using the effective interest method over the term of the related debt.

# Goodwill and Intangible
Assets

Goodwill represents the excess of
acquisition costs over the fair market value of the net assets of acquired businesses and
through 2001 was amortized on a straight-line basis over the estimated useful lives of
such assets, which range from 8 to 25 years. Goodwill expense was $0.7 million and $1.0
million for the years ended December 31, 2001 and 2000, respectively.

The cost of other acquired
intangibles is amortized on a straight-line basis over their estimated useful lives.
Amortization expense was $4.1 million, $2.5 million and $1.5 million in 2002, 2001 and
2000, respectively. Accumulated amortization was $14.9 million, $4.0 million and $1.5
million at December 31, 2002, 2001 and 2000, respectively.

# Impairment of Long-Lived
Assets and Intangible Assets

The Company periodically evaluates
whether events and circumstances have occurred which may affect the estimated useful life
or the recoverability of the remaining balance of its long-lived assets. If such events or
circumstances were to indicate that the carrying amount of these assets was not
recoverable, the Company would estimate the future cash flows expected to result from the
use of the assets and their eventual disposition. If the sum of the expected future cash
flows (undiscounted and without interest charges) was less than the carrying amount of the
long-lived assets, the Company would recognize an impairment loss. No impairment loss was
recorded during 2002, 2001 or 2000.

# Income Taxes

The Company uses the liability method
in accounting for income taxes. Under the liability method, deferred income taxes are
recognized, at currently enacted income tax rates, to reflect the tax effect of temporary
differences between the financial and tax basis of assets and liabilities. Such temporary
differences are the result of provisions in the income tax law that either require or
permit certain items to be reported on the income tax return in a different period than
they are reported in the financial statements. The Company classifies deferred tax assets
and liabilities into current and non-current amounts based on the classification of the
related assets and liabilities.

The Company files a consolidated
federal income tax return with other affiliates. For financial statement purposes,
consolidated federal income taxes are allocated to the individual companies based on
amounts calculated on a separate return basis.

# Revenue Recognition

Revenue is recognized when there is
persuasive evidence of an arrangement with a fixed or determinable price, delivery has
occurred or services have been rendered, and collectibility is reasonably assured. For
long-term non-utility power sales agreements revenue is recognized either in accordance
with Emerging Issues Task Force (EITF) Issue No. 91-6, Revenue Recognition of
Long-Term Power Sales Contracts (EITF 91-6), or in accordance with SFAS No. 13,
Accounting for Leases, (SFAS 13) as appropriate. Under EITF 91-6, revenue is
generally recognized as the lower of the amount billed or the average rate expected over
the life of the agreement. Under SFAS 13, revenue is generally levelized over the life of
the agreement. For its Investment in Associated Companies (see Note 4), which are involved
in power generation, the Company uses the equity method to recognize as earnings its pro
rata share of the net income or loss of the associated company.

# Reclassifications

Certain 2001 and 2000 amounts in the
financial statements have been reclassified to conform to the 2002 presentation. These
reclassifications had no effect on the Companys common stockholders equity or
results of operations, as previously reported.

---

# Recently Adopted
Accounting Pronouncements

In June 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 141, Business Combinations,
(SFAS 141) and No. 142, Goodwill and Other Intangible Assets (SFAS 142). The
Company has adopted SFAS 141, which requires all business combinations initiated after
June 30, 2001 to be accounted for using the purchase method of accounting. Under SFAS 142,
goodwill and intangible assets with indefinite lives are no longer amortized but the
carrying values are reviewed annually (or more frequently if impairment indicators arise)
for impairment. Intangible assets with a defined life will continue to be amortized over
their useful lives (but with no maximum life). The amortization provisions of SFAS 142
apply to goodwill and intangible assets acquired after June 30, 2001. With respect to
goodwill and intangible assets acquired prior to July 1, 2001, the Company was required to
adopt SFAS 142 effective January 1, 2002. The cumulative effect of the change in
accounting principle, net of tax at January 1, 2002, was a $0.9 million benefit. If the
carrying value exceeds the fair value, an impairment loss will be recognized. A discounted
cash flow approach was used to determine fair value of the Companys businesses for
the purposes of testing for impairment. Intangible assets with a defined life will
continue to be amortized over their useful lives (but with no maximum life). The Company
adopted SFAS 142 on January 1, 2002.

The pro forma effects of adopting
SFAS No. 142 for the years ended December 31, 2002, 2001 and 2000 are as follows (in
thousands):

|                                                    | 2002 |  | 2001 |        | 2000 |  
|--------------------------------------------------- | ---- |  | ---- | ------ | ---- | -
|
|Net income as reported                              |      |  | $    | 41,179 |      | $
|Cumulative effect of change in                      |      | 
|accounting principle, net of tax                    |      |  |      | (896   | )    |  
|                                                    |      |  |      |        |      |  
|Income excluding cumulative effect of change in     |      | 
|accounting principle                                |      |  |      | 40,283 |      |  
|Add: goodwill amortization                          |      |  |      | --     |      |  
|                                                    |      |  |      |        |      |  
|Net income excluding cumulative effect of change in |      | 
|accounting principle and goodwill amortization      |      |  | $    | 40,283 |      | $
|                                                    |      |  |      |        |      |  

The cumulative effect adjustment
recognized upon adoption of SFAS 142 was $0.9 million (after tax).  The adjustment
consisted of income from the after-tax write-off of negative goodwill from prior
acquisitions in our Independent Power segment.

The Company's goodwill and
intangible assets are contained within the Independent Power segment.  Changes to
goodwill and intangible assets during the year ended December 31, 2002, including the
effects of adopting SFAS No. 142, are as follows (in thousands):

|                                     | Goodwill |  | Other Intangible Assets |       
|------------------------------------ | -------- |  | ----------------------- | ------
|
|Balance at December 31, 2001, net of |          |  |                         |       
|accumulated amortization             |          |  | $                       | 25,566
|Change in accounting principle       |          |  |                         | 1,493 
|Additions                            |          |  |                         | 3,826 
|Adjustments                          |          |  |                         | (323  
|Amortization expense                 |          |  |                         | --    
|                                     |          |  |                         |       
|Balance at December 31, 2002, net of |          | 
|accumulated amortization             |          |  | $                       | 30,562
|                                     |          |  |                         |       

Intangible assets totaled $77.7
million, net of accumulated amortization of $14.9 million at December 31, 2002 and $86.0
million, net of accumulated amortization of $4.0 million at December 31, 2001.
 Intangible assets are primarily related to site development fees and above-market
long-term contracts, and all have definite lives ranging from 7 to 40 years, over which
they continue to be amortized.  Amortization expense for intangible assets for the next
five years is expected to be approximately $4.1 million a year.

Goodwill additions during the year
ended December 31, 2002, were from contingent consideration related to the July 7, 2000
acquisition of Indeck Capital, Inc. (see Note 11).

---

Intangible asset additions during
the year ended December 31, 2002 were primarily the result of a $9.3 million addition
related to preliminary purchase allocations in the acquisition of additional ownership
interest in the Harbor Cogeneration Facility (See Note 16).  This intangible asset
primarily relates to an acquired ownership of additional interest in a contract
termination payment stream at the facility.

Adjustments of intangible assets
during the year ended December 31, 2002 primarily relate to final adjustments to the
preliminary purchase price allocation of the Company's third quarter 2001 Las Vegas
Cogeneration acquisition.

In August 2001, the FASB issued SFAS
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144).
 SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and the accounting and reporting
provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of
Operations - Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions" (APB 30).
 SFAS 144 establishes a single accounting model for long-lived assets to be disposed of
by sale and resolves implementation issues related to SFAS 121.  The Company adopted SFAS
144 effective January 1, 2002.  Adoption did not have a material impact on the Company's
consolidated financial position, results of operations or cash flows.

# Recently Issued
Accounting Pronouncements

In June 2001, the FASB issued
Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143).  SFAS 143 requires that the fair value of a liability for an
asset retirement obligation be recognized in the period in which it is incurred with the
associated asset retirement costs being capitalized as part of the carrying amount of the
long-lived asset.  Over time, the liability is accreted to its present value each period
and the capitalized cost is depreciated over the useful life of the related asset.  The
Company adopted SFAS 143 on January 1, 2003.  Adoption did not have an effect on the
Company's consolidated financial statements.

# Derivatives and
 Hedging Activities

The Company accounts for its
derivative and hedging activities in accordance with Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
133).  SFAS 133 requires that derivative instruments be recorded in the balance sheet as
either an asset or liability measured at fair value.  SFAS 133 requires that changes in
the derivative instrument's fair value be recognized currently in earnings unless
specific hedge accounting criteria are met.

SFAS 133 allows hedge accounting for
qualifying fair value and cash flow hedges.  SFAS 133 provides that the gain or loss on a
derivative instrument designated and qualifying as a fair value hedging instrument as
well as the offsetting loss or gain on the hedged item attributable to the hedged risk be
recognized currently in earnings in the same accounting period.  SFAS 133 provides that
the effective portion of the gain or loss on a derivative instrument designated and
qualifying as a cash flow hedging instrument be reported as a component of other
comprehensive income and be reclassified into earnings in the same period or periods
during which the hedged forecasted transaction affects earnings.  The remaining gain or
loss on the derivative instrument, if any, must be recognized currently in earnings.

The Company adopted SFAS 133 on
January 1, 2001.  On January 1, 2001, the Company had interest rate swaps documented as
cash flow hedges.  These contracts were defined as derivatives under SFAS 133 and met the
requirements for cash flow hedges.  Because the contracts were documented as hedges prior
to adoption, the transition adjustment was reported in accumulated other comprehensive
income.  The aggregated entry for these derivatives identified as cash flow hedges increased
derivative assets by $0.3 million, increased derivative liabilities by $7.8 million and
decreased accumulated other comprehensive income by $7.5 million pre-tax.

---

# (2)      NON-CASH DIVIDEND AND DISCONTINUED OPERATIONS

During the quarter ended March 31,
2001, the Company distributed a non-cash dividend to its parent company, Black Hills
Corporation (the Parent).  The dividend included 50,000 common shares of Wyodak Resources
Development Corporation (Wyodak), which represents 100 percent ownership of Wyodak.  The
Company therefore no longer operates in the coal production segment, oil and natural gas
production segment, energy marketing segment or communications as the Company had
indirectly owned the companies operating in these segments through its ownership of
Wyodak.  As a result, the Company's only subsidiary is Black Hills Energy Capital and its
subsidiaries.  The Company's investment in Wyodak at the time of the distribution was
$89.6 million.

The consolidated financial
statements and notes to consolidated financial statements have been restated to reflect
the continuing operations of the Company for all periods presented.

The net operating results of
discontinued operations are included in the Consolidated Statements of Income under the
caption "Discontinued operations, net of income taxes" and are summarized as follows:

|                           | 2001* |  | 2000 |        
|-------------------------- | ----- |  | ---- | -------
|
|Revenue                    |       |  | $    | 197,274
|Income before income taxes |       |  |      | 7,849  
|Federal income taxes       |       |  |      | 3,017  
|Net income                 |       |  |      | 4,832  

_________________

*Includes only one month of
operations

# (3)      RISK MANAGEMENT
ACTIVITIES

The Companys activities in the
regulated and unregulated energy sector expose it to a number of risks in the normal
operations of its businesses. Depending on the activity, the Company is exposed to varying
degrees of market risk and counterparty risk. The Company has developed policies,
processes, systems, and controls to manage and mitigate these risks.

Market risk is the potential loss
that might occur as a result of an adverse change in market price or rate. The Company is
exposed to the following market risks:

- commodity price risk primarily associated with its fuel procurement for its gas fired generation assets; and
- interest rate risk associated with variable rate credit facilities and project financing
floating rate debt as described in Notes 7 and 8.

# Energy Activities

The Company has a portfolio of
natural gas-fired generation assets located throughout several western states. Most of
these generation assets are locked into long-term tolling contracts with third parties
whereby any commodity price risk is transferred to the third party. However, the Company
does have some natural gas fueled generation assets under long term contracts and a few
merchant plants that do possess market risk for fuel purchases.

A potential risk related to power
sales is the risk arising from the sale of wholesale power that exceeds the Companys
generating capacity. These short positions can arise from unplanned plant outages or from
unanticipated load demands. To control such risk, the Company restricts wholesale
off-system sales to amounts by which the Companys anticipated generating
capabilities exceed its anticipated load requirements plus a required reserve margin.

---

In 2001, the Company acquired several
natural gas swaps when it completed the Las Vegas Cogeneration acquisition on August 31,
2001 (Note 16). The projects 53 megawatt Las Vegas I plant has a long-term fixed
price power sales agreement and an index-priced natural gas purchase contract for 5,000
MMBtus per day through April 30, 2010. These swaps fixed the long-term purchase price of
the index-priced natural gas purchase contract. At acquisition close, the fair value of
these swaps was $6.0 million. These swaps were executed with Enron North America Corp.
(Enron), which is currently in bankruptcy proceedings.

These swaps met the definition of
derivatives under SFAS 133. The Company elected to treat these derivatives as cash flow
hedges so that any gains or losses on the fair values of the swaps could be deferred and
subsequently recognized when the underlying hedged natural gas was consumed in the plant.
The swaps were properly documented and met the criteria for cash flow hedges.

During the fourth quarter of 2001,
the Company determined that it was probable that Enron would default on its obligations to
the Company in conjunction with these swaps. Upon that determination, the Company ceased
to account for these swaps as cash flow hedges. In addition, the Company recognized a $6.0
million pre-tax valuation reserve in recognition of Enrons probable performance
default and resulting consequence that the Company would not receive payment for these
amounts.

# Financing Activities

The Company engages in activities to
manage risks associated with changes in interest rates. The Company has entered into
floating-to-fixed interest rate swap agreements to reduce its exposure to interest rate
fluctuations associated with its floating rate debt obligations. At December 31, 2002,
these hedges met effectiveness testing criteria and retained their cash flow hedge status.
At December 31, 2002, the Company had $212.3 million of notional amount floating-to-fixed
interest rate swaps, having a maximum term of four years and a fair value of $(17.2)
million. These hedges are substantially effective and any ineffectiveness was immaterial.

On December 31, 2002 and 2001, the
Companys interest rate swaps and related balances were as follows (in thousands):

|                  | Notional | Weighted
Average
Fixed
Interest
Rate | Maximum
Terms in
Years | Current
Assets | Non-
current
Assets | Current
Liabilities | Non-
current
Liabilities | Accumulated
Other
Comprehensive
Income (Loss)
|----------------- | -------- | ------------------------------------ | ---------------------- | -------------- | ------------------- | ------------------- | ------------------------ | ---------------------------------------------
|
|Swaps on project  |          |                                      |                        |                |                     |                     |                          |                                              
|financing         |          |                                      | $                      | 212,256        |                     |                     | 5.98                     | %                                            
|                  |          |                                      |                        |                |                     |                     |                          |                                              
|December 31, 2001 |          |                                     
|Swaps on project  |          |                                      |                        |                |                     |                     |                          |                                              
|financing         |          |                                      | $                      | 316,397        |                     |                     | 5.85                     | %                                            
|                  |          |                                      |                        |                |                     |                     |                          |                                              

The Company anticipates a portion of
unrealized losses recorded in accumulated other comprehensive income will be realized as
increased interest expense in 2003. Based on December 31, 2002 market interest rates, $9.3
million will be realized as additional interest expense during 2003. Estimated and
realized amounts will likely change during 2003 as market interest rates change.

At December 31, 2002, the Company had
$871.9 million of outstanding, variable-rate debt of which $659.6 million was not offset
with interest rate swap transactions that effectively convert the debt to a fixed rate. A
100 basis point increase in interest rates would cause interest expense to increase $6.6
million.

During 2002, the Company entered into
a $50 million treasury lock to hedge a portion of the Companys $75 million First
Mortgage Bond offering completed in August 2002. The treasury lock cash settled on August
8, 2002, the bond pricing date, and resulted in a $1.8 million loss. This treasury lock
was treated as a cash flow hedge and accordingly the resulting loss is carried in
Accumulated other comprehensive loss on the Consolidated Balance Sheet and amortized over
the life of the related bonds as additional interest expense.

---

In addition, at December 31, 2001,
the Company had a $100 million forward starting floating-to-fixed interest rate swap to
hedge the anticipated floating rate debt financing related to the Companys Las Vegas
II Plant. This swap terminated during the second quarter 2002 and resulted in a $1.1
million gain. This swap was treated as a cash flow hedge and accordingly in the second
quarter of 2002 the resulting gain was carried in Accumulated other comprehensive income
on the Consolidated Balance Sheet and was to be amortized over the life of the anticipated
long-term financing. In the third quarter of 2002, this cash flow hedge was determined to
be ineffective due to uncertainties about the eventual timing and form of financing for
this project. As a result, $1.1 million was taken into earnings. The gain was offset by
the expensing of approximately $1.0 million of deferred financing costs related to the
anticipated financing.

# Credit Risk

Credit risk relates to the risk of
financial loss resulting from non-performance of contractual obligations by a
counterparty. The Company maintains credit policies with regard to its counterparties that
the Company believes limit its overall credit risk.

The Company attempts to mitigate its
credit risk by conducting a majority of its business with investment grade companies,
obtaining netting agreements where possible and securing its exposure with less
creditworthy counterparties through parental guarantees, prepayments and letters of
credit.

# (4)     INVESTMENTS IN
ASSOCIATED COMPANIES

Included in Investments on the
Consolidated Balance Sheets are the following investments that have been recorded on the
equity method of accounting:

- A 12.6 percent, 6.9 percent and 5.3 percent interest in Energy Investors Fund, L.P.,
Energy Investors Fund II, L.P., and Project Finance Fund III, L.P., respectively, which in
turn have investments in numerous electric generating facilities in the United States and
elsewhere. The Company has a carrying amount in the investment of $11.0 million and $10.0
million at December 31, 2002 and 2001, respectively, which includes $1.9 million that
represents the cost of the investment over the underlying net assets of the funds. As of
and for the year ended December 31, 2002, the funds had assets of $160.7 million,
liabilities of $0.7 million and net income of $25.8 million. As of, and for the year ended
December 31, 2001, the funds had assets of $215.1 million, liabilities of $0.7 million and
net income of $37.2 million.
- A 50 percent interest in two natural gas-fired co-generation facilities located in Rupert
and Glenns Ferry, Idaho. The Companys carrying amount in the investment is $3.4
million and $3.9 million as of December 31, 2002 and 2001, respectively, which includes
$0.6 million that represents the cost of the investment over the value of the underlying
net assets of the projects. As of and for the year ended December 31, 2002, these projects
had assets of $24.5 million, liabilities of $17.1 million and net income of $0.7 million.
As of, and for the year ended December 31, 2001, these projects had assets of $25.6
million, liabilities of $19.0 million and a net loss of $(0.4) million.

# (5)     MINORITY INTEREST

The partnership agreements for two of
the Companys consolidated subsidiaries contain certain performance targets that
result in the Company earning additional partnership equity in those subsidiaries when
those targets are met. In 2002 certain targets were met by the subsidiaries resulting in a
transfer of approximately $1.0 million of partnership equity from the minority interest to
the Company. Of this amount, approximately $1.6 million was recorded as a reduction to
Minority interest expense on the consolidated statement of income and
approximately $(0.6) million was recorded as an item of Other comprehensive loss (see Note
13) on the consolidated statement of stockholders equity and comprehensive income.

# (6)     COMMON STOCK

The Company is a wholly owned
subsidiary of Black Hills Corporation.

---

# (7) LONG-TERM DEBT

Long-term debt outstanding at December
31, is as follows:

|                                                 | 2002 | 2001
|------------------------------------------------ | ---- | ----
|
|First mortgage bonds:                            |      |     
|6.50% due 2002                                   |      |     
|9.00% due 2003                                   |      |     
|8.06% due 2010                                   |      |     
|9.49% due 2018                                   |      |     
|9.35% due 2021                                   |      |     
|8.30% due 2024                                   |      |     
|7.23% due 2032                                   |      |     
|                                                 |      |     
|                                                 |      |     
|                                                 |      |     
|Other long-term debt:                            |      |     
|Pollution control revenue bonds at 6.7% due 2010 |      |     
|Pollution control revenue bonds at 7.5% due 2024 |      |     
|GECC Financing at 3.41% due 2010 (a)(b)(c)       |      |     
|Other                                            |      |     
|                                                 |      |     
|                                                 |      |     
|                                                 |      |     
|Project financing floating rate debt (b):        |      |     
|Fountain Valley project at 3.3% (c) due 2006     |      |     
|Hudson Falls at 3.15% (c) due 2010               |      |     
|South Glens Falls at 3.15% (c) due 2009          |      |     
|Valmont and Arapahoe at 3.1% (c) due 2008        |      |     
|                                                 |      |     
|                                                 |      |     
|                                                 |      |     
|Total long-term debt                             |      |     
|Less current maturities                          |      |     
|                                                 |      |     
|Net long-term debt                               |      |     
|                                                 |      |     

_________________

|(a) |  | Floating
rate debt secured by a spare LM6000 turbine.
|--- |  | -----------------------------------------------------

|(b) |  | Approximately
58 percent of the December 31, 2002 balance has been hedged with                an
interest rate swap moving the floating rates to fixed rates with a weighted
               average interest rate of 5.98 percent (see Note 3-Risk Management
Activities).
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(c) |  | Interest
rates are presented as of December 31, 2002.
|--- |  | -----------------------------------------------------

Substantially all of the
Companys utility property is subject to the lien of the indenture securing its first
mortgage bonds. First mortgage bonds of the Company may be issued in amounts limited by
property, earnings and other provisions of the mortgage indentures.

Project financing debt is
non-recourse debt collateralized by a mortgage on each respective projects land and
facilities, leases and rights, including rights to receive payments under long-term
purchase power contracts.

Certain debt instruments of the
Company and its subsidiaries contain restrictive covenants, all of which the Company and
its subsidiaries were in compliance with at December 31, 2002. Some of the subsidiary debt
agreements provide that approximately $23.3 million of the subsidiarys cash balance
at December 31, 2002 may not be distributed to the parent company.

Scheduled maturities for the next
five years are: $22.1 million in 2003, $24.2 million in 2004, $25.6 million in 2005,
$138.1 million in 2006, and $125.3 million in 2007.

---

# (8)      NOTES PAYABLE

On August 26, 2002, the Company
closed a secured $50.0 million credit agreement. The credit agreement, as amended, has an
expiration date of May 26, 2003 and a variable interest rate. The credit agreement is
secured by the Companys 224 megawatt plant at the Las Vegas facility and has a
backstop guaranty provided by the Parent. The interest rate was 4.42 percent
at December 31, 2002.

In addition, the Company has an
unsecured line of credit with Black Hills Generation, a wholly-owned indirect subsidiary
of the Parent, which is due on demand; however, Black Hills Generation has agreed not to
demand payment until such time as outside financing is obtained. Borrowings under the note
bear interest at prime rate (4.25 percent at December 31, 2002) and interest is payable
monthly. Borrowings were $454.8 million and $447.2 million at December 31, 2002 and 2001,
respectively.

# (9)     FAIR VALUE OF
FINANCIAL INSTRUMENTS

The estimated fair values of the
Companys financial instruments at December 31, are as follows (in thousands):

|                          | 2002 | 2001
|------------------------- | ---- | ----
|
|Cash and cash equivalents |      |     
|Restricted cash           |      |     
|Derivative financial      |      |     
|instruments - liabilities |      |     
|Notes payable             |      |     
|Long-term debt            |      |     

The following methods and assumptions
were used to estimate the fair value of each class of the Companys financial
instruments.

# Cash and Cash
Equivalents and Restricted Cash

The carrying amount approximates fair
value due to the short maturity of these instruments.

# Derivative Financial
Instruments

These instruments are carried at fair
value. Descriptions of the various instruments the Company uses and the valuation method
employed are available in Note 3 of the Consolidated Financial Statements.

# Notes Payable

The carrying amount approximates fair
value due to their variable interest rates with short reset periods.

# Long-Term Debt

The fair value of the Companys
long-term debt is estimated based on quoted market rates for debt instruments having
similar maturities and similar debt ratings. The Companys outstanding bonds are
either currently not callable or are subject to make-whole provisions which would
eliminate any economic benefits for the Company to call and refinance the bonds.

---

# (10)     JOINTLY OWNED
FACILITY

The Company owns a 20 percent
interest and Pacific Power owns an 80 percent interest in the Wyodak Plant (Plant), a 330
megawatt coal-fired electric generating station located in Campbell County, Wyoming.
Pacific Power is the operator of the Plant. The Company receives 20 percent of the
Plants capacity and is committed to pay 20 percent of its additions, replacements
and operating and maintenance expenses. As of December 31, 2002, the Companys
investment in the Plant included $71.5 million in electric plant and $26.5 million in
accumulated depreciation, and is included in the corresponding captions in the
accompanying Consolidated Balance Sheets. The Companys share of direct expenses of
the Plant was $5.5 million, $5.9 million and $5.6 million for the years ended December 31,
2002, 2001 and 2000, respectively, and is included in the corresponding categories of
operating expenses in the accompanying Consolidated Statements of Income.

# (11)     COMMITMENTS AND
CONTINGENCIES

# Acquisition Earn-out Agreement

On July 7, 2000, the Company acquired
Indeck Capital, Inc. and merged it into its subsidiary, Black Hills Energy Capital, Inc.
The acquisition was a stock transaction resulting in a purchase price of $37.8 million.
Additional consideration may be paid in the form of an earn-out over a four-year period
beginning in 2000. As of December 31, 2001, $3.6 million has been paid under the earn-out.
On December 31, 2002, additional consideration of $3.8 million was earned and payable.
Additional consideration paid out under the earn-out is recorded as an increase to
goodwill. The earn-out consideration is based on the acquired companys earnings
during such period and cannot exceed $35.0 million in total.

# Power Agreement 
Pacific Power

In 1983, the Company entered into a
40 year power agreement with PacifiCorp providing for the purchase by the Company of 75
megawatts of electric capacity and energy from PacifiCorps system. An amended
agreement signed in October 1997 reduces the contract capacity by 25 megawatts (5
megawatts per year starting in 2000). The price paid for the capacity and energy is based
on the operating costs of one of PacifiCorps coal-fired electric generating plants.
Costs incurred under this agreement were $10.9 million in 2002, (net of a $1.3 million
refund for prior years) $13.9 million in 2001 and $14.6 million in 2000.

# Long Term Power Sales
Agreements

The Company, through its
subsidiaries, has the following significant long-term power sales contracts:

- The Company has long-term power sales contracts with the Public Service Company of
Colorado (PSCC) for the output of several of its plants. All of the output of the
Companys Fountain Valley, Arapahoe and Valmont gas-fired facilities, totaling 450
megawatts is included under the contracts which expire in 2012. The contracts are treated
as leases under generally accepted accounting principles and establish capacity and
availability payments over the lives of the contracts. The contracts are tolling
arrangements in which the Company assumes no fuel price risk.
- The Company has secured long-term contracts for the output of the 277 megawatt Las Vegas
facility. The 53 megawatt Las Vegas I power plant is contracted with Nevada Power through
2024. The 224 megawatt Las Vegas II power plant was completed at year end and is under a
tolling arrangement with Allegheny Energy Supply that expires in 2017.
- Various long-term contracts with Niagara Mohawk Power Corporation have been entered into
to sell the output of several of the Companys hydroelectric projects located in
upstate New York. The Companys net ownership of capacity under contract is
approximately 21 megawatts with contracts expiring between 2029 and 2035. There are
additional contracts on plants with a net ownership capacity of approximately 21 megawatts
that expire during 2003.
- The Company has entered into a 5 year tolling agreement with Southern California Edison
for 100 megawatts of capacity and power from the Companys gas-fired Harbor
Cogeneration plant. The agreement is seasonal and runs from June through October of each
year. The agreement expires in 2007.

---

- The Company has a ten year power sales contract with the Municipal Energy Agency of
Nebraska for 20 megawatts of contingent capacity from the Neil Simpson Unit #2 plant.

# Ongoing Litigation

Hell Canyon Fire

In September 2001 a fire occurred in
the southwestern Black Hills. It is alleged that the fire occurred when a high voltage
electrical span broke and electrical arcing from the severed line ignited dry grass. The
fire burned approximately 10,000 acres of land owned by the Black Hills National Forest,
the Oglala Sioux Tribe and other private landowners. The State of South Dakota initiated
litigation against the Company in the Seventh Judicial Circuit Court, Fall River County,
South Dakota, on or about January 31, 2003. The complaint seeks recovery of damages for
alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble
damages is asserted with respect to the claim for injury to timber. It is expected that
substantially similar claims will be asserted against the Company by the United States
Forest Service. The Companys investigation into the cause and origin of the fire is
still pending. The total amount of damages claimed by the State of South Dakota is not
specified in the complaint. The Company has denied all claims and will vigorously defend
this matter, the timing or outcome of which is uncertain.

Grizzly Gulch Fire

On June 29, 2002, a forest fire began
near Deadwood, South Dakota. Before being contained more than eight days later, the fire
consumed approximately 11,000 acres of public and private land, mostly consisting of
rugged forested areas. The fire destroyed approximately 20 structures. There were no
reported personal injuries. In addition, the fire burned to the edge of the City of
Deadwood, forcing the evacuation of the City of Deadwood and the adjacent City of Lead,
South Dakota. These communities are active in the tourist and gaming industries.
Individuals were ordered to leave their homes and businesses were closed for a short
period of time. On July 16, 2002, the State of South Dakota announced the results of its
investigation of the cause and origin of the fire. The State asserted that the fire was
caused by tree encroachment into and contact with a transmission line owned and maintained
by the Company.

On September 6, 2002, the State of
South Dakota commenced litigation against the Company, in the Seventh Judicial Circuit
Court, Pennington County, South Dakota. The complaint seeks recovery of damages for
alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble
damages is asserted with respect to the claim for injury to timber. The total amount of
alleged damages is not specified.

On March 3, 2003 the United States of
America filed a similar suit against the Company, in the United States District Court,
District of South Dakota, Western Division. The federal government complaint likewise
seeks recovery of damages for alleged injury to timber, fire suppression and
rehabilitation costs. A similar claim for treble damages is asserted with respect to the
claim for injury to timber. The total amount of alleged federal damages is not specified.

The Company is completing its own
investigation of the fire cause and origin and has requested access to the materials that
form the basis for the assertions of state and federal fire investigators. The
Companys investigation is not complete, but based on information currently
available, the Company expects to deny all claims and vigorously defend any and all claims
brought by governmental or private parties.

Although we cannot predict the
outcome of our investigation or the viability of potential claims based on information
currently available, management believes that any such claims, if determined adversely to
us, will not have a material adverse effect on our financial condition or results of
operations.

---

# Federal Energy
Regulatory Commission (FERC) Investigation

In August 2001, the Company purchased
a partnership interest in the 53 megawatt Las Vegas Cogeneration Facility from an
affiliate of Enron. The partnership is called Las Vegas Cogeneration, L.P. The prior owner
certified to us and to relevant governmental authorities that the facility complied with
all regulations necessary to obtain and maintain qualifying facility status
under Public Utility Regulatory Policies Act of 1978 (PURPA). Qualifying facilities are
allowed to sell their output to electric utilities at avoided cost rates,
which are usually higher than prevailing market-based rates. The prior owner contracted
with Nevada Power Company to sell 45 megawatts of the facilitys output during the
periods of peak electricity consumption at avoided cost rates. In connection with
acquiring the facility, we assumed this contract.

Recently FERC issued an order
announcing an investigation to determine whether Enrons ownership of the Las Vegas
Cogeneration Facility violated the qualifying facility regulations under PURPA. In
addition, the SEC recently issued an initial decision concluding that Enron is an electric
utility and is thus not exempt from regulations under the Public Utility Holding Company
Act of 1935 (PUHCA), that, among other things, prohibit electric utilities from owning
more than 50 percent of a qualifying facility. Enron is appealing this decision.

The FERC investigation does not
relate to the 224 megawatt gas-fired facility owned and operated by Las Vegas Cogeneration
II, LLC and located on the same site in North Las Vegas, Nevada. This facility is not now,
and never was certified as a qualifying facility under PURPA.

If FERC determines that Enron
violated the qualifying facility rules with respect to the Las Vegas Cogeneration
Facility, the Company, as a partner in the entity that now owns that facility, could be
liable for any refunds, fines or other penalties FERC imposes. The Company could also be
subject to additional liabilities resulting from third party claims. The Company has the
right to seek indemnification from the prior owner. While the prior owner does not appear
among the Enron subsidiaries and affiliates currently in bankruptcy, the Enron bankruptcy
could impair the Companys ability to enforce a claim for indemnification. Because
FERC has only recently begun its investigation, the Company cannot predict the outcome of
FERCs investigation. However, based upon information currently available, management
does not believe that any refunds, fines or penalties resulting from the investigation
will have a material affect on the Companys financial condition or results of
operations.

Other Proceedings

In addition to the above proceedings,
the Company and its subsidiaries are involved in numerous legal proceedings, claims and
litigation in the ordinary course of business. In the opinion of management, the amount of
liability, if any, with respect to these actions would not materially affect the
consolidated financial position or results of operations of the Company.

There are currently no pending
material legal proceedings to which an officer or director is a party or has a material
interest, that is adverse to us or our subsidiaries. There are also 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.

# (12)     EMPLOYEE BENEFIT
PLANS

# Defined Benefit Pension
Plan

The Company has a noncontributory
defined benefit pension plan (Plan) covering employees who meet certain eligibility
requirements. The benefits are based on years of service and compensation levels during
the highest five consecutive years of the last ten years of service. The Companys
funding policy is in accordance with the federal governments funding requirements.
The Plans assets are held in trust and consist primarily of equity securities and
cash equivalents.

---

Net pension income for the Plan was
as follows:

|                                            | 2002 | 2001 | 2000
|------------------------------------------- | ---- | ---- | ----
|
|Service cost                                |      |      | $   
|Interest cost                               |      |      |     
|Expected return on assets                   |      |      |     
|Amortization of transition amount           |      |      |     
|Amortization of prior service cost          |      |      |     
|Recognized net actuarial loss (gain)        |      |      |     
|                                            |      |      |     
|Net pension income                          |      |      | $   
|                                            |      |      |     
|Actuarial assumptions:                      |      |     
|Used for net periodic pension cost          |      |      |     
|Used to value pension (liability)/asset at  |      |     
|year-end                                    |      |      |     
|Expected long-term rate of return on assets |      |      |     
|Rate of increase in compensation levels     |      |      |     

_________________

| | *The
discount rate used for net periodic pension cost was changed from 7.50 percent in 2002 to
6.75 percent for the calculation of the 2003 Net Periodic Pension cost. This change is
expected to increase pension costs by approximately $0.3 million.
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | **The
expected rate of return on plan assets was changed from 10.5 percent to 10 percent for
the calculation of the 2003 Net Periodic Pension Cost. This change is expected to
increase pension costs in 2003 by approximately $0.1 million.
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | ***The
rate of increase in compensation levels changed in 2001 from a single rate assumption for
all ages to an age- based salary scale assumption resulting in a weighted average
increase of 5.0 percent.
| | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

A reconciliation of the beginning and
ending balances of the projected benefit obligation is as follows (in thousands):

|                                       | 2002 |  | 2001 |       
|-------------------------------------- | ---- |  | ---- | ------
|
|Beginning projected benefit obligation |      |  | $    | 33,151
|Service cost                           |      |  |      | 588   
|Interest cost                          |      |  |      | 2,406 
|Actuarial losses                       |      |  |      | 571   
|Discount rate change                   |      |  |      | 3,380 
|Benefits paid                          |      |  |      | (1,955
|Business divestiture                   |      |  |      | --    
|                                       |      |  |      |       
|Net increase (decrease)                |      |  |      | 4,990 
|                                       |      |  |      |       
|Ending projected benefit obligation    |      |  | $    | 38,141
|                                       |      |  |      |       

A reconciliation of the fair value of Plan
assets as of October 1 of each year is as follows (in thousands):

|                                      | 2002 |  | 2001 |       
|------------------------------------- | ---- |  | ---- | ------
|
|Beginning market value of plan assets |      |  | $    | 32,938
|Benefits paid                         |      |  |      | (1,955
|Investment loss                       |      |  |      | (5,153
|Asset transfer                        |      |  |      | --    
|                                      |      |  |      |       
|Ending market value of plan assets    |      |  | $    | 25,830
|                                      |      |  |      |       

---

Funding information for the Plan as
of October 1 each year was as follows (in thousands):

|                                   | 2002 |  | 2001 |        
|---------------------------------- | ---- |  | ---- | -------
|
|Fair value of plan assets          |      |  | $    | 25,830 
|Projected benefit obligation       |      |  |      | (38,141
|                                   |      |  |      |        
|Funded status                      |      |  |      | (12,311
|                                   |      | 
|Unrecognized:                      |      | 
|Net loss                           |      |  |      | 17,075 
|Prior service cost                 |      |  |      | 1,253  
|                                   |      |  |      |        
|Net amount recognized              |      |  | $    | 6,017  
|                                   |      |  |      |        
|                                   |      | 
|Amounts recognized in statement of |      | 
|financial position consist of:     |      | 
|Accrued pension (liability) asset  |      |  | $    | (6,370 
|Intangible asset                   |      |  |      | 1,326  
|Accumulated other comprehensive    |      | 
|loss                               |      |  |      | 11,061 
|                                   |      |  |      |        
|Net amount recognized              |      |  | $    | 6,017  
|                                   |      |  |      |        
|Accumulated benefit obligation     |      |  | $    | 32,254 
|                                   |      |  |      |        

The provisions of Statement of
Financial Accounting Standards No. 87 "Employers' Accounting for Pensions" (SFAS 87)
requires the Company to record an accrued pension liability of $6.4 million at December
31, 2002, and is included in Accrued liabilities on the accompanying Consolidated Balance
Sheet.  This liability represents the amount by which the accumulated benefit obligation
exceeds the sum of the fair market value of plan assets and accrued amounts previously
recorded.  The additional liability may be offset by an intangible asset to the extent of
previously unrecognized prior service cost, therefore an intangible asset of $1.3 million
at December 31, 2002 is included in the line item Other in Other Assets on the
accompanying Consolidated Balance Sheet.  The remaining amount of $11.1 million is
recorded as a component of stockholder's equity, net of related tax benefits of $4.0
million, in the line item Accumulated other comprehensive loss on the accompanying
Consolidated Balance Sheet at December 31, 2002.

# Supplemental Nonqualified Defined Benefit Retirement Plan

The Company has various supplemental
retirement plans for outside directors and key executives of the Company.  The plans are
nonqualified defined benefit plans.  Expenses recognized under the plans were $0.2
million in 2002 and $0.4 million in 2001 and 2000, respectively.

The following table summarizes the
projected benefit obligation and accumulated benefit obligation of the unfunded plan at
December 31, 2002 (in thousands):

|                               | 2002 |  | 2001 |      
|------------------------------ | ---- |  | ---- | -----
|
|Accumulated benefit obligation |      |  | $    | 1,445
|Projected benefit obligation   |      |  | $    | 1,676

The provisions of SFAS 87 required
the Company to record an additional minimum liability of $0.4 million at December 31,
2002. This amount is included in Accrued liabilities on the accompanying Consolidated
Balance Sheet. This liability represents the amount by which the accumulated benefit
obligation exceeds the sum of the fair market value of plan assets and accrued amounts
previously recorded. The amount of $0.4 million is recorded as a component of
stockholders equity, net of related tax benefits of $0.1 million, in the line item
Accumulated other comprehensive loss on the accompanying Consolidated Balance Sheet at
December 31, 2002.

---

# Non-pension Defined
Benefit Postretirement Plan

Employees who are participants in the
Plan and who retire from the Company on or after attaining age 55 after completing at
least five years of service to the Company are entitled to postretirement healthcare
benefits. These benefits are subject to premiums, deductibles, co-payment provisions and
other limitations. The Company may amend or change the Plan periodically. The Company is
not pre-funding its retiree medical plan.

The net periodic postretirement cost
was as follows (in thousands):

|                                      | 2002 |  | 2001 |     | 2000 |  
|------------------------------------- | ---- |  | ---- | --- | ---- | -
|
|Service cost                          |      |  | $    | 160 |      | $
|Interest cost                         |      |  |      | 402 |      |  
|Amortization of transition obligation |      |  |      | 117 |      |  
|Amortization of prior service cost    |      |  |      | (19 | )    |  
|Loss                                  |      |  |      | 34  |      |  
|                                      |      |  |      |     |      |  
|                                      |      |  | $    | 694 |      | $
|                                      |      |  |      |     |      |  

Funding information as of October 1
was as follows (in thousands):

|                                                       | 2002 |  | 2001 |       
|------------------------------------------------------ | ---- |  | ---- | ------
|
|Accumulated postretirement benefit obligation:         |      |  |      |       
|Retirees                                               |      |  | $    | 2,937 
|Fully eligible active participants                     |      |  |      | 1,472 
|Other active participants                              |      |  |      | 2,138 
|                                                       |      |  |      |       
|Unfunded accumulated postretirement benefit obligation |      |  |      | 6,547 
|Unrecognized net loss                                  |      |  |      | (1,830
|Unrecognized prior service cost                        |      |  |      | 265   
|Unrecognized transition obligation                     |      |  |      | (1,167
|Contributions                                          |      |  |      | (51   
|                                                       |      |  |      |       
|Accrued postretirement cost                            |      |  | $    | 3,764 
|                                                       |      |  |      |       

For measurement purposes, a 12.0
percent annual rate of increase in healthcare benefits was assumed for 2002; the rate was
assumed to decrease gradually to 5 percent in 2009 and remain at that level thereafter.
The healthcare cost trend rate assumption has a significant effect on the amounts
reported. A one percent increase in the healthcare cost trend assumption would increase
the service and interest cost $0.1 million or 19.5 percent and the net periodic
postretirement cost $1.1 million or 17.0 percent. A one percent decrease would reduce the
service and interest cost by $0.1 million or 16.0 percent and decrease the net periodic
postretirement cost $0.9 million or 13.6 percent. The weighted-average discount rate used
in determining the accumulated postretirement benefit obligation was 6.75 percent for 2002
and 7.5 percent for 2001.

# Defined Contribution Plan

The Company also sponsors a 401(k)
savings plan for eligible employees. Participants elect to invest up to 20 percent of
their eligible compensation on a pre-tax basis. Effective January 1, 2000 (May 1, 2000 for
employees covered by the collective bargaining agreement), the Company provides a matching
contribution of 100 percent of the employees tax-deferred contribution up to a
maximum 3 percent of the employees eligible compensation. Matching contributions
vest at 20 percent per year and are fully vested when the participant has 5 years of
service with the Company. The Companys matching contributions totaled $0.4 million
for 2002, $0.6 million for 2001 and $0.3 million for 2000.

---

# (13)     OTHER COMPREHENSIVE
LOSS

The following tables display the
related tax effects allocated to each component of Other Comprehensive Loss for the years
ended December 31, (in thousands):

|                                                                | 2002
|--------------------------------------------------------------- | ----
|
|
|Net change in fair value of derivatives designated as cash flow |     
|hedges (net of minority interest share of $(164))               |     
|Minimum pension liability adjustment                            |     
|                                                                |     
|Other comprehensive loss                                        |     
|                                                                |     

|                                                                | 2001
|--------------------------------------------------------------- | ----
|
|
|
|Net change in fair value of derivatives designated as cash flow |     
|hedges (net of minority interest share of $2,875)               |     
|                                                                |     

Items of other comprehensive income
(loss) were not significant in 2000.

---

# (14)     INCOME TAXES

Income tax expense (benefit) for the
years ended December 31 was (in thousands):

|         | 2002 |  | 2001 |        | 2000 |  
|-------- | ---- |  | ---- | ------ | ---- | -
|
|Current  |      |  | $    | (1,318 | )    | $
|Deferred |      |  |      | 22,993 |      |  
|         |      |  |      |        |      |  
|         |      |  | $    | 21,675 |      | $
|         |      |  |      |        |      |  

The temporary differences which gave rise
to the net deferred tax liability were as follows (in thousands):

|2002                                                         |  | 2001
|------------------------------------------------------------ |  | ----
|
|Deferred tax assets, current:                                |  |     
|Valuation reserve                                            |  |     
|Employee benefits                                            |  |     
|Items of other comprehensive income                          |  |     
|Other                                                        |  |     
|                                                             |  |     
|                                                             |  |     
|                                                             |  |     
|Deferred tax liabilities, current:                           |  |     
|Employee benefits                                            |  |     
|State income tax                                             |  |     
|Items of other comprehensive income                          |  |     
|Other                                                        |  |     
|                                                             |  |     
|                                                             |  |     
|                                                             |  |     
|Net deferred tax asset, current                              |  |     
|                                                             |  |     
|Deferred tax assets, non-current:                            |  |     
|Accelerated depreciation and other plant related differences |  |     
|Regulatory asset                                             |  |     
|ITC                                                          |  |     
|Items of other comprehensive income                          |  |     
|Net operating loss carryforward                              |  |     
|Other                                                        |  |     
|                                                             |  |     
|                                                             |  |     
|                                                             |  |     
|Deferred tax liabilities, non-current:                       |  |     
|Accelerated depreciation and other plant related differences |  |     
|AFUDC                                                        |  |     
|Regulatory liability                                         |  |     
|Other                                                        |  |     
|                                                             |  |     
|                                                             |  |     
|                                                             |  |     
|Net deferred tax liability, non-current                      |  |     
|                                                             |  |     
|Net deferred tax liability                                   |  |     
|                                                             |  |     

---

The following table reconciles the
change in the net deferred income tax liability from December 31, 2001, to December 31,
2002, to deferred income tax expense:

|                                                                                             | 2002 | 
|-------------------------------------------------------------------------------------------- | ---- | 
|
|Net change in deferred income tax liability from the preceding table                         |      | 
|Deferred taxes associated with 2001 Federal Income Tax Return True-up related to accelerated |      | 
|depreciation and other plant-related differences                                             |      | 
|Deferred taxes associated with other comprehensive loss                                      |      | 
|Other                                                                                        |      | 
|                                                                                             |      | 
|                                                                                             |     
|Deferred income tax expense for the period                                                   |      | 
|                                                                                             |      | 

The effective tax rate differs from
the federal statutory rate for the years ended December 31, as follows:

|                                                           | 2002 |  | 2001 |      | 2000 | 
|---------------------------------------------------------- | ---- |  | ---- | ---- | ---- | 
|
|Federal statutory rate                                     |      |  |      | 35.0 | %    | 
|Amortization of excess deferred and investment tax credits |      |  |      | (1.0 | )    | 
|Research and development credit                            |      |  |      | (1.8 | )    | 
|Other                                                      |      |  |      | 2.8  |      | 
|                                                           |      |  |      |      |      | 
|                                                           |      |  |      | 35.0 | %    | 
|                                                           |      |  |      |      |      | 

At December 31, 2002, the Company had
net operating loss carryforwards of $2.8 million which expire in the year 2020 and $1.1
million which expire in the year 2022.

# (15) BUSINESS SEGMENTS

The Companys reportable
segments are those that are based on the Companys method of internal reporting,
which generally segregates the strategic business groups due to differences in products,
services and regulation. As of December 31, 2002, substantially all of the Companys
operations and assets are located within the United States. The Companys operations
are conducted through two business groups: Electric, which supplies electric utility
service to western South Dakota, northeastern Wyoming and southeastern Montana; and
Independent Power, which produces and sells power and capacity to wholesale customers.

|2002                       |  | 2001 |  
|-------------------------- |  | ---- | -
|
|Total assets               |  |      |  
|Electric utility           |  |      | $
|Independent power          |  |      |  
|                           |  |      |  
|Total assets               |  |      | $
|                           |  |      |  
|Capital expenditures       |  |     
|Electric utility           |  |      | $
|Independent power          |  |      |  
|                           |  |      |  
|Total capital expenditures |  |      | $
|                           |  |      |  

---

|                                         | 2002 |  | 2001 |         | 2000 |  
|---------------------------------------- | ---- |  | ---- | ------- | ---- | -
|
|Operating revenues                       |      |  |      |         |      |  
|Electric utility                         |      |  | $    | 162,186 |      | $
|Independent power                        |      |  |      | 125,267 |      |  
|                                         |      |  |      |         |      |  
|Total operating revenues                 |      |  | $    | 287,453 |      | $
|                                         |      |  |      |         |      |  
|                                         |      |  |     
|Depreciation and amortization            |      | 
|Electric utility                         |      |  | $    | 17,499  |      | $
|Independent power                        |      |  |      | 26,434  |      |  
|                                         |      |  |      |         |      |  
|Total depreciation and amortization      |      |  | $    | 43,933  |      | $
|                                         |      |  |      |         |      |  
|                                         |      |  |     
|Operating income                         |      | 
|Electric utility                         |      |  | $    | 58,160  |      | $
|Independent power                        |      |  |      | 51,978  |      |  
|                                         |      |  |      |         |      |  
|Total operating income                   |      |  | $    | 110,138 |      | $
|                                         |      |  |      |         |      |  
|                                         |      |  |     
|Interest expense                         |      | 
|Electric utility                         |      |  | $    | 13,663  |      | $
|Independent power                        |      |  |      | 34,202  |      |  
|                                         |      |  |      |         |      |  
|Total interest expense                   |      |  | $    | 47,865  |      | $
|                                         |      |  |      |         |      |  
|Interest income                          |      | 
|Electric utility                         |      |  | $    | 734     |      | $
|Independent power                        |      |  |      | 91      |      |  
|                                         |      |  |      |         |      |  
|Total interest income                    |      |  | $    | 825     |      | $
|                                         |      |  |      |         |      |  
|Income taxes                             |      | 
|Electric utility                         |      |  | $    | 15,067  |      | $
|Independent power                        |      |  |      | 6,608   |      |  
|                                         |      |  |      |         |      |  
|Total income taxes                       |      |  | $    | 21,675  |      | $
|                                         |      |  |      |         |      |  
|                                         |      |  |     
|Income (loss) from continuing operations |      | 
|Electric utility                         |      |  | $    | 30,217  |      | $
|Independent power                        |      |  |      | 10,066  |      |  
|                                         |      |  |      |         |      |  
|Total income from continuing operations  |      |  | $    | 40,283  |      | $
|                                         |      |  |      |         |      |  

---

# (16)     
ACQUISITIONS

On March 15, 2002, BHEC paid $25.7
million to acquire an additional 30 percent interest in the Harbor Cogeneration Facility
(Harbor), a 98 megawatt gas-fired plant located in Wilmington, California. In addition,
during the fourth quarter of 2002, the Company paid $13.8 million to acquire the remaining
ownership interest in Harbor and the Pepperell Facility (Pepperell), a 40 megawatt
gas-fired plant located in Pepperell, Massachusetts. These transactions give the Company a
100 percent ownership interest in Harbor and Pepperell and were funded by borrowings from
affiliates.

The Companys investment in the
above entity prior to the above acquisition was accounted for under the equity method of
accounting and was included in Investments on the accompanying Consolidated Balance
Sheets. The above acquisition gave the Company majority ownership and voting control,
therefore, after acquisition the Company has consolidated the entity in its consolidated
financial statements.

The above acquisition has been
accounted for under the purchase method of accounting and, accordingly, the purchase price
has been allocated to the acquired assets and liabilities based on preliminary estimates
of the fair values of the assets purchased and the liabilities assumed as of the date of
acquisition. The estimated purchase price allocations are subject to adjustment, generally
within one year of the date of acquisition. The purchase price and related acquisition
cost exceeded the fair value assigned to net intangible assets by approximately $9.3
million, and was recorded as long-lived intangible assets.

The impact of these acquisitions was
not material in relation to the Companys results of operations. Consequently, pro
forma information is not presented.

On August 31, 2001, BHEC purchased a
277 megawatt gas-fired co-generation power plant project located in North Las Vegas,
Nevada from Enron North America, a wholly owned subsidiary of Enron Corporation. At
acquisition, the facility had a 53 megawatt co-generation power plant in operation, of
which the Company owns 50 percent. Most of the power from that facility is under a
long-term contract expiring in 2024. Although the Company only owns 50 percent of this
plant, under generally accepted accounting principles the Company is required to
consolidate 100 percent of this plant. The project also has a 224 megawatt combined-cycle
expansion under construction of which the Company owns 100 percent. The facility became
fully operational in January 2003 and utilizes LM-6000 technology. The power to be
generated by the expansion project is also under a long-term sales contract that expires
in 2017. This contract for the expansion requires the purchaser to provide fuel to the
power plant when it is dispatched. Total cost for the entire facility is expected to be
approximately $325 million of which $314 million was expended as of December 31, 2002.

The acquisition has been accounted
for under the purchase method of accounting and, accordingly, the purchase price of
approximately $205 million has been allocated to the acquired assets and liabilities based
on preliminary estimates of the fair values of the assets purchased and the liabilities
assumed as of the date of acquisition. Fair values in the allocation include assets
acquired of approximately $150 million (excluding goodwill and other intangibles) and
liabilities assumed of approximately $2 million. The purchase price and related
acquisition costs exceeded the fair values assigned to net tangible assets by
approximately $42 million, which was recorded as long-lived intangible assets and
goodwill.

On April 11, 2001, BHEC purchased the
Fountain Valley facility, a 240 megawatt generation facility located near Colorado
Springs, Colorado, featuring six LM-6000 simple-cycle, gas-fired turbines. The facility
came on-line mid third quarter of 2001. The facility was purchased from Enron Corporation.
Total cost of the project was approximately $183 million and has been financed primarily
with non-recourse project debt. The Company has obtained an 11-year contract with Public
Service Company of Colorado to utilize the facility for peaking purposes. The contract is
a tolling arrangement in which the Company assumes no fuel price risk. The transaction has
been accounted for as an asset purchase recorded at cost.

In addition, during 2001, BHEC
acquired an additional 31 percent interest and a 13 percent interest in its consolidated
majority-owned subsidiaries, Black Hills North American Power Fund, L.P. and Indeck North
American Power Partners, L.P., respectively, from minority shareholders. Total
consideration paid was $15.9 million.

Pro forma financial amounts
reflecting the effects of the above acquisitions are not presented as such acquisitions
were not significant to the Companys results of operations.

---

# (17)     QUARTERLY
HISTORICAL DATA (Unaudited)

The Company operates on a calendar
year basis. The following table sets forth selected unaudited historical operating results
data for each quarter of 2002 and 2001.

|                                  | First
Quarter | Second
Quarter | Third
Quarter | Fourth
Quarter
|--------------------------------- | ------------- | -------------- | ------------- | --------------
|
|2002:                             |               |                |               |               
|Operating revenues                |               |                | $             | 66,671        
|Operating income                  |               |                |               | 28,926        
|Income from continuing operations |               |                |               | 11,088        
|Net income                        |               |                |               | 11,984        
|                                  |               |                |               |               
|2001:                             |               |               
|Operating revenues                |               |                | $             | 85,684        
|Operating income                  |               |                |               | 34,230        
|Income from continuing operations |               |                |               | 16,249        
|Net income                        |               |                |               | 21,081        

# (18)     SUBSEQUENT EVENT

On February 26, 2003, the
Companys parent filed an application with the Federal Energy Regulatory Commission
(FERC) asking for authorization to implement a corporate restructuring. This application
was approved by FERC. To effect this corporate restructuring, the Company declared a
non-cash dividend, consisting of all the Companys stock in its wholly-owned
subsidiary, Black Hills Energy Capital. This dividend will be paid to the Parent on March
31, 2003. With the completion of this restructuring, the Companys business will
consist solely of the electric utility operations.

# ITEM 9.     CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE

In May 2002, Black Hills Power, Inc.
announced that the Board of Directors, upon recommendation of its Audit Committee, ended
the engagement of Arthur Andersen LLP as the Companys independent public accountants
and in June 2002 engaged Deloitte & Touche LLP to serve as the Companys
independent auditors for the fiscal year ended December 31, 2002.

For more information, see the
Companys Current Report on Form 8-K filed with the Securities and Exchange
Commission on May 24, 2002.

In November 2002, Deloitte &
Touche LLP completed re-audits of the Companys 2000 and 2001 consolidated financial
statements, which were previously audited by Arthur Andersen LLP.

# PART III

# ITEM 14.     CONTROLS AND
PROCEDURES

Evaluation of disclosure controls and
procedures

Within 90 days prior to the filing
date of the Form 10-K, our chief executive officer and chief financial officer evaluated
the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-14(c)
and 15d-14(c) of the Securities Exchange Act of 1934 (Exchange Act). Based on their
evaluation, they have concluded that our disclosure controls and procedures are adequate
and effective to ensure that material information relating to us that is included in our
reports filed under the Exchange Act is recorded, processed, summarized and reported
within the required time periods.

---

Changes in internal controls

Our chief executive officer and chief
financial officer have concluded that there were no significant changes in our internal
controls or in other factors that could significantly affect these controls subsequent to
the date of their most recent evaluation of such controls, and that there were no
significant deficiencies or material weaknesses in our internal controls.

# PART IV

# ITEM 15.      EXHIBITS,
FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)     1.           Consolidated
Financial Statements

| | Financial
statements required by Item 15 are listed in the index included in Item 8 of Part II.
| | -----------------------------------------------------------------------------------------------

2.           Schedules

| | Schedule
II  Consolidated Valuation and Qualifying Accounts for the years ended December 31,
2002, 2001 and 2000.
| | ------------------------------------------------------------------------------------------------------------------

| | All
other schedules have been omitted because of the absence of the conditions under which
they are required or because the required information is included elsewhere in the
financial statements incorporated by reference in the Form 10-K.
| | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

BLACK HILLS POWER, INC.SCHEDULE
II  CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTSYEARS
ENDED DECEMBER 31, 2002, 2001 AND 2000

Additions

|Balance at
beginning of year | Charged to costs
and expenses | Deductions | Balance at
end of year
|---------------------------- | ----------------------------- | ---------- | ----------------------
|
|
|
|                             |                               |            |                       
|2002                         |                               |            | $                     
|2001                         |                               |            |                       
|2000                         |                               |            |                       

3.           Exhibits

|ExhibitNumber |  | Description
|------------- |  | -----------

| | 2* |  | Plan
of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as
                           an exhibit to the Black Hills Holding Corporation's
Registration Statement on Form S-4 (No. 333-52664)).
| | -- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.1* |  | Restated
Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form
8-K                            dated June 7, 1994 (No. 1-7978)).
| | ---- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.2* |  | Articles
of Amendment to the Articles of Incorporation of the Registrant, as filed with the
Secretary of                            State of the State of South Dakota on December
22, 2000 (filed as an exhibit to the Registrant's Form 10-K
                           for 2000).
| | ---- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.3* |  | Bylaws
of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form
S-8 dated                            July 13, 1999).
| | ---- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------

---

| | 4.1* |  | Restated
and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now
called Black                            Hills Power, Inc.) dated as of September 1, 1999
(filed as an exhibit to Black Hills Holding Corporation's
                           Registration Statement on Form S-4 (No. 333-52664)).  First
Supplemental Indenture, dated as of August 13,                            2002, between
Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.1 to the
                           Registrant's Form 10-Q for the quarter ended September 30,
2002).
| | ---- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.1* |  | Agreement
for Transmission Service and the Common Use of Transmission Systems dated January 1,
1986, among                            Black Hills Power, Inc., Basin Electric Power
Cooperative, Rushmore Electric Power Cooperative, Inc.,
                           Tri-County Electric Association, Inc., Black Hills Electric
Cooperative, Inc. and Butte Electric                            Cooperative, Inc. (filed
as Exhibit 10(d) to the Registrant's Form 10-K for 1987).
| | ----- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.2* |  | Restated
and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit
10(c) to the                            Registrant's Form 10-K for 1992).
| | ----- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.3* |  | Second
Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp
and Black                            Hills Power, Inc. (filed as Exhibit 10(e) to the
Registrant's Form 10-K for 1997).
| | ----- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.4* |  | Reserve
Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light
Company and Black                            Hills Power, Inc. (filed as Exhibit 10(u) to
the Registrant's Form 10-K for 1987).
| | ----- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.5* |  | Rate
Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999).
| | ----- |  | --------------------------------------------------------------------------------------

| | 10.6* |  | Purchase
and Sale Agreement by and between TLS Investors, LLC and Black Hills Energy Capital, Inc.
dated                            June 18, 2001 to purchase Southwest Power, LLC.
| | ----- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 99.1 |  | Certification
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley                            Act of 2002.
| | ---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------

| | 99.2 |  | Certification
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley                            Act of 2002.
| | ---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------

_________________

| | * |  | Previously
filed as part of the filing indicated and incorporated by reference herein.
| | - |  | --------------------------------------------------------------------------------------

| | + |  | Indicates
a board of director or management compensatory plan.
| | - |  | --------------------------------------------------------------

| | (b) |  | Reports
on Form 8-K
| | --- |  | -------------------

| |  |  | The Registrant
has not filed any reports on Form 8-K during the last quarter of the period covered by
this report.
| |  |  | ------------------------------------------------------------------------------------------------------------------

| | (c) |  | See
(a) 3. Exhibits above.
| | --- |  | --------------------------

| | (d) |  | See
(a) 2. Schedules above.
| | --- |  | ---------------------------

SUPPLEMENTAL INFORMATION TO BE
FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH
HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

The Registrant is not required to
send an Annual Report or Proxy to its sole security holder and parent company, Black
Hills Corporation.

---

# 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 POWER, INC.
| | -----------------------

| |  |  |  |  |  |  | By: /S/ DANIEL P. LANDGUTH
Daniel P. Landguth, Chairman
  and Chief Executive Officer
| |  |  |  |  |  |  | -------------------------------------------------------------------------------------

Dated: March 31, 2003

Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the Registrant and in the capacities and on
the dates indicated.

`/s/ DANIEL P. LANDGUTH                                       Director and Principal                      March 31, 2003
Daniel P. Landguth, Chairman,                                   Executive Officer
 and Chief Executive Officer

  /s/ MARK T. THIES                                            Principal Financial Officer                 March 31, 2003
Mark T. Thies, Senior Vice President and
 Chief Financial Officer

  /s/ ROXANN R. BASHAM                                         Principal Accounting Officer                March 31, 2003
Roxann R. Basham, Vice President-Controller,
 and Assistant Secretary

  /s/ BRUCE B. BRUNDAGE                                        Director                                    March 31, 2003
Bruce B. Brundage

  /s/ DAVID C. EBERTZ                                          Director                                    March 31, 2003
David C. Ebertz

  /s/ JOHN R. HOWARD                                          Director                                    March 31, 2003
John R. Howard

  /s/ EVERETT E. HOYT                                         Director and Officer                        March 31, 2003
Everett E. Hoyt, President and Chief
Operating Officer

  /s/ KAY S. JORGENSEN                                        Director                                    March 31, 2003
Kay S. Jorgensen

  /s/ DAVID S. MANEY                                          Director                                    March 31, 2003
David S. Maney

  /s/ THOMAS J. ZELLER                                        Director                                    March 31, 2003
Thomas J. Zeller`

---

# CERTIFICATION

I, Daniel P. Landguth, certify that:

|1. |  | I have reviewed this annual report on Form 10-K of Black Hills Power, Inc.;
|-- |  | ---------------------------------------------------------------------------

|2. |  | Based on my knowledge, this annual report does not contain any untrue statement
               of a material fact or omit to state a material fact necessary to make the
               statements made, in light of the circumstances under which such statements were
               made, not misleading with respect to the period covered by this annual report;
|-- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|3. |  | Based on my knowledge, the financial statements, and other financial information
               included in this annual report, fairly present in all material respects the
               financial condition, results of operations and cash flows of the registrant as
               of, and for, the periods presented in this annual report;
|-- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|4. |  | The registrants other certifying officers and I are responsible for
               establishing and maintaining disclosure controls and procedures (as defined in
               Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
|-- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | a) |  | designed
such disclosure controls and procedures to ensure that material
               information relating to the registrant, including its consolidated
subsidiaries,                is made known to us by others within those entities,
particularly during the                period in which this annual report is being
prepared;
| |  |  | -- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | b) |  | evaluated
the effectiveness of the registrants disclosure controls and
               procedures as of a date within 90 days prior to the filing date of this
annual                report (the Evaluation Date); and
| |  |  | -- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | c) |  | presented
in this annual report our conclusions about the effectiveness of the
               disclosure controls and procedures based on our evaluation as of the
Evaluation                Date;
| |  |  | -- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|5. |  | The registrants other certifying officers and I have disclosed, based on
               our most recent evaluation, to the registrants auditors and the audit
               committee of registrants board of directors (or persons performing the
               equivalent functions):
|-- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | a) |  | all
significant deficiencies in the design or operation of internal controls
               which could adversely affect the registrants ability to record,
process,                summarize and report financial data and have identified for the
               registrants auditors any material weaknesses in internal controls;
and
| |  |  | -- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | b) |  | any
fraud, whether or not material, that involves management or other employees
               who have a significant role in the registrants internal controls;
and
| |  |  | -- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------

|6. |  | The registrants other certifying officers and I have indicated in this
               annual report whether or not there were significant changes in internal controls
               or in other factors that could significantly affect internal controls subsequent
               to the date of our most recent evaluation, including any corrective actions with
               regard to significant deficiencies and material weaknesses.
|-- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Date:  March 31, 2003

/s/ Daniel P. Landguth

Chairman and
Chief Executive Officer

---

# CERTIFICATION

I, Mark T. Thies, certify that:

|1. |  | I have reviewed this annual report on Form 10-K of Black Hills Power, Inc.;
|-- |  | ---------------------------------------------------------------------------

|2. |  | Based on my knowledge, this annual report does not contain any untrue statement
               of a material fact or omit to state a material fact necessary to make the
               statements made, in light of the circumstances under which such statements were
               made, not misleading with respect to the period covered by this annual report;
|-- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|3. |  | Based on my knowledge, the financial statements, and other financial information
               included in this annual report, fairly present in all material respects the
               financial condition, results of operations and cash flows of the registrant as
               of, and for, the periods presented in this annual report;
|-- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|4. |  | The registrants other certifying officers and I are responsible for
               establishing and maintaining disclosure controls and procedures (as defined in
               Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
|-- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | a) |  | designed
such disclosure controls and procedures to ensure that material
               information relating to the registrant, including its consolidated
subsidiaries,                is made known to us by others within those entities,
particularly during the                period in which this annual report is being
prepared;
| |  |  | -- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | b) |  | evaluated
the effectiveness of the registrants disclosure controls and
               procedures as of a date within 90 days prior to the filing date of this
annual                report (the Evaluation Date); and
| |  |  | -- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | c) |  | presented
in this annual report our conclusions about the effectiveness of the
               disclosure controls and procedures based on our evaluation as of the
Evaluation                Date;
| |  |  | -- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|5. |  | The registrants other certifying officers and I have disclosed, based on
               our most recent evaluation, to the registrants auditors and the audit
               committee of registrants board of directors (or persons performing the
               equivalent functions):
|-- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | a) |  | all
significant deficiencies in the design or operation of internal controls
               which could adversely affect the registrants ability to record,
process,                summarize and report financial data and have identified for the
               registrants auditors any material weaknesses in internal controls;
and
| |  |  | -- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | b) |  | any
fraud, whether or not material, that involves management or other employees
               who have a significant role in the registrants internal controls;
and
| |  |  | -- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------

|6. |  | The registrants other certifying officers and I have indicated in this
               annual report whether or not there were significant changes in internal controls
               or in other factors that could significantly affect internal controls subsequent
               to the date of our most recent evaluation, including any corrective actions with
               regard to significant deficiencies and material weaknesses.
|-- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Date:  March 31, 2003

/s/ Mark T. Thies

Senior Vice President and
Chief Financial Officer

---

# INDEX TO EXHIBITS

|ExhibitNumber |  | Description
|------------- |  | -----------

| | 2* |  | Plan
of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as
                           an exhibit to the Black Hills Holding Corporation's
Registration Statement on Form S-4 (No. 333-52664)).
| | -- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.1* |  | Restated
Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form
8-K                            dated June 7, 1994 (No. 1-7978)).
| | ---- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.2* |  | Articles
of Amendment to the Articles of Incorporation of the Registrant, as filed with the
Secretary of                            State of the State of South Dakota on December
22, 2000 (filed as an exhibit to the Registrant's Form 10-K
                           for 2000).
| | ---- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.3* |  | Bylaws
of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form
S-8 dated                            July 13, 1999).
| | ---- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------

| | 4.1* |  | Restated
and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now
called Black                            Hills Power, Inc.) dated as of September 1, 1999
(filed as an exhibit to Black Hills Holding Corporation's
                           Registration Statement on Form S-4 (No. 333-52664)).  First
Supplemental Indenture, dated as of August 13,                            2002, between
Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.1 to the
                           Registrant's Form 10-Q for the quarter ended September 30,
2002).
| | ---- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.1* |  | Agreement
for Transmission Service and the Common Use of Transmission Systems dated January 1,
1986, among                            Black Hills Power, Inc., Basin Electric Power
Cooperative, Rushmore Electric Power Cooperative, Inc.,
                           Tri-County Electric Association, Inc., Black Hills Electric
Cooperative, Inc. and Butte Electric                            Cooperative, Inc. (filed
as Exhibit 10(d) to the Registrant's Form 10-K for 1987).
| | ----- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.2* |  | Restated
and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit
10(c) to the                            Registrant's Form 10-K for 1992).
| | ----- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.3* |  | Second
Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp
and Black                            Hills Power, Inc. (filed as Exhibit 10(e) to the
Registrant's Form 10-K for 1997).
| | ----- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.4* |  | Reserve
Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light
Company and Black                            Hills Power, Inc. (filed as Exhibit 10(u) to
the Registrant's Form 10-K for 1987).
| | ----- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.5* |  | Rate
Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999).
| | ----- |  | --------------------------------------------------------------------------------------

| | 10.6* |  | Purchase
and Sale Agreement by and between TLS Investors, LLC and Black Hills Energy Capital, Inc.
dated                            June 18, 2001 to purchase Southwest Power, LLC.
| | ----- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 99.1 |  | Certification
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley                            Act of 2002.
| | ---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------

| | 99.2 |  | Certification
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley                            Act of 2002.
| | ---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------

_________________

| | * |  | Previously
filed as part of the filing indicated and incorporated by reference herein.
| | - |  | --------------------------------------------------------------------------------------

| | + |  | Indicates
a board of director or management compensatory plan.
| | - |  | --------------------------------------------------------------