UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
X EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
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 Street
Rapid City, South Dakota 57701
Registrant's telephone number, including area code
(605) 721-1700
Securities registered pursuant to Section 12(b) of the Act: 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
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.
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 29, 2002
----- -----------------------------
Common stock, $1.00 par value 23,416,396 shares
Reduced Disclosure
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.
FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" as defined by the
Securities and Exchange Commission. These statements concern our plans,
expectations and objectives for future operations. All statements, other than
statements of historical facts, included in this Form 10-K that address
activities, events or developments that we expect, believe or anticipate will or
may occur in the future are forward-looking statements. The words "believe,"
"plan," "intend," "anticipate," "estimate," "project" and similar expressions
are also intended to identify forward-looking statements. These forward-looking
statements include, among others, such things as:
o expansion and growth of our business and operations;
o future financial performance;
o future acquisition and development of power plants; and
o business strategy.
These forward-looking statements are based on assumptions, which we believe
are reasonable based on current expectations and projections about future events
and industry conditions and trends affecting our business. However, whether
actual results and developments will conform to our expectations and predictions
is subject to a number of risks and uncertainties which could cause actual
results to differ materially from those contained in the forward-looking
statements, including the following factors:
o prevailing governmental 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;
o changes in and compliance with environmental and safety laws and
policies;
o weather conditions;
o counterparty credit risk;
o population growth and demographic patterns;
o competition for retail and wholesale customers;
o pricing and transportation of commodities;
o market demand, including structural market changes;
o changes in tax rates or policies or in rates of inflation;
o changes in project costs;
o unanticipated changes in operating expenses or capital expenditures;
o capital market conditions;
o technological advances;
o competition for new energy development opportunities; and
o legal and administrative proceedings that influence our business
and profitability.
2
TABLE OF CONTENTS
Page
ITEMS
1 & 2. BUSINESS AND PROPERTIES.............................................4
General.........................................................4
Electric Utility................................................4
Independent Power...............................................4
ITEM 3. LEGAL PROCEEDINGS...................................................5
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.................................................5
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS...............................................5
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..........8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................11
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE..............................32
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.....32
SIGNATURES..........................................................35
3
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. We began selling and marketing various forms of energy
on an unregulated basis in 1956. 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 to
approximately 59,200 customers in South Dakota, Wyoming and Montana. We own 395
megawatts of generating capacity with an additional 40 megawatts under
construction. We also purchase 60 megawatts of capacity from PacifiCorp under a
long-term power contract. In 2002, approximately 50 percent of our generating
capacity will consist of coal-fired plants and 38 percent will be gas- or
oil-fired, with the remaining 12 percent purchased from others.
Our revenue mix for 2001 was comprised of 31 percent wholesale off-system, 10
percent short-term contract wholesale, 22 percent commercial, 17 percent
residential, 11 percent industrial, 8 percent long-term contract wholesale and 1
percent municipal sales. In 2001, our South Dakota customers accounted for 92
percent of our retail electric revenues. Our retail electric rates in South
Dakota are subject to a five-year freeze expiring on January 1, 2005. Because
our generation capacity typically exceeds our peak load demands, we rarely
purchase power on the spot market during periods of peak usage, permitting us to
preserve our low-cost rate structure for our retail customers. Off-system sales
offer a means to optimize the utilization of our power supply sources by
permitting us to sell capacity and energy in excess of our native load
requirements to wholesale customers at market prices, which sometimes exceed our
regulated retail rates. Wholesale off-system sales have represented an
increasing percentage of our total revenues and net income. Although the demand
for power in the western markets has eased from the record levels seen in the
first half of 2001, further increases in the volume of off-system sales are
expected in the future due to demand growth in the Rocky Mountain region and the
early 2002 addition of 40 megawatts of gas-fired generating capacity.
We operate a transmission system of 447 miles of high voltage and 541 miles of
lower voltage lines. In addition, we jointly own 43 miles of high voltage lines
with Basin Electric Cooperative. Our system has the capability of connecting to
either the eastern or western transmission systems, which provides us with
access between the Western Systems Coordinating Council and the Mid-Continent
Area Power Pool. This allows us the opportunity to improve system reliability
and take advantage of power price differentials between the two electric grids.
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 553 megawatts, as well as
minority interests in several power-related funds with a net ownership interest
of 24 megawatts. We are in the process of acquiring or constructing an
additional net ownership interest of approximately 274 megawatts of generation
capacity, which is expected to be brought into service in 2002.
4
ITEM 3. LEGAL PROCEEDINGS
There are currently no pending material legal proceedings to which we are a
party. There are currently no pending material legal proceedings to which an
officer or director is a party or has a material interest adverse to us or our
subsidiaries. There are 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:
2001 2000 1999
---- ---- ----
Revenue:
Electric utility 71% 81% 100%
Independent power 29 19 -
--- --- ---
100% 100% 100%
=== === ===
Net income (loss):
Electric utility 105% 92% 100%
Independent power (5) 8 -
--- --- ---
100% 100% 100%
=== === ===
2001 Compared to 2000
Consolidated net income from continuing operations for 2001 was $43.3 million
compared to $40.3 million in 2000. Consolidated revenues, expenses and operating
income increased 41 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.
5
2000 Compared to 1999
Consolidated net income from continuing operations for 2000 was $40.3 million
compared to $27.3 million in 1999.
Earnings growth in 2000 was primarily due to increased wholesale off-system
electric utility sales and expanded power generation. Unusual market conditions
stemming from electricity shortages in the West contributed to our strong
financial performance in 2000.
Consolidated revenues increased from $133.2 million in 1999 to $212.8 million in
2000 primarily as a result of price volatility in the western markets and the
acquisition and growth of the power generation group.
Electric Utility
2001 2000 1999
---- ---- ----
(in thousands)
Revenue $213,210 $173,308 $133,222
Operating expenses 129,102 105,100 80,936
-------- -------- --------
Operating income $ 84,108 $ 68,208 $ 52,286
======== ======== ========
Net income $ 45,238 $ 37,105 $ 27,286
======== ======== ========
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 395
megawatts of electric utility generating capacity and purchase an additional 65
megawatts under a long-term agreement (decreasing to 60 megawatts in 2002). An
additional 40 megawatts of generating capacity is currently under construction.
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 the newly formed Black Hills Corporation 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.
6
2000 Compared to 1999
Electric revenue increased 30 percent in 2000 compared to 1999. The increase in
electric revenue in 2000 was primarily due to a 381 percent increase in
wholesale off-system sales at an average price that was 3 times higher than the
average price in 1999. The increase in off-system sales was driven by high spot
market prices for energy in late 2000, which enabled us to generate more energy
from our combustion turbine facilities, including the Neil Simpson combustion
turbine, which we placed into commercial operation in June 2000. Megawatt-hours
generated from our oil-fired diesel and natural gas-fired combustion turbines
were 305,767 in 2000 compared to 25,882 in 1999.
Firm kilowatt-hour sales increased 3 percent. Residential and commercial sales
increases of 4 percent were partially offset by a 2 percent decrease in
industrial sales, primarily due to load reductions at Homestake Gold Mine.
Degree days, a measure of weather trends, were 16 percent above 1999 and 1
percent above normal.
Revenue per kilowatt-hour sold was 6.4 cents in 2000 compared to 5.4 cents in
1999. The number of customers in the service area increased to 58,601 in 2000
from 57,709 in 1999. The increase in the revenue per kilowatt-hour sold in 2000
is due to a 54 percent increase in wholesale off-system sales to 684,378
megawatt-hours and robust wholesale power prices.
Electric utility operating expenses increased by 30 percent in 2000 primarily
due to increased fuel, purchased power, and operating and maintenance expenses,
partially offset by lower depreciation. Fuel expense in 2000 included the cost
associated with the additional combustion turbine generation.
Independent Power
2001 2000*
---- ----
(in thousands)
Revenue $87,811 $39,502
Expenses 61,980 19,135
------- -------
Operating income $25,831 $20,367
======= =======
Net income (loss) $(1,964) $ 3,173
======= =======
- ---------------
* Year 2000 results are for the partial period July 7, 2000, the date of the
acquisition of Indeck Capital, Inc., through December 31, 2000.
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 more than
doubled in 2001 compared to 2000. We now own 577 net megawatts in currently
operating plants compared to 250 net megawatts at December 31, 2000. Of these
577 net megawatts, approximately 88 percent are under contracts or tolling
arrangements with at least one year remaining, whereby the purchaser assumes the
fuel risk. An additional 274 megawatts of generating capacity is currently under
construction. Substantially all of this output will be 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.
7
2000 Compared to 1999
We were not involved in the independent power generation business in 1999. In
July 2000, we completed the acquisition of Indeck Capital, representing the
beginning of our position in the power generation business. At December 31,
2000, we owned 250 net megawatts of generation in operating plants and had 340
megawatts of generating capacity under construction.
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, fuel
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 assets and liabilities of Wyodak are shown in the
Consolidated Balance Sheets under the captions "Assets of discontinued
operations" and "Liabilities of discontinued operations".
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 1999
---- ---- ----
(in thousands)
Revenue $197,274 $1,425,675 $658,653
Income before income taxes 7,849 20,345 13,124
Federal income taxes 3,017 7,775 3,343
Net income 4,832 12,570 9,781
- --------------------------------
*Includes only one month of operations
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our operations and financial results are impacted by numerous factors including,
but not limited to, commodity price risk, interest risk and counterparty risk.
In the normal course of business, we actively manage our exposure to these
market risks by entering into various hedging transactions. Hedging transactions
involve the use of a variety of derivative financial instruments. Our risk
management policies place controls on these activities.
We have adopted Risk Management Policies and Procedures, approved by our Board
of Directors, and routinely reviewed by the Audit Committee of the Board of
Directors. Our Risk Management Policies and Procedures include, but are not
limited to, risk tolerance levels relating to authorized derivative financial
instruments, position limits, authorization of transactions and credit exposure.
Energy Activities
We acquired several natural gas swaps when we completed the Las Vegas
Cogeneration acquisition on August 31, 2001 (Note 16). The project 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
fix the long-term purchase price of the index-priced natural gas purchase
contract. At acquisition close, the fair value of these swaps was approximately
8
$6.0 million. These swaps were executed with Enron North America Corp. (Enron),
which is currently in bankruptcy proceedings.
These swaps are derivatives under Statement of Financial Accounting Standards
No. 133 (SFAS 133) "Accounting for Derivative Instruments and Hedging
Activities." We 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, we determined that it was probable that Enron
would default on its obligations to us in conjunction with these swaps. Upon
that determination, we ceased to account for these swaps as cash flow hedges. As
a result, we recognized a $6.0 million pre-tax valuation reserve in recognition
of Enron's probable performance default and resulting consequence that we would
not receive payment for these amounts.
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, 2001, these hedges met effectiveness
testing criteria and retained their cash flow hedge status. At December 31,
2001, we had $216.4 million of notional amount floating-to-fixed interest rate
swaps, having a maximum term of five years and a fair value of $(12.7) million.
These hedges are substantially effective and any ineffectiveness was immaterial.
In addition to the above interest rate swaps, we have entered into a $100
million forward starting floating-to-fixed interest rate swap to hedge the
anticipated floating rate debt financing related to our Las Vegas Cogeneration
expansion. The forward starting period for the swap is the second quarter of
2002, with a term of ten years. The swap will terminate and cash settle on its
forward starting date, based on the fair market value of the swap at the
starting date. At December 31, 2001, the swap had a fair market value of $2.3
million. The hedge has met effectiveness criteria. Upon completion of the
long-term financing of the project, any gain or loss on the fair market value of
the swap is anticipated to be amortized over the life of the long-term
financing.
On January 1, 2001 (the transition adjustment date for SFAS 133 adoption) and on
December 31, 2001, our interest rate swaps and related balances were as follows
(in thousands):
Weighted
Average Accumulated
Current Fixed Maximum Other
Notional Interest Terms in Current Non-current Current Non-current Comprehensive
Amount Rate Years Assets Assets Liabilities Liabilities Income (Loss)
------ ---- ----- ------ ------ ----------- ----------- -------------
January 1, 2001
Swaps on project
financing $127,416 7.38% 5 $ - $ 265 $ 2,440 $5,332 $ (7,507)
======== ===== ======= ======== ====== ========
December 31, 2001
Swaps on project
financing $316,397 5.85% 4 $ - $5,746 $10,212 $5,949 $(10,415)
======== ===== ====== ======= ====== ========
We anticipate a portion of unrealized losses recorded in accumulated other
comprehensive income will be realized as increased interest expense in 2002.
Based on December 31, 2001 market interest rates, $10.2 million will be realized
as additional interest expense during 2002. Estimated and realized amounts will
likely change during 2002 as market interest rates change.
9
At December 31, 2001, we had $743.4 million of outstanding, floating rate debt
($447.1 million is with a related party), of which $427.0 million was not offset
with interest rate swaps transactions that effectively convert the debt to fixed
rate. The table below presents principal (or notional) amounts and related
weighted average interest rates by year of maturity for our short-term
investments and long-term debt obligations, including current maturities (in
thousands).
2002 2003 2004 2005 2006 Thereafter Total
Cash equivalents
Fixed rate $14,832 $ - $ - $ - $ - $ - $ 14,832
Long-term debt
Fixed rate $18,042 $ 3,095 $ 1,986 $ 1,991 $ 1,996 $128,214 $155,324
Average interest rate 6.97% 9.28% 9.44% 9.45% 9.46% 8.26% 8.18%
Variable rate (a) $17,839 $19,301 $21,126 $22,674 $135,285 $ 79,646 $295,871
Average interest rate 3.45% 3.45% 3.45% 3.45% 3.32% 3.48% 3.40%
Total long-term debt $35,881 $22,396 $23,112 $24,665 $137,281 $207,860 $451,195
Average interest rate 5.22% 4.25% 3.97% 3.94% 3.41% 6.43% 5.04%
(a) Approximately 74 percent of the variable rate debt has been hedged with
interest rate swaps moving the floating rates to fixed rates with an
average interest rate of 5.85 percent.
Credit Risk
Credit risk relates to the risk of financial loss resulting from non-performance
of contractual obligations by a counterparty. We maintain credit policies with
regards to our counterparties that we believe limits our overall credit risk.
We attempt to mitigate our credit risk by conducting a majority of our 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.
10
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants 11
Consolidated Statements of Income
for the three years ended December 31, 2001 12
Consolidated Balance Sheets as of December 31, 2001 and 2000 13
Consolidated Statements of Cash Flows
for the three years ended December 31, 2001 14
Consolidated Statements of Common Stockholder's Equity
for the three years ended December 31, 2001 15
Notes to Consolidated Financial Statements 16-32
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholder of Black Hills Power, Inc.:
We have audited the accompanying consolidated balance sheets of Black Hills
Power, Inc. (a South Dakota corporation and wholly owned subsidiary of Black
Hills Corporation) and Subsidiaries as of December 31, 2001 and 2000, and the
related consolidated statements of income, common stockholder's equity and cash
flows for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Black Hills Power, Inc. and
Subsidiaries as of December 31, 2001 and 2000 and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 1 to the consolidated financial statements, effective
January 1, 2001, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities."
Arthur Andersen LLP
Minneapolis, Minnesota,
March 22, 2002
11
BLACK HILLS POWER, INC.
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 2001 2000 1999
---- ---- ----
(in thousands)
Operating revenues $301,021 $212,810 $133,222
-------- -------- --------
Operating expenses:
Fuel and purchased power 77,055 57,584 31,556
Operations and maintenance 41,999 26,258 20,970
Administrative and general 28,700 14,721 6,330
Depreciation, depletion and amortization 31,703 18,612 15,552
Taxes, other than income taxes 11,625 7,060 6,528
-------- -------- --------
191,082 124,235 80,936
-------- -------- --------
Operating income 109,939 88,575 52,286
-------- -------- --------
Other income (expense):
Interest expense (44,584) (25,329) (13,830)
Interest income 5,239 5,758 1,190
Other, net 883 5,195 86
-------- -------- --------
(38,462) (14,376) (12,554)
-------- -------- --------
Income from continuing operations before minority
interest and income taxes 71,477 74,199 39,732
Minority interest (4,186) (11,338) -
Income taxes (24,017) (22,583) (12,446)
-------- -------- --------
Income from continuing operations 43,274 40,278 27,286
Discontinued operations, net of income taxes
(Note 2) 4,832 12,570 9,781
-------- -------- --------
Net income $ 48,106 $ 52,848 $ 37,067
======== ======== ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
12
BLACK HILLS POWER, INC.
CONSOLIDATED BALANCE SHEETS
At December 31, 2001 2000
---- ----
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 14,832 $ 12,697
Receivables (net of allowance for doubtful accounts of $2,677
and $542, respectively) -
Customers 26,352 19,339
Related party 9,457 89,203
Other 5,982 19,653
Materials, supplies and fuel 10,399 10,703
Prepaid expenses 9,822 6,788
Assets of discontinued operations (Note 2) - 247,548
---------- ----------
76,844 405,931
---------- ----------
Investments 51,543 42,397
---------- ----------
Property and equipment 1,251,630 817,728
Less accumulated depreciation and depletion (240,472) (207,805)
---------- ----------
1,011,158 609,923
---------- ----------
Other assets:
Regulatory asset 4,071 4,134
Goodwill and other intangible assets 109,719 35,897
Other 16,239 9,644
---------- ----------
130,029 49,675
---------- ----------
$1,269,574 $1,107,926
========== ==========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt $ 35,881 $ 13,960
Notes payable 450 86,000
Notes payable - related party 447,125 98,631
Accounts payable 13,271 12,734
Accounts payable - related party 4,385 3,756
Accrued liabilities 16,929 20,336
Derivative liabilities 10,212 -
Liabilities of discontinued operations (Note 2) - 163,862
---------- ----------
528,253 399,279
---------- ----------
Long-term debt, net of current maturities 415,314 307,092
---------- ----------
Deferred credits and other liabilities:
Federal income taxes 61,239 54,706
Regulatory liability 6,249 7,203
Other 17,255 9,459
---------- ----------
84,743 71,368
---------- ----------
Minority interest in subsidiaries 19,536 37,963
---------- ----------
Commitments and contingencies (Notes 11, 12 and 16)
Preferred stock:
$100 par value, cumulative preferred stock; 270,000 shares authorized;
0 shares issued and outstanding - -
No par value, cumulative preferred stock; 400,000 shares authorized;
0 shares issued and outstanding - -
Common stock equity:
Common stock $1 par value; 50,000,000 shares authorized;
Issued: 23,416,396 shares in 2001 and 2000 23,416 23,416
Additional paid-in capital 80,961 77,326
Retained earnings 121,875 191,482
Accumulated other comprehensive (loss) (4,524) -
---------- ----------
221,728 292,224
---------- ----------
$1,269,574 $1,107,926
========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
13
BLACK HILLS POWER, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2001 2000 1999
---- ---- ----
(in thousands)
Operating activities:
Net income $ 48,106 $ 52,848 $ 37,067
Income from discontinued operations (4,832) (12,570) (9,781)
Principal non-cash items-
Depreciation, depletion and amortization 31,703 18,612 15,552
Provision for valuation allowances 8,135 279 12
Gain on sales of assets - (3,736) -
Deferred income taxes 4,522 1,293 1,121
Minority interest 4,186 11,338 -
Change in operating assets and liabilities-
Accounts receivable 4,695 (9,461) (7,626)
Other current assets (2,259) (4,725) (177)
Accounts payable 118 10,331 27
Accrued liabilities (3,407) 1,882 1,631
Other, net (1,044) (6,718) (319)
-------- --------- --------
89,923 59,373 37,507
-------- --------- --------
Investing activities:
Property, plant and equipment additions (316,809) (46,975) (31,714)
Payment for acquisition of net assets, net of cash acquired (199,001) (28,688) -
Payment for acquisition of minority interest (16,676) - -
Increase in investments - (10,377) -
Notes receivable from associated companies, net 81,134 (87,835) (52,646)
Proceeds from sales of assets - 5,500 -
Available-for-sale securities purchased - - (8,203)
Available-for-sale securities sold - 5,345 13,049
-------- -------- ---------
(451,352) (163,030) (79,514)
-------- -------- ---------
Financing activities:
Dividends paid on common stock (28,070) (23,527) (22,602)
Common stock issued - 3,852 424
Increase in short-term borrowings, net 262,944 84,379 60,000
Long-term debt - issuance 144,103 60,082 -
Long-term debt - repayments (13,960) (1,330) (1,330)
Subsidiary distributions to minority interests (1,453) (10,900) -
-------- -------- ---------
363,564 112,556 36,492
-------- -------- ---------
Increase in cash and cash equivalents 2,135 8,899 (5,515)
Cash and cash equivalents:
Beginning of year 12,697 3,798 9,313
-------- -------- ---------
End of year $ 14,832 $ 12,697 $ 3,798
======== ======== =========
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $44,820 $26,258 $13,701
Income taxes $22,891 $16,427 $11,113
Noncash net assets acquired through issuance of common and
preferred stock (Note 16) $ 3,635 $34,493 $ -
Stock dividend distribution to Black Hills Corporation, the
parent company of Black Hills Power, Inc. (Note 2) $89,643 $ - $ -
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
14
BLACK HILLS POWER, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated
Common Stock Additional Other
------------------------ Paid-In Retained Comprehensive
Shares Amount Capital Earnings Loss Total
------ ------ ------- -------- ---- -----
(in thousands)
Balance at
December 31, 1998 21,719 $ 21,719 $ 40,254 $ 147,774 $ - $209,747
------ -------- -------- --------- ----------- --------
Comprehensive Income:
Net income - - - 37,067 - 37,067
------ -------- -------- --------- ----------- --------
Total comprehensive income - - - 37,067 - 37,067
Dividends on common stock - - - (22,602) - (22,602)
Issuance of common stock 20 20 404 - - 424
------ -------- -------- --------- ----------- --------
Balance at
December 31, 1999 21,739 21,739 40,658 162,239 - 224,636
------ -------- -------- --------- ----------- --------
Comprehensive Income:
Net income - - - 52,848 - 52,848
------ -------- -------- --------- ----------- --------
Total comprehensive income - - - 52,848 - 52,848
Dividends on preferred stock - - - (78) - (78)
Dividends on common stock - - - (23,527) - (23,527)
Issuance of common stock 140 140 4,428 - - 4,568
Issuance of common stock
for acquisition 1,537 1,537 32,240 - - 33,777
------ -------- -------- -------- ----------- --------
Balance at
December 31, 2000 23,416 23,416 77,326 191,482 - 292,224
------ -------- -------- -------- ----------- --------
Comprehensive Income:
Net income - - - 48,106 - 48,106
Unrealized loss on mark to
market interest rate swaps - - - - (1,597) (1,597)
Initial impact of adoption of
SFAS 133, net of minority
interest - - - - (2,927) (2,927)
------ -------- --------- -------- ---------- ---------
Total comprehensive income - - - 48,106 (4,524) 43,582
Dividends on common stock - - - (28,070) - (28,070)
Earnout consideration on
acquisition - - 3,635 - - 3,635
Stock distribution to parent - - - (89,643) - (89,643)
------ -------- --------- -------- ---------- --------
Balance at December 31, 2001 23,416 $ 23,416 $ 80,961 $121,875 $ (4,524) $221,728
====== ======== ========= ======== ========== ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Power, Inc. and its subsidiary (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.
During 2000, the Company became a wholly owned subsidiary of Black Hills
Corporation through a "plan of exchange" between the Company and Black Hills
Corporation. The "plan of exchange" provided that each share of the Company's
common stock would be exchanged for one share of common stock of the holding
company. As a result:
o all common shareholders of Black Hills Power, Inc. became shareholders of
Black Hills Corporation, the holding company;
o Black Hills Power, Inc. became a wholly owned subsidiary of Black Hills
Corporation;
o The debt securities and other financial obligations of Black Hills Power,
Inc. remain its obligations.
Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
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
uncollectable accounts receivable, realization of market value of derivatives
due to commodity risk, intangible asset valuations 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 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 2001 and 2000. 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.
16
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 No. 71 (SFAS 71), "Accounting for the Effects of
Certain Types of Regulation," and its financial statements reflect the effects
of the different ratemaking principles followed by the various jurisdictions
regulating 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 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:
2001 2000
---- ----
(in thousands)
Electric utility $ 580,090 $540,907
Independent power 671,540 276,821
---------- --------
$1,251,630 $817,728
========== ========
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 10.2, 9.7 and 8.3
percent during 2001, 2000 and 1999, respectively. In addition, the Company
capitalizes interest, when applicable, on certain non-regulated construction
projects. The amount of AFUDC and interest capitalized was $6.8 million, $1.0
million and $0.2 million in 2001, 2000 and 1999, 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 3.0 percent
in 2001, 2.8 percent in 2000 and 3.1 percent in 1999. Non-regulated property,
plant and equipment is depreciated on a straight-line basis using estimated
useful lives ranging from 3 to 39 years.
17
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. The cost of other acquired intangibles is amortized on a
straight-line basis over their estimated useful lives. Amortization expense was
$3.5 million, $2.5 million and $0 in 2001, 2000 and 1999, respectively.
Accumulated amortization was $6.0 million, $2.5 million and $0 at December 31,
2001, 2000 and 1999, 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 2001, 2000 or 1999.
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 noncurrent amounts based on the
classification of the related assets and liabilities.
Revenue Recognition
Generally, 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 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," 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 2000 and 1999 amounts in the financial statements have been reclassified
to conform to the 2001 presentation. These reclassifications had no effect on
the Company's common stockholder's equity or results of operations, as
previously reported.
Recently Issued Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 141, "Business Combinations" (SFAS 141)
and No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). SFAS 141
requires all business combinations initiated after June 30, 2001 to be accounted
for using the purchase method of accounting. Under SFAS 142, goodwill and
intangible assets with indefinite lives are no longer amortized but are reviewed
annually (or more frequently if impairment indicators arise) for impairment.
Intangible assets with a defined life will continue to be amortized over their
useful lives (but with no maximum life). The amortization provisions of SFAS 142
apply to goodwill and intangible assets acquired after June 30, 2001. With
respect to goodwill and intangible assets acquired prior to July 1, 2001, the
Company was required to adopt SFAS 142 effective January 1, 2002. Management is
currently evaluating the effects adoption will have on the Company's
consolidated financial statements.
18
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. Management expects to adopt SFAS 143 effective January 1, 2003
and is currently evaluating the effects adoption will have on the Company's
consolidated financial statements.
In August 2001, the FASB issued Statement of Financial Accounting Standards No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS
144). SFAS 144 supersedes FASB Statement 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 as well as
resolves implementation issues related to SFAS 121. Management adopted SFAS 144
effective January 1, 2002 with no impact on the Company's consolidated financial
position, results of operations or cash flows.
Change in Accounting Principle - Derivatives and Hedging Activities
In June 1998, the FASB issued Statement of Financial Accounting Standards No.
133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities."
SFAS 133, as amended, establishes accounting and reporting standards requiring
that every derivative instrument be recorded in the balance sheet as either an
asset or liability measured at its fair value. SFAS 133 requires that changes in
the derivative instrument's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met.
SFAS 133 allows special hedge accounting for fair value and cash flow hedges.
SFAS 133 provides that the gain or loss on a derivative instrument designated
and qualifying as a fair value hedging instrument as well as the offsetting loss
or gain on the hedged item attributable to the hedged risk be recognized
currently in earnings in the same accounting period. SFAS 133 provides that the
effective portion of the gain or loss on a derivative instrument designated and
qualifying as a cash flow hedging instrument be reported as a component of other
comprehensive income and be reclassified into earnings in the same period or
periods during which the hedged forecasted transaction affects earnings. The
remaining gain or loss on the derivative instrument, if any, must be recognized
currently in earnings.
SFAS 133 requires that on date of initial adoption, an entity shall recognize
all freestanding derivative instruments in the balance sheet as either assets or
liabilities and measure them at fair value. The difference between a
derivative's previous carrying amount and its fair value shall be reported as a
transition adjustment. The transition adjustment resulting from adopting this
Statement shall be reported in net income or other comprehensive income, as
appropriate, as the effect of a change in accounting principle in accordance
with paragraph 20 of Accounting Principles Board Opinion No. 20 (APB 20),
"Accounting Changes."
On January 1, 2001, the Company adopted SFAS 133. Upon adoption, the Company had
certain interest rate swaps documented as cash flow hedges. These contracts were
defined as derivatives under SFAS 133 and meet the requirements for cash flow
hedges. Because these contracts were documented as hedges prior to adoption, the
transition adjustment 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 the derivative
liabilities by $7.8 million and decreased accumulated other comprehensive income
by $7.5 million pre-tax.
19
(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, fuel 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 assets and liabilities of Wyodak are
shown in the Consolidated Balance Sheets under the captions "Assets of
discontinued operations" and "Liabilities of discontinued operations".
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 1999
---- ---- ----
(in thousands)
Revenue $197,274 $1,425,675 $658,653
Income before income taxes 7,849 20,345 13,124
Federal income taxes 3,017 7,775 3,343
Net income 4,832 12,570 9,781
- --------------------------------
*Includes only one month of operations
(3) RISK MANAGEMENT ACTIVITIES
Energy Activities
The Company acquired several natural gas swaps when it completed the Las Vegas
Cogeneration acquisition on August 31, 2001 (Note 16). The project 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
fix the long-term purchase price of the index-priced natural gas purchase
contract. At acquisition close, the fair value of these swaps was approximately
$6.0 million. These swaps were executed with Enron North America Corp. (Enron),
which is currently in bankruptcy proceedings.
These swaps are 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. As a result, 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, 2001, these hedges met
effectiveness testing criteria and retained their cash flow hedge status. At
December 31, 2001, the Company had $216.4 million of notional amount
floating-to-fixed interest rate swaps, having a maximum term of five years and a
fair value of $(12.7) million. These hedges are substantially effective and any
ineffectiveness was immaterial.
20
In addition to the above interest rate swaps, the Company has entered into 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
Cogeneration expansion. The forward starting period for the swap is the second
quarter of 2002, with a term of ten years. The swap will terminate and cash
settle on its forward starting date, based on the fair market value of the swap
at the starting date. At December 31, 2001, the swap had a fair market value of
$2.3 million. The hedge has met effectiveness criteria. Upon completion of the
long-term financing of the project, any gain or loss on the fair market value of
the swap is anticipated to be amortized over the life of the long-term
financing.
At December 31, 2001, the Company had $743.4 million of outstanding, floating
rate debt ($447.1 million is with a related party), of which $427.0 million was
not offset with interest rate swaps transactions that effectively convert the
debt to fixed rate.
On January 1, 2001 (the transition adjustment date for SFAS 133 adoption) and on
December 31, 2001, the Company's interest rate swaps and related balances were
as follows (in thousands):
Weighted
Average Accumulated
Current Fixed Maximum Other
Notional Interest Terms in Current Non-current Current Non-current Comprehensive
Amount Rate Years Assets Assets Liabilities Liabilities Income (Loss)
------ ---- ----- ------ ------ ----------- ----------- -------------
January 1, 2001
Swaps on project
financing $127,416 7.38% 5 $ - $ 265 $ 2,440 $5,332 $ (7,507)
======== ===== ====== ======== ====== ========
December 31, 2001
Swaps on project
financing $316,397 5.85% 4 $ - $5,746 $10,212 $5,949 $(10,415)
======== ===== ====== ======= ====== ========
The Company anticipates a portion of unrealized losses recorded in accumulated
other comprehensive income will be realized as increased interest expense in
2002. Based on December 31, 2001 market interest rates, $10.2 million will be
realized as additional interest expense during 2002. Estimated and realized
amounts will likely change during 2002 as market interest rates change.
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 regards 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:
o 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 $10.0 million and $8.4 million at
December 31, 2001 and 2000, respectively, which includes $1.9 million and
$2.1 million, respectively, that represents the cost of the investment over
the underlying net assets of the funds. This excess is being amortized over
10 years. 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
21
$37.2 million. As of, and for the year ended December 31, 2000, the funds
had assets of $186.8 million, liabilities of $16.0 million and net income
of $27.1 million.
o 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 $3.9 million and $4.1 million as of December 31, 2001 and
2000, respectively, which includes $0.5 million that represents the cost of
the investment over the value of the underlying net assets of the projects.
This excess is being amortized over 19 years. As of and for the year ended
December 31, 2001, these projects had assets of $25.6 million, liabilities
of $19.0 million and a net loss of $(0.4) million. As of, and for the year
ended December 31, 2000, these projects had assets of $26.0 million,
liabilities of $18.7 million and net income of $0.9 million.
o A direct and indirect ownership of approximately 53 percent (32 percent in
2000), representing 50 percent voting control, of Harbor Co-generation
Company (see Note 18). Harbor Cogeneration owns a 98 megawatt gas-fired
plant (expanded from 80 megawatts in 2000) located in Wilmington,
California. At December 31, 2001 and 2000, the Company's carrying amount in
the investment was $47.9 million and $42.2 million, respectively, which
includes $12.2 million and $13.7 million, respectively, which represents
the cost of the investment over the value of the underlying net assets of
Harbor. This excess is being amortized over 15 years. As of and for the
year ended December 31, 2001, Harbor had assets of $51.4 million,
liabilities of $0.4 million and net income of $10.1 million. As of, and for
the year ended December 31, 2000, Harbor had assets of $41.7 million,
liabilities of $0.8 million and net income of $28.8 million.
(5) COMMON STOCK
During 2000, the Company became a wholly owned subsidiary of Black Hills
Corporation (see Note 1 - Business Description). Black Hills Corporation assumed
all of the Company's stock option, employee stock purchase and dividend
reinvestment and stock purchase plans.
(6) PREFERRED STOCK
During 2000, the Company issued 4,000 preferred shares in the Indeck Capital
acquisition. The preferred shares issued were non-voting, cumulative, no par
shares with a dividend rate equal to 1 percent per annum per share, computed on
the basis of $1,000 per share plus an amount equal to any dividend declared
payable with respect to the common stock, multiplied by the number of shares of
common stock into which each share of preferred stock is convertible.
In the "plan of exchange" with Black Hills Corporation, the preferred stock held
by the Indeck shareholders was exchanged for preferred stock of the holding
company and the Company converted all of its preferred stock held by the holding
company into shares of common stock.
22
(7) LONG-TERM DEBT
Long-term debt outstanding at December 31 is as follows (in thousands):
2001 2000
---- ----
First mortgage bonds:
6.50% due 2002 $ 15,000 $ 15,000
9.00% due 2003 2,176 3,215
8.06% due 2010 30,000 30,000
9.49% due 2018 4,840 5,130
9.35% due 2021 33,300 35,000
8.30% due 2024 45,000 45,000
--------- ---------
130,316 133,345
--------- ---------
Other long-term debt:
Pollution control revenue bonds at 6.7% due 2010 12,300 12,300
Pollution control revenue bonds at 7.5% due 2024 12,200 12,200
Other 3,363 3,911
--------- ---------
27,863 28,411
--------- ---------
Project financing floating rate debt (a):
Fountain Valley project at 3.29% (b) due 2006 144,581 -
Hudson Falls at 3.7% (b) due 2010 69,479 74,147
South Glens Falls at 3.7% (b) due 2009 24,008 26,124
Valmont and Arapahoe at 3.31% (b) due 2010 54,948 59,025
--------- ---------
293,016 159,296
--------- ---------
Total long-term debt 451,195 321,052
Less current maturities (35,881) (13,960)
--------- ---------
Net long-term debt $415,314 $307,092
========= =========
- ---------------
(a) Approximately 74 percent of the December 31, 2001 balance has been
hedged with an interest rate swap moving the floating rates to fixed
rates with a weighted average interest rate of 5.85 percent (see Note
3-Risk Management Activities).
(b) Interest rates are presented as of December 31, 2001.
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
or have obtained amendments and waivers effective at December 31, 2001.
Scheduled maturities for the next five years are: $35.9 million in 2002, $22.4
million in 2003, $23.1 million in 2004, $24.7 million in 2005, and $137.3
million in 2006.
23
(8) NOTES PAYABLE
Under the Valmont and Arapahoe long-term debt facility, the Company has a
secured operating line of credit, which allows for borrowings of up to $5.0
million and is renewable annually through December 31, 2010. The Company had
borrowings of $0.3 million outstanding under this agreement as of December 31,
2001. Borrowings under this agreement bear interest at LIBOR plus 1.875 percent
(3.8 percent at December 31, 2001).
Under the South Glens Falls long-term debt facility, the Company has a secured
operating line of credit, which allows for borrowings of up to $2.5 million and
is renewable annually through December 31, 2009. The Company had borrowings of
$0.15 million outstanding under this agreement as of December 31, 2001.
Borrowings under this agreement bear interest at LIBOR plus 1.875 percent (3.8
percent at December 31, 2001).
In addition, the Company has an unsecured line of credit with Black Hills
Generation, a sister subsidiary company, 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
(4.75 percent at December 31, 2001) and interest is payable monthly. Borrowings
were $447.2 million and $98.6 million at December 31, 2001 and 2000,
respectively.
(9) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments are as follows:
2001 2000
---- ----
(in thousands)
Carrying Amount Fair Value Carrying Amount Fair Value
--------------- ---------- --------------- ----------
Cash and cash equivalents $ 14,832 $ 14,832 $ 12,697 $ 12,697
Derivative financial
instruments - liabilities 10,212 10,212 - -
Notes payable 447,575 447,575 184,631 184,631
Long-term debt 451,195 469,009 321,052 337,446
The following methods and assumptions were used to estimate the fair value of
each class of the Company's financial instruments.
Cash and Cash Equivalents
The carrying amount approximates fair value due to the short maturity of these
instruments.
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.
24
(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, 2001, the Company's investment in
the Plant included $71.7 million in electric plant and $22.8 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 $5.9 million, $5.6 million and $4.9 million for the years ended
December 31, 2001, 2000 and 1999, respectively, and is included in the
corresponding categories of operating expenses in the accompanying Consolidated
Statements of Income.
(11) COMMITMENTS AND CONTINGENCIES
Power Agreement - Pacific Power
In 1983, the Company entered into a 40 year power agreement with Pacific Power
providing for the purchase by the Company of 75 megawatts of electric capacity
and energy from Pacific Power's system. An amended agreement signed in October
1997 reduces the contract capacity by 25 megawatts (5 megawatts per year
starting in 2000). The price paid for the capacity and energy is based on the
operating costs of one of Pacific Power's coal-fired electric generating plants.
Costs incurred under this agreement were $13.9 million in 2001, $14.6 million in
2000 and $17.8 million in 1999.
Long Term Power Sales Agreements
The Company, through its subsidiaries, has the following significant long-term
power sales contracts:
o 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 400 megawatts in operation plus an additional 50
megawatts combined-cycle expansion currently under construction, is
included under the contracts which expire in 2012. The contracts are
tolling arrangements in which the Company assumes no fuel price risk.
o The Company has secured long-term contracts for the output of the 277
megawatt Las Vegas facility that was acquired during the third quarter of
2001. See Note 16 for a description of the facility and the related
long-term contracts.
o The Company has various long-term contracts with Niagara Mohawk Power
Corporation 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 2028 and 2032. There are additional contracts on plants
with a net ownership capacity of approximately 21 megawatts that expire
during 2002 and 2003.
Ongoing Litigation
The Company is subject to various legal proceedings and claims which arise in
the ordinary course of operations. In the opinion of management, the amount of
liability, if any, with respect to these actions would not materially affect the
consolidated financial position or results of operations of the Company.
25
(12) EMPLOYEE BENEFIT PLANS
Defined Benefit Pension and Other Postretirement Plans
The Company has a noncontributory defined benefit pension plan (Plan) covering
the employees of Black Hills Power 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:
2001 2000 1999
---- ---- ----
(in thousands)
Service cost $ 719 $ 744 $ 867
Interest cost 2,565 2,401 2,164
Estimated return on assets (4,928) (4,465) (3,540)
Amortization of transition amount - (63) (63)
Amortization of prior service cost 199 199 78
Recognized net actuarial gain (453) (452) -
-------- -------- -------
Net pension income $(1,898) $(1,636) $ (494)
======== ======== =======
Actuarial assumptions:
Discount rate 7.5% 7.5% 6.75%
Expected long-term rate of return on assets 10.5% 10.5% 10.5%
Rate of increase in compensation levels 5.0%* 5.0% 5.0%
- -------------------
*The rate of increase in compensation levels for 2001 was changed 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:
2001 2000
---- ----
(in thousands)
Beginning projected benefit obligation $34,454 $33,034
------- -------
Service cost 719 744
Interest cost 2,565 2,401
Actuarial losses 183 156
Benefits paid (1,933) (1,881)
Business divestiture (2,837) -
------- -------
Net increase (decrease) (1,303) 1,420
------- -------
Ending projected benefit obligation $33,151 $34,454
======= =======
A reconciliation of the fair value of Plan assets as of October 1 of each year
is as follows:
2001 2000
---- ----
(in thousands)
Beginning market value of plan assets $47,993 $43,543
Benefits paid (1,933) (1,881)
Investment income (loss) (11,133) 6,331
Asset transfer (1,989) -
------- -------
Ending market value of plan assets $32,938 $47,993
======= =======
26
Funding information for the Plan as of October 1 each year was as follows:
2001 2000
---- ----
(in thousands)
Fair value of plan assets $32,938 $47,993
Projected benefit obligation (33,151) (34,454)
-------- -------
Funded status (213) 13,539
Unrecognized:
Net gain 4,721 (11,492)
Prior service cost 1,437 1,756
-------- --------
Prepaid pension cost $ 5,945 $ 3,803
======== =======
Accumulated benefit obligation $ 28,505 $28,257
======== =======
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 $0.4 million in 2001, 2000 and 1999.
Employees who are participants in the Plan and who retire from the Company on or
after attaining age 55 after completing at least five years of service to the
Company are entitled to postretirement healthcare benefits coverage. These
benefits are subject to premiums, deductibles, copayment provisions and other
limitations. The Company may amend or change the Plan periodically. The Company
is not pre-funding its retiree medical plan.
The net periodic postretirement cost was as follows:
2001 2000 1999
---- ---- ----
(in thousands)
Service cost $208 $204 $159
Interest cost 414 427 290
Amortization of transition obligation 124 124 124
Loss 22 64 -
---- ---- ----
$768 $819 $573
==== ==== ====
Funding information as of October 1 was as follows:
2001 2000
---- ----
(in thousands)
Accumulated postretirement benefit obligation:
Retirees $2,761 $2,171
Fully eligible active participants 1,585 1,004
Other active participants 2,929 2,421
------ ------
Unfunded accumulated postretirement benefit obligation 7,275 5,596
Unrecognized net loss (2,481) (1,052)
Unrecognized transition obligation (1,365) (1,489)
------ ------
Accrued postretirement cost $3,429 $3,055
====== ======
For measurement purposes, an 8.0 percent annual rate of increase in healthcare
benefits was assumed for 2001; the rate was assumed to decrease gradually to 6
percent in 2005 and remain at that level thereafter. The healthcare cost trend
rate assumption has a significant effect on the amounts reported. A one percent
increase in the healthcare cost trend assumption would increase the service and
interest cost 23.8 percent and the net periodic postretirement cost 28.1
percent. A one percent decrease would reduce the service and interest cost by
18.3 percent and decrease the net periodic postretirement cost 17.2 percent. The
weighted-average discount rate used in determining the accumulated
postretirement benefit obligation was 7.5 percent.
27
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 $0.6 million for 2001 and $0.3 million for 2000.
(13) OTHER COMPREHENSIVE LOSS
The following table displays the related tax effects allocated to each component
of Other Comprehensive Loss for the year ended December 31, 2001:
Pre-tax Tax Expense Net-of-tax
Amount (Benefit) Amount
-------- ----------- ----------
(in thousands)
Net change in fair value of derivatives designated as cash flow
hedges (net of minority interest share of $2,875) $ (7,540) $ (3,016) $ (4,524)
======== ========= =========
Items of other comprehensive income (loss) were not significant in 2000 or 1999.
(14) INCOME TAXES
Income tax expense for the years indicated was:
2001 2000 1999
---- ---- ----
(in thousands)
Current $19,495 $21,290 $11,325
Deferred 4,522 1,293 1,121
------- ------- -------
$24,017 $22,583 $12,446
======= ======= =======
The temporary differences which gave rise to the net deferred tax liability were
as follows:
Years ended December 31, 2001 2000
---- ----
(in thousands)
Deferred tax assets:
Accelerated depreciation and other plant-related differences $ - $ 5,393
Regulatory asset 2,168 2,507
Valuation reserves 2,789 149
Employee benefits 3,103 2,922
Items of other comprehensive income 3,927 -
Other 4,920 1,970
--------- --------
16,907 12,941
--------- --------
Deferred tax liabilities:
Accelerated depreciation and other plant-related differences 67,302 59,955
Regulatory liability 1,425 1,447
Employee benefits 2,042 1,331
Items of other comprehensive income 911 -
Other 6,466 4,914
--------- --------
78,146 67,647
--------- --------
Net deferred tax liability $61,239 $54,706
========= ========
28
The effective tax rate differs from the federal statutory rate for the years
ended December 31, as follows:
2001 2000 1999
---- ---- ----
Federal statutory rate 35.0% 35.0% 35.0%
Amortization of tax credits (1.0) (1.0) (1.2)
Other 1.7 1.9 (2.5)
---- ---- ----
35.7% 35.9% 31.3%
==== ==== ====
(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, 2001, 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 to wholesale customers.
December 31: 2001 2000
---- ----
(in thousands)
Total assets
Electric utility $ 430,737 $ 501,416
Independent power 838,837 358,962
Discontinued operations - 247,548
---------- ----------
Total assets $1,269,574 $1,107,926
========== ==========
Capital expenditures
Electric utility $ 41,313 $ 25,257
Independent power 491,173 60,380*
---------- ----------
Total capital expenditures $ 532,486 $ 85,637
========== ==========
- ------------------------------
*Excludes the non-cash acquisition of Indeck Capital Inc. as described in
Note 16.
2001 2000 1999
---- ---- ----
(in thousands)
Operating revenues
Electric utility $213,210 $173,308 $133,222
Independent power 87,811 39,502 -
-------- -------- --------
Total operating revenues $301,021 $212,810 $133,222
======== ======== ========
Depreciation, depletion and amortization
Electric utility $ 15,773 $ 14,966 $ 15,552
Independent power 15,930 3,646 -
-------- -------- --------
Total depreciation, depletion and amortization $ 31,703 $ 18,612 $ 15,552
======== ======== ========
Operating income
Electric utility $ 84,108 $ 68,208 $ 52,286
Independent power 25,831 20,367 -
-------- -------- --------
Total operating income $109,939 $ 88,575 $ 52,286
======== ======== ========
29
Interest expense
Electric utility $ 15,780 $ 17,411 $ 13,830
Independent power 28,804 7,918 -
--------- --------- ---------
Total interest expense $ 44,584 $ 25,329 $ 13,830
========= ========= =========
Interest income
Electric utility $ 4,858 $ 5,658 $ 1,190
Independent power 381 100 -
--------- ---------- ---------
Total interest income $ 5,239 $ 5,758 $ 1,190
========= ========== =========
Income taxes
Electric utility $ 24,255 $ 19,469 $ 12,446
Independent power (238) 3,114 -
--------- ---------- ---------
Total income taxes $ 24,017 $ 22,583 $ 12,446
========= ========== =========
Net income (loss) before discontinued operations
Electric utility $ 45,238 $ 37,105 $ 27,286
Independent power (1,964) 3,173 -
--------- ---------- ---------
Total net income (loss) before discontinued
operations $ 43,274 $ 40,278 $ 27,286
========= ========== =========
(16) ACQUISITIONS
On April 11, 2001, Black Hills Energy Capital 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 risk. The transaction has been accounted for as an
asset purchase recorded at cost.
On August 31, 2001, Black Hills Energy Capital 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. The
facility currently has a 53 megawatt co-generation power plant in operation.
Most of the power from that facility is under a long-term contract expiring in
2024. The Company has sold 50 percent of this power plant to other parties;
however, 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 way, which is 100 percent owned by the Company.
The facility is scheduled to be fully operational in the third quarter of 2002
and will utilize LM-6000 technology. The power of the expansion is also under a
long-term contract, which expires in 2017. This contract for the expansion
requires the purchaser to provide fuel to the power plant when it is dispatched.
The cost for the entire facility is expected to be approximately $330 million
and the Company is in the process of obtaining long-term financing, which is
expected to be primarily non-recourse project debt.
The acquisition has been accounted for under the purchase method of accounting
and, accordingly, the purchase price of approximately $205 million has been
allocated to the acquired assets and liabilities based on preliminary estimates
of the fair values of the assets purchased and the liabilities assumed as of the
date of acquisition. Fair values in the allocation include assets acquired of
approximately $157 million (excluding goodwill and other intangibles) and
liabilities assumed of approximately $2 million. The estimated purchase price
allocations are subject to adjustment, generally within one year of the date of
the acquisition, should new or additional facts about the acquisitions become
available, any changes to the preliminary estimates will be reflected as an
adjustment to goodwill. The purchase price and related acquisition costs
exceeded the fair values assigned to net tangible assets by approximately $57
million, which was recorded as long-lived goodwill and other intangible assets.
30
In addition, during 2001, the Company 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.
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 with the Company issuing 1,536,747 shares of common stock to the
shareholders of Indeck priced at $21.98 per share, along with $4.0 million in
preferred stock, resulting in a purchase price of $37.8 million. Additional
consideration, consisting of common and preferred stock, may be paid in the form
of an earn-out over a four-year period beginning in 2000. As of December 31,
2001, $3.6 million has been paid under the earn-out. The earn-out consideration
is based on the acquired company's earnings during such period and cannot exceed
$35.0 million in total. Additional consideration paid out under the earn-out is
recorded as an increase to goodwill.
The acquisition was accounted for under the purchase method of accounting and,
accordingly, the purchase price was allocated to the acquired assets and
liabilities based on estimates of the fair values of the assets purchased and
the liabilities assumed as of the date of acquisition. Fair values in the
allocation include assets acquired of $151.1 million (excluding goodwill) and
liabilities assumed of $138.7 million. The purchase price and related
acquisition costs exceeded the fair values assigned to net tangible assets by
$25.4 million, which was recorded as goodwill and was being amortized over 25
years on a straight-line basis, during 2001 and 2000.
In addition during 2000, the Company made several step-acquisitions resulting in
consolidation of $169.5 million of assets and $138.8 million of liabilities. The
related transactions are as follows:
o Through various transactions, acquired an additional 27.11 percent interest
in Indeck North American Power Fund, L.P. and an additional 46.66 percent
interest in Indeck North American Power Partners, L.P., for $13.0 million
in cash.
o Acquired a 39.6 percent interest in each of Northern Electric Power
Company, L.P. and South Glens Falls Limited Partnership for $4.2 million in
cash.
o Acquired substantially all of the partnership interests in Middle Falls
Limited Partnership, Sissonville Limited Partnership and New York State Dam
Limited Partnership for $12.9 million in cash.
(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 2001
and 2000.
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
(in thousands)
2001:
Operating revenues $88,625 $84,077 $64,742 $63,577
Operating income 34,230 40,524 22,916 12,269
Net income from continuing operations 16,249 19,971 8,258 (1,204)
Net income 21,081 19,971 8,258 (1,204)
2000:
Operating revenues $33,299 $35,899 $75,762 $67,850
Operating income 13,643 12,981 36,444 25,507
Net income from continuing operations 7,225 7,095 13,046 12,912
Net income 9,061 8,061 16,322 19,404
31
(18) SUBSEQUENT EVENT (Unaudited)
On March 15, 2002, the Company closed on $135 million of senior secured
financing for the Arapahoe and Valmont Facilities. These projects have a total
of 210 megawatts in service and under construction and are located in the
Denver, Colorado area. Proceeds from this financing were used to refinance $53.8
million of an existing seven-year senior secured term project-level facility,
pay down approximately $50 million of short-term credit facility borrowings and
approximately $31 million will be used for future project construction.
On March 15, 2002, the Company paid $25.7 million to acquire an additional 30
percent interest in the Harbor Cogeneration Facility (the Facility), a 98
megawatt gas-fired plant located in Wilmington, California. This acquisition was
funded through borrowings under short-term revolving credit facilities and gives
the Company an 83 percent ownership interest and voting control of the Facility.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No change of accountants or disagreements on any matter of accounting principles
or practices or financial statement disclosure have occurred.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements
Financial statements required by Item 14 are listed in the index
included in Item 8 of Part II.
2. Schedules
All schedules have been omitted because of the absence of the
conditions under which they are required or because the required
information is included elsewhere in the financial statements
incorporated by reference in the Form 10-K.
3. Exhibits
3. Exhibits
Exhibit
Number 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)).
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).
32
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* Marketing, Capacity and Storage Service Agreement between Black Hills Power, Inc. and PacifiCorp dated
September 1, 1995 (filed as Exhibit 10(ag) to the Registrant's Form 10-K for 1995).
10.6* Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999).
10.7+ Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001.
10.8+ Severance, Confidentiality, Non-disclosure and Release Agreement dated October 30, 2001 between Black
Hills Corporation and Gary R. Fish.
10.9*+ Black Hills Corporation Nonqualified Deferred Compensation Plan dated June 1, 1999 (filed as Exhibit
10.13 to Black Hills Corporation's Form 10-K for 2000).
10.10*+ Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (filed as
Exhibit 10(gg) to the Registrant's Form 10-K for 1992).
10.11*+ Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1999).
10.12* Agreement and Plan of Merger, dated as of January 1, 2000, among Black Hills Corporation, Black Hills
Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier,
Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 2 to Schedule 13D filed on behalf of
the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett,
Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.13* Addendum to the Agreement and Plan of Merger, dated as of April 6, 2000, among Black Hills Corporation,
Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 3 to Schedule 13D filed on
behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R.
Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated
July 7, 2000).
10.14* Supplemental Agreement Regarding Contingent Merger Consideration, dated as of January 1, 2000, among
Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe,
Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr.
(Exhibit 4 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting
of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and
John W. Salyer, Jr., dated July 7, 2000).
10.15* Supplemental Agreement Regarding Restructuring of Certain Qualifying Facilities (Exhibit 5 to Schedule
13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe,
Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated
July 7, 2000).
10.16* Addendum to the Agreement and Plan of Merger, dated as of June 30, 2000, among Black Hills Corporation,
Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 6 to Schedule 13D filed on
behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R.
Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated
July 7, 2000).
10.17 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.
21 List of Subsidiaries of Black Hills Power, Inc.
99.1 Letter to Commission Pursuant to Temporary Note 3T.
- ----------
* 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
33
We have not filed any Reports on Form 8-K since September 30, 2001.
(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.
34
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 DANIEL P. LANDGUTH
-----------------------------
Daniel P. Landguth, Chairman
and Chief Executive Officer
Dated: March 29, 2002
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.
DANIEL P. LANDGUTH Director and Principal March 29, 2002
- ------------------------------------------ Executive Director
Daniel P. Landguth, Chairman,
and Chief Executive Officer
MARK T. THIES Principal Financial Officer March 29, 2002
- -------------------------------------------
Mark T. Thies, Senior Vice President and
Chief Financial Officer
ROXANN R. BASHAM Principal Accounting Officer March 29, 2002
- -------------------------------------------
Roxann R. Basham, Vice President-Controller,
and Assistant Secretary
ADIL M. AMEER Director March 29, 2002
- -------------------------------------------
Adil M. Ameer
BRUCE B. BRUNDAGE Director March 29, 2002
- -------------------------------------------
Bruce B. Brundage
DAVID C. EBERTZ Director March 29, 2002
- -------------------------------------------
David C. Ebertz
JOHN R. HOWARD Director March 29, 2002
- -------------------------------------------
John R. Howard
EVERETT E. HOYT Director and Officer March 29, 2002
- -------------------------------------------
Everett E. Hoyt, President and Chief
Operating Officer
KAY S. JORGENSEN Director March 29, 2002
- -------------------------------------------
Kay S. Jorgensen
DAVID S. MANEY Director March 29, 2002
- -------------------------------------------
David S. Maney
THOMAS J. ZELLER Director March 29, 2002
- -------------------------------------------
Thomas J. Zeller
35
INDEX TO EXHIBITS
Exhibit
Number 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 the Registrant's Registration
Statement on Form S-4 (No. 333-52664)).
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* Marketing, Capacity and Storage Service Agreement between Black Hills Power, Inc. and PacifiCorp dated
September 1, 1995 (filed as Exhibit 10(ag) to the Registrant's Form 10-K for 1995).
10.6* Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999).
10.7+ Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001.
10.8+ Severance, Confidentiality, Non-disclosure and Release Agreement dated October 30, 2001, between Black Hills
Corporation and Gary R. Fish.
10.9*+ Black Hills Corporation Nonqualified Deferred Compensation Plan dated June 1, 1999 (filed as Exhibit 10.13 to
Black Hills Corporation's Form 10-K for 2000).
10.10*+ Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (filed as Exhibit 10(gg)
to the Registrant's Form 10-K for 1992).
10.11*+ Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1999).
36
10.12* Agreement and Plan of Merger, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy
Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 2 to Schedule 13D filed on behalf of the former
shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier,
Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.13* Addendum to the Agreement and Plan of Merger, dated as of April 6, 2000, among Black Hills Corporation, Black
Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier,
Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 3 to Schedule 13D filed on behalf of the
former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha
Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.14* Supplemental Agreement Regarding Contingent Merger Consideration, dated as of January 1, 2000, among Black
Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R.
Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 4 to Schedule
13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe,
Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July
7, 2000).
10.15* Supplemental Agreement Regarding Restructuring of Certain Qualifying Facilities (Exhibit 5 to Schedule 13D
filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle
R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.16* Addendum to the Agreement and Plan of Merger, dated as of June 30, 2000, among Black Hills Corporation, Black
Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier,
Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 6 to Schedule 13D filed on behalf of the
former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha
Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.17 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.
21 List of Subsidiaries of Black Hills Power, Inc.
99.1 Letter to Commission Pursuant to Temporary Note 3T.
- ----------
* Previously filed as part of the filing indicated and incorporated by reference
herein.
+ Indicates a board of director or management compensatory plan.
37