SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
November 25, 2002
(Date of earliest event reported)
BLACK HILLS CORPORATION
(Exact name of Registrant as specified in its charter)
South Dakota 001-31303 46-0458824
(State of Incorporation) (Commission File No.) (IRS Employer
Identification Number)
625 Ninth Street
P. O. Box 1400
Rapid City, South Dakota 57709
(Address of principal executive offices)
(605) 721-1700
(Registrant's telephone number, including area code)
Not Applicable
(Former name or former address if changed since last report)
1
Item 5. Other Events
Black Hills Corporation announced today that our new independent public
accountants, Deloitte & Touche LLP, have completed the audit of Black Hills
Corporation's 2001, 2000 and 1999 financial statements that were originally
audited by Arthur Andersen LLP. The reissued financial statements, including the
report of Deloitte & Touche, are included in this Form 8-K. The net income and
earnings per share in the reissued financial statements are unchanged from
amounts previously reported in our Form 10-K. Black Hills Corporation issued a
press release to announce the reissuance of its financial statements, which is
included as Exhibit 99.1 and incorporated herein by reference.
Because Black Hills Corporation is reissuing the financial statements as of a
current date, three areas of the reissued financial statements being filed today
differ from Black Hills Corporation's 2001 Annual Report on Form 10-K as
previously filed:
o Discontinued operations presentation in the financial statements for
the disposition of Black Hills Coal Network;
o Reporting of energy trading results on a net basis; and
o Disclosure of various subsequent events occurring since the 2001
financial statements were previously issued.
The discontinued operations disclosures and presentation changes in the reissued
financial statements relate to Black Hills Corporation's second quarter 2002
plan to dispose of its coal marketing subsidiary, Black Hills Coal Network,
Inc., and the completion of the sale in July 2002. Securities and Exchange
Commission (SEC) rules require that once operations are reported as discontinued
(as they were in the second and third quarter Form 10-Qs for 2002), subsequent
financial statements must present such operations on a consistent basis.
Discontinued operations disclosures have been added in a new footnote to Black
Hills Corporation's reissued financial statements.
The trading reclassifications relate to new reporting requirements issued in
2002 by the Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board. The EITF's decision requires that beginning in 2003 trading
revenues and expenses be presented on a net basis. Black Hills elected to
reclassify trading costs of approximately $1.0 billion, $1.3 billion and $0.6
billion in 2001, 2000 and 1999, respectively against trading revenues to present
net trading margins in Black Hills Corporation's reissued income statements.
Given the current release of the reissued financial statements, reporting rules
require that certain subsequent events in 2002 be disclosed to the extent they
are relevant to the 2001, 2000 and 1999 financial statements. The reissued Black
Hills Corporation financial statements include updated disclosures of various
events in 2002.
The disclosure and presentation changes did not affect net income or earnings
per share from amounts previously reported for Black Hills Corporation. Also,
total assets, liabilities and shareholders' equity remain unchanged in the
reissued financial statements from amounts previously reported for Black Hills
Corporation. The discontinued operations and the trading reclassifications,
however, did reduce total revenues of Black Hills Corporation from amounts
previously reported and did reclassify other items on the income statements and
balance sheets.
The following information is included as part of this Form 8-K:
Page
----
Selected Financial Data 3
Management's Discussion and Analysis of Financial Condition
and Results of Operations 4-13
Financial Statements and Supplementary Data
Report of Independent Public Accountants 14
Consolidated Statements of Income 15
Consolidated Balance Sheets 16
Consolidated Statements of Cash Flow 17
Consolidated Statements of Common Stockholders' Equity 18
Notes to Consolidated Financial Statements 19-50
2
SELECTED FINANCIAL DATA
Years ended December 31, 2001 2000 1999 1998 1997
---- ---- ---- ---- ----
TOTAL ASSETS (in thousands) $1,658,767 $1,320,320 $668,492 $559,417 $508,741
PROPERTY AND INVESTMENTS
(in thousands)
Total property and investments $1,564,664 $1,072,013 $699,928 $619,549 $598,306
Accumulated depreciation and depletion 328,325 277,797 245,992 229,942 197,179
Capital expenditures 594,142 173,517* 152,948 27,225 28,319
CAPITALIZATION (in thousands)
Long-term debt $415,798 $307,092 $160,700 $162,030 $163,360
Preferred stock equity 5,549 4,000 - - -
Common stock equity 509,615 278,346 216,606 206,666 205,403
-------- -------- -------- -------- --------
Total capitalization $930,962 $589,438 $377,306 $368,696 $368,763
======== ======== ======== ======== ========
CAPITALIZATION RATIOS
Long-term debt 44.7% 52.1% 42.6% 43.9% 44.3%
Preferred stock equity 0.6 0.7 - - -
Common stock equity 54.7 47.2 57.4 56.1 55.7
----- ----- ----- ----- -----
Total 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
TOTAL OPERATING REVENUES
(in thousands) $461,938 $292,142 $185,287 $180,674 $171,936
INCOME FROM CONTINUING
OPERATIONS (in thousands) $87,584 $52,812 $37,738 $25,808** $32,359
DIVIDENDS PAID ON COMMON STOCK
(in thousands) $28,517 $23,527 $22,602 $21,737 $20,540
COMMON STOCK DATA
(in thousands)
Shares outstanding, average 25,374 22,118 21,445 21,623 21,692
Shares outstanding, average diluted 25,771 22,281 21,482 21,665 21,706
Shares outstanding, end of year 26,652 22,921 21,372 21,578 21,705
(in dollars)
Basic earnings per average share -
Continuing operations $ 3.43 $ 2.39 $ 1.76 $ 1.19 $ 1.49
Discontinued operations 0.02 - (0.03) - -
--------- --------- --------- --------- ---------
Total $ 3.45 $ 2.39 $ 1.73 $ 1.19** $ 1.49
========= ========= ========= ========= =========
Diluted earnings per average share -
Continuing operations $ 3.40 $ 2.37 $ 1.76 $ 1.19 $ 1.49
Discontinued operations 0.02 - (0.03) - -
--------- --------- --------- --------- ---------
Total $ 3.42 $ 2.37 $ 1.73 $ 1.19** $ 1.49
========= ========= ========= ========= =========
Dividends paid per share $ 1.12 $ 1.08 $ 1.04 $ 1.00 $ 0.95
Book value per share, end of year $ 19.12 $ 12.14 $ 10.14 $ 9.58 $ 9.46
RETURN ON COMMON STOCK EQUITY
(year-end) 17.2% 19.0% 17.1% 12.5%** 15.8%
*Excludes the non-cash acquisition of Indeck Capital, Inc.
**Includes impact of $8.8 million, or 41 cents per average share,
write-down of certain oil and gas properties
3
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
We are a growth oriented, diversified energy holding company operating
principally in the United States. Our unregulated and regulated businesses have
expanded significantly in recent years. Our integrated energy group, Black Hills
Energy, Inc. (formerly Black Hills Energy Ventures, Inc.), produces and markets
electric power and fuel. We produce and sell electricity in a number of markets,
with a strong emphasis in the western United States. We also produce coal,
natural gas and crude oil, primarily in the Rocky Mountain region, transport
crude oil in Texas and market energy products nationwide. Our electric utility,
Black Hills Power, Inc., serves an average of 59,600 customers in South Dakota,
Wyoming and Montana. Our communications group offers state-of-the-art broadband
communications services to over 23,700 residential and business customers in
Rapid City and the northern Black Hills region of South Dakota through Black
Hills FiberCom, LLC.
In 2002, we decided to discontinue operations in our coal marketing business due
to challenges encountered in marketing our Wyodak coal from the Powder River
Basin of Wyoming to East Coast markets. The non-strategic assets were sold
effective August 1, 2002.
The following discussion should be read in conjunction with Item 7. -
Management's Discussion and Analysis of Financial Condition and Results of
Operations - included in our 2001 Annual Report on Form 10-K and with Item 2. -
Management's Discussion and Analysis of Financial Condition and Results of
Operations - included in our 2002 Periodic Reports on Form 10-Q that have been
filed with the Securities and Exchange Commission.
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 from
continuing operations were as follows:
2001 2000 1999
---- ---- ----
Revenue:
Integrated energy 50% 38% 28%
Electric utility 46 59 72
Communications 4 3 -
--- --- ---
100% 100% 100%
=== === ===
Net income (loss) from
continuing operations:
Integrated energy 66% 56% 33%
Electric utility 52 70 73
Communications and other (18) (26) (6)
--- --- ---
100% 100% 100%
=== === ===
During the second quarter of 2002, we adopted a plan to dispose of our coal
marketing subsidiary, Black Hills Coal Network. The sale and disposal was
finalized in July 2002. Results of operations have been restated to reflect the
discontinued operations.
4
2001 Compared to 2000
Consolidated income from continuing operations for 2001 was $87.6 million,
compared to $52.8 million in 2000, or $3.40 per average common share in 2001,
compared to $2.37 per average common share in 2000. Income from discontinued
operations was $0.5 million or $0.02 per share in 2001 compared to $36,000 in
2000. This equates to a 17.2 percent and 19.0 percent return on year-end common
equity in 2001 and 2000, respectively. The return on year-end common equity in
2001 was diluted due to the net proceeds of $163 million from the public stock
offering in 2001.
We reported record earnings in 2001, primarily due to strong natural gas
marketing activity, increased fuel production, expanded power generation and
increased wholesale off-system electric utility sales. Strong results in our
integrated energy business group and electric utility business group were
partially offset by losses in our communications business. Unusual energy market
conditions stemming primarily from gas and electricity shortages in the West
contributed to our strong financial performance in 2001 and 2000. There was an
approximately $1.40 and $0.40 contribution to 2001 and 2000 earnings per share,
respectively, due to prevailing prices of gas and electricity and unusually wide
gas trading margins in the last part of year 2000 and first half of 2001.
Consolidated revenues were $461.9 million in 2001 compared to $292.1 million in
2000. Revenue increased in all segments. Daily volumes of natural gas marketed
increased 22 percent from 860,800 million British thermal units per day in 2000
to 1,047,700 million British thermal units in 2001. Prices of financial and
physical natural gas marketed decreased from an average of $2.77 per million
British thermal units in 2000 to $2.14 per million British thermal units in
2001.
Earnings in 2001 included a $4.4 million after-tax charge ($0.17 per share) for
a 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. We have taken action to mitigate this
exposure. We are seeking authority to "net," or offset certain obligations with
Enron and its subsidiaries, both payable and receivable, among our subsidiaries.
If we are successful in these efforts, substantially all of the financial value
of the fuel swap could be recovered, and we would not have any remaining
exposure to Enron and its bankrupt subsidiaries.
Earnings in 2001 also reflect a $0.12 per share charge for employee stock bonus
awards and the funding of a new non-profit foundation to advance our charitable
and philanthropic endeavors. Both of these transactions were funded with Black
Hills Corporation common stock.
2000 Compared to 1999
Consolidated income from continuing operations for 2000 was $52.8 million,
compared to $37.7 million in 1999, or $2.37 per average common share in 2000,
compared to $1.76 per average common share in 1999. This equates to a 19.0
percent and 17.1 percent return on year-end common equity in 2000 and 1999,
respectively. Income (loss) from discontinued operations was $36,000 in 2000
compared to $(0.7) million or $(0.03) per share in 1999.
Earnings growth in 2000 was primarily due to strong natural gas marketing
activity, increased fuel production, expanded power generation and increased
wholesale off-system electric utility sales. Strong results in our integrated
energy business group were partially offset by losses in our communications
business. Unusual energy market conditions stemming primarily from gas and
electricity shortages in the West during the last part of 2000 contributed to
our strong financial performance. There was an approximately $0.40 contribution
to 2000 earnings per share due to higher prevailing prices of gas and
electricity and unusually wide gas trading margins.
5
Consolidated revenues were $292.1 million in 2000 compared to $185.3 million in
1999. The growth in revenues in 2000 was a result of high energy commodity
prices and increased volumes of fuel marketed, primarily as a result of extreme
price volatility in the western markets, acquisitions and growth in the
integrated energy business group and increases in off-system sales by our
electric utility. Prices of financial and physical natural gas marketed
increased from an average of $1.38 per million British thermal units in 1999 to
$2.77 per million British thermal units in 2000.
The following business group and segment information does not include
intercompany eliminations.
Integrated Energy Group
2001 2000 1999
---- ---- ----
(in thousands)
Revenue:
Energy marketing $ 83,884 $ 40,204 $ 7,640
Power generation 80,233 20,083 -
Oil and gas 33,408 20,328 13,052
Coal mining 31,800 30,530 31,095
----------- ----------- ---------
Total revenue 229,325 111,145 51,787
Expenses 126,429 49,957 36,726
----------- ----------- ---------
Operating income $ 102,896 $ 61,188 $ 15,061
=========== =========== =========
Net income $ 57,930 $ 29,379 $ 12,554
=========== =========== =========
The following is a summary of sales volumes of our coal, oil and natural gas
production and various measures of power generation:
2001 2000 1999
---- ---- ----
Tons of coal sold 3,518,000 3,050,000 3,180,000
Barrels of oil sold 445,500 334,000 318,000
Mcf of natural gas sold 4,619,500 3,274,000 2,791,000
Mcf equivalent sales 7,292,500 5,278,000 4,698,000
MWs of independent power
capacity in service 617 250 -
MWs of independent power
capacity under construction 364 470 -
The following is a summary of average daily energy marketing volumes:
2001 2000 1999
---- ---- ----
Natural gas - MMBtus 1,047,700 860,800 635,500
Crude oil - barrels 36,500 44,300 19,270
2001 Compared to 2000
Net income of our integrated energy group nearly doubled in 2001 compared to
2000. These strong earnings resulted primarily from the unusually high prices of
natural gas and high gas trading margins received in western markets during the
first half of 2001, an increase in volumes marketed and fuel production, and
expanded power generation.
6
In addition, in 2001, we reached a settlement of ongoing litigation with
PacifiCorp concerning rights and obligations under a coal supply agreement under
which PacifiCorp purchased coal from our coal mine to meet the coal requirements
of the Wyodak Power Plant. As a result of this settlement, we recognized $5.6
million pre-tax non-operating income. In addition, we sold the "North Conveyor
System" which resulted in a $2.6 million pre-tax gain. See Note 10 of Notes to
Consolidated Financial Statements.
The integrated energy business group's revenues more than doubled to $229
million in 2001 compared to $111 million in 2000. The increase was related to a
full year of independent power operations revenues related to the July 2000
acquisition of Indeck Capital and an increase in revenue from fuel production
and gas marketing. Daily volumes of natural gas marketed increased 22 percent.
The integrated energy business group's total operating expenses increased 153
percent due to the expanded power production and increased volumes of fuel
production and energy marketed. Operating income increased over 68 percent from
2000 levels due to higher production volumes.
2000 Compared to 1999
Net income of our integrated energy group increased 134 percent in 2000 compared
to 1999. Operating expenses and operating income increased over 36 percent and
306 percent, respectively. These increases resulted primarily from our gas
marketing operations--which experienced a dramatic increase in both trading
volumes and margins, a significant increase in fuel production volumes, record
fuel and power prices and expanded power generation, including the acquisition
of Indeck Capital.
The integrated energy business group's revenues increased 115 percent in 2000
compared to 1999. The revenue increase was a direct result of gas and
electricity shortages in the West Coast markets and the closing of the Indeck
Capital acquisition. Daily volumes of natural gas marketed increased 35 percent.
Energy Marketing
Our energy marketing companies produced the following results:
2001 2000 1999
---- ---- ----
(in thousands)
Revenue $83,884 $40,204 $7,640
Operating income (loss) 53,662 24,113 (1,366)
Net income 34,566 13,973 486
2001 Compared to 2000
Earnings from the energy marketing segment increased $20.6 million due
substantially to high gas margins received in the first half of 2001, as well as
a 22 percent increase in natural gas average daily volumes marketed in 2001
compared to 2000. Revenues increased 109 percent from 2000 primarily due to
higher daily volumes and the high gas margins.
The unusual energy market conditions stemming primarily from natural gas and
electricity shortages in California and our ability to capture the higher
margins contributed significantly to the strong financial performance.
2000 Compared to 1999
The strong increase in earnings in 2000 compared to 1999 was due to the unusual
energy market conditions that existed in the last half of 2000 stemming from the
natural gas and electricity shortages in California. Average daily volumes of
natural gas marketed increased 35 percent in 2000 compared to 1999.
7
Power Generation
Our power generation segment produced the following results:
2001 2000 1999
---- ---- ----
(in thousands)
Revenue $80,233 $20,083 $ -
Operating income (loss) 27,455 20,374 (157)
Net income (loss) 1,576 3,242 (108)
2001 Compared to 2000
2001 reflects the first full year of operations of our power generation
segment and our continued expansion of generation facilities. At December 31,
2001, we owned 617 net megawatts in currently operating plants. Of these 617 net
megawatts, approximately 90 percent are under contracts or tolling arrangements
with at least one year remaining. At year end, an additional 364 megawatts of
generating capacity was under construction. Substantially all of this output
will be sold pursuant to existing long-term contracts. The increased production
capacity was offset by a $4.4 million after-tax charge for Enron exposure,
additional reserves for exposure to western power markets and reduced water flow
at hydro power plants in New York.
2000 Compared to 1999
Results from the power generation segment were not significant in 1999. In
July 2000, we completed the acquisition of Indeck Capital, representing a
significant advancement of our position in the power generation segment. At
December 31, 2000, we owned 250 net megawatts of generating capacity in
operating plants and had 470 megawatts under construction.
Oil and Gas
Oil and gas operating results were as follows:
2001 2000 1999
---- ---- ----
(in thousands)
Revenue $33,408 $20,328 $13,052
Operating income 15,193 7,906 3,978
Net income 10,197 4,992 2,462
The following is a summary of our oil and gas reserves at December 31:
2001 2000 1999
---- ---- ----
Barrels of oil (in thousands) 4,055 4,413 4,109
Mcf of natural gas 24,071 18,404 19,460
Total in Mcf equivalents 48,401 44,882 44,114
These reserves are based on reports prepared by Ralph E. Davis Associates, Inc.,
an independent consulting and engineering firm. Reserves were determined using
constant product prices at the end of the respective years. Estimates of
economically recoverable reserves and future net revenues are based on a number
of variables, which may differ from actual results. We intend to increase our
net proved reserves by selectively increasing our oil and gas exploration and
development activities and by acquiring producing properties.
8
2001 Compared to 2000
Record net income in 2001 was primarily a result of a 27 percent increase in the
average price received and a 38 percent increase in production volumes. The
increase in gas reserves at December 31, 2001 was due to strong drilling results
and reserve acquisitions.
In 2001, we acquired the operating and non-operating interests in 74 gas and oil
wells located in Colorado and Wyoming from Stewart Petroleum Corporation of
Denver, Colorado, for approximately $10 million. The acquired interest in these
fuel assets represents approximately 10 billion cubic feet equivalent of natural
gas. The acquisition increased our proved reserves by approximately 22 percent
(based on year-end 2000 reserve estimates) and our current production rates by
10 percent.
2000 Compared to 1999
The increase in net income in 2000 was primarily the result of record natural
gas prices, higher crude oil prices, and a significant increase in production
volumes. The increase in economically recoverable oil reserves at December 31,
2000 was due to improved product prices.
Coal Mining
Coal mining results were as follows:
2001 2000 1999
---- ---- ----
(in thousands)
Revenue $31,800 $30,530 $31,095
Operating income 6,586 8,795 12,606
Net income 11,591 7,172 9,714
2001 Compared to 2000
Coal mining earnings increased $4.4 million as a result of a coal contract
settlement, a gain on the sale of mining equipment and a 15 percent increase in
tons sold, partially offset by lower average coal prices due to a coal contract
settlement and an increase in mining related expenses. Tons of coal sold
increased primarily due to the commencement of sales through our train load-out
facility.
In 2001, we reached a settlement of ongoing litigation with PacifiCorp
concerning rights and obligations under a coal supply agreement under which
PacifiCorp purchased coal from our coal mine to meet the coal requirements of
the Wyodak Power Plant. As a result of this settlement, we recognized $5.6
million pre-tax non-operating income. In addition, we sold the "North Conveyor
System" which resulted in a $2.6 million pre-tax gain. See Note 10 of Notes to
Consolidated Financial Statements.
2000 Compared to 1999
A planned five-week outage at the Wyodak Plant resulted in lower coal sales and
earnings in 2000 compared to 1999.
Electric Utility Group
2001 2000 1999
---- ---- ----
(in thousands)
Revenue $212,355 $173,308 $133,222
Operating expenses 128,247 105,100 80,936
-------- -------- --------
Operating income $ 84,108 $ 68,208 $ 52,286
======== ======== ========
Net income $ 45,238 $ 37,178 $ 27,362
======== ======== ========
9
We currently have a winter peak load 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). At December 31, 2001, an additional 40 megawatts of generating
capacity was 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 average wholesale power prices.
Electric utility operating expenses increased 22 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 non-cash charge
related to the contribution of Black Hills Corporation Common Stock 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.
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 three 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.
10
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.
Communications Group
2001 2000 1999
---- ---- ----
(in thousands)
Revenue - external* $ 20,258 $ 7,689 $ 278
Revenue - intersegment* 4,250 3,682 3,145
Operating expenses 37,758 23,857 7,070
-------- ---------- --------
Operating loss $(13,250) $ (12,486) $ (3,647)
======== ========== ========
Net loss $(12,300) $ (11,382) $ (968)
======== ========== ========
---------------------------
*External revenue is revenue from our broadband communications business.
Intersegment revenue is primarily revenue from our information services company
derived from providing services to our other business segments. This
intersegment revenue and associated expenses are eliminated in the consolidation
process.
2001 2000 1999
---- ---- ----
Residential customers 15,660 8,368 143
Business customers 2,250 646 110
Fiber optic backbone miles 242 210 200
Hybrid fiber coaxial cable miles 737 588 100
In September 1998, we formed our broadband communications business to
provide facilities-based communications services for Rapid City and the northern
Black Hills of South Dakota. As of December 31, 2001, we had invested
approximately $125 million in state-of-the-art technology that offers local and
long distance telephone service, expanded cable television service, Internet
access, and high-speed data and video services. We began serving communications
customers in late 1999 and market our services to schools, hospitals, cities,
economic development groups, and business and residential customers. The
build-out is approximately 85 percent complete at December 31, 2001. Losses are
expected to continue as we proceed with building the network and increasing the
customer base. We expect our communications group will sustain approximately
$7.0 million in net losses in 2002, with annual losses decreasing thereafter and
profitability expected by 2004. The recovery of capital investment and future
profitability are dependent primarily on our ability to attract new customers.
If we are unable to attract additional customers or technological advances make
our network obsolete, we could have a material write-down of assets.
2001 Compared to 2000
Our customer base nearly doubled in 2001 to 15,660 residential customers and
2,250 business customers. The increase in revenues from a larger customer base
in 2001 was partially offset by increases in reserves for inventory and carrier
billings and increased interest expense. Operating expense increased due to the
expansion of the business. Operating performance in 2001 was in line with our
expectations.
2000 Compared to 1999
Operating losses in 2000 were attributable to increased interest, depreciation
and operating expenses. Operating losses in 1999 were primarily due to start-up
organizational costs, increased depreciation expense and increased interest
expense associated with the capital deployment.
11
Safe Harbor for Forward Looking Information
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 (Reform Act), we are hereby filing cautionary
statements identifying important factors that could cause our actual results to
differ materially from those projected in forward-looking statements (as such
term is defined in the Reform Act) made by or on behalf of the Company in this
Current Report on Form 8-K, our Annual Report on Form 10-K, Annual Report,
Quarterly Report on Form 10-Q, and presentations, or in response to questions or
otherwise. These statements concern our plans, expectations and objectives for
future operations. All statements, other than statements of historical fact that
address activities, events or developments that we expect, believe or anticipate
will or may occur in the future are forward-looking statements.
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 among other things:
o unanticipated developments in the western power markets, including
unanticipated governmental intervention, deterioration in the financial
condition of counterparties, default on amounts due from counterparties,
adverse changes in current or future litigation, adverse changes in the
tariffs of the California Independent System Operator, market disruption
and adverse changes in energy and commodity supply, volume and pricing and
interest rates;
o prevailing governmental policies and regulatory actions, with respect to
allowed rates of return, industry and rate structure, acquisition and
disposal of assets and facilities, operation and construction of plant
facilities, recovery of purchased power and other capital investments, and
present or prospective wholesale and resale competition;
o the State of California's efforts to reform its long-term power purchase
contracts and recover refunds for alleged price manipulation;
o changes in and compliance with environmental and safety laws and policies;
o weather conditions;
o population growth and demographic patterns;
o competition for retail and wholesale customers;
o pricing and transportation of commodities;
o market demand, including structural market changes;
o changes in tax rates or policies or in rates of inflation;
o changes in project costs;
o unanticipated changes in operating expenses or capital expenditures;
o capital market conditions;
o technological advances by competitors;
o competition for new energy development opportunities;
o legal and administrative proceedings that influence our business and
profitability;
o the effects on our business, including the availability of insurance,
resulting from the terrorist actions on September 11, 2001, or any other
terrorist actions or responses to such actions;
o the effects on our business resulting from the financial difficulties of
Enron and other energy companies, including their effects on liquidity in
the trading and power industry, and their effects on the capital markets
views of the energy or trading industry, and our ability to access the
capital markets on the same favorable terms as in the past;
o the effects on our business in connection with a lowering of our credit
rating (or actions we may take in response to changing credit ratings
criteria), including, increased collateral requirements to execute our
business plan, demands for increased collateral by our current
counterparties, refusal by our current or potential counterparties or
customers to enter into transactions with us and our inability to obtain
credit or capital in amounts or on terms favorable to us; and
o other factors discussed from time to time in our filings with the SEC.
12
Any forward-looking statement speaks only as to the date on which that statement
is made, and we undertake no obligation to update any forward-looking statement
to reflect events or circumstances after the date on which that statement is
made or to reflect the occurrence of an anticipated event. New factors emerge
from time to time, and it is not possible for management to predict all such
factors, nor can it assess the impact of any such factor on the business or the
extent to which factor, or combination of factors, may cause results to differ
materially from those contained in any forward-looking statement.
13
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Shareholders of Black Hills Corporation
We have audited the accompanying consolidated balance sheets of Black Hills
Corporation (a South Dakota corporation) and Subsidiaries as of December 31,
2001 and 2000, and the related consolidated statements of income, common
stockholders' equity and cash flows for 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 of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Black Hills Corporation and
Subsidiaries as of December 31, 2001, and 2000, and the results of their
operations and their cash flows for each of the years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company adopted Statement of Financial Accounting Standards
No. 133, Accounting for Derivative Instruments and Hedging Activities, which
changed its method of accounting for certain commodity contracts and other
derivatives.
DELOITTE & TOUCHE, LLP
Minneapolis, Minnesota,
November 15, 2002
14
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 2001 2000 1999
---- ---- ----
(in thousands, except per share amounts)
Operating revenues $461,938 $292,142 $185,287
-------- -------- --------
Operating expenses:
Fuel and purchased power 86,245 60,302 31,825
Operations and maintenance 65,556 46,054 36,463
Administrative and general 78,339 43,318 16,518
Depreciation, depletion and amortization 53,811 32,624 24,827
Taxes, other than income taxes 22,993 14,904 12,880
-------- -------- --------
306,944 197,202 122,513
-------- -------- --------
Equity in earnings of unconsolidated subsidiaries 14,776 20,149 -
-------- -------- --------
Operating income 169,770 115,089 62,774
-------- -------- -------
Other income (expense):
Interest expense (39,479) (30,136) (15,226)
Interest income 2,372 7,067 3,597
Other expense (4,759) (2,278) (2,920)
Other income 14,016 4,685 3,797
-------- -------- --------
(27,850) (20,662) (10,752)
-------- -------- --------
Income from continuing operations before minority
interest and income taxes 141,920 94,427 52,022
Minority interest (4,186) (11,273) 1,935
Income taxes (50,150) (30,342) (16,219)
-------- -------- --------
Income from continuing operations 87,584 52,812 37,738
Income (loss) from discontinued operations,
net of taxes 493 36 (671)
-------- -------- --------
Net income 88,077 52,848 37,067
Preferred stock dividends (527) (78) -
-------- -------- --------
Net income available for common stock $ 87,550 $ 52,770 $ 37,067
======== ======== ========
Earnings per share of common stock:
Basic-
Continuing operations $ 3.43 $ 2.39 $ 1.76
Discontinued operations 0.02 - (0.03)
-------- -------- --------
Total $ 3.45 $ 2.39 $ 1.73
======== ======== ========
Diluted-
Continuing operations $ 3.40 $ 2.37 $ 1.76
Discontinued operations 0.02 - (0.03)
-------- -------- --------
Total $ 3.42 $ 2.37 $ 1.73
======== ======== ========
Weighted average common shares outstanding:
Basic 25,374 22,118 21,445
======== ======== ========
Diluted 25,771 22,281 21,482
======== ======== ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
15
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
At December 31, 2001 2000
---- ----
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 29,956 $ 24,290
Securities available-for-sale 3,550 2,113
Receivables (net of allowance for doubtful accounts of $5,913
and $3,631, respectively) 110,831 295,908
Derivative assets 38,144 62,531
Other assets 29,992 23,490
Assets of discontinued operations 10,090 12,009
--------- ---------
222,563 420,341
--------- ---------
Investments 59,895 50,137
--------- ---------
Property, plant and equipment 1,564,664 1,072,013
Less accumulated depreciation and depletion (328,325) (277,797)
--------- ---------
1,236,339 794,216
--------- ---------
Other assets:
Derivative assets 6,407 391
Goodwill 28,693 29,891
Intangible assets 86,528 16,281
Other 18,342 9,063
--------- ---------
139,970 55,626
--------- ---------
$1,658,767 $1,320,320
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 96,218 $ 241,799
Accrued liabilities 39,085 49,517
Current maturities of long-term debt 35,904 13,960
Notes payable 360,450 211,000
Derivative liabilities 42,681 57,968
Liabilities of discontinued operations 8,820 11,080
---------- ----------
583,158 585,324
---------- ----------
Long-term debt, net of current maturities 415,798 307,092
---------- ----------
Deferred credits and other liabilities:
Federal income taxes 75,302 62,679
Derivative liabilities 7,119 3,532
Other 42,693 41,386
---------- ----------
125,114 107,597
---------- ----------
Minority interest in subsidiaries 19,533 37,961
---------- ----------
Commitments and contingencies (Notes 10, 11, 15 and 18)
Stockholders' equity:
Preferred stock - no par Series 2000-A; 21,500 shares authorized; issued
and outstanding: 5,177 shares in 2001, 4,000 shares in 2000 5,549 4,000
---------- ----------
Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized;
issued: 26,890,943 shares in 2001 and 23,302,111 shares in 2000 26,891 23,302
Additional paid-in capital 240,454 73,442
Retained earnings 250,515 191,482
Treasury stock, at cost (4,503) (9,067)
Accumulated other comprehensive loss (3,742) (813)
--------- ---------
509,615 278,346
--------- ---------
Total stockholders' equity 515,164 282,346
--------- ---------
$1,658,767 $1,320,320
========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
16
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2001 2000 1999
---- ---- ----
(in thousands)
Operating activities:
Net income available for common $87,550 $52,770 $37,067
Principal non-cash items-
(Income) loss from discontinued operations (493) (36) 671
Depreciation, depletion and amortization 53,811 32,624 24,827
Issuance of treasury stock for operating expenses (Note 4) 4,243 - -
Provision for valuation allowances 9,632 3,232 (3)
Net change in derivative assets and liabilities 2,498 (1,422) -
Gain on sales of assets (2,587) (3,736) (2,541)
Deferred income taxes and investment tax credits 9,792 1,937 2,291
Undistributed earnings in associated companies (9,287) (3,672) -
Minority interest 4,186 11,273 (1,935)
Change in operating assets and liabilities-
Accounts receivable and other current assets 176,974 (208,078) (2,941)
Accounts payable and other current liabilities (157,061) 181,058 11,238
Other, net (852) 1,691 5,427
--------- --------- ---------
178,406 67,641 74,101
--------- --------- ---------
Investing activities:
Property, plant and equipment additions (378,465) (134,855) (100,629)
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 (471) (9,974) (52,319)
Proceeds from sales of assets 2,900 5,500 3,463
Available-for-sale securities purchased - - (7,870)
Available-for-sale securities sold - 4,660 22,959
---------- --------- ---------
(591,713) (163,357) (134,396)
---------- --------- ---------
Financing activities:
Dividends paid on common stock (28,517) (23,527) (22,602)
Treasury stock issued (purchased) 321 (1,037) (4,949)
Common stock issued 168,522 3,854 424
Increase in short-term borrowings, net 149,450 75,998 90,900
Long-term debt - issuance 144,610 60,082 -
Long-term debt - repayments (13,960) (1,330) (1,330)
Subsidiary distributions to minority interests (1,453) (10,900) -
--------- --------- ---------
418,973 103,140 62,443
--------- --------- ---------
Increase in cash and cash equivalents 5,666 7,424 2,148
Cash and cash equivalents:
Beginning of year 24,290 16,866 14,718
--------- --------- ---------
End of year $ 29,956 $ 24,290 $ 16,866
========= ========= =========
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $ 39,563 $ 31,094 $ 15,098
Income taxes $ 40,374 $ 18,880 $ 13,329
Noncash net assets acquired through issuance of common
and preferred stock (Note 15) $ 3,628 $ 34,493 $ -
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
17
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Accumulated
Common Stock Additional Treasury Stock Other
---------------------- Paid-In Retained ----------------- Comprehensive
Shares Amount Capital Earnings Shares Amount Income (loss) Total
------ ------ ------- -------- ------ ------ ------------- -----
(in thousands)
Balance at
December 31, 1998 21,719 $ 21,719 $ 40,254 $ 147,774 141 $(3,081) - $ 206,666
-------- -------- -------- --------- ------- ------- ----------- ---------
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
Treasury stock acquired, net - - - - 227 (4,949) - (4,949)
-------- --------- --------- ---------- ------- -------- ----------- ---------
Balance at
December 31, 1999 21,739 21,739 40,658 162,239 368 (8,030) - 216,606
-------- --------- --------- ---------- ------- -------- ----------- ---------
Comprehensive Income:
Net income - - - 52,848 - - - 52,848
Other comprehensive
income, net of tax:
Unrealized loss on
available for sale - - - - - - (813) (813)
securities -------- --------- --------- ---------- ------- -------- ----------- --------
Total comprehensive income - - - 52,848 - - (813) 52,035
Dividends on preferred stock - - - (78) - - - (78)
Dividends on common stock - - - (23,527) - - - (23,527)
Issuance of common stock 1,563 1,563 32,784 - - - - 34,347
Treasury stock acquired, net - - - - 13 (1,037) - (1,037)
------ --------- ---------- ---------- ------- ------- ----------- ---------
Balance at
December 31, 2000 23,302 23,302 73,442 191,482 381 (9,067) (813) 278,346
------ --------- ---------- ---------- ------- ------- ---------- ---------
Comprehensive Income:
Net income - - - 88,077 - - - 88,077
Other comprehensive income,
net of tax:
Unrealized gain on
available for
sale securities - - - - - - 1,438 1,438
Initial impact of adoption of
SFAS 133, net of minority
interest - - - - - - (4,510) (4,510)
Fair value adjustment on
derivatives designated as
cash flow hedges, net of
minority interest - - - - - - 143 143
------ --------- --------- --------- ------- ------- ---------- --------
Total comprehensive income - - - 88,077 - - (2,929) 85,148
Dividends on preferred stock - - - (527) - - - (527)
Dividends on common stock - - - (28,517) - - - (28,517)
Issuance of common stock 3,589 3,589 167,012 - - - - 170,601
Treasury stock issued, net - - - - (142) 4,564 - 4,564
------ --------- --------- --------- -------- ------- ---------- --------
Balance at
December 31, 2001 26,891 $ 26,891 $ 240,454 $ 250,515 239 $(4,503) (3,742) $509,615
====== ========= ========= ========= ======== ======= ========== ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
18
BLACK HILLS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation and its subsidiaries operate in three primary operating
groups: non-regulated integrated energy, regulated electric utility and
communications. The Company operates its integrated energy businesses through
its direct and indirect subsidiaries: Wyodak Resources related to coal, Black
Hills Exploration and Production related to oil and natural gas, Enserco Energy
and Black Hills Energy Resources related to energy marketing of natural gas and
oil, respectively, and Black Hills Energy Capital and its subsidiaries and Black
Hills Generation related to independent power activities, all aggregated for
reporting purposes as Black Hills Energy (formerly Black Hills Energy Ventures);
operates its public utility electric operations through its subsidiary, Black
Hills Power, Inc.; and operates its communications operations through its
indirect subsidiaries Black Hills Fiber Systems, Black Hills FiberCom L.L.C. and
Daksoft. For further descriptions of the Company's business segments, see Note
14.
In 2002, the Company decided to sell its coal marketing business. The
non-strategic assets were sold effective August 1, 2002.
In December 2000, the Company effected a holding company structure under the
renamed holding company, Black Hills Corporation.
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, inventory obsolescence, realization of market
value of derivatives due to commodity risk, intangible asset valuations and
useful lives, proved oil and gas reserve volumes, employee benefit plans,
environmental accruals and contingencies. Actual results could differ from those
estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills
Corporation 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 except for revenues and expenses associated with intercompany fuel
sales to the Company's regulated subsidiary, Black Hills Power, Inc. in
accordance with the provisions of Statement of Financial Accounting Standards
No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Total intercompany fuel sales not eliminated were $11.2 million, $9.7 million
and $7.7 million in 2001, 2000 and 1999, respectively.
The Company owns 51 percent of the voting securities of Black Hills FiberCom,
LLC (FiberCom). During 2000, FiberCom's operating losses reduced its
unaffiliated members' equity below zero. At that point, the Company began to
fund all operations and recognize 100 percent of FiberCom's operating losses and
will continue to do so until such time as additional equity investments are made
by third parties or future net income restores the Company's equity to a
positive amount.
As discussed in Note 15, the Company and its subsidiaries 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 Company uses the proportionate consolidation method to account for its
working interests in oil and gas properties.
19
Minority Interest in Subsidiaries
Minority interest in the accompanying Consolidated Statements of Income
represents the share of 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 in those subsidiaries.
Regulatory Accounting
The Company's subsidiary, Black Hills Power, is subject to regulation by various
state and federal agencies. The accounting policies followed are generally
subject to the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC). These accounting policies differ in some respects from those
used by the Company's non-regulated businesses.
Black Hills Power follows the provisions of SFAS 71, and its financial
statements reflect the effects of the different ratemaking principles followed
by the various jurisdictions regulating Black Hills Power. As a result of Black
Hills Power's 1995 rate case settlement, a 50-year depreciable life for the Neil
Simpson II plant is used for financial reporting purposes. If Black Hills Power
were not following SFAS 71, a 35 to 40 year life would be more appropriate,
which would increase depreciation expense by approximately $0.6 million per
year. If rate recovery of generation-related costs becomes unlikely or
uncertain, due to competition or regulatory action, these accounting standards
may no longer apply to Black Hills Power's generation operations. In the event
Black Hills Power determines that it no longer meets the criteria for following
SFAS 71, the accounting impact to the Company could be an extraordinary non-cash
charge to operations of an amount that could be material. Criteria that give
rise to the discontinuance of SFAS 71 include increasing competition that could
restrict Black Hills Power's ability to establish prices to recover specific
costs and a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation. The Company
periodically reviews these criteria to ensure that the continuing application of
SFAS 71 is appropriate.
At December 31, 2001 and 2000, the Company had regulatory assets of $4.1
million. The Company also had regulatory liabilities of $4.2 million and $4.7
million at December 31, 2001 and 2000, respectively. The regulatory assets are
included in Other assets and the regulatory liabilities are included in Other
deferred credits and other liabilities on the Consolidated Balance Sheets.
Cash Equivalents
The Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents.
Securities Available-for-Sale
The Company has investments in marketable securities that are classified as
available-for-sale securities and are carried at fair value in accordance with
the provisions of Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities." The
unrealized gain or loss each period resulting from the changes in the
securities' fair value is included as a component of accumulated other
comprehensive income in common stockholders' equity.
Inventory
Materials, supplies and fuel are generally stated at the lower of cost or market
on a first-in, first-out basis. During 2001, 2000 and 1999, provisions of $1.4
million, $1.5 million and $0, respectively, were charged to operations to
write-down inventories at the Company's communications group to estimated net
realizable value. Natural gas and oil inventories held in energy marketing
companies are stated at market.
20
Property, Plant and Equipment
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
10.0 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 $7.5 million, $2.0
million and $1.2 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, except for oil and gas properties as described below, result in gains or
losses recognized as a component of income. Repairs and maintenance of property
are charged to operations as incurred.
Depreciation provisions for regulated electric property, plant and equipment is
computed on a straight-line basis resulting in 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 are depreciated on a straight-line basis using
estimated useful lives ranging from 3 to 39 years. Capitalized coal mining costs
and coal leases are amortized on a unit-of-production method on volumes produced
and estimated reserves.
Goodwill and Intangible Assets
Goodwill represents the excess of acquisition costs over the fair 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 ranged
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
$3.8 million, $2.9 million and $3.3 million in 2001, 2000 and 1999,
respectively. Accumulated amortization was $10.0 million, $6.1 million and $0.7
million 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.
Oil and Gas Operations
The Company accounts for its oil and gas activities under the full cost method.
Under the full cost method, all costs related to acquisition, exploration and
development drilling activities are capitalized. These costs are amortized using
a unit-of-production method based on volumes produced and proved reserves. Any
conveyances of properties, including gains or losses on abandonments of
properties, are treated as adjustments to the cost of the properties with no
gain or loss recognized.
Under the full cost method, net capitalized costs are subject to a "ceiling
test" which limits these costs to the present value of future net cash flows
discounted at 10 percent, net of related tax effects, plus the lower of cost or
fair value of unproved properties included in the net capitalized costs. Future
net cash flows are estimated based on end-of-period spot market prices adjusted
for contracted price changes. If the net capitalized costs exceed the full cost
"ceiling" at period end, a permanent noncash write-down would be charged to
earnings in that period unless known subsequent market price changes eliminate
or reduce the indicated write-down. Given the volatility of oil and gas prices,
the Company's estimate of discounted future net cash flows from proved oil and
gas reserves could change in the near term. If oil and gas prices decline
significantly, even if only for a short period of time, it is possible that a
write-down of oil and gas properties could occur in the future. No "ceiling
test" write-downs were recorded during 2001, 2000 or 1999.
21
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns.
Income taxes for consolidated subsidiaries are allocated to the subsidiaries
based on separate company computations of taxable income or loss.
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. Energy
marketing businesses also use the mark-to-market method of accounting. Under
that method, all energy trading activities are recorded at fair value as of the
balance sheet date and net gains or losses resulting from the revaluation of
these contracts to fair value are recognized currently in the results of
operations. For long-term non-utility power sales agreements, revenue is
generally recognized as the lower of the amount billed or at the average rate
expected over the life of the agreement.
Earnings Per Share of Common Stock
Basic earnings per share is computed by dividing net income available to common
shareholders by the weighted average number of common shares outstanding during
each year. Diluted earnings per share is computed under the treasury stock
method and is calculated to compute the dilutive effect primarily resulting from
outstanding stock options and conversion of preferred shares. A reconciliation
of Income from continuing operations and basic and diluted share amounts is as
follows (in thousands):
2001 2000 1999
---- ---- ----
Average Average Average
Income Shares Income Shares Income Shares
------ ------ ------ ------ ------ ------
Income from continuing operations $87,584 $52,812 $37,738
Less: preferred stock dividends (527) (78) -
------- ------- -------
Basic - available for common shareholders 87,057 25,374 52,734 22,118 37,738 21,445
Dilutive effect of:
Stock options - 223 - 86 - 37
Convertible preferred stock 527 148 78 56 - -
Others - 26 - 21 - -
------- ------ ------- ------ ------- ------
Diluted - available for common shareholders $87,584 25,771 $52,812 22,281 $37,738 21,482
======= ====== ======= ====== ======= ======
Reclassifications
Realized and unrealized gains and losses under energy trading contracts in the
energy marketing segment have been reclassified to be presented on a net basis
in Operating revenues on the accompanying Condensed Consolidated Statements of
Income in accordance with Emerging Issues Task Force (EITF) Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." If the Company had reported these items on a gross basis, both
operating revenues and fuel and purchased power costs would have been $1.0
billion, $1.3 billion and $0.6 billion higher for 2001, 2000 and 1999,
respectively. The net presentation of these items rather than a gross
presentation has no impact on operating income or net income.
22
Certain 2000 and 1999 amounts in the consolidated financial statements have been
reclassified to conform to the 2001 presentation. These reclassifications had no
effect on the Company's common stockholders' 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. The cumulative
effect of the change in accounting principle, net of tax at January 1, 2002, was
a $896,000 benefit.
The pro forma effects of adopting SFAS 142 are as follows (in thousands, except
per share amounts):
2001 2000 1999
---- ---- ----
Net income as reported $ 88,077 $ 52,848 $ 37,067
Add goodwill amortization 1,499 1,394 2,523
-------- -------- --------
Adjusted net income $ 89,576 $ 54,242 $ 39,590
======== ======== ========
2001 2000 1999
---- ---- ----
Basic earnings per share $ 3.45 $ 2.39 $ 1.73
Add goodwill amortization 0.06 0.06 0.12
--------- -------- --------
Adjusted basic earnings per share $ 3.51 $ 2.45 $ 1.85
========= ======== ========
Diluted earnings per share $ 3.42 $ 2.37 $ 1.73
Add goodwill amortization 0.06 0.06 0.12
--------- -------- --------
Adjusted diluted earnings per share $ 3.48 $ 2.43 $ 1.85
========= ======== ========
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. The Company was required to
adopt SFAS 144 effective January 1, 2002. Adoption did not have a material
impact on the Company's consolidated financial position, results of operations
or cash flows.
23
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 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, most of the
Company's energy marketing activities previously accounted for under Emerging
Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk
Management Activities" (EITF 98-10) fell under the purview of SFAS 133. The
effect of adoption on the energy marketing companies and risk management
activities was not material because, unless otherwise noted, the energy
marketing companies did not designate their risk management activities as hedge
instruments. This "no hedge" designation resulted in these derivatives being
measured at fair value and gains and losses recognized currently in earnings.
This treatment under SFAS 133 was comparable to the accounting under EITF 98-10.
At January 1, 2001, the Company had certain non-trading energy contracts and
interest rate swaps documented as cash flow hedges. These contracts were defined
as derivatives under SFAS 133 and met the requirements for cash flow hedges.
Because 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 $0.9 million, increased the derivative
liabilities by $11.2 million and decreased accumulated other comprehensive
income by $10.3 million pre-tax and before minority interests.
(2) RISK MANAGEMENT ACTIVITIES
The Company's operations and financial results are impacted by numerous factors
including, but not limited to, commodity price risk, interest rate risk and
counterparty risk. The Company is exposed to commodity price variability in
nearly all core energy marketing and trading businesses. In addition, fuel
requirements at its gas-fired generation and its natural long position in crude
oil and natural gas production introduce additional commodity price risk.
Energy Marketing Activities
The Company markets natural gas and crude oil in specific areas of the United
States and Canada. The Company offers wholesale energy marketing and price risk
management products and services to a variety of customers. These activities
subject the Company to numerous risks including commodity price risk.
The Company has adopted Risk Management Policies and Procedures (RMP&P) covering
all marketing activities. The RMP&P have been approved by the Company's Board of
Directors and are routinely reviewed by the Audit Committee of the Board of
Directors. The RMP&P include, but are not limited to, trader limits, position
limits and credit exposure limits.
24
The Company employs risk management methods to mitigate its commodity price
risk. As a general policy, the Company only permits speculation with limited
"open" positions as defined in the RMP&P. Therefore, substantially all of its
marketing activities are fully hedged or back-to-back positions; in other words,
each sale is matched with a purchase.
To maintain compliance with the RMP&P and mitigate its commodity price risk, the
Company routinely utilizes fixed price forward purchase and sales contracts and
over-the-counter swaps and options. The Company attempts to balance its fixed
price physical and financial purchase and sale commitments in terms of volume
and timing of performance and delivery obligations. However, the Company may at
times have a bias in the market, within established guidelines, resulting from
the management of its portfolio. In addition, the Company may, at times, be
unable to fully hedge its portfolio for certain market risks as a result of
marketplace illiquidity and other factors.
The Company's energy marketing operations are accounted for under mark-to-market
accounting. The Company records its fair values as either Derivative assets
and/or Derivative liabilities on the accompanying Consolidated Balance Sheet.
The net gains or losses are recorded as Revenues in the accompanying
Consolidated Statements of Income.
The contract or notional amounts and terms of the Company's derivative commodity
instruments held for trading purposes at December 31, 2001 and 2000, are set
forth below:
2001 2000
Notional Maximum Notional Maximum
Amounts Term in Years Amounts Term in Years
(thousands of MMBtu's) -------- ------------- -------- --------------
Natural gas basis swaps purchased 9,882 1 25,578 2
Natural gas basis swaps sold 10,696 1 26,060 2
Natural gas fixed-for-float swaps purchased 10,646 2 6,476 1
Natural gas fixed-for-float swaps sold 11,815 2 7,361 1
Natural gas swing swaps purchased 465 1 - -
Natural gas swing swaps sold 930 1 - -
Natural gas physical purchases 13,159 1 - -
Natural gas physical sales 19,339 1 - -
(thousands of barrels)
Crude oil purchased 3,139 1 2,186 1
Crude oil sold 3,142 1 2,530 1
As required under SFAS 133, derivatives and energy trading activities were
marked to fair value on December 31, 2001, and the gains and/or losses
recognized in earnings. The amounts related to the accompanying Consolidated
Balance Sheets and Statements of Income as of December 31, 2001 and 2000, are as
follows (in thousands):
Current Non-current Current Non-current Unrealized
Assets Assets Liabilities Liabilities Gain
December 31, 2001 ------ ------ ----------- ----------- ----
Natural gas $29,755 $ 661 $25,437 $ 953 $4,026
Crude Oil 6,267 - 5,497 - 770
------- ------- ------- ------- ------
$36,022 $ 661 $30,934 $ 953 $4,796
======= ======= ======= ======= ======
December 31, 2000
Natural gas $61,008 $ 391 $56,968 $ 3,532 $ 899
Crude oil 1,523 - 1,000 - 523
--------- ------- ------- ------- ------
$62,531 $ 391 $57,968 $ 3,532 $1,422
======= ======= ======= ======= ======
25
At December 31, 2001, the Company had a mark to fair value unrealized gain of
$4.8 million for its energy marketing activities. Of this amount, $5.1 million
was current and $(0.3) million was non-current. The current portion of
unrealized gains is associated with back to back transactions in which each sale
is matched to a purchase. The Company anticipates that substantially all of the
current portion of unrealized gains for these transactions will be realized
during the next twelve months. Conversely, estimated and actual realized gains
or losses related to open positions will likely change during 2002 as market
prices change from the December 31, 2001 estimates.
Non-trading Energy Activities
The Company produces natural gas and crude oil through its exploration and
production activities. These natural long positions, or unhedged open positions,
introduce commodity price risk and variability in cash flows for the Company.
The Company employs risk management methods to mitigate this commodity price
risk and preserve its cash flows. The Company has adopted guidelines covering
hedging for its natural gas and crude oil production. These guidelines have been
approved by the Company's Board of Directors and are routinely reviewed by its
Audit Committee.
To mitigate commodity price risk and preserve cash flows, the Company uses
over-the-counter swaps and options. These derivative instruments fall under the
purview of SFAS 133 and the Company elects to utilize hedge accounting as
allowed under this Statement.
At December 31, 2001, the Company had a portfolio of swaps to hedge portions of
its crude oil and natural gas production. These transactions were previously
identified as cash flow hedges, properly documented, and met prospective
effectiveness testing. At year-end, these transactions met retrospective
effectiveness testing criteria and retained their cash flow hedge status.
At December 31, 2001, the derivatives were marked to fair value and were
recorded in Derivative assets or Derivative liabilities on the accompanying
Consolidated Balance Sheets. The effective portion of the gain or loss on these
derivatives was reported in other comprehensive income and the ineffective
portion was reported in earnings.
On January 1, 2001 (the transition adjustment date for SFAS 133 adoption) and
December 31, 2001, the Company had the following swaps and related balances (in
thousands):
Accumulated
Maximum Other
Terms in Current Non-current Current Non-current Comprehensive
Notional* Years Assets Assets Liabilities Liabilities Income (Loss) Earnings
--------- ----- ------ ------ ----------- ----------- ------------- --------
January 1, 2001
Crude oil swaps 294,000 2 $ 33 $ 151 $ - $ - $ 184 $ -
Crude oil options 120,000 1 472 - - - 472 -
Natural gas swaps 1,581,000 1 - - 3,411 - (3,411) -
------- ------ ------ ------ ------- ------
$ 505 $ 151 $3,411 $ - $(2,755) $ -
======= ====== ====== ====== ======= ======
December 31, 2001
Crude oil swaps 90,000 1 $ 529 $ - $ - $ - $ 529 $ -
Natural gas swaps 1,216,000 1 1,593 - - - 1,463 130
------- ------ ------ ----- ------- ------
$ 2,122 $ - $ - $ - $ 1,992 $ 130
======= ====== ====== ===== ======= ======
-----------------------
*crude in bbls, gas in MMBtu's
Most of the Company's crude oil and natural gas hedges are highly effective,
resulting in very little earnings impact prior to realization. During 2001, the
Company recorded $0.1 million earnings due to ineffectiveness for certain
natural gas swaps due to basis risk.
26
All existing hedges at December 31, 2001 expire during the year ended December
31, 2002. The unrealized earnings gains or losses currently recorded in
accumulated other comprehensive income are expected to be realized in earnings
during 2002. Based on December 31, 2001 market prices, $2.0 million will be
realized and reported in earnings during 2002. These estimated realized gains
for 2002 were calculated using December 31, 2001 market prices. Estimated and
actual realized gains will likely change during 2002 as market prices change.
In addition, the Company acquired several natural gas swaps when it completed
the Las Vegas Cogeneration acquisition on August 31, 2001 (Note 15). 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 $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. In addition, the Company recognized a $6.0 million
pre-tax charge to income 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 $291.4 million of notional amount
floating-to-fixed interest rate swaps, having a maximum term of five years and a
fair value of $(14.4) million. These hedges are substantially effective and any
ineffectiveness was immaterial.
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. At December 31, 2001, the swap had a fair market value
of $2.3 million. This swap terminated during the second quarter 2002 and
resulted in a $1.1 million gain. This swap was treated as a cash flow hedge and
accordingly in the second quarter of 2002 the resulting gain was carried in
Accumulated Other Comprehensive Income and was to be amortized over the life of
the anticipated long-term financing. In the third quarter of 2002, this cash
flow hedge was determined to be ineffective due to uncertainties about the
eventual timing and form of financing for this project. As a result, $1.1
million was taken into earnings. The gain was offset by the expensing of
approximately $1.0 million of deferred financing costs related to the
anticipated financing.
At December 31, 2001, the Company had $655.8 million of outstanding, floating
rate debt, of which $364.4 million was not offset with interest rate swaps
transactions that effectively convert the debt to fixed rate.
27
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)
Swaps on corporate
debt 75,000 4.45% 3 - - 1,535 217 (1,752)
-------- ----- ------ ------- ------ --------
Total $391,397 $ - $5,746 $11,747 $6,166 $(12,167)
======== ===== ====== ======= ====== ========
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, $11.7 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.
For its energy marketing, energy production and risk management activities, 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.
At the end of the year, the Company's credit exposure (exclusive of
regulated retail customers and communications) was concentrated with investment
grade companies. Approximately 85 percent of the Company's credit exposure was
with investment grade companies. For the 15 percent credit exposure with
non-investment grade rated counterparties, approximately 60 percent of this
exposure was supported through letters of credit, prepayments, parental
guarantees or asset liens.
(3) INVESTMENTS IN ASSOCIATED COMPANIES
Included in Investments on the Consolidated Balance Sheets are the following
investments that have been recorded on the equity method of accounting:
o A 33.33 percent interest (see Note 18) in Millennium Pipeline Company,
L.P., a Texas limited partnership, which owns and operates an oil pipeline
in the Gulf Coast region of Texas. The Company has a carrying amount in the
investment of $7.0 million and $6.9 million as of December 31, 2001 and
2000, respectively. The partnership had assets of $23.8 million and $22.0
million, liabilities of $2.8 million and $1.0 million as of December 31,
2001 and 2000, and net income of $3.4 million and $2.8 million during 2001
and 2000, respectively.
28
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
$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 Cogeneration
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.
(4) COMMON STOCK
Common Stock Offering
During 2001, the Company completed a public offering of its common stock through
which approximately 3.4 million shares were sold at $52 per share. Net proceeds
were approximately $163 million after commissions and expenses. The proceeds
were used to repay a portion of current indebtedness under revolving credit
facilities, to fund various power plant construction costs and for general
corporate purposes.
Employee Stock Incentive and Employee Stock Purchase Plans
The Company has several employee stock incentive plans (Stock Incentive Plans),
which allow for the granting of stock options with exercise prices equal to the
stock's fair market value on the date of grant, and an employee stock purchase
plan (ESPP Plan). The Company accounts for such plans under APB No. 25, and has
adopted the disclosure-only provisions of SFAS No. 123, "Accounting for Stock
Based Compensation" (SFAS 123). Accordingly, no compensation cost has been
recognized.
The Company may grant options for up to 2,200,000 shares of common stock under
the Stock Incentive Plans. The Company has 1,037,882 shares available to grant
at December 31, 2001. The option exercise price equals the fair market value of
the stock on the day of the grant. The options granted vest one-third a year for
three years and all expire after ten years from the grant date.
29
A summary of the status of the stock option plans at December 31, 2001, 2000 and
1999, and changes during the years then ended are as follows:
2001 2000 1999
---- ---- ----
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------ ----- ------ ----- ------ -----
Balance at beginning of year 914,917 $23.43 431,450 $21.35 292,700 $20.29
Granted 203,000 $37.09 492,500 $25.22 140,250 $23.58
Forfeited (30,834) $22.13 (4,000) $23.25 (1,500) $23.06
Exercised (94,211) $20.41 (5,033) $21.33 - $ -
------- ------- -------
Balance at end of year 992,872 $26.55 914,917 $23.43 431,450 $21.35
======= ======= =======
Exercisable at end of year 445,252 $22.76 292,891 $20.43 182,400 $19.19
======= ======= =======
Details of outstanding options at December 31, 2001 are as follows:
Weighted Average
Option Exercise Shares Weighted Average Remaining Weighted Average
Prices Outstanding Exercise Price Contractual Life Shares Exercisable Exercise Price
------ ----------- -------------- ---------------- ------------------ --------------
$16.67 to $25.00 680,872 $21.75 7.4 years 407,600 $21.45
$25.01 to $37.50 151,000 $31.04 9.8 years 3,166 $28.63
$37.51 to $55.36 161,000 $42.65 9.1 years 34,486 $37.69
The fair value of each option is estimated on the date of grant using the
Black-Scholes option pricing model. The weighted average fair value of the
options granted and the assumptions used to estimate the fair value of options
are as follows:
2001 2000 1999
---- ---- ----
Weighted average fair value of options at grant date $10.77 $3.88 $4.16
Weighted average risk-free interest rate 5.92% 6.30% 6.68%
Weighted average expected price volatility 34.92% 20.60% 19.85%
Weighted average expected dividend yield 2.90% 4.20% 4.50%
Expected life in years 10 10 10
30
Had compensation cost been determined consistent with SFAS 123, the Company's
net income and earnings per share would have been reduced to the following pro
forma amounts for the years ended December 31 (unaudited):
2001 2000 1999
---- ---- ----
(in thousands, except per share amounts)
Net income available for common:
As reported $87,550 $52,770 $37,067
Pro forma $86,845 $52,432 $36,877
Earnings per share:
As reported -
Basic
Continuing operations $ 3.43 $ 2.39 $1.76
Discontinued operations 0.02 - (0.03)
------- ------- -----
Total $ 3.45 $ 2.39 $1.73
======= ======= =====
Diluted
Continuing operations $ 3.40 $ 2.37 $1.76
Discontinued operations 0.02 - (0.03)
------- ------- -----
Total $ 3.42 $ 2.37 $1.73
======= ======= =====
Pro forma -
Basic
Continuing operations $ 3.40 $ 2.38 $1.75
Discontinued operations 0.02 - (0.03)
------- ------- -----
Total $ 3.42 $ 2.38 $1.72
======= ======= =====
Diluted
Continuing operations $ 3.37 $ 2.35 $1.75
Discontinued operations 0.02 - (0.03)
------- ------- -----
Total $ 3.39 $ 2.35 $1.72
======= ======= =====
The Company maintains the ESPP Plan under which it sells shares to employees at
90 percent of the stock's market price on the offering date. The Company issued
48,368, 21,394 and 19,565 shares of common stock under the ESPP Plan in 2001,
2000 and 1999, respectively. At December 31, 2001, 177,808 shares are reserved
and available for issuance under the ESPP Plan. The fair value per share of
shares sold in 2001 was $22.50 on the offering date.
Employee Stock Awards
During 2001, the Company issued a total of 36,550 common shares as a stock bonus
award to its non-officer employees. The bonus was grossed up to cover related
employee taxes. The total pre-tax compensation charge recognized by the Company
was $1.9 million, which is based on the market value of the stock on the grant
date. Additionally, approximately 18,000 common shares will be issued at the
two-year anniversary date of the original award, contingent on certain vesting
restrictions. Pre-tax compensation cost related to this portion of the award is
estimated to be $0.9 million and is being expensed over the two-year vesting
period.
During 2001, the Company issued 12,177 restricted common shares (net of 4,512
common shares forfeited) to certain officers. The shares carry a restriction on
the officer's ability to sell the shares, until the shares vest. The shares vest
one-third per year over three years, contingent on employment. Pre-tax
compensation cost related to the award was $0.7 million, which is being expensed
over the three-year vesting period.
Nonemployee stock award
During 2001, the Company issued 100,000 common shares as a charitable
contribution to the newly formed not-for-profit entity, Black Hills Corporation
Foundation. The charitable contribution cost included in "Other, net" on the
2001 Consolidated Statement of Income was $3.1 million, which is based on the
stock market value on the grant date.
31
Dividend Reinvestment and Stock Purchase Plan
The Company has a Dividend Reinvestment and Stock Purchase Plan under which
shareholders may purchase additional shares of common stock through dividend
reinvestment and/or optional cash payments at 100 percent of the recent average
market price. The Company has the option of issuing new shares or purchasing the
shares on the open market. The Company purchased shares on the open market in
2001, 2000 and 1999. At December 31, 2001, 1,290,797 shares of unissued common
stock were available for future offerings under the Plan.
(5) PREFERRED STOCK
The Company has 25,000,000 authorized shares of no-par preferred stock.
During 2001 and 2000, the Company issued 5,177 preferred shares in the Indeck
Capital acquisition and the related "earn-out" provisions. The preferred shares
issued are non-voting, cumulative, no par shares with a dividend rate equal to 1
percent per annum per share, computed on the basis of $1,000 per share plus an
amount equal to any dividend declared payable with respect to the common stock,
multiplied by the number of shares of common stock into which each share of
preferred stock is convertible. The record and payment dates are the same as the
record and payment dates with respect to the payment of dividends on common
stock. No dividend may be declared or paid with respect to common stock unless
such a dividend is declared and paid with respect to the preferred stock. The
preferred stock is senior to the common stock in liquidation events.
The Company may redeem the preferred stock in whole or in part, at any time
solely at its option. The redemption price per share for the preferred stock
shall be $1,000 per share plus all accrued and unpaid dividends. Each share of
the preferred stock is convertible at the option of the holder into common stock
at any time prior to July 7, 2005 and automatically converted into common stock
on July 7, 2005. Each share of preferred stock is convertible into 28.57 common
shares. If the Company delivers a notice of redemption, the conversion price
shall be adjusted to equal the lesser of (i) the conversion price then in
effect, and (ii) the current market price on the redemption notice date.
32
(6) LONG-TERM DEBT
Long-term debt outstanding at December 31 is as follows (in thousands):
2001 2000
---- ----
Fixed rate 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 3,870 3,911
-------- --------
28,370 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 451,702 321,052
Less current maturities (35,904) (13,960)
-------- --------
Net long-term debt $415,798 $307,092
======== ========
---------------
(a) Approximately 74 percent of the December 31, 2001 balance has been
hedged with interest rate swaps moving the floating rates to fixed rates
with a weighted average interest rate of 5.85 percent (see Note 2-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 of long-term debt 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.
(7) NOTES PAYABLE
The Company has committed lines of credit with various banks totaling $400
million at December 31, 2001 and $290 million at December 31, 2000. At December
31, 2001, these lines consist of a $200 million revolving credit facility with a
term of 364 days, which terminates August 27, 2002, and a $200 million revolving
credit facility with a term of three years, which terminates on August 27, 2004.
The Company had $360 million of borrowings and $33.0 million of letters of
credit and $211 million of borrowings and $20.6 million of letters of credit
issued on the lines at December 31, 2001 and 2000, respectively. The Company had
no compensating balance requirements associated with these lines of credit.
33
At December 31, 2001, the above facilities contained ratings trigger provisions
that, if violated, would have been considered an event of default and would have
allowed the lender to terminate the remaining commitment and accelerate the
principal and interest outstanding to become immediately due. The Company would
have been considered in violation of these ratings trigger provisions if its
Standard & Poor's (S&P) Rating ceased to be at least BBB- or its Moody's Rating
ceased to be at least Baa3. In addition, certain of the Company's interest rate
swap agreements with a $150.0 million notional amount and a $0.7 million fair
value at December 31, 2001 include cross-default provisions. These provisions
would allow the counterparty the right to terminate the swap agreement and
liquidate at a prevailing market rate, in the event of default. The facilities
that had rating triggers were amended during the second quarter of 2002 to
remove default provisions pertaining to credit rating status. The Company's S&P
and Moody's Ratings were BBB and A3, respectively at December 31, 2001.
In addition to the above lines of credit, at December 31, 2001, Enserco Energy
(Enserco) has a $75.0 million ($90.0 million at December 31, 2000) uncommitted,
discretionary line of credit to provide support for the purchases of natural
gas. The line of credit is secured by all of Enserco's assets. The Company and
its other subsidiaries provide no guarantees to the lender. At December 31, 2001
and 2000, there were outstanding letters of credit issued under the facility of
$36.2 million and $69.8 million, respectively, with no borrowing balances on the
facility.
Black Hills Energy Resources (BHER) has a $25.0 million uncommitted,
discretionary credit facility secured by all of its assets. The transactional
line of credit provides credit support for the purchases of crude oil of BHER.
The Company and its other subsidiaries provide no guarantees to the lender. At
December 31, 2001 and 2000, BHER had letters of credit outstanding of $4.4
million and $8.5 million, respectively, with no borrowing balances on the
facility.
Our credit facilities contain certain restrictive covenants. The Company and its
subsidiaries had complied with all the covenants at December 31, 2001.
Interest rates under the facility borrowings vary and are based, at the option
of the Company at the time of the loan origination, on either (i) a prime based
borrowing rate varying from prime rate (4.75 percent at December 31, 2001) to
prime rate plus 1.0 percent, or (ii) on a London Interbank Offered Rate (LIBOR)
based borrowing rate varying from LIBOR plus 0.6 percent to LIBOR plus 0.625
percent. The one-month LIBOR rate at December 31, 2001 was 1.87 percent. In
addition to interest on outstanding borrowings, the credit facilities contain a
0 percent to 0.15 percent annual facility fee on the total facility amount, and
an annual utilization fee ranging from 0 percent to 0.125 percent of the total
used facility amount.
The Company has entered into floating-to-fixed interest rate swaps to hedge a
portion of its exposure to interest rate fluctuations with the above floating
rate obligations. See Note 2 for further details.
(8) 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 $ 29,956 $ 29,956 $ 24,290 $ 24,290
Securities available-for-sale $ 3,550 $ 3,550 $ 2,113 $ 2,113
Derivative financial instruments - assets $ 44,551 $ 44,551 $ 62,922 $ 62,922
Derivative financial instruments - liabilities $ 49,800 $ 49,800 $ 61,500 $ 61,500
Notes payable $360,450 $360,450 $211,000 $211,000
Long-term debt $451,702 $469,787 $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.
34
Securities Available-for-Sale
The fair value of the Company's investments equals the quoted market price. The
Company has classified all of its marketable securities as available-for-sale as
of December 31, 2001 and 2000. An unrealized gain on the Company's investments
of $1.4 million and an unrealized loss of $0.8 million was recorded as of
December 31, 2001 and 2000, respectively.
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 2 of these 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.
(9) 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. As discussed in Note 10, the Company's coal mining
subsidiary, Wyodak Resources, supplies coal to the Plant under an agreement
expiring in 2022. This coal supply agreement is collateralized by a mortgage on
and a security interest in some of Wyodak Resources' coal reserves. Under the
coal supply agreement, Pacific Power is obligated to purchase a minimum of
1,500,000 tons of coal each year of the contract term, subject to adjustment for
planned outages. Wyodak Resources' sales to the Plant were $21.0 million, $23.2
million and $24.9 million for the years ended December 31, 2001, 2000 and 1999,
respectively.
(10) COMMITMENTS AND CONTINGENCIES
Off Balance Sheet Lease
The Company's subsidiary, Black Hills Generation, has entered into an Agreement
for Lease and Lease with Wygen Funding, Limited Partnership for the Wygen Plant,
a 90 megawatt coal-fired power plant under construction in Campbell County,
Wyoming. Wygen Funding is a special purpose entity that owns the Wygen Plant and
has financed the project. Total cost of the project is estimated to be
approximately $130 - $140 million. Neither Wygen Funding, its owners, nor its
officers are related to the Company, and other than the lease transaction and
obligations incurred as a result of this transaction, there is no obligation to
provide additional funding or issue securities to Wygen Funding. Lease payments
are based on final construction and financing costs and are currently estimated
to be approximately $6.5 million per year based on five-year treasury rates.
Lease payments will begin after substantial completion of construction scheduled
for first quarter 2003. The lease will be accounted for as an operating lease.
The initial lease term is five years with two five-year renewal options and
includes a purchase option equal to the adjusted acquisition cost. The adjusted
acquisition cost is essentially equal to the final construction cost of the
project. If the Company elects to terminate or not renew the lease and not
purchase the project, then it must make a termination payment equal to the
lesser of 83.5 percent of the adjusted acquisition cost or the shortfall of
proceeds received from the owner's sale of the project relative to the owner's
cost. Black Hills Corporation has guaranteed the Agreement for Lease and Lease.
35
Power Purchase Agreement - Pacific Power
In 1983, the Company entered into a 40 year power purchase 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 Beginning September 1, 2001, the Company has a ten year power sales
contract with Cheyenne Light, Fuel and Power (CLF&P) for the output of the
40 megawatt gas-fired Gillette CT. The contract is a tolling arrangement in
which the Company assumes no fuel risk. In addition, the Company entered
into a ten year contract with CLF&P for 60 megawatts of contingent capacity
from the 90 megawatt Wygen Plant, currently under construction. Twenty
megawatts of the remaining capacity of this plant has been sold under a ten
year contract with the Municipal Electric Agency of Nebraska.
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 15 for a description of the facility and the related
long-term contracts.
o Various long-term contracts with Niagara Mohawk Power Corporation have been
entered into to sell the output of several of the Company's hydroelectric
projects located in upstate New York. The Company's net ownership of
capacity under contract is approximately 21 megawatts with contracts
expiring between 2028 and 2032. There are additional contracts on plants
with a net ownership capacity of approximately 21 megawatts that expire
during 2002 and 2003.
Reclamation Liability
Under its mining permit, Wyodak Resources is required to reclaim all land where
it has mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual basis,
much of the reclamation occurs over an extended period after the area is mined.
Approximately $0.7 million is charged to operations as reclamation expense
annually. As of December 31, 2001, accrued reclamation costs included in Other
liabilities on the accompanying Consolidated Balance Sheets were approximately
$18.2 million.
Legal Proceedings
Settlement
On April 3, 2001, the Company reached a settlement of ongoing litigation with
PacifiCorp filed in the United States District Court, District of Wyoming, (File
No. 00CV-155B). The litigation concerned the parties' rights and obligations
under the Further Restated and Amended Coal Supply Agreement dated May 5, 1987,
under which PacifiCorp purchased coal from the Company's coal mine to meet the
coal requirements of the Wyodak Power Plant. The Settlement Agreement provided
for the dismissal of the litigation, with prejudice, coupled with the execution
of several new coal-related agreements between the parties discussed below. The
Company believes the value of the Settlement Agreements is equal to the net
present value of the litigated Further Restated and Amended Coal Supply
Agreement.
New Restated and Amended Coal Supply Agreement: Effective January 1, 2001, the
parties agreed to terminate the Further Restated and Amended Coal Supply
Agreement, and replace it with the New Restated and Amended Coal Supply
Agreement (New Agreement). The New Agreement began on January 1, 2001, and
extends to December 31, 2022. Under the New Agreement, the Company received an
extension of sales beyond the June 8, 2013 term of the former Coal Supply
Agreement. PacifiCorp will receive a price reduction for each ton of coal
purchased. The minimum purchase obligation under the New Agreement increased to
1,500,000 tons of coal for each calendar year of the contract term, subject to
adjustment for planned
36
outages. The New Agreement further provided for a special one-time payment
by PacifiCorp in the amount of $7.3 million, which was received in August 2001.
This payment primarily related to disputed billings under the previous agreement
and a value transfer premium. Of this payment, $5.6 million was recognized
currently and is included in "Other, net" non-operating income on the
accompanying Consolidated Statements of Income, $1.0 million was previously
recognized in revenues and the remaining $0.7 million is being recognized as
sales are made under the New Agreement.
Coal Option Agreement: The term of this agreement began October 1, 2001, and
extends until December 31, 2010. The agreement provides that PacifiCorp shall
purchase 1,400,000 tons of coal during the period of October 1, 2001 through
December 31, 2002 and 1,000,000 tons of coal in 2003 at a fixed price. The
agreement further provides the Company with a "put" option for 2002 and 2003
under which the Company may sell to PacifiCorp up to 500,000 tons of coal from
the Wyodak Mine at a market based price. For each calendar year from January 1,
2004 through 2010, the put option is increased to a maximum of 1,000,000 tons at
a market based price. The "put" tonnages will be reduced or offset for
quantities of an enhanced coal known as "K-Fuel" purchased by PacifiCorp under
the KFx Facility Output Agreement. Additionally, for each calendar year during
which the Company is selling to PacifiCorp K-Fuel under the KFx Facility Output
Agreement described below, and in which the Company has not exercised its "put"
option, PacifiCorp may elect to purchase an equal amount of tonnage from the
Company's coal reserves to use in a 50/50 blend with the K-Fuel, up to 500,000
tons per year in 2002 through 2007 at a market based price with a fixed floor.
Asset Option Agreement: This agreement provides PacifiCorp an option to purchase
a 10 percent interest in the KFx facility or the legal entity that owns the KFx
facility at a market based price.
Sale of North Conveyor System: The Company sold the "North Conveyor System" to
PacifiCorp, which served as the backup coal delivery system for the Wyodak Power
Plant which resulted in a $2.6 million gain that is included in "Other, net"
non-operating income on the accompanying Consolidated Statements of Income.
KFx Facility Output Agreement: The KFx plant is a coal enhancement facility the
Company owns located near its Wyodak Coal Mine. The KFx plant was built to
produce an enhanced coal known as "K-Fuel." Assuming the plant becomes
operational, PacifiCorp agrees to purchase K-Fuel for a term beginning January
1, 2002, and extending to December 31, 2007. If the plant is not operational on
or before December 31, 2003, the agreement will become void. Under this
agreement, PacifiCorp agrees to purchase the output of K-Fuel from the KFx
plant, up to a maximum of 500,000 tons for each calendar year from 2002 through
2007 at fixed price with market based escalation. Wyodak reserves the right to
sell up to a total of 100,000 tons from the output of the KFx plant to other
customers during the same time period.
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.
(11) EMPLOYEE BENEFIT PLANS
Defined Benefit Pension and Other Postretirement Plans
The Company has a noncontributory defined benefit pension plan (Plan) covering
the employees of the Company and those of the following subsidiaries, Black
Hills Power, Wyodak Resources Development Corp., Black Hills Exploration and
Production and Daksoft who meet certain eligibility requirements. The benefits
are based on years of service and compensation levels during the highest five
consecutive years of the last ten years of service. The Company's funding policy
is in accordance with the federal government's funding requirements. The Plan's
assets are held in trust and consist primarily of equity securities and cash
equivalents.
37
Net pension income for the Plan was as follows:
2001 2000 1999
---- ---- ----
(in thousands)
Service cost $ 945 $ 967 $ 1,174
Interest cost 3,080 2,885 2,598
Estimated return on assets (5,814) (5,257) (4,162)
Amortization of transition amount - (90) (90)
Amortization of prior service cost 231 231 89
Recognized net actuarial gain (556) (537) -
------- ------- -------
Net pension income $(2,114) $(1,801) $ (391)
======= ======= =======
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 $41,314 $39,615
------- -------
Service cost 945 967
Interest cost 3,080 2,885
Actuarial gains (167) (48)
Benefits paid (2,156) (2,105)
------- -------
Net increase 1,702 1,699
------- -------
Ending projected benefit obligation $43,016 $41,314
======= =======
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 $56,560 $51,212
Benefits paid (2,156) (2,105)
Investment income (loss) (13,136) 7,453
------- -------
Ending market value of plan assets $41,268 $56,560
======= =======
Funding information for the Plan as of October 1 each year was as follows:
2001 2000
---- ----
(in thousands)
Fair value of plan assets $41,268 $56,560
Projected benefit obligation (43,016) (41,314)
------- -------
Funded status (1,748) 15,246
Unrecognized:
Net (gain) loss 5,527 (13,812)
Prior service cost 1,823 2,054
------- -------
Prepaid pension cost $ 5,602 $ 3,488
======= =======
Accumulated benefit obligation $35,695 $33,374
======= =======
38
The Company has various supplemental retirement plans for outside directors and
key executives of the Company. The plans are nonqualified defined benefit plans.
Expenses recognized under the plans were $0.5 million during 2001 and 2000 and
$0.4 million during 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 $ 289 $ 282 $225
Interest cost 507 523 362
Amortization of transition obligation 150 150 150
Loss 21 68 1
------- ------ ----
$ 967 $1,023 $738
======= ====== ====
Funding information as of October 1 was as follows:
2001 2000
---- ----
(in thousands)
Accumulated postretirement benefit obligation:
Retirees $3,186 $2,478
Fully eligible active participants 1,803 1,203
Other active participants 3,963 3,172
------ ------
Unfunded accumulated postretirement benefit obligation 8,952 6,853
Unrecognized net loss (2,792) (1,001)
Unrecognized transition obligation (1,648) (1,797)
------ ------
Accrued postretirement cost $4,512 $4,055
====== ======
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 6.0
percent in 2005 and remain at that level thereafter. The healthcare cost trend
rate assumption has a significant effect on the amounts reported. A one percent
increase in the healthcare cost trend assumption would increase the service and
interest cost $0.2 million or 23.8 percent and the net periodic postretirement
cost $0.3 million or 28.1 percent. A one percent decrease would reduce the
service and interest cost by $0.1 million or 18.3 percent and decrease the net
periodic postretirement cost $0.2 million or 17.2 percent. The weighted-average
discount rate used in determining the accumulated postretirement benefit
obligation was 7.5 percent.
Defined Contribution Plan
The Company also sponsors a 401(k) savings plan for eligible employees.
Participants elect to invest up to 20 percent of their eligible compensation on
a pre-tax basis. Effective January 1, 2000 (May 1, 2000 for employees covered by
the collective bargaining agreement), the Company provides a 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 $0.9 million for 2001 and $0.6 million for 2000.
39
(12) OTHER COMPREHENSIVE INCOME
The following table displays the related tax effects allocated to each component
of Other Comprehensive Income (Loss) for the year ended December 31, 2001:
Pre-tax Tax Expense Net-of-tax
Amount (Benefit) Amount
------ --------- ------
(in thousands)
Unrealized gain on securities during the year $ 1,775 $ 337 $ 1,438
Net change in fair value of derivatives designated as cash flow
hedges (net of minority interest share of $2,875) (7,299) (2,932) (4,367)
------- ------- -------
Other comprehensive loss $(5,524) $(2,595) $(2,929)
======= ======= =======
Items of other comprehensive income (loss) were not significant in 2000 or 1999.
(13) INCOME TAXES
Income tax expense for the years indicated was:
2001 2000 1999
---- ---- ----
(in thousands)
Current:
Federal $38,372 $27,122 $13,662
State 1,986 1,283 266
------- ------- -------
40,358 28,405 13,928
Deferred 10,224 2,576 2,931
Tax credits (432) (639) (640)
------- ------- -------
$50,150 $30,342 $16,219
======= ======= =======
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, amortization and other plant-related differences $ 647 $ 5,393
Regulatory asset 2,169 2,507
Valuation reserves 3,057 508
Mining development and oil exploration 1,501 3,605
Employee benefits 4,168 3,308
Items of other comprehensive income 4,540 -
Other 6,176 3,203
------- -------
22,258 18,524
------- -------
Deferred tax liabilities:
Accelerated depreciation and other plant-related differences 74,449 63,559
Regulatory liability 1,425 1,447
Mining development and oil exploration 8,650 8,450
Employee benefits 2,152 1,347
Derivative fair value adjustments 1,776 -
Items of other comprehensive income 1,945 -
Other 7,163 6,400
------- -------
97,560 81,203
------- -------
Net deferred tax liability $75,302 $62,679
======= =======
40
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%
State income tax 1.4 1.5 0.5
Amortization of investment tax credits (0.3) (0.8) (1.2)
Percentage depletion in excess of cost (0.8) (1.1) (1.6)
Other 1.1 1.9 (2.6)
---- ---- ----
36.4% 36.5% 30.1%
==== ==== ====
41
(14) 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 six
business segments that include: Electric, which supplies electric utility
service to western South Dakota, northeastern Wyoming and southeastern Montana;
Integrated Energy consisting of: Mining, which engages in the mining and sale of
coal from its mine near Gillette, Wyoming; Oil and Gas, which produces, explores
and operates oil and natural gas interests located in the Rocky Mountain region,
Texas, California and other states; Energy Marketing, which markets natural gas,
oil and related services to customers in the Midwest, Southwest, Rocky Mountain,
West Coast and Northwest regions markets; Power Generation, which produces and
sells power to wholesale customers; and Communications, which primarily markets
communications and software development services.
December 31: 2001 2000
---- ----
(in thousands)
Total assets
Integrated energy:
Coal mining $ 42,198 $ 47,038
Oil and gas 57,766 36,376
Energy marketing 134,496 328,960
Power generation 867,203 375,801
Electric utility 421,280 412,213
Communications 123,634 106,884
Corporate 2,100 1,039
Discontinued operations 10,090 12,009
---------- ----------
Total assets $1,658,767 $1,320,320
========== ==========
Capital expenditures and acquisitions
Integrated energy:
Coal mining $ 7,855 $ 2,419
Oil and gas 27,114 9,259
Energy marketing 152 273
Power generation 497,653 76,932*
Electric utility 41,313 25,257
Communications 20,030 59,377
Corporate 25 -
---------- ----------
Total capital expenditures and acquisitions $ 594,142 $ 173,517
========== ==========
--------------------------------------------------------------------
*Excludes the non-cash acquisition of Indeck Capital, Inc. as
described in Note 15.
Property, plant and equipment
Integrated energy:
Coal mining $ 63,592 $ 57,720
Oil and gas 104,926 77,812
Energy marketing 660 1,443
Power generation 696,345 294,805
Electric utility 569,368 530,380
Communications 129,748 109,718
Corporate 25 135
---------- ----------
Total property, plant and equipment $1,564,664 $1,072,013
========== ==========
42
December 31: 2001 2000 1999
---- ---- ----
(in thousands)
External operating revenues
Integrated energy:
Coal mining $ 20,551 $ 20,880 $ 23,431
Oil and gas 33,408 20,328 13,052
Energy marketing (a) 83,884 40,204 7,640
Power generation 80,233 20,083 -
Electric utility 212,355 173,308 133,222
Communications 20,258 7,689 278
----------- ----------- --------
Total external operating revenues $ 450,689 $ 282,492 $177,623
=========== =========== ========
Intersegment operating revenues
Integrated energy:
Coal mining $ 11,249 $ 9,650 $ 7,664
Communications 4,250 3,682 3,145
Intersegment eliminations (4,250) (3,682) (3,145)
----------- ----------- --------
Total intersegment operating revenues(b) $ 11,249 $ 9,650 $ 7,664
=========== =========== ========
--------------------------------------------------------------
(a) Operating revenues presented for energy marketing represent
trading margins.
(b) In accordance with the provisions of SFAS 71, intercompany fuel
sales to the electric utility segment are not eliminated.
Depreciation, depletion and amortization
Integrated energy:
Coal mining $ 2,984 $ 3,525 $ 3,259
Oil and gas 7,806 4,071 2,953
Energy marketing 484 404 2,517
Power generation 16,520 3,646 -
Electric utility 15,773 14,966 15,552
Communications 9,944 6,012 546
Corporate 300 - -
--------- --------- --------
Depreciation, depletion and amortization $ 53,811 $ 32,624 $ 24,827
========= ========= ========
Operating income (loss)
Integrated energy:
Coal mining $ 6,586 $ 8,795 $12,606
Oil and gas 15,193 7,906 3,978
Energy marketing 53,662 24,113 (1,366)
Power generation 27,455 20,374 (157)
Electric utility 84,108 68,208 52,286
Communications (13,250) (12,486) (3,647)
Corporate (3,984) (1,821) (926)
--------- -------- -------
Total operating income $ 169,770 $115,089 $62,774
========= ======== =======
43
December 31: 2001 2000 1999
---- ---- ----
(in thousands)
Interest income
Integrated energy:
Coal mining $ 8,125 $ 9,974 $ 2,709
Oil and gas 45 39 18
Energy marketing 1,854 527 330
Power generation 8,991 4,085 101
Electric utility 4,858 5,658 1,190
Communications 15 657 1,050
Corporate 7,379 369 399
Intersegment eliminations (28,895) (14,242) (2,200)
--------- ------- ---------
Total interest income $ 2,372 $ 7,067 $ 3,597
========= ======= =========
Interest expense
Integrated energy:
Coal mining $ 5,752 $ 8,006 $ 1,259
Oil and gas 145 372 568
Energy marketing 17 329 486
Power generation 33,593 11,911 111
Electric utility 15,780 17,411 13,830
Communications 5,789 6,244 1,155
Corporate 7,298 105 17
Intersegment eliminations (28,895) (14,242) (2,200)
--------- -------- ---------
Total interest expense $ 39,479 $ 30,136 $ 15,226
========= ======== =========
Income taxes
Integrated energy:
Coal mining $ 6,266 $ 2,660 $ 3,439
Oil and gas 4,930 2,609 968
Energy marketing 20,933 9,308 480
Power generation 1,668 3,154 (58)
Electric utility 24,255 19,469 12,446
Communications (6,561) (6,477) (807)
Corporate (1,341) (381) (249)
--------- -------- --------
Total income taxes $ 50,150 $ 30,342 $ 16,219
========= ======== ========
Net income (loss) from continuing operations
Integrated energy:
Coal mining $ 11,591 $ 7,172 $ 9,714
Oil and gas 10,197 4,992 2,462
Energy marketing 34,566 13,973 486
Power generation 1,576 3,242 (108)
Electric utility 45,238 37,178 27,362
Communications (12,300) (11,382) (968)
Corporate (2,560) (1,175) (295)
Intersegment eliminations (724) (1,188) (915)
--------- -------- --------
Total net income from continuing operations $ 87,584 $ 52,812 $ 37,738
========= ======== ========
44
(15) ACQUISITIONS
On April 11, 2001, the Company's power generation subsidiary, 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 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 operational in the fourth 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.
Total construction and acquisition cost for the entire facility is expected to
be approximately $330 million of which $302 million was expended as of September
30, 2002.
The acquisition has been accounted for under the purchase method of accounting
and, accordingly, the purchase price of approximately $205 million has been
allocated to the acquired assets and liabilities based on preliminary estimates
of the fair values of the assets purchased and the liabilities assumed as of the
date of acquisition. Fair values in the allocation include assets acquired of
approximately $150 million (excluding goodwill and other intangibles) and
liabilities assumed of approximately $2.0 million. The purchase price and
related acquisition costs exceeded the fair values assigned to net tangible
assets by approximately $57.0 million, which was recorded as long-lived
intangible assets and goodwill.
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
financial position or 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.
45
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.
(16) OIL AND GAS RESERVES (Unaudited)
Black Hills Exploration and Production has interests in 813 producing oil and
gas properties in nine states. Black Hills Exploration and Production also holds
leases on approximately 228,551 net undeveloped acres.
The following table summarizes Black Hills Exploration and Production's
quantities of proved developed and undeveloped oil and natural gas reserves,
estimated using year-end product prices, as of December 31, 2001, 2000 and 1999,
and a reconciliation of the changes between these dates. These estimates are
based on reserve reports by Ralph E. Davis Associates, Inc., an independent
engineering company selected by the Company. Such reserve estimates are based
upon a number of variable factors and assumptions, which may cause these
estimates to differ from actual results.
2001 2000 1999
---- ---- ----
Oil Gas Oil Gas Oil Gas
--- --- --- --- --- ---
(in thousands of barrels of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year 4,413 18,404 4,109 19,460 2,368 15,952
Production (446) (4,615) (352) (3,285) (309) (2,801)
Additions 749 19,111 625 4,228 376 7,718
Property sales - - - - (164) (66)
Revisions to previous estimates (661) (8,829) 31 (1,999) 1,838 (1,343)
------ ------- ------ ------- ------ -------
Balance at end of year 4,055 24,071 4,413 18,404 4,109 19,460
====== ======= ====== ======= ====== =======
Proved developed reserves at end of
year included above 2,962 22,420 3,047 16,418 2,819 14,391
====== ======= ====== ======= ====== =======
Year-end prices (average well-head) $18.12 $ 2.05 $26.76 $ 8.05 $25.60 $ 1.99
====== ======= ====== ======= ====== =======
46
(17) QUARTERLY HISTORICAL DATA (Unaudited)
The Company operates on a calendar year basis. The following table sets forth
selected unaudited historical operating results and market data for each quarter
of 2001 and 2000.
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
(in thousands, except per share amounts)
2001
Operating revenues $142,301 $130,442 $95,124 $94,071
Operating income 60,711 63,651 30,817 14,591
Income from continuing operations 31,436 34,528 17,005 4,615
Income from discontinued operations 655 325 (638) 151
Net income 32,091 34,853 16,367 4,766
Net income available for common
stock 32,050 34,553 16,235 4,712
Earnings per common share:
Basic -
Continuing operations 1.36 1.34 0.64 0.17
Discontinued operations 0.03 0.01 (0.03) 0.01
Total 1.39 1.35 0.61 0.18
Diluted -
Continuing operations 1.34 1.33 0.63 0.17
Discontinued operations 0.03 0.01 (0.02) 0.01
Total 1.37 1.34 0.61 0.18
Dividends paid per share 0.28 0.28 0.28 0.28
Common stock prices
High 45.74 58.50 45.55 34.20
Low 31.00 39.50 27.76 26.00
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
(in thousands, except per share amounts)
2000
Operating revenues $48,352 $50,571 $81,228 $111,991
Operating income 16,992 15,669 43,037 39,391
Income from continuing operations 9,187 8,363 16,365 18,897
Income from discontinued operations (126) (302) (43) 507
Net income 9,061 8,061 16,322 19,404
Net income available for common
stock 9,061 8,061 16,285 19,363
Earnings per common share:
Basic -
Continuing operations 0.43 0.39 0.72 0.82
Discontinued operations (0.01) (0.01) (0.01) 0.02
Total 0.42 0.38 0.71 0.84
Diluted -
Continuing operations 0.43 0.39 0.71 0.81
Discontinued operations (0.01) (0.01) - 0.02
Total 0.42 0.38 0.71 0.83
Dividends paid per share 0.27 0.27 0.27 0.27
Common stock prices
High 25.19 25.19 30.13 46.06
Low 20.44 20.88 22.00 27.00
47
(18) SUBSEQUENT EVENTS
Discontinued Operations
During the second quarter of 2002, the Company adopted a plan to dispose of its
coal marketing subsidiary, Black Hills Coal Network. The sale and disposal was
finalized in July 2002. In connection with the plan of disposal, the Company
determined that the carrying values of some of the underlying assets exceeded
their fair values and a charge to operations was required. The Company recorded
an after tax charge of approximately $1.0 million, which represents the
difference between the carrying value of the assets and liabilities of the
subsidiary versus its fair value, less cost to sell. Results of operations and
the related charges have been classified as "Discontinued operations" in the
accompanying Consolidated Statements of Income, and prior periods have been
restated. For business segment reporting purposes, the coal marketing business
results were previously included in the segment "Energy Marketing."
Revenues and net income from the discontinued operations are as follows:
2001 2000 1999
---- ---- ----
(in thousands)
Revenues $ 3,660 $ 1,578 $ 1,111
-------- -------- --------
Pre-tax income (loss) from discontinued operations 886 52 (1,101)
Income tax benefit (expense) (393) (16) 430
-------- -------- --------
Net income (loss) from discontinued operations $ 493 $ 36 $ (671)
======== ======== ========
Assets and liabilities of the discontinued operations are as follows:
2001 2000
---- ----
(in thousands)
Current assets $ 7,878 $ 10,287
Non-current assets 2,212 1,722
Current liabilities (8,724) (11,080)
Non-current liabilities (96) -
------- ---------
Net assets (liabilities) of discontinued operations $ 1,270 $ 929
======= =========
Energy Trading Activities
During June 2002, the Emerging Issues Task Force (EITF) reached a consensus on
Issues 1 and 3 of EITF Issue No. 02-3, "Recognition and Reporting of Gains and
Losses on Energy Trading Contracts under EITF Issue No. 98-10," "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," and No.
00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue
No. 98-10."
At a meeting on October 25, 2002, the EITF reached new consensuses that
effectively supersede the consensus on EITF 02-3, reached at its June 2002
meeting. At its October 2002 meeting, the EITF reached a consensus to rescind
EITF 98-10, the impact of which is to preclude mark-to-market accounting for all
energy trading contracts not within the scope of FASB Statement No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The EITF also
reached a consensus that gains and losses on derivative instruments within the
scope of Statement 133 should be shown net in the income statement if the
derivative instruments are held for trading purposes. The consensus regarding
the rescission of Issue 98-10 is applicable for fiscal periods beginning after
December 15, 2002. Energy trading contracts not within the scope of Statement
133 entered into after October 25,2002, but prior to the implementation of the
consensus are not permitted to apply mark-to-market accounting. The Company has
not yet quantified the financial statement effect of this EITF action. The
Company currently reports its energy trading activities on a net basis.
48
Acquisitions of Additional Interests
On March 8, 2002, the Company acquired an additional 67 percent ownership
interest in Millennium Pipeline Company, L.P., which owns and operates a
200-mile pipeline. The pipeline has a capacity of approximately 65,000 barrels
of oil per day, and transports imported crude oil from Beaumont, Texas to
Longview, Texas, which is the transfer point to connecting carriers. The Company
also acquired additional ownership interest in Millennium Terminal Company,
L.P., which has 1.1 million barrels of crude oil storage connected to the
Millennium Pipeline at the Oil Tanking terminal in Beaumont. The Millennium
system is presently operating near capacity through shipper agreements. These
acquisitions give the Company 100 percent ownership in the Millennium companies.
Total cost of the acquisitions was $11.0 million and was funded through
borrowings under short-term revolving credit facilities.
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. The 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.
The Company's investments in the above entities prior to the above acquisitions
were accounted for under the equity method of accounting and were included in
Investments on the accompanying Consolidated Balance Sheets. Each of the above
acquisitions gave the Company majority ownership and voting control of the
respective entities, therefore, after acquisition the Company will consolidate
each of the entities in its consolidated financial statements.
The above acquisitions have been accounted for under the purchase method of
accounting and, accordingly, the purchase prices have been allocated to the
acquired assets and liabilities based on preliminary estimates of the fair
values of the assets purchased and the liabilities assumed as of the date of
acquisition. The estimated purchase price allocations are subject to adjustment,
generally within one year of the date of acquisition. The purchase prices and
related acquisition costs exceeded the fair values assigned to net intangible
assets by approximately $9.3 million, which was recorded as long-lived
intangible assets.
The impact of these acquisitions was not material in relation to the Company's
results of operations. Consequently, pro forma information is not presented.
Other Acquisitions
During July 2002, the Company purchased the assets of the Kilgore to Houston
Pipeline System from Equilon Pipeline Company, LLC. The Kilgore pipeline
transports crude oil from the Kilgore, Texas region south to Houston, Texas,
which is the transfer point to connecting carriers via the Oil Tanking Houston
terminal facilities. The 10-inch pipeline is approximately 190 miles long and
has a capacity of up to approximately 35,000 barrels per day. In addition, the
Kilgore system has approximately 400,000 barrels of crude oil storage at Kilgore
and 375,000 barrels of storage at the Texoma Tank Farm located in Longview,
Texas. Total cost of the acquisition was $6.7 million and was funded through
borrowings under short-term credit facilities.
Potential Acquisition - unaudited
On October 1, 2002, the Company entered into a definitive merger agreement to
acquire Denver-based Mallon Resources Corporation. Total cost of the acquisition
is estimated to be $52 million, which includes the Company's acquisition on
October 1, 2002 of Mallon's debt to Aquila Energy Capital Corporation and the
settlement of outstanding hedges, amounting to $30.5 million. The merger
agreement, which has been approved by both companies' Board of Directors,
provides that Mallon shareholders will receive 0.044 of a share of Black Hills
for each share of Mallon. Completion of the acquisition which is subject to
customary conditions, including the approval by the shareholders of Mallon, is
expected in the first quarter of 2003.
49
Mallon Resources' proved reserves, as reported at December 31, 2001, were 53.3
billion cubic feet of gas equivalent. The Company estimates that Mallon's
current proved reserves could be substantially higher based on its review of the
reserves and current oil and gas prices. The reserves are located primarily on
the Jicarilla Apache Nation in the San Juan Basin of New Mexico and are
comprised almost entirely of natural gas in shallow sand formations. The oil and
gas leases of the acquisition total more than 66,500 gross acres (56,000 net),
most of which is contained in a contiguous block that is in the early stages of
development.
Current daily net production of the Mallon properties is nearly 13 million cubic
feet of gas equivalent. Mallon operates 149 of 171 total gas and oil wells, with
working interests averaging 90 to 100 percent in most of the wells and
undeveloped acreage.
Upon closing, the Company expects the acquisition to increase gas and oil
production immediately by approximately 60 percent and more than double the
Company's proven oil and gas reserves. After the acquisition is closed, the
Company plans to initiate an expanded development and exploratory drilling
program on the properties which is expected to increase gas production, reserves
and cash flow from fuel operations in late 2003 and beyond. The acquisition is
expected to have a nominal earnings-per-share impact until production levels can
be increased.
Financings
On March 14, 2002, the Company closed on $135 million five-year senior secured
project-level financing for the Arapahoe and Valmont facilities. These projects
have a total of 210-megawatts in service and are located in the Denver, Colorado
area. Proceeds from this financing were used to refinance $53.8 million of an
existing seven-year secured term project-level facility, pay down approximately
$50 million of short-term credit facility borrowings and approximately $31.2
million was used for project construction. At September 30, 2002, all of the
$135 million financing had been utilized.
During the first quarter of 2002, the Company completed a $50 million bridge
credit agreement. The credit agreement supplemented the Company's revolving
credit facilities and had the same terms as those facilities with an original
expiration date of June 30, 2002, which was subsequently extended to September
27, 2002. On September 27, 2002, this $50 million facility was replaced by a $50
million secured financing for the expansion at our Las Vegas II project, a
224-megawatt gas-fired generation facility located in North Las Vegas, Nevada
which expires on November 26, 2002. The financing is guaranteed by the Company.
On June 18, 2002, the Company closed on a $75 million bridge credit agreement.
The credit agreement bridged the issuance of $75 million of Black Hills Power
First Mortgage Bonds, which were issued on August 13, 2002. The termination date
of the bridge credit agreement was August 13, 2002, the date on which the First
Mortgage Bonds were issued.
On June 28, 2002, the Company's gas marketing subsidiary, Enserco Energy, Inc.
closed on a $135 million uncommitted, discretionary credit facility, which
became effective July 1, 2002 and expires June 27, 2003. This facility replaced
the prior $75 million Enserco Energy facility.
On August 13, 2002, The Company's electric utility subsidiary, Black Hills
Power, Inc., issued $75 million of First Mortgage Bonds, Series AE, due 2032.
The First Mortgage Bonds have a 7.23 percent coupon with interest payable
semiannually, commencing February 15, 2003. Net proceeds from the offering were
and will be used to fund the Company's portion of construction and installation
costs for an AC-DC-AC Converter Station; for general capital expenditures for
the remainder of 2002 and 2003; to repay a portion of current bank indebtedness;
to satisfy bond maturities for certain outstanding first mortgage bonds due in
2003; and for general corporate purposes.
In August 2002, the Company closed on a $195 million unsecured revolving credit
facility that expires August 26, 2003. The credit facility extended the
Company's previous $200 million 364-day credit facility that expired on August
27, 2002.
On September 25, 2002, the Company closed on a $35 million two-year unsecured
credit agreement. Proceeds were used to fund the Company's working capital needs
and for general corporate purposes.
The $195 million credit facility, the $200 million three-year credit facility
and the $35 million two-year credit facility contain a liquidity covenant that
requires the Company to have $30 million in liquid assets as of the last day of
each fiscal quarter beginning with December 31, 2002. Liquid assets are defined
as unrestricted cash and available unused capacity under capacity under the
Company's credit facilities.
50
Exhibit No. Description
----------- -----------
23.1 Independent Auditors' Consent
23.2 Consent of Petroleum Engineer and Geologist
99.1 Press release dated November 25, 2002 issued by
Black Hills Corporation
51
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
BLACK HILLS CORPORATION
By: /s/ Mark T. Thies
---------------------
Mark T. Thies
Sr. Vice President
and Chief Financial Officer
Date: November 25, 2002
52
Exhibit Index
Exhibit
Number Description
------ -----------
23.1 Independent Auditors' Consent
23.2 Consent of Petroleum Engineer and Geologist
99.1 Press release dated November 25, 2002 issued by
Black Hills Corporation
53