EXHIBIT 13
FINANCIAL DIRECTORY
Management's Discussion and Analysis of
Financial Condition and Results of
Operations . . . . . . . . . . . . . . . .12
Report of Management . . . . . . . . . . . .19
Report of Independent Public Accountants . .19
Consolidated Statements of Income . . . . .20
Consolidated Statements of Retained
Earnings . . . . . . . . . . . . . . . . .20
Consolidated Statements of Cash Flows. . . .21
Consolidated Balance Sheets . . . . . . . .22
Consolidated Statements of Capitalization .23
Notes to Consolidated Financial Statements .24
Financial Statistics . . . . . . . . . . . .30
Electric Operation Statistics . . . . . . .31
Investor Information . . . . . . . . . . . .32
Management's Discussion and Analysis
of Financial Condition and Results of Operations
Black Hills Corporation (the Company) is an energy services company
primarily consisting of three principal businesses: electric, coal mining,
and oil and gas production. Under the assumed name of Black Hills Power and
Light Company, the Company provides electric service to customers in the
states of South Dakota, Wyoming, and Montana; Wyodak Resources Development
Corp. (WRDC) mines and sells coal via long-term contracts; and Western
Production Company (WPC) explores and produces oil and gas.
Liquidity and Capital Resources
The Company generated cash from operations sufficient to meet operating
needs, pay dividends on common stock and finance a portion of capital
requirements. Except for the Company's current construction of Neil Simpson
Unit #2 (NSS #2), a new power plant, property additions from 1992 through
1994 were primarily for the replacement of equipment, modernization of
facilities, and for oil and gas investments. The primary capital
requirements of the Company for the past three years were as follows:
1994 1993 1992
(in thousands)
Construction of NSS #2 $73,984 $12,792 $ 2,227
Other electric property
additions 14,187 13,140 15,507
Coal mining additions 5,911 7,425 5,001
Oil and gas investments 8,977 6,933 5,180
Common stock dividends 18,920 17,720 16,977
Maturities and redemptions
of long-term debt 3,542 4,166 3,725
-------- ------- -------
$125,521 $62,176 $48,617
Capital requirements for projected construction, capital improvements,
and oil and gas investments are estimated to be as follows:
1995 1996 1997
(in thousands)
NSS #2 $31,100 $ - $ -
Other electric 13,200 15,000 14,500
Coal mining 1,700 2,500 1,100
Oil and gas 9,500 6,000 6,000
------- ------- -------
$55,500 $23,500 $21,600
Major capital expenditures forecasted for the electric operations
include the completion of NSS #2 in 1995 (See Construction of Neil Simpson
Unit #2). The coal mining operations forecasted expenditures include the
replacement of mining equipment. Forecasted expenditures for the oil and
gas operations is dependent upon future cash flows and include an active
development and exploratory drilling program and acquisition of existing
producing properties. WYGEN, Inc., a newly formed subsidiary in 1994, does
not currently have any forecasted capital expenditures. WYGEN was formed as
an exempt wholesale generator and will not incur substantial costs until and
unless long-term power sale contracts are obtained.
Long-term debt and sinking fund requirements are as follows:
1995 1996 1997
(in thousands)
Electric $2,136 $2,255 $2,384
Coal mining 8 - -
------ ------ ------
$2,144 $2,255 $2,384
Under its mining permit, WRDC 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 $600,000 is charged to operations as reclamation
expense annually. As of December 31, 1994, accrued reclamation costs were
approximately $7,600,000.
The Company's capitalization for the three years ended December 31 was
as follows:
1994 1993 1992
Long-term debt 42% 34% 37%
Common equity 58 66 63
--- --- ---
100% 100% 100%
The Company sold 525,000 shares of Common Stock, $1 par value, at a
price of $25-3/8 per share in 1993 through a public stock offering.
Proceeds from the sale were used to finance NSS #2. Net proceeds from the
sale were approximately $12,700,000.
The Company revised its Dividend Reinvestment and Stock Purchase Plan
in 1993, under which shareholders may purchase additional shares of Common
Stock through dividend reinvestment or optional cash payments at 100 percent
of the recent average market price. The Company has the option of issuing
new shares or purchasing the shares on the open market. The Company issued
112,578 new shares under the Plan in 1994 and 26,891 shares in 1993.
Proceeds from the sale of new shares were used to finance capital
expenditures.
The Company filed a Form S-3, shelf registration in 1994 for
$100,000,000 first mortgage bonds. The Company issued $45,000,000 first
mortgage bonds under this filing on September 1, 1994. The bonds have a 30
year life and carry an 8.3 percent rate of interest. The Company issued
$3,000,000 Environmental Improvement Revenue Bonds in 1994. The
environmental bonds carry a variable rate of interest which is currently
reset weekly. The average interest rate applied to the bonds in 1994 was
3.5 percent. The environmental bonds are structured so that the Company can
determine from time to time whether to cause them to be remarketed
periodically on a short-term or long-term basis. The ability to continue
the environmental bonds on a short-term basis to take advantage of lower
interest rates depends on the ability to continue to remarket the bonds.
Proceeds from both bond issues were used to finance NSS #2. These
additional financings increased the debt component of the Company's capital
structure from 34 percent at December 31, 1993 to 42 percent at December 31,
1994.
The Company also completed the refinancing of the $12,200,000, City of
Gillette Pollution Control Revenue Bonds during 1994. During 1992 the
Company entered into a forward refunding agreement on the $12,200,000, 10.5
percent, City of Gillette Pollution Control Revenue Bonds. The new bonds
were issued in July 1994 at 7.5 percent and the Series 1984 bonds were
called and redeemed on August 1, 1994 at 102 percent of par.
Subsequent to year-end, the Company issued $30,000,000 first mortgage
bonds under the shelf registration. The bonds have a 15 year life and carry
an 8.06 percent rate of interest. The bondholders have a one-time option to
cause the Company to redeem the bonds at par on February 1, 2002. Management
believes that this issue will complete the long-term debt financing
associated with NSS #2. The remaining expenditures related to the project
will be financed by existing cash balances, short-term investments, and
short-term lines of credit. (See Construction of Neil Simpson Unit #2).
The Company issued $12,300,000, 6.7 percent, Pollution Control Revenue
Refunding Bonds in 1992 to redeem $12,300,000 Pollution Control and
Industrial Revenue Bonds which were collateralized by first mortgage bonds.
The refunding bonds have no sinking fund requirements and mature in 2010.
The refunding bonds are not secured under the Company's Indenture of
Mortgage.
At December 31, 1994, the Company had $70,000,000 of unsecured short-
term lines of credit which provides for interim borrowings and the
opportunity for timing of permanent financing. Borrowings outstanding under
these lines of credit were $36,975,000 and $11,700,000 as of December 31,
1994 and 1993, respectively. The weighted average interest rate on these
borrowings at December 31, 1994 and 1993 was 6.9 percent and 4.5 percent,
respectively. Average borrowings during 1994, 1993, and 1992 were
$21,070,000, $11,059,000, and $5,616,000, respectively. The increase in
borrowings was directly related to the financing of the construction of NSS
#2. There are no compensating balance requirements associated with these
lines of credit. The Company pays a 0.125 percent facility fee on
$25,000,000 of the existing short-term lines.
In the past the Company has depended upon internally generated funds,
issuance of short and long-term debt, and sales of common stock to finance
its activities.
Credit ratings for the Company's First Mortgage Bonds remained at an A1
level at Moody's Investors Service, Inc. and a 5 (High Single A) at Duff &
Phelps, Inc. in 1994. Standard & Poor's reduced the Company's rating from
an A+ level with a negative outlook in 1993 to an A level with negative
outlook in 1994. These ratings reflect the opinion of the respective
agencies as to the credit quality of the Company's bonds. Standard & Poor's
stated that the downgrade was issued to reflect a burdensome construction
program which will pressure financial results and require supportive rate
treatment to maintain current credit worthiness. They stated the negative
outlook would be removed if the Company receives favorable rate orders on
NSS #2.
(TABLE IN ANNUAL REPORT)
COMMON STOCK DATA
1994 1993 1992
Net Income $23,805,000 $22,946,000 $23,638,000
Earnings Per Average Share $1.66 $1.66 $1.73
Weighted Average Shares
Outstanding 14,339,095 13,810,912 13,689,105
Dividends Paid Per Share $1.32 $1.28 $1.24
Five-Year Dividend Growth
Rate 5.5% 6.6% 8.4%
Payout Ratio 79.5% 77.1% 71.7%
Book Value $12.19 $11.78 $10.89
Year-end Stock Price $21.38 $22.75 $27.50
Dividend Yield on
Market Value 6.2% 5.6% 4.5%
Price Earnings Ratio 13 14 16
Return on Common Equity
at Year-end 13.6% 13.7% 15.8%
Construction of Neil Simpson Unit #2
Construction of NSS #2, an 80 MW coal fired generating plant located
adjacent to WRDC's coal mine, commenced in August 1993. Construction of NSS
#2 is proceeding ahead of schedule and costs incurred to date are under the
initial project budget. The construction costs of the plant are currently
budgeted at $121,000,000. NSS #2 will increase net utility plant by more
than 50 percent. Commercial operation is currently estimated to begin in
September 1995. Purchased power is utilized by the Company in the interim
to meet load growth not satisfied by existing resources. As of December 31,
1994, the Company has incurred approximately $89,000,000 of costs related to
the plant. NSS #2 will be fueled by coal from WRDC's mine. The coal
pricing methodology is not expected to increase earnings on coal sales to
the Company because of the Company's agreement to limit coal payments to a
return on its affiliate's investment base. Earnings on coal sales to the
Company could be further limited because the Company has agreed to further
discount the price of coal during a period of time that under prudent
dispatch that power plant would not have been operated if it were not for
the discounted price of coal.
The Company guaranteed to the South Dakota Public Utilities Commission
and the Wyoming Public Service Commission that the Company will never
include in rate base for the determination of electric rates any initial
capital costs of NSS #2 that exceed $124,889,000, including allowance for
funds used during construction. Due to the guarantee, the Company would
likely be forced to write off against earnings any construction costs of NSS
#2 in excess of the guaranteed costs except to the extent that those costs
could be recovered through performance guarantees and damage provisions in
the contracts with the vendors and contractors. Management believes that
the cost of the project will not exceed the amount of the guarantee.
(CHART IN ANNUAL REPORT)
CONSOLIDATED DEBT RATIOS (in percent)
1994 42.4
1993 33.7
1992 37.3
1991 39.6
1990 36.9
1989 38.3
MDU Power Sale
During 1994, the Company entered into a Power Integration Agreement
with Montana-Dakota Utilities Co. (MDU), a division of MDU Resources Group,
Inc. The market-based agreement provides that for a period of 10 years
commencing January 1, 1997, the Company will supply up to 55 MW of the
electric power and energy required by MDU for its electric service area in
and around Sheridan, Wyoming. MDU's Sheridan service area has experienced a
45 MW peak and a load factor of approximately 60 percent. The agreement is
subject to the approval of the Federal Energy Regulatory Commission.
The agreement further provides that the Company and MDU will share
equal ownership in a combustion turbine of approximately 70 MW to be
constructed at such time as the Company determines a new peaking resource is
required. Both companies will receive the benefit of lower unit costs from
a turbine that will be larger than either company could justify on its own.
Rate Applications
On February 1, 1995 the Company filed an application with the South
Dakota Public Utilities Commission requesting authority to increase rates by
an average of 9.96 percent with the condition that rates will not be reduced
when the benefits of the MDU Power Sale are realized commencing January 1,
1997. The Company has requested that the rate increase become effective
when NSS #2 begins commercial operation. The Company plans to file an
application for a rate increase with the Wyoming Public Service Commission
in March 1995.
The Company is seeking a negotiated increase in rates with its only
wholesale customer, the City of Gillette, Wyoming. A tentative agreement
with Gillette, subject to final approval of the parties and the Federal
Energy Regulatory Commission, has been reached that will result an effective
rate increase of 12.3 percent when NSS #2 becomes commercial and reduced to
8.8 percent on January 1, 1997 when the MDU Power Sale becomes effective.
Competition
Management believes the Company's electric rates after the rate
increase will remain favorably competitive with most rural electric
cooperatives serving adjacent to the Company's service territory. However,
this could be affected by many factors beyond the control of the Company.
The electric utility industry can be expected to become increasingly
competitive, due to a variety of regulatory, economic, and technological
changes. The increasing level of competition is being fostered, in part, by
the enactment of the National Energy Policy Act (NEPA) of 1992. NEPA
encourages competition by allowing both utilities and non-utilities to form
non-regulated generation subsidiaries without being restricted by the Public
Utility Holding Company Act of 1935. As a result of competition in electric
generation, wholesale power markets have become increasingly competitive.
Although NEPA specifically bans federal-mandated wheeling of power for
retail customers, several state public utility regulatory commissions are
currently studying retail wheeling. None of the utility commissions in the
Company's service territory have instituted proceedings on retail wheeling
at this time. With the passage of NEPA and the advent of a more competitive
electric utility environment, the Company continues to review its strategic
plan and implement changes to increase its competitiveness.
To assist in the planning for new resources and to minimize the risk of
loss of large loads, the Company endeavors to contract with its large
industrial users to serve all electric power needs for a term of years.
Currently, Homestake Mining Company is under a 9-year contract to purchase
all of its electric power requirements from the Company. The South Dakota
State Cement Plant is under a similar 5-year contract and the City of
Gillette is under a 17-year contract for 23 MW of its base load. These
three customers in 1994 accounted for 29 percent of the Company's total firm
kilowatthour sales and 20 percent of firm electric sales revenue.
Results of Operations:
Consolidated Results
Consolidated net income for 1994 was $23,805,000 compared to
$22,946,000 in 1993 and $23,638,000 in 1992 or $1.66 per average common
share in 1994 and 1993 and $1.73 per average common share in 1992. This
equates to a 13.6 percent return on year-end common equity in 1994, 13.7
percent in 1993, and 15.8 percent in 1992. The Company recognized a non-
recurring $940,000 after-tax non-cash gain in 1992 related to the PacifiCorp
Settlement (see PacifiCorp Settlement) which was equivalent to $0.07 per
share. Without this gain, earnings per share would have been flat for the
three year period with 4 percent and 1 percent more average common shares
outstanding in 1994 and 1993, respectively. Consolidated net income for
1994 includes non-cash earnings of $2,371,000 for allowance for equity funds
used during construction.
Consolidated revenue and income provided by the three businesses as a
percentage of the total were as follows:
Revenue
1994 1993 1992
Electric 72% 71% 72%
Coal mining 20 21 21
Oil and gas 8 8 7
--- --- ---
100% 100% 100%
Net Income
Electric 54% 49% 47%
Coal mining 41 46 49
Oil and gas 5 5 4
--- --- ---
100% 100% 100%
Dividends paid on common stock totaled $1.32 per share in 1994. This
reflected increases approved by the Board of Directors from $1.28 per share
in 1993 and $1.24 per share in 1992. Dividends have increased at a 4.1
percent average annual compound growth rate over the last three years. All
dividends were paid out of current earnings.
In January 1995 the Board of Directors increased the quarterly dividend
1.5 percent to 33.5 cents per share. If this dividend is maintained during
1995, the increase will be equivalent to an annual increase of 2 cents per
share.
Wyodak Plant Maintenance Schedule
The Wyodak Plant was out of operation for five weeks in 1994 for
scheduled maintenance. Fiscal 1993 and 1992 represent whole years of
operations from the Wyodak Plant. When the Wyodak Plant is out of service,
replacement power is provided from purchased power and increased generation
from the Company's other generating plants. Additional purchased power
costs are recovered by the utility through the fuel adjustment clauses. The
loss of coal sales to the Wyodak Plant is partially mitigated through
greater coal sales to the Company's other generating plants and reduced
operating costs.
(CHART IN ANNUAL REPORT)
FIRM ELECTRIC SALES (Millions of Kwh)
1994 1,638
1993 1,594
1992 1,540
1991 1,532
1990 1,479
PacifiCorp Settlement
In 1987 WRDC and the Company entered into settlement agreements with
PacifiCorp canceling PacifiCorp's obligation to purchase coal commencing in
1990 for a second plant scheduled to be constructed adjacent to the Wyodak
Plant but which had been canceled, and settling a dispute over the quantity
of coal PacifiCorp was required to purchase to operate the Wyodak Plant.
This settlement resulted in an increase in the Company's net income in 1994,
1993, and 1992 of approximately $1,700,000, $1,500,000, and $2,800,000 or
$0.12, $0.11, and $0.20 per share of common stock, respectively. The
settlement provided for, among other things, payments to WRDC of $2,000,000
each on January 2, 1988 through 1991 for an option to purchase 50,000,000
tons of coal if PacifiCorp should construct a second Wyodak power plant and
required PacifiCorp to pay up to $15,000,000, such amount to be adjusted for
inflation and deflation, for the cost of new coal handling facilities.
Construction of the coal handling facilities commenced in 1992 and was
completed in 1994. As a result of a definitive agreement entered into with
PacifiCorp in 1992 regarding the construction of these facilities, the
Company recognized a non-recurring $940,000 after-tax non-cash gain in 1992.
The gain was due to the assumption by PacifiCorp of certain liabilities
related to the existing coal handling facilities that were replaced by the
construction of the new facilities. Other benefits from the PacifiCorp
Settlement will continue to have a positive effect on earnings for the life
of the agreements. The exact amount of earnings each year will depend
largely upon the continued successful operation of the Wyodak Plant.
Electric Operations
1994 1993 1992
(in thousands)
Revenue $104,756 $98,155 $97,448
Operating expenses 79,680 74,173 74,056
-------- ------- -------
Operating income $ 25,076 $23,982 $23,392
======== ======= =======
Net income $ 12,852 $11,171 $11,041
======== ======= =======
Electric revenue increased 6.7 percent in 1994 compared to a 0.7
percent increase in 1993 and a 0.7 percent decrease in 1992. Firm
kilowatthour sales increased 2.7 percent in 1994 compared to a 3.5 percent
increase in 1993 and a 0.5 percent increase in 1992 and have averaged an
annual 2.2 percent growth rate over the last three years. Sales growth in
1992 was reduced by mild weather conditions.
The increase in revenue in 1994 was due to the 2.7 percent increase in
firm kilowatthour sales and an increase in the fuel and purchased power
adjustment passed on to electric customers. The increase in purchased power
costs was primarily due to replacement power purchased while the Wyodak
Plant was down for maintenance.
The revenue increase in 1993 from additional electric sales was offset
by a decrease in the fuel and purchased power adjustment passed on to
electric customers. The decrease in the purchased power adjustment passed
on to electric customers was due to a $2,000,000 refund received from
PacifiCorp on the 40-year power purchase agreement. Homestake Mining
Company, the Company's largest customer, reduced its energy usage by 22,000
megawatt hours in 1993 by concentrating on more efficient production areas.
Revenue decreased in 1992 due to a decrease in the fuel and purchased
power adjustment passed on to electric customers. This decrease was a
result of a $600,000 increase in the refund accrued for the limitation on
the return allowed on WRDC coal sales to the Company's power plants and a
$600,000 decrease in fuel and purchased power expense. Purchased power
decreased in 1992 compared to 1991 due to a full year of operations at the
Wyodak Plant.
In South Dakota the Company may not include in rates any cost of coal
which allows WRDC to earn a return on equity on sales of coal to the
Company's utility operations in excess of a percentage equal to the rate on
long-term "A" rated utility bonds plus 400 basis points (4 percent). The
investment base on which the return is calculated includes all of WRDC's
investment base except for investments in subsidiary companies and other
non-mining interests. The maximum return on equity to be applied in 1995
for the 1994 adjustment will be approximately 12.3 percent. The returns
applied for the 1993 and 1992 adjustments were 11.6 percent and 12.7
percent, respectively. The Company has recorded an accrual for the 1995
refund for sales in 1994 of approximately $760,000. The 1994 and 1993
refunds were approximately $1,061,000 and $1,538,000, respectively. Tons of
WRDC's coal sold to the Company represent approximately 33 percent of its
total coal sales. The refund decreased in 1994 primarily due to the
increase in long-term "A" rated utility bond interest rates.
The decrease in the allowed return in 1993 was offset by an increase in
WRDC's investment base primarily due to its investment in an electric shovel
and new coal conveying facilities.
Revenue per kilowatt sold was 6.1 cents in 1994 up from 5.9 cents in
1993 and 6.0 cents in 1992. The number of customers in the service area
increased to 53,959 in 1994 from 53,330 in 1993 and 52,535 in 1992. The
increase in revenue per kilowatthour sold in 1994 was due to the increase in
purchased power cost related to replacement power purchased during the
Wyodak Plant maintenance period.
Operating expenses increased substantially in 1994 due to the increase
in purchased power costs, remained relatively flat in 1993 compared to 1992
as a result of the $2,000,000 purchased power refund, and increased 0.7
percent in 1992.
(CHART IN ANNUAL REPORT)
TONS OF COAL SOLD (thousands of tons)
1994 2,796
1993 3,027
1992 2,958
1991 2,742
1990 2,908
Coal Mining Operations
1994 1993 1992
(in thousands)
Revenue $28,594 $29,822 $28,296
Operating expenses 16,772 17,462 16,724
------- ------- -------
Operating income $11,822 $12,360 $11,572
======= ======= =======
Net income $ 9,873 $10,648 $11,695
======= ======= =======
Revenue decreased 4.1 percent in 1994 and increased 5.4 percent in 1993
and 8.3 percent in 1992 due to a 7.6 percent decrease and a 2.3 percent and
7.9 percent increase, respectively in tons of coal sold. The decrease in
tons of coal sold in 1994 was caused by the Wyodak Plant being out of
service for five weeks of scheduled maintenance. Operating expenses
decreased 4.0 percent in 1994 reflecting the decrease in tons of coal mined
offset by an increase in depreciation expense. Operating expense increased
4.4 percent in 1993 reflecting an increase in depreciation expense as a
result of an increase in capital investments and higher taxes associated
with increased revenues. Operating expenses remained relatively flat in
1992 caused by a decrease in administrative and general expenses offset by
an increase in coal production.
Non-operating income was $1,763,000 in 1994 compared to $2,226,000 in
1993 and $3,894,000 in 1992. Non-operating income includes the PacifiCorp
Settlement, a coal contract settlement from Grand Island, Nebraska, and
interest income from investments. Non-operating income decreased in 1994
and 1993 due to a decrease in interest income attributable to lower interest
rates and a non-recurring $940,000 after-tax non-cash gain recognized in
1992 related to the PacifiCorp Settlement.
WRDC formed two new subsidiaries during 1994, WYGEN, Inc. and DAKSOFT,
Inc. WYGEN is an exempt wholesale generator as authorized by the National
Energy Policy Act of 1992 and will engage exclusively in the business of
owning or operating eligible electric generating facilities and selling
electricity at wholesale. WYGEN plans to seek an air quality permit to
construct the WYGEN Plant, an 80 MW mine-mouth, coal fired, electric
generating plant, to be constructed next to NSS #2. Construction of the
WYGEN Plant will not commence and WYGEN will not incur substantial costs
until and unless long-term power sale contracts are obtained, justifying the
construction. DAKSOFT, Inc. was formed to develop and market internally
generated computer software associated with the Company's business segments.
Neither company has recorded any revenue as of December 31, 1994, and their
expenses are primarily organizational costs. Because of the immaterial
amount of these costs they have been included with coal mining expenses.
Oil and Gas Production
1994 1993 1992
(in thousands)
Revenue $12,052 $11,396 $9,599
Production expenses 10,196 9,952 8,214
------- ------ ------
Operating income $ 1,856 $1,444 $1,385
======= ====== ======
Net income $ 1,080 $1,127 $ 902
======= ====== ======
The oil and gas operations have not been a significant percent of the
Company's total operations. Net income and assets related to oil and gas
operations have been 7 percent or less of the Company's consolidated amounts
over the last three years.
Revenue is primarily comprised of oil and gas sales and is supplemented
by field services in eastern Wyoming. Equivalent barrels of oil sold
increased approximately 34 percent to 624,000 barrels in 1994 from 465,000
barrels in 1993 and 315,000 barrels in 1992. The average sales price of oil
per barrel was $15.56 in 1994 compared to $16.69 in 1993 and $19.10 in 1992.
The average sales price per mcf of gas was $1.81 in 1994 compared to $2.31
in 1993 and $1.63 in 1992. WPC's production expenses increased 2.5 percent
in 1994 compared to 21 percent in 1993 and 6.4 percent in 1992. Production
expenses increased primarily due to increased depletion expense as a result
of increased oil and gas production and lower oil and gas prices. WPC
recognized $4,450,000, $3,725,000, and $2,291,000 of depletion expense in
1994, 1993, and 1992, respectively.
Low oil and gas prices reduce the cash flow and value of the Company's
oil and gas assets and will cause the Company to increase its depletion
expense.
WPC's proved reserves, and the revenues generated from production, will
decline as production occurs, except to the extent WPC conducts successful
exploration and development activities or acquires additional proved
reserves. WPC has been in an active exploration and development drilling
program during the past three years. Much of WPC's production growth in
1994 and 1993 was the result of its horizontal drilling program in the
Austin Chalk formation in Texas. WPC intends to increase its net proved
reserves by selectively increasing its oil and gas exploration and
development activities and by acquiring producing properties primarily with
the use of internally generated funds.
WPC's reserves are based on reports prepared by Ralph E. Davis
Associates, Inc. Reserves were determined using constant product prices at
the end of the respective years. Estimates of economically recoverable
reserves and future net revenues are based on a number of variables which
may differ from actual results. WPC's unaudited reserves, principally
proved developed and proved undeveloped properties, were estimated to be
1.4, 1.1, and 2.2 million barrels of oil and 9.1, 2.8, and 3.2 billion cubic
feet of natural gas as of December 31, 1994, 1993, and 1992, respectively.
The increase in reserves as of December 31, 1994, was primarily due to the
active drilling program and a production acquisition in South Texas. The
decrease in the reserves in 1993 was caused by price decreases, production
increases, and engineering revisions. WPC has interests in 410 producing
oil and gas properties in seven states. WPC operates a total of 349 wells
in Wyoming and Colorado. WPC's non-operated properties are located in
Texas, Wyoming, Colorado, North Dakota, Montana, Kansas, and California.
(CHART IN ANNUAL REPORT)
EQUIVALENT BARRELS OF OIL SOLD (thousands of barrels)
1994 624
1993 465
1992 315
1991 262
1990 205
Regulatory Accounting
The Company follows Statement of Financial Accounting Standards (SFAS)
No. 71, Accounting for the Effects of Certain Types of Regulation, and its
financial statements reflect the effects of the different ratemaking
principles followed by the various jurisdictions regulating the Company. If
rate recovery of generation-related costs become unlikely or uncertain, due
to competition or regulatory action, these accounting standards may no
longer apply to the Company's generation operations. In the event the
Company determines that it no longer meets the criteria for following SFAS
71, the accounting impact to the Company would be an extraordinary non-cash
charge to operations of an amount that could be material. Criteria that
give rise to the discontinuance of SFAS 71 include increasing competition
that could restrict the Company's ability to establish prices to recover
specific costs and a significant change in the manner in which rates are set
by regulators from cost-based regulation to another form of regulation. The
Company periodically reviews these criteria to ensure the continuing
application of SFAS 71 is appropriate.
Accounting for Certain Investments in Debt and Equity Securities
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 115, Accounting for Certain Investments in Debt and
Equity Securities, which requires a change in accounting from cost to fair
value. Under the fair value method, investments are classified in three
categories: held to maturity securities, which are reported at amortized
cost; trading securities, which are reported at fair value, with unrealized
gains and losses included in earnings; available-for-sale securities, which
are reported at fair value, with unrealized gains and losses reported as a
separate component of shareholder's investment, net of income taxes.
At December 31, 1994, the Company's short-term and other investments
were classified as held-to-maturity securities and were reported at
amortized cost.
Employers' Accounting for Postretirement Benefits Other than Pensions
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions. This new standard requires that the expected
cost of these benefits must be accrued for during the years employees render
service. The Company prospectively adopted the new standard effective
January 1, 1993, and is amortizing the discounted present value of the
accumulated postretirement benefit obligation of $2,996,000 to expense over
a 20 year period. The net periodic postretirement cost charged to expense
in 1994 and 1993 was $669,000 and $527,000 (pre-tax), respectively. For
measurement purposes, an 11 percent annual rate of increase in healthcare
benefits was assumed for 1995; the rate was assumed to decrease gradually to
6 percent in 2005 and remain at that level thereafter. The healthcare cost
trend rate assumption has a significant effect on the amount reported. A 1
percent increase in the health care cost trend assumption would increase the
net periodic postretirement benefit cost by approximately $192,000 annually
or 22.5 percent.
The South Dakota Public Utilities Commission has continued to treat
postretirement benefits on a "pay as you go" basis for rate making purposes.
Accounting for Income Taxes
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes, which requires
the use of the liability method in accounting for income taxes. Under the
liability method, deferred income taxes are recognized, at currently enacted
income tax rates, to reflect the tax effect of temporary differences between
the financial reporting 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 new standard required adjustments to existing balances of
accumulated deferred income taxes to reflect changes in income tax rates.
To the extent such income taxes are recoverable or payable through future
rates, a $6,925,000 net regulatory liability has been recorded in the
accompanying consolidated balance sheets. Initial application of the
statement had no material impact on the Company's results of operations.
Inflation
Inflation may have a significant impact on replacement of property and
capital improvements in the future due to the capital intensive nature of
the utility business. The rate making process gives no recognition to the
fair value of existing plant; however, in the past, the Company has been
allowed to recover and earn on the increased cost of its net investment when
the addition to or replacement of facilities occurred. The majority of the
mining operations' coal contracts provide for the adjustment over time of
components of the sales price through indexes, formulas, or direct
pass-through of costs.
REPORT OF MANAGEMENT
Management of Black Hills Corporation is responsible for the
preparation, integrity, and objectivity of the consolidated financial
statements of the Company and its subsidiaries. The consolidated financial
statements are prepared in conformity with generally accepted accounting
principles and reflect management's informed judgments and best estimates
incorporating accounting policies that are reasonable and prudent for the
Company's business environment. Information contained elsewhere in the
Annual Report is consistent with the consolidated financial statements.
The Company's system of internal controls is designed to provide
reasonable assurance, on a cost-effective basis, that assets are
safeguarded, transactions are executed in accordance with management's
authorization, and the consolidated financial statements are prepared in
accordance with generally accepted accounting principles. The internal
controls are continually reviewed and evaluated for effectiveness. No
internal control system can prevent the occurrence of errors and
irregularities with absolute assurance due to the inherent limitations of
any system.
The Audit Committee, composed exclusively of outside directors, is
responsible for overseeing the Company's financial reporting process and
reporting the results of its activities to the Board of Directors. This
committee, management, and the internal auditor periodically review matters
associated with financial reporting, audit activities, and internal
controls. As part of their audit of the Company's 1994 consolidated
financial statements, the Company's independent auditors, Arthur Andersen
LLP, considered the Company's system of internal controls to the extent they
deemed necessary to determine the nature, timing, and extent of their audit
tests. The independent and internal auditors have free access to the Audit
Committee to discuss the results of their audits without the presence of
management.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Black Hills Corporation:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of BLACK HILLS CORPORATION AND SUBSIDIARIES as
of December 31, 1994 and 1993, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years in the
period ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Black Hills
Corporation and Subsidiaries as of December 31, 1994 and 1993, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1994, in conformity with generally accepted
accounting principles.
As discussed in Notes 8 and 9 to the consolidated financial statements,
effective January 1, 1993, the Company changed its method of accounting for
postretirement benefits other than pensions and its method of accounting for
income taxes.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota,
January 27, 1995
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31 1994 1993 1992
(in thousands)
Operating revenues:
Electric . . . . . . . . . . . . . $104,756 $ 98,155 $ 97,448
Coal mining . . . . . . . . . . . 28,594 29,822 28,296
Oil and gas . . . . . . . . . . . 12,052 11,396 9,599
------- ------- -------
145,402 139,373 135,343
------- ------- -------
Operating expenses:
Fuel and purchased power . . . . . 41,970 36,946 38,209
Operations and maintenance . . . . 28,713 30,237 29,850
Administrative and general . . . . 7,921 8,144 7,811
Depreciation, depletion, and
amortization . . . . . . . . . . 17,676 16,051 13,860
Taxes, other than income
taxes (Note 12) . . . . . . . . . 10,368 10,209 9,264
------- ------- -------
106,648 101,587 98,994
------- ------- -------
Operating income:
Electric . . . . . . . . . . . . . 25,076 23,982 23,392
Coal mining . . . . . . . . . . . 11,822 12,360 11,572
Oil and gas . . . . . . . . . . . 1,856 1,444 1,385
------- ------- -------
38,754 37,786 36,349
------- ------- -------
Other income (expense):
Interest expense . . . . . . . . . (10,339) (8,817) (8,965)
Investment income . . . . . . . . 1,631 1,739 3,149
Allowance for funds used during
construction . . . . . . . . . 3,983 729 378
Other, net . . . . . . . . . . . . 171 474 1,233
------- ------- -------
(4,554) (5,875) (4,205)
------- ------- -------
Income before income taxes . . . . . 34,200 31,911 32,144
Income taxes (Note 9) . . . . . . . . (10,395) (8,965) (8,506)
------- ------- -------
Net income . . . . . . . . . . . $ 23,805 $ 22,946 $ 23,638
======= ======= =======
Weighted average common shares
outstanding . . . . . . . . . . . . 14,339 13,811 13,689
Earnings per share of common
stock . . . . . . . . . . . . . . . $ 1.66 $ 1.66 $ 1.73
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years ended December 31 1994 1993 1992
(in thousands)
Balance, beginning of year . . . . . . . . . . $110,399 $105,173 $ 98,512
Net income . . . . . . . . . . . . . . . . . . 23,805 22,946 23,638
Cash dividends on common stock ($1.32,
$1.28, and $1.24 per share, respectively) . . (18,920) (17,720) (16,977)
-------- -------- --------
Balance, end of year . . . . . . . . . . . . . $115,284 $110,399 $105,173
======== ======== ========
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31 1994 1993 1992
(in thousands)
Operating activities:
Net income . . . . . . . . . . . . . . . . . $ 23,805 $22,946 $23,638
Principal non-cash items-
Depreciation, depletion, and
amortization . . . . . . . . . . . . . . 17,676 16,051 13,860
Deferred income taxes and
investment tax credits. . . . . . . . . . 2,470 1,042 761
Gain on coal settlement . . . . . . . . . . - - (940)
Allowance for other funds used during
construction . . . . . . . . . . . . . . (2,371) (333) (94)
(Increase) decrease in receivables,
inventories, and other current assets . . . (3,438) (1,556) 1,378
Increase (decrease) in current liabilities . 5,054 (2,562) 4,814
Other, net . . . . . . . . . . . . . . . . . 5,740 4,259 1,091
------- ------- -------
48,936 39,847 44,508
------- ------- -------
Investing activities:
Neil Simpson Unit #2 construction costs,
excluding allowance for other funds
used during construction (Note 7) . . . . . (71,956) (12,675) (2,227)
Other property additions, excluding
allowance for other funds used
during construction . . . . . . . . . . . . (28,732) (27,282) (25,594)
Short-term investments purchased . . . . . . (41,923) (33,622) (33,938)
Short-term investments sold . . . . . . . . . 42,006 25,504 32,610
Proceeds from sale of long-term investments . 4,958 14,724 -
------- ------- -------
(95,647) (33,351) (29,149)
------- ------- -------
Financing activities:
Dividends paid . . . . . . . . . . . . . . . (18,920) (17,720) (16,977)
Common stock issued . . . . . . . . . . . . . 2,436 13,705 534
Net short-term borrowings . . . . . . . . . . 25,250 3,784 900
Long-term debt issued . . . . . . . . . . . . 45,795 - -
Long-term debt retired . . . . . . . . . . . (3,542) (4,166) (3,725)
------- ------- -------
51,019 (4,397) (19,268)
------- ------- -------
Increase (decrease) in cash and
cash equivalents. . . . . . . . . . . . . 4,308 2,099 (3,909)
Cash and cash equivalents:
Beginning of year . . . . . . . . . . . . . . 7,866 5,767 9,676
------- ------ ------
End of year . . . . . . . . . . . . . . . . . $ 12,174 $ 7,866 $ 5,767
======= ====== ======
Supplemental disclosure of cash flow
information:
Cash paid during the period for -
Interest . . . . . . . . . . . . . . . . . $ 9,244 $ 9,283 $ 9,296
Income taxes. . . . . . . . . . . . . . . . $ 7,290 $ 8,000 $ 7,440
Non-cash activities (Note 3)
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
December 31 1994 1993
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents . . . . . . . . $ 12,174 $ 7,866
Short-term investments . . . . . . . . . . 24,134 24,217
Receivables, net
Customers . . . . . . . . . . . . . . . 12,409 12,415
Other . . . . . . . . . . . . . . . . . 4,045 901
Materials, supplies, and fuel . . . . . . 7,139 6,765
Prepaid expenses . . . . . . . . . . . . . 1,564 1,638
------- -------
Total current assets . . . . . . . . 61,465 53,802
------- -------
Property and investments:
Electric . . . . . . . . . . . . . . . . . 425,690 341,852
Coal mining. . . . . . . . . . . . . . . . 52,267 51,670
Oil and gas . . . . . . . . . . . . . . . 38,842 32,371
Investments . . . . . . . . . . . . . . . 2,785 7,250
------- -------
519,584 433,143
Less accumulated depreciation
and depletion. . . . . . . . . . . . . . (156,046) (144,492)
------- -------
Net property and investments. . . . . 363,538 288,651
------- -------
Deferred charges:
Federal income taxes . . . . . . . . . . . 7,505 7,271
Other . . . . . . . . . . . . . . . . . . 4,369 3,129
------- -------
11,874 10,400
------- -------
$436,877 $352,853
======= =======
LIABILITIES AND CAPITALIZATION
Current liabilities:
Current maturities of long-term debt. . . . $ 2,144 $ 3,542
Notes payable (Note 4). . . . . . . . . . . 37,018 11,768
Accounts payable . . . . . . . . . . . . . 12,018 9,535
Accrued liabilities-
Taxes . . . . . . . . . . . . . . . . . . 6,331 5,583
Fuel and purchased power refunds . . . . 1,025 1,375
Interest . . . . . . . . . . . . . . . . 2,795 1,700
Other . . . . . . . . . . . . . . . . . . 7,101 6,023
------- -------
Total current liabilities . . . . . . 68,432 39,526
------- -------
Deferred credits:
Federal income taxes . . . . . . . . . . . 39,953 36,705
Investment tax credits . . . . . . . . . . 5,521 6,027
Reclamation costs . . . . . . . . . . . . . 7,618 7,290
Regulatory liability . . . . . . . . . . . 6,925 6,912
Other . . . . . . . . . . . . . . . . . . . 4,093 3,030
------- -------
Total deferred credits . . . . . . . . 64,110 59,964
------- -------
Commitments and contingent liabilities
(Notes 7 and 8) . . . . . . . . . . . . . .
Capitalization, per accompanying statements:
Common stock equity . . . . . . . . . . . . 175,410 168,089
Long-term debt. . . . . . . . . . . . . . . 128,925 85,274
------- -------
Total capitalization . . . . . . . . . 304,335 253,363
------- -------
$436,877 $352,853
======= =======
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these consolidated balance sheets.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31 1994 1993
(in thousands)
Common stock equity (Note 2):
Common stock, $1 par value; 50,000,000
shares authorized; 14,386,353 and
14,269,580 shares outstanding,
respectively . . . . . . . . . . . . . . . . . $ 14,386 $ 14,270
Additional paid-in capital . . . . . . . . . . . 45,740 43,420
Retained earnings . . . . . . . . . . . . . . . . 115,284 110,399
------- -------
Total common stock equity . . . . . . . . . 175,410 168,089
------- -------
Cumulative preferred stock:
No par value; 400,000 shares authorized;
no shares outstanding . . . . . . . . . . . . . - -
$100 par value; 270,000 shares
authorized; no shares outstanding . . . . . . . - -
Long-term debt (Note 3):
First mortgage bonds-
8.375% due 1998 . . . . . . . . . . . . . . . . 2,675 3,340
8.05% due 1999. . . . . . . . . . . . . . . . . 4,850 4,875
6.625% pollution control and
industrial development revenue
bonds, collateralized with first
mortgage bonds, due 2007 . . . . . . . . . . 1,680 1,840
9.00% due 2003. . . . . . . . . . . . . . . . . 10,561 11,739
9.49% due 2018. . . . . . . . . . . . . . . . . 6,000 6,000
9.35% due 2021. . . . . . . . . . . . . . . . . 35,000 35,000
8.30% due 2024. . . . . . . . . . . . . . . . . 45,000 -
------- -------
105,766 62,794
------- -------
Other-
6.7% pollution control revenue bonds, due 2010 . 12,300 12,300
10.50% pollution control revenue
bonds, due 2014. . . . . . . . . . . . . . . . - 12,200
7.50% pollution control revenue bonds, due 2024. 12,200 -
$3,000,000, variable rate, environmental
improvement bonds, due 2024, less $2,204,832
in construction fund . . . . . . . . . . . . . 795 -
Other long-term obligations . . . . . . . . . . 8 1,522
------- -------
25,303 26,022
------- -------
Total long-term debt 131,069 88,816
Current maturities . . . . . . . . . . . . . . . (2,144) (3,542)
------- -------
Net long-term debt . . . . . . . . . . . . . 128,925 85,274
------- -------
Total capitalization . . . . . . . . . . . . $304,335 $253,363
======= =======
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1994, 1993, and 1992
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation and its Subsidiaries (the Company) operate in three
primary business segments: electric, coal mining, and oil and gas
production. The Company's electric utility operation is engaged in the
generation, purchase, transmission, distribution, and sale of electric power
and energy in western South Dakota, northeastern Wyoming, and southeastern
Montana. Sales of electric power to the three largest electric customers
represented 20 percent of the Company's electric revenue in 1994 and 1993,
and 22 percent in 1992.
The coal mining operation of the Company, located in northeastern Wyoming,
mines and sells sub-bituminous coal primarily under long-term coal supply
agreements. As discussed in Note 6, 70 percent of the coal mining
operation's sales are to the Wyodak Plant. Sales of coal to the Company and
to PacifiCorp represent 89 percent of total coal sales.
The Company's oil and gas exploration and production business operates and
has working interests in oil wells principally located in the Rocky Mountain
region and Texas.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills
Corporation and its wholly owned subsidiaries. All significant inter-
company balances and transactions have been eliminated in consolidation
except for revenues and expenses associated with intercompany coal sales
in accordance with the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation." Total intercompany coal sales not eliminated were $9,445,000,
$10,047,000, and $9,811,000 in 1994, 1993, and 1992, respectively.
Property
Property is recorded at cost which includes an allowance for funds used
during construction where applicable. The cost of electric property
retired, together with removal cost less salvage, is charged to accumulated
depreciation. Repairs and maintenance of property are charged to operations
as incurred.
Depreciation and Depletion
Depreciation is computed using the straight-line method over the estimated
useful lives of the related assets. Depreciation provisions for the
electric property were equivalent to annual composite rates of 3.1 percent
in 1994 and 3.2 percent in 1993 and 1992. Composite depreciation rates for
other property were 10.3 percent, 9.6 percent, and 7.5 percent in 1994,
1993, and 1992, respectively.
Depletion of coal and oil and gas properties is computed using the cost
method for financial reporting and the gross income method or cost method,
whichever is applicable, for federal income tax reporting.
Cash Equivalents and Short-term Investments
Cash of the Company is invested in money market investments such as
municipal put bonds, money market preferreds, commercial paper,
Euro-dollars, and certificates of deposit. The Company considers all highly
liquid investments with an original maturity of three months or less to be
cash equivalents. Cash equivalents and short-term investments are stated at
cost which approximates market.
Revenue Recognition
Revenue from sales of electric energy is based on rates filed with
applicable regulatory authorities. Electric revenue includes an accrual for
estimated unbilled revenue for services provided through year-end.
Revenue from other business segments is recognized at the time the products
are delivered or the services are rendered.
Oil and Gas Exploration
The Company accounts for its oil and gas exploration activities under the
full cost method. Capitalized costs associated with unsuccessful wells are
amortized over future periods as the reserves from successful wells are
produced.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFDC) represents the
approximate composite cost of borrowed funds and a return on capital used to
finance construction expenditures and is capitalized as a component of the
electric property. The AFDC was computed at an annual composite rate of 8.7
percent in 1994, 7.7 percent in 1993, and 10.5 percent in 1992.
Income Taxes
Deferred taxes are provided on all significant temporary differences,
principally depreciation. Investment tax credits have been deferred in the
electric operation and the accumulated balance is amortized as a reduction
of income tax expense over the useful lives of the related electric property
which gave rise to the credits.
(2) CAPITAL STOCK
Common Stock
Common shares issued at $1.00 par value during the years indicated were:
1994 1993 1992
Public offering - 525,000 -
Employee Stock
Purchase Plan 4,195 16,402 24,332
Dividend Reinvestment
and Stock Purchase Plan 112,578 26,891 -
------- ------- ------
116,773 568,293 24,332
At December 31, 1994, 70,014 shares of unissued common stock were available
for future offerings under the Employee Stock Purchase Plan.
The Board of Directors adopted a new Dividend Reinvestment and Stock
Purchase Plan in 1993, 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. At December 31, 1994, 860,531 shares of unissued common stock were
available for future offerings under the Plan.
Additional Paid-in Capital
Changes in additional paid-in capital for the years indicated were:
1994 1993 1992
(in thousands)
Balance, beginning of year $43,420 $30,284 $29,776
Premium, net of expenses,
received from sales of
common stock 2,320 13,136 508
------ ------ ------
Balance, end of year $45,740 $43,420 $30,284
(3) LONG-TERM DEBT
Substantially all of the Company's utility property is subject to the lien
of the Indenture securing its first mortgage bonds. First mortgage bonds of
the Company may be issued in amounts limited by property, earnings, and
other provisions of the mortgage indentures.
In 1994 the Company filed a Form S-3, shelf registration for $100,000,000
first mortgage bonds. The Company issued $45,000,000 first mortgage bonds
under this filing on September 1, 1994. The bonds have a 30 year life and
carry an 8.3 percent rate of interest. Subsequent to year-end, the Company
sold an additional $30,000,000 first mortgage bonds under the shelf
registration. The bonds have a 15 year life and carry an 8.06 percent rate
of interest. The Company also issued $3,000,000 Environmental Improvement
Revenue Bonds in 1994. The bonds carry a variable rate of interest which is
currently reset weekly. The average interest rate applied to the bonds in
1994 was 3.5 percent. These bond issues were used to finance Neil Simpson
Unit #2 (NSS #2).
The Company also completed the refinancing of the $12,200,000, City of
Gillette Pollution Control Revenue Bonds during 1994. In 1992 the Company
entered into a forward refunding on the $12,200,000, 10.5 percent, City of
Gillette Pollution Control Revenue Bonds. The new bonds were issued in July
1994 at 7.5 percent, due 2024.
In 1992 the Company issued $12,300,000, 6.7 percent Unsecured Pollution
Control Refunding Revenue Bonds, due 2010. The proceeds were used to redeem
$12,300,000 of 6.625 percent and 6.85 percent, Pollution Control Revenue
Bonds, due 2007.
Scheduled maturities of long-term debt for the next five years are:
$2,144,000 in 1995, $2,255,000 in 1996, $2,384,000 in 1997, $2,196,000 in
1998, and $6,240,000 in 1999.
(4) NOTES PAYABLE TO BANKS
At December 31, 1994, the Company had $70,000,000 of unsecured short-term
lines of credit. Borrowings outstanding under these lines of credit were
$36,975,000 and $11,700,000 as of December 31, 1994 and 1993, respectively.
The weighted average interest rate on these borrowings at December 31, 1994
and 1993 was 6.9 percent and 4.5 percent, respectively. Average borrowings
during 1994, 1993, and 1992 were $21,070,000, $11,059,000, and $5,616,000,
respectively. The Company has no compensating balance requirements
associated with these lines of credit. The Company pays a 0.125 percent
facility fee on $25,000,000 of the existing short-term lines. The lines of
credit are subject to periodic review and renewal during the year by the
banks.
(5) FAIR VALUE OF FINANCIAL INSTRUMENTS
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.
Short-Term and Other Investments
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 115, Accounting for Certain Investments in
Debt and Equity Securities, which requires a change in accounting for
certain investments from cost to fair value. Under the fair value method,
investments are classified in three categories: held-to-maturity
securities, which are reported at amortized cost; trading securities, which
are reported at fair value, with unrealized gains and losses included in
earnings; available-for-sale securities, which are reported at fair value,
with unrealized gains and losses reported as a separate component of
shareholders' investment, net of income taxes.
At December 31, 1994, all of the Company's short-term and other investments
were classified as held-to-maturity securities under SFAS No. 115, and
reported at amortized cost with $24,134,000 maturing within one year. The
classification of the Company's short-term and other investments by major
security type at December 31, 1994, was as follows:
Net Unrealized
Amortized Cost Fair Value Holding Losses
(in thousands)
Corporate debt securities $12,197 $12,200 $ 3
Debt securities issued by states
of the United States and
municipalities of the states 12,246 12,222 (24)
------ ------ ---
$24,443 $24,422 $(21)
Long-Term Debt
The fair value of the Company's long-term debt is estimated based on quoted
market rates for utility debt instruments having similar maturities and
similar debt ratings, with an exception for debt associated with the federal
coal lease modifications. The fair value of the bonus payments for the
federal coal lease modifications equals the discounted future cash flows
using the prime rate as the discount rate. The final federal bonus payment
was made February 1, 1994.
The estimated fair values of the Company's financial instruments are as
follows:
1994
(in thousands)
Carrying Fair
Amount Value
Cash and cash equivalents $ 12,174 $ 12,174
Short-term investments 24,134 24,114
Other investments 2,785 2,784
Long-term debt 131,069 133,313
1993
(in thousands)
Carrying Fair
Amount Value
Cash and cash equivalents $ 7,866 $ 7,866
Short-term investments 24,217 24,217
Other investments 7,250 7,257
Long-term debt 88,816 105,639
The majority of the Company's outstanding bonds are currently subject to
make-whole provisions which would eliminate any economic benefits for the
Company to call and refinance the bonds.
(6) WYODAK PLANT
The Company owns a 20 percent interest and PacifiCorp an 80 percent interest
in the Wyodak Plant (the Plant), a 330 MW coal-fired electric generating
station located in Campbell County, Wyoming. PacifiCorp 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, 1994, the Company's investment
in the Plant included $71,531,000 in electric plant and $20,956,000 in
accumulated depreciation. The Company's share of direct expenses of the
Plant is included in the corresponding categories of operating expenses in
the accompanying consolidated statements of income.
Wyodak Resources Development Corp. (WRDC) supplies coal to the Plant under
an agreement expiring in 2013 with a PacifiCorp option to renew for 10
years. This coal supply agreement is collateralized by a mortgage on and a
security interest in some of WRDC's coal reserves. At December 31, 1994,
approximately 30,292,000 tons were covered under this agreement. WRDC's
sales to the Plant were $20,671,000, $21,438,000, and $20,317,000 for the
years ended December 31, 1994, 1993, and 1992, respectively.
(7) COMMITMENTS AND CONTINGENT LIABILITIES
New Power Plant
Construction of NSS #2, an 80 MW coal fired generating plant located
adjacent to the Wyodak coal mine, commenced in August 1993 and is proceeding
ahead of schedule and under the $124,889,000 budget. The Company committed
to the South Dakota Public Utilities Commission and the Wyoming Public
Service Commission to construct NSS #2 at a capital cost not to exceed
$124,889,000 including AFDC and to not include in rate base any capital
costs in excess thereof. On February 1, 1995, the Company filed an
application with the South Dakota Public Utilities Commission requesting
authority to increase rates by an average of 9.96 percent. The Company
requested the increase become effective when NSS #2 begins commercial
operation. Commercial operation is currently estimated to begin in
September 1995. The Company has incurred approximately $89,000,000 of costs
related to the plant as of December 31, 1994.
WRDC has committed to supply all of the coal requirements for the life of
NSS #2. The coal pricing methodology is not expected to have a material
effect on WRDC's earnings because earnings from coal sales to the Company
are limited to a return on WRDC's investment base. WRDC has committed to
further reduce the price for coal to be used in any of the Company's power
plants during a period of time that under prudent dispatch that power plant
would not have been operated if it were not for the discounted price of
coal.
MDU Power Sale
During 1994, the Company entered into a Power Integration Agreement with
Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. (MDU).
The agreement provides that for a period of 10 years commencing January 1,
1997, the Company will supply up to 55 MW of electric power and associated
energy required by MDU for its Sheridan, Wyoming, service territory. MDU's
Sheridan service area has experienced a 45 MW peak and a load factor of
approximately 60 percent. The agreement is subject to the approval of the
Federal Energy Regulatory Commission.
Coal Obligations
In addition to the 30,292,000 tons of coal reserved under the agreement to
supply coal to the Wyodak Plant, WRDC has reserved 29,075,000 tons of coal
under existing contracts and 51,000,000 tons of coal under future purchase
options. None of the purchase options are expected to be exercised because
the option price is substantially higher than the market price. An option
for 50,000,000 tons can be exercised only if WRDC has not committed the coal
reserves to other buyers prior to the exercise of the option.
PacifiCorp Purchase Power Agreement
In 1983 the Company entered into a 40 year power agreement with PacifiCorp
providing for the purchase of 75 megawatts of electric capacity and energy.
Although the price paid for the capacity and energy is based on the
operating costs of one of PacifiCorp's coal-fired electric generating
plants, PacifiCorp's obligation is to provide power from its system. Costs
incurred under this agreement were $23,132,000, $21,106,000, and $21,507,000
in 1994, 1993, and 1992, respectively.
Reclamation
Under its mining permit, WRDC 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 $600,000 is charged to operations as reclamation
expense annually. As of December 31, 1994, accrued reclamation costs were
approximately $7,600,000.
Other
The Company is subject to various legal proceedings and claims which arise
in the ordinary course of operations. In the opinion of management, the
amount of liability, if any, with respect to these actions would not
materially affect the consolidated financial position or results of
operations of the Company.
(8) EMPLOYEE BENEFIT PLANS
The Company has a defined benefit pension plan (the Plan) covering
substantially all employees. The benefits are based on years of service and
compensation levels during the highest five consecutive years of the last
ten years of service. The Company's funding policy is in accordance with
the federal government's funding requirements. The Plan's assets consist
primarily of equity securities and cash equivalents.
Net pension expense (income) for the Plan was as follows:
1994 1993 1992
(in thousands)
Service cost $ 865 $ 651 $ 535
Interest cost 2,074 1,899 1,687
Return on assets:
Actual (1,819) (2,852) (2,224)
Deferred (793) 333 (215)
------ ------ ------
Net pension expense (income) $ 327 $ 31 $ (217)
Funding information for the Plan as of October 1 of each year was as
follows:
1994 1993
(in thousands)
Fair value of plan
assets $25,584 $25,186
Projected benefit
obligation 27,931 28,367
------ ------
(2,347) (3,181)
Unrecognized:
Net loss 2,747 3,779
Prior service cost 885 1,105
Transition asset (541) (631)
------ ------
Prepaid pension cost $ 744 $ 1,072
====== ======
Accumulated benefit
obligation $22,649 $22,464
Vested benefit obligation $21,749 $21,507
Actuarial assumptions:
Discount rate 8.0% 7.5%
Expected long-term rate of
return on assets 10.5% 11%
Rate of increase in
compensation levels 5% 5%
The change in the assumed discount rate from 7.5 percent in 1993 to 8.0
percent in 1994 resulted in a decrease in the accumulated benefit obligation
and projected benefit obligation of $1,260,000 and $2,086,000, respectively.
The Company has various supplemental retirement plans for outside directors
and key executives of the Company. The plans are nonqualified defined
benefit plans. Costs incurred under the plans were $401,000, $633,000, and
$735,000 in 1994, 1993, and 1992, respectively.
On January 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions. The new standard requires that the expected cost of these
benefits must be charged to expense during the years that the employees
render service. Prior to adopting the standard the Company expensed these
benefits as they were paid. The Company is amortizing the transition
obligation of $2,996,000 over a 20 year period.
Employees retiring from the Company on or after attaining age 55 who have
rendered at least five years of service to the Company are entitled to
postretirement healthcare benefits coverage. These benefits are subject to
premiums, deductibles, copayment provisions, and other limitations. The
Company may amend or change the plan periodically. The Company is not pre-
funding its retiree medical plan.
The net periodic postretirement cost for the Company was as follows:
1994 1993
(in thousands)
Service cost $188 $127
Interest cost 303 250
Amortization of transition
obligation 150 150
Amortization of loss 28 -
--- ---
Net periodic postretirement
benefit cost $669 $527
Funding information as of October 1 was as follows:
1994 1993
(in thousands)
Accumulated postretirement benefit
obligation:
Retirees $1,805 $1,316
Fully eligible active participants 1,246 865
Other active participants 2,400 1,921
Unfunded accumulated postretirement
benefit obligation 5,451 4,102
Unrecognized net loss (1,838) (892)
Unrecognized transition obligation (2,696) (2,846)
----- -----
Accrued postretirement benefit cost $ 917 $ 364
For measurement purposes, an 11 percent annual rate of increase in
healthcare benefits was assumed for 1995; the rate was assumed to decrease
gradually to 6 percent in 2005 and remain at that level thereafter. The
healthcare cost trend rate assumption has a significant effect on the
amounts reported. A 1 percent increase in the healthcare cost trend
assumption would increase the net periodic postretirement cost by
approximately $192,000 annually or 22.5 percent. The weighted-average
discount rate used in determining the accumulated postretirement benefit
obligation was 8 percent.
(9) INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes, which requires
the use of the liability method in accounting for income taxes. Under the
liability method, deferred income taxes are recognized, at currently enacted
income tax rates, to reflect the tax effect of temporary differences between
the financial reporting 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. To implement the statement, certain adjustments were made to
accumulated deferred income taxes. To the extent such income taxes are
recoverable or payable through future rates, regulatory assets and
liabilities have been recorded in the accompanying consolidated balance
sheets. Initial application of the statement had no material impact on the
Company's results of operations.
Income tax expense for the years indicated was:
1994 1993 1992
(in thousands)
Current $ 7,925 $7,923 $7,745
Deferred 2,975 1,547 1,273
Investment tax credits, net (505) (505) (512)
------ ----- -----
$10,395 $8,965 $8,506
The sources of temporary differences and the tax effect of each are
summarized as follows:
1994 1993 1992
(in thousands)
Tax in excess of book depreciation $1,885 $ 662 $ 566
AFDC-equity 830 - -
Inventory accounting method (82) (184) (179)
Mining development and oil
exploration costs 196 1,315 848
Other 146 (246) 38
----- ----- -----
$2,975 $1,547 $1,273
The temporary differences which gave rise to the net deferred tax liability
at December 31, 1994 and 1993 were as follows:
Net Deferred
Income
Tax Asset
December 31, 1994 Assets Liabilities (Liability)
(in thousands)
Accelerated depreciation and
other plant-related differences $ - $33,649 $(33,649)
AFDC-equity - 1,291 (1,291)
Regulatory asset 2,350 - 2,350
Unamortized investment tax credits 2,109 - 2,109
Mining development and oil
exploration 678 2,896 (2,218)
Employee benefits 1,521 278 1,243
Other 847 1,839 (992)
----- ------ -------
$7,505 $39,953 $(32,448)
Net Deferred
Income
Tax Asset
December 31, 1993 Assets Liabilities (Liability)
(in thousands)
Accelerated depreciation and
other plant-related differences $ - $32,507 $(32,507)
AFDC-equity - 461 (461)
Regulatory asset 2,350 - 2,350
Unamortized investment tax credits 2,109 - 2,109
Mining development and oil
exploration 746 2,383 (1,637)
Employee benefits 1,227 455 772
Other 839 899 (60)
----- ------ -------
$7,271 $36,705 $(29,434)
The effective tax rate differs from the federal statutory rate for the years
ended December 31, as follows:
1994 1993 1992
Federal statutory rate 35.0% 35.0% 34.0%
Percentage depletion in
excess of cost (1.7) (2.8) (2.3)
Amortization of investment
tax credits (1.5) (1.6) (1.5)
Tax exempt interest income (1.1) (1.7) (2.3)
Other (0.3) (0.8) (1.4)
---- ---- ----
30.4% 28.1% 26.5%
(10) OIL AND GAS RESERVES (Unaudited)
The following table summarizes Western Production Company's (WPC) estimated
quantities of proved developed and undeveloped oil and natural gas reserves
at December 31, 1994 and 1993, and a reconciliation of the changes between
these dates using constant product prices for the respective years. These
estimates are based on reserve reports by 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.
1994 1993
Oil Gas Oil Gas
(in thousands of barrels of oil and MCF of gas)
Proved developed and
undeveloped reserves:
Balance at beginning of year 1,116 2,759 2,199 3,243
Production (321) (1,731) (327) (777)
Additions 107 7,582 259 1,847
Revisions to previous
estimates due to changed
economic conditions 536 470 (1,015) (1,554)
----- ----- ----- -----
Balance at end of year 1,438 9,080 1,116 2,759
===== ===== ===== =====
Proved developed reserves at end
of year included above 1,436 6,246 1,116 2,759
===== ===== ===== =====
Year end prices $15.75 $ 1.72 $13.00 $ 2.35
WPC has interests in 410 producing oil and gas properties in seven states.
WPC operates a total of 349 wells in Wyoming and Colorado. WPC's non-
operated properties are located in Texas, Wyoming, Colorado, North Dakota,
Montana, Kansas, and California. WPC also holds leases on approximately
64,000 net undeveloped acres.
(11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS
The three primary segments of the Company's business are its electric, coal
mining, and oil and gas production operations. The following table
summarizes certain information specifically identifiable with each segment
as of or for the years ended December 31.
1994 1993 1992
(in thousands)
Assets at year end:
Electric $340,042 $259,680 $238,378
Coal mining 72,851 72,328 71,194
Oil and gas 23,984 20,845 20,630
------- ------- -------
$436,877 $352,853 $330,202
======= ======= =======
Depreciation, depletion, and
amortization:
Electric $ 10,314 $ 9,952 $ 9,614
Coal mining 2,502 1,953 1,482
Oil and gas 4,860 4,146 2,764
------- ------- -------
$ 17,676 $ 16,051 $ 13,860
======= ======= =======
Capital expenditures:
NSS #2 (includes AFDC) $ 73,984 $ 12,792 $ 2,227
Other electric 14,187 13,140 15,507
Coal mining 5,911 7,425 5,001
Oil and gas 8,977 6,933 5,180
------- ------- -------
$103,059 $ 40,290 $ 27,915
======= ======= =======
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
PacifiCorp Coal Settlement
In 1987 WRDC entered into an agreement with PacifiCorp which (a) settled
PacifiCorp's obligation to purchase coal commencing in 1990 for a second
plant to be located at Wyodak, the construction of which had been canceled,
(b) provided for, among other things, increases in the coal price and
minimum coal purchase obligations by PacifiCorp for the Wyodak Plant, and
(c) provided for payments to WRDC of $2,000,000 each on January 2, 1988
through 1991 for an option to purchase additional coal. These settlements
resulted in an increase in the Company's net income in 1994, 1993, and 1992
of approximately $1,700,000, $1,500,000, and $2,800,000 or $0.12, $0.11, and
$0.20 per share of common stock, respectively.
Taxes Other Than Income Taxes
1994 1993 1992
(in thousands)
Property $ 3,637 $ 3,549 $2,996
Production and severance 2,995 2,982 2,622
Payroll 1,334 1,195 1,225
Black lung 1,205 1,256 1,191
Federal reclamation 979 1,060 1,035
Other 218 167 195
------ ------ ------
$10,368 $10,209 $ 9,264
(13) QUARTERLY FINANCIAL DATA (Unaudited)
Quarterly financial data for the years indicated are summarized as follows:
First Second Third Fourth
(in thousands, except per share amounts)
Year ended December 31, 1994
Operating revenues $35,660 $34,491 $38,589 $36,662
Operating income 9,679 7,511 11,347 10,217
Net income 5,800 4,383 6,979 6,643
Earnings per share of common
stock 0.41 0.31 0.49 0.45
Common stock prices
High $22-3/4 $22-1/8 $20-3/4 $22-1/4
Low $20-3/4 $18-1/4 $17-7/8 $17-3/4
Dividends paid per share
of common stock $ 0.33 $ 0.33 $ 0.33 $ 0.33
Year ended December 31, 1993
Operating revenues $34,375 $32,924 $36,304 $35,770
Operating income 9,980 7,793 10,087 9,926
Net income 6,103 4,575 6,011 6,257
Earnings per share of common
stock 0.45 0.33 0.44 0.44
Common stock prices
High $28-1/4 $27-1/4 $27-1/8 $26-1/8
Low $24-7/8 $24-5/8 $25-1/8 $21-7/8
Dividends paid per share
of common stock $ 0.32 $ 0.32 $ 0.32 $ 0.32
SELECTED FINANCIAL DATA
(unaudited)
Years ended December 31 1994 1993 1992 1991 1990
(in thousands, except per share amounts)
Operating revenues $145,402 $139,373 $135,343 $133,373 $127,498
Net income 23,805 22,946 23,638 22,681 22,938
Per share of common stock:
Earnings 1.66 1.66 1.73 1.66 1.68
Dividends paid 1.32 1.28 1.24 1.17 1.09
Total assets 436,877 352,853 330,202 319,895 294,929
Total long-term
debt 128,925 85,274 88,816 92,982 78,978
FINANCIAL STATISTICS
Years ended December 31 1994 1993 1992
TOTAL ASSETS (in thousands) $436,877 $352,853 $330,202
PROPERTY AND INVESTMENTS (in thousands)
Total property and investments . . . $519,584 $433,143 $413,192
Accumulated depreciation
and depletion. . . . . . . . . . . 156,046 144,492 132,890
Capital expenditures
(includes AFDC) . . . . . . . . . . 103,059 40,290 27,915
CAPITALIZATION (in thousands)
Long-term debt . . . . . . . . . . . $128,925 $ 85,274 $ 88,816
Common stock equity . . . . . . . . . 175,410 168,089 149,158
------- ------- -------
Total . . . . . . . . . . . . . $304,335 $253,363 $237,974
======= ======= =======
CAPITALIZATION RATIOS
Long-term debt . . . . . . . . . . . 42.4% 33.7% 37.3%
Common stock equity . . . . . . . . . 57.6 66.3 62.7
----- ----- -----
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0%
===== ===== =====
AVERAGE INTEREST RATE ON LONG-TERM DEBT 8.5% 9.0% 8.9%
NET INCOME AVAILABLE FOR
COMMON STOCK (in thousands) . . . . . $23,805 $22,946 $23,638
DIVIDENDS PAID ON COMMON STOCK
(in thousands) . . . . . . . . . . . . $18,920 $17,720 $16,977
COMMON STOCK DATA (in thousands)*
Shares outstanding, average . . . . . 14,339 13,811 13,689
Shares outstanding, end of year . . . 14,386 14,270 13,701
Earnings per average share,
in dollars . . . . . . . . . . . . $1.66 $1.66 $1.73
Dividends paid per share, in dollars. $1.32 $1.28 $1.24
Book value per share, end of
year, in dollars . . . . . . . . . $12.19 $11.78 $10.89
RETURN ON COMMON STOCK EQUITY . . . . 13.6% 13.7% 15.8%
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
AS PERCENT OF NET INCOME . . . . . . 16.7% 3.2% 1.6%
(continued)
Years ended December 31 1991 1990 1989
TOTAL ASSETS (in thousands) $319,895 $294,929 $272,523
PROPERTY AND INVESTMENTS (in thousands)
Total property and investments . . . $390,766 $355,276 $331,310
Accumulated depreciation
and depletion. . . . . . . . . . . 122,574 111,111 101,591
Capital expenditures
(includes AFDC) . . . . . . . . . . 36,981 22,336 10,176
CAPITALIZATION (in thousands)
Long-term debt . . . . . . . . . . . $ 92,982 $ 78,978 $ 78,939
Common stock equity . . . . . . . . . 141,963 135,329 127,338
------- ------- -------
Total . . . . . . . . . . . . . $234,945 $214,307 $206,277
======= ======= =======
CAPITALIZATION RATIOS
Long-term debt . . . . . . . . . . . 39.6% 36.9% 38.3%
Common stock equity . . . . . . . . . 60.4 63.1 61.7
----- ----- -----
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0%
===== ===== =====
AVERAGE INTEREST RATE ON LONG-TERM DEBT 8.9% 8.6% 8.5%
NET INCOME AVAILABLE FOR
COMMON STOCK (in thousands) . . . . . $22,681 $22,938 $21,096
DIVIDENDS PAID ON COMMON STOCK
(in thousands) . . . . . . . . . . . . $16,045 $14,947 $13,858
COMMON STOCK DATA (in thousands)*
Shares outstanding, average . . . . . 13,675 13,675 13,675
Shares outstanding, end of year . . . 13,675 13,675 13,675
Earnings per average share,
in dollars . . . . . . . . . . . . $1.66 $1.68 $1.54
Dividends paid per share, in dollars. $1.17 $1.09 $1.01
Book value per share, end of
year, in dollars . . . . . . . . . $10.38 $9.90 $ 9.31
RETURN ON COMMON STOCK EQUITY . . . . 16.0% 16.9% 16.6%
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
AS PERCENT OF NET INCOME . . . . . . 0.8% 1.2% 0.5%
<FN>
* Common stock data have been adjusted retroactively to reflect the
three-for-two stock split in March 1992.
ELECTRIC OPERATION STATISTICS
Years ended December 31 1994 1993 1992
ELECTRIC ENERGY GENERATED
AND PURCHASED (megawatt hours)
Generated, net station output . . . . 1,108,530 1,227,084 1,226,153
Purchased and net interchange . . . . 595,872 435,990 397,478
--------- --------- ---------
Total generated and purchased . . 1,704,402 1,663,074 1,623,631
Non-firm sales . . . . . . . . . . . . (1,000) (7,780) (10,405)
Company use and losses . . . . . . . . (65,651) (61,336) (73,627)
--------- --------- ---------
Total electric energy sales . . . 1,637,751 1,593,958 1,539,599
========= ========= =========
ELECTRIC ENERGY SALES (megawatt hours)
Residential . . . . . . . . . . . . . 368,953 370,736 339,341
General and commercial . . . . . . . . 495,909 469,496 446,036
Industrial . . . . . . . . . . . . . . 583,258 568,316 572,244
Public authorities . . . . . . . . . . 23,051 22,621 21,798
Sales for resale . . . . . . . . . . . 166,580 162,789 160,180
--------- --------- ---------
Total electric energy sales . . . 1,637,751 1,593,958 1,539,599
========= ========= =========
ELECTRIC REVENUE (in thousands)
Residential . . . . . . . . . . . . . $ 28,574 $ 27,064 $ 25,366
General and commercial . . . . . . . . 35,390 32,295 30,742
Industrial . . . . . . . . . . . . . . 27,318 25,901 27,106
Public authorities . . . . . . . . . . 1,718 1,537 1,586
Sales for resale . . . . . . . . . . . 7,460 7,122 7,002
-------- --------- --------
Total electric revenue . . . . . 100,460 93,919 91,802
Other revenue . . . . . . . . . . . . 4,296 4,236 5,646
--------- --------- ---------
Total revenue $ 104,756 $ 98,155 $ 97,448
========= ========= =========
ELECTRIC CUSTOMERS (end of year)
Residential . . . . . . . . . . . . . 45,060 44,657 44,100
General and commercial . . . . . . . . 8,732 8,507 8,279
Industrial . . . . . . . . . . . . . . 36 41 38
Public authorities . . . . . . . . . . 130 124 117
Other electric utilities . . . . . . . 1 1 1
------ ------ ------
Total . . . . . . . . . . . . . . 53,959 53,330 52,535
====== ====== ======
RESIDENTIAL STATISTICS
Average annual KWH usage:
With electric heating. . . . . . . . 16,369 17,601 15,380
Without electric heating . . . . . . 6,488 6,428 6,172
All residential. . . . . . . . . . . 8,198 8,351 7,743
Average price per KWH, in cents . . . 7.7 7.3 7.5
AVERAGE PRICE PER KWH, ALL CUSTOMERS
(in cents). . . . . . . . . . . . . . 6.1 5.9 6.0
(continued)
Years ended December 31 1991 1990 1989
ELECTRIC ENERGY GENERATED
AND PURCHASED (megawatt hours)
Generated, net station output . . . . 1,148,259 1,169,054 1,046,971
Purchased and net interchange . . . . 444,848 379,268 468,768
--------- --------- ---------
Total generated and purchased . . 1,593,107 1,548,322 1,515,739
Non-firm sales . . . . . . . . . . . . (1,040) (5,576) (29,087)
Company use and losses . . . . . . . . (59,896) (64,031) (53,282)
--------- --------- ---------
Total electric energy sales . . . 1,532,171 1,478,715 1,433,370
========= ========= =========
ELECTRIC ENERGY SALES (megawatt hours)
Residential . . . . . . . . . . . . . 355,691 338,391 343,645
General and commercial . . . . . . . . 440,043 415,635 395,712
Industrial . . . . . . . . . . . . . . 550,999 542,312 529,703
Public authorities . . . . . . . . . . 21,347 20,819 20,980
Sales for resale . . . . . . . . . . . 164,091 161,558 143,330
--------- --------- ---------
Total electric energy sales . . . 1,532,171 1,478,715 1,433,370
========= ========= =========
ELECTRIC REVENUE (in thousands)
Residential . . . . . . . . . . . . . $ 27,053 $ 25,498 $ 25,456
General and commercial . . . . . . . . 31,227 29,027 27,815
Industrial . . . . . . . . . . . . . . 26,812 25,917 25,153
Public authorities . . . . . . . . . . 1,593 1,540 1,563
Sales for resale . . . . . . . . . . . 7,223 6,532 5,745
--------- --------- ---------
Total electric revenue . . . . . 93,908 88,514 85,732
Other revenue . . . . . . . 4,250 3,762 4,650
--------- --------- ---------
Total revenue $ 98,158 $ 92,276 $ 90,382
========= ========= =========
ELECTRIC CUSTOMERS (end of year)
Residential . . . . . . . . . . . . . 43,539 43,020 42,505
General and commercial . . . . . . . . 8,083 7,866 7,703
Industrial . . . . . . . . . . . . . . 40 44 40
Public authorities . . . . . . . . . . 112 114 111
Other electric utilities . . . . . . . 1 1 1
------ ------ ------
Total . . . . . . . . . . . . . . 51,775 51,045 50,360
====== ====== ======
RESIDENTIAL STATISTICS
Average annual KWH usage:
With electric heating. . . . . . . . 16,773 15,978 16,881
Without electric heating . . . . . . 6,502 6,288 6,421
All residential. . . . . . . . . . . 8,218 7,897 8,171
Average price per KWH, in cents . . . 7.6 7.5 7.4
AVERAGE PRICE PER KWH, ALL CUSTOMERS
(in cents). . . . . . . . . . . . . . 6.1 6.0 6.0
DIRECTORY
Common Stock
Transfer Agent, Registrar, and Dividend Disbursing Agent
Chemical Bank
450 West 33rd Street
New York, New York 10001
First Mortgage Bonds
Trustee and Paying Agent
Chemical Bank
450 West 33rd Street
New York, New York 10001
Pollution Control and Industrial Development Revenue Bonds
Trustee and Paying Agent
Norwest Bank Minnesota, N.A.
Eighth Street and Marquette Avenue
Minneapolis, Minnesota 55479
Environmental Improvement Revenue Bonds
Trustee and Paying Agent
First National Bank of Chicago
One First National Plaza
Chicago, Illinois 60670
General Counsel
Morrill Brown & Thomas
P.O. Box 8108
Rapid City, South Dakota 57709
Corporate Offices
Black Hills Corporation
P.O. Box 1400
Rapid City, South Dakota 57709
(605) 348-1700
The Company's common stock ($1 par value) is traded on The New York Stock
Exchange. Quotations for the common stock are reported under the symbol BKH.
At year-end the Company had 7,141 common shareholders of record. All fifty
states and the District of Columbia plus twelve foreign countries are
represented.
The continued interest and support of equity owners is appreciated. The Company
has declared common stock dividends payable in cash in each year since its
incorporation in 1941. At its January 1995 meeting the Board of Directors
raised the quarterly dividend to 33.5 cents per share, equivalent to an annual
increase of 2 cents per share. This regular quarterly dividend is payable
March 1, 1995. All dividends are reportable for federal income tax purposes as
ordinary dividend income.
The Annual Report is mailed to each shareholder in accordance with government
rules. Dividend payment dates are normally March 1, June 1, September 1, and
December 1. You may receive more than one copy of the Annual Report if there
are variations in your name or address in which your stock is registered.
Duplicate mailings of annual and interim reports can be eliminated upon written
request of the shareholder.
A copy of the Company's Annual Report on Form 10-K, filed with the Securities
and Exchange Commission, is available to shareholders without charge upon writ-
ten request to Roxann R. Basham, Secretary, P.O. Box 1400, Rapid City, South
Dakota 57709.
1995 ANNUAL MEETING
The Annual Meeting of Shareholders will be held at the Holiday Inn - Rushmore
Plaza Hotel, 505 North Fifth Street, Rapid City, South Dakota, at 9:30 A.M.,
on May 23, 1995. Prior to the meeting, formal notice, proxy statement, and
proxy will be mailed to shareholders.
DIRECT DEPOSIT OF DIVIDENDS
The Company encourages you to consider the direct deposit of your dividends.
With direct deposit, your quarterly dividend payment can be automatically
transferred on the dividend payment date to the bank, savings and loan, or
credit union of your choice. Direct deposit assures payments are credited to
shareholders' accounts without delay. A form is attached to your dividend check
where you can request information about this method of payment. Questions
regarding direct deposit should be directed to Chemical Bank, Security Holder
Relations, P. O. Box 24935, Church Street Station, New York, New York 10249.
DIVIDEND REINVESTMENT PLAN
A Dividend Reinvestment and Stock Purchase Plan (the Plan) is available to
common shareholders. The Plan provides a method of investing common stock
dividends and optional cash payments in additional shares of common stock of the
Company at 100 percent of the recent average market price. The participant may
elect to continue to receive cash dividends on shares registered in their names
and invest by making optional cash payments only. Questions regarding the Plan
should be directed to the Secretary of the Company or Chemical Bank, Dividend
Reinvestment Department, J.A.F. Building, P.O. Box 3069, New York, New York
10116-3069 or by calling the Bank toll free at 1-800-279-1246.