EXHIBIT 13-A
SELECTED CONSOLIDATED FINANCIAL DATA
- ----------------------------------------------------------------------------------------------------------------------------
2001 2000 (1) 1999 (1)(2) 1998 (3) 1997 1996 1991
-------- -------- -------- -------- -------- -------- --------
(thousands, except number of shareholders and per-share data)
REVENUES
Electric $307,684 $262,280 $233,527 $227,477 $205,121 $199,345 $179,456
Plastics 63,216 82,667 31,504 24,946 24,953 22,049 --
Manufacturing 123,436 97,506 87,086 62,488 58,221 42,519 --
Health services 79,129 66,319 68,805 69,412 66,859 61,697 --
Other business operations 80,667 78,159 68,322 48,829 44,173 45,323 20,389
-------- -------- -------- -------- -------- -------- --------
Total operating revenues $654,132 $586,931 $489,244 $433,152 $399,327 $370,933 $199,845
SPECIAL CHARGES -- -- -- 9,522 -- -- --
CUMULATIVE CHANGE IN ACCOUNTING PRINCIPLE -- -- -- 3,819 -- -- --
NET INCOME 43,603 41,042 45,295 34,520 32,346 30,624 26,096
CASH FLOW FROM OPERATIONS 77,529 61,761 81,850 63,959 69,398 68,611 46,667
CAPITAL EXPENDITURES 53,596 46,273 35,245 29,289 41,973 64,823 24,642
TOTAL ASSETS 782,541 737,708 694,341 655,612 655,441 669,704 491,633
LONG-TERM DEBT 227,360 195,128 180,159 181,046 189,973 163,176 146,326
REDEEMABLE PREFERRED -- 18,000 18,000 18,000 18,000 18,000 13,150
BASIC EARNINGS PER SHARE (4) (6) 1.69 1.59 1.75 1.36 1.29 1.23 1.07
DILUTED EARNINGS PER SHARE (4) (6) 1.68 1.59 1.75 1.36 1.29 1.23 1.07
RETURN ON AVERAGE COMMON EQUITY 15.5% 15.4% 18.4% 15.0% 14.9% 14.9% 15.4%
DIVIDENDS PER COMMON SHARE (6) 1.04 1.02 0.99 0.96 0.93 0.90 0.80
DIVIDEND PAYOUT RATIO 62% 64% 57% 71% 72% 73% 74%
COMMON SHARES OUTSTANDING -YEAR END (6) 24,653 24,574 24,571 23,759 23,462 23,072 22,370
NUMBER OF COMMON
SHAREHOLDERS (5) 14,358 14,103 13,438 13,699 13,753 13,829 13,928
- -----------------------------------------------------------------------------------------------------------------------------
Notes:
(1) Restated to reflect the effects of two 2001 acquisitions accounted for
under the pooling-of-interests method. The impact of the poolings on years
prior to 1999 is not material.
(2) During 1999 radio station assets were sold for a net gain of $8.1 million
or 34 cents per share.
(3) In the first quarter of 1998 the Company changed its method of electric
revenue recognition in the states of Minnesota and South Dakota from
meter-reading dates to energy-delivery dates. Basic and diluted earnings
per share includes 16 cents per share related to the cumulative effect of
the change in accounting principle.
(4) Based on average number of shares outstanding.
(5) Holders of record at year end.
(6) Common shares outstanding and per-share data reflect the effect of the
two-for-one stock split effective March 15, 2000.
Management's discussion and analysis of
financial condition and results of operations
Otter Tail Corporation's primary financial goals are to maximize its earnings
and cash flows and to allocate capital profitably toward growth opportunities
that will increase shareholder value. Management meets these objectives by
earning the returns regulators allow in electric operations combined with
successfully growing diversified operations. Meeting these objectives enables
the Company to preserve and enhance its financial capability by maintaining
optimal capitalization ratios and a strong interest coverage position, and
preserving strong credit ratings on outstanding securities, which in the form of
lower interest rates benefits both the Company's customers and shareholders.
LIQUIDITY:
The Company believes its financial condition is strong and that its cash, other
liquid assets, operating cash flows, access to equity capital markets and
borrowing capital, when taken together, provide adequate resources to fund
ongoing operating requirements and future capital expenditures related to
expansion of existing businesses and development of new projects. However, the
Company's operating cash flow and access to capital markets can be impacted by
macroeconomic factors outside its control. In addition, the Company's borrowing
costs can be impacted by short and long-term debt ratings assigned by
independent rating agencies, which in part are based on certain credit measures
such as interest coverage and leverage ratios.
The Company has achieved a high degree of long-term liquidity by maintaining
desired capitalization ratios and strong credit ratings, implementing
cost-containment programs, and investing in projects that provide returns in
excess of the Company's weighted average cost of capital.
Cash provided by operating activities of $77.5 million combined with cash on
hand of $1.3 million at December 31, 2000, allowed the Company to pay dividends,
meet sinking fund payment requirements, and partially finance capital
expenditures.
The $15.8 million increase in cash provided by operating activities between 2001
and 2000 reflects an increase in net income of $2.6 million, a $1.5 million
increase in depreciation and amortization expense, a $3.2 million change in
deferred taxes, a $5.1 million decrease in deferred debits and other assets
primarily reflecting the change in the pension asset and $16.7 million increase
in working capital.
The $17.7 million decrease in net cash used in investing activities between 2001
and 2000 reflects an increase in capital expenditures of $7.3 million offset by
a $25.2 million reduction in cash used to complete acquisitions. The majority of
the increase in capital expenditures occurred in the electric segment as a
result of in-progress construction of a new gas-fired combustion turbine and
construction of a new transmission line in North Dakota. In 2001 the Company
completed six acquisitions. Two of the acquisitions were completed by issuing
Company common stock. The remaining four were funded with cash which aggregated
$8.9 million in merger consideration.
Net cash used in financing activities was $6.3 million for 2001 compared with
$6.6 million for 2000. The slight decrease between the years was due to the
following. The Company received net proceeds from employee stock plans of $1.3
million. Dividends paid increased $889,000 and the net change in the issuance of
long-term debt over the retirement of long-term debt and preferred stock
decreased $208,000 between the periods.
The Company sold $20.79 million of Pollution Control Refunding Revenue Bonds,
Mercer County, ND 4.85 percent Series due 2022 and $5.185 million of Pollution
Control Refunding Revenue Bonds, Grant County, SD 4.65 percent Series due in
2017 in September 2001. The proceeds were used to redeem the 2019 Series Mercer
County (Coyote project) Pollution Control Refunding Revenue Bonds and the 2006
Series Grant County (Big Stone project) Pollution Control Refunding Revenue
Bonds in October 2001.
The Company sold $90 million of Senior Notes, 6.63 percent Series due 2011 in
December 2001. The proceeds from the sale were used to retire the 8.75 percent
Series First Mortgage Bonds at the aggregate redemption price of $19.3 million;
retire the $6.35 Cumulative Preferred Shares at the aggregate redemption price
of $18.2 million; retire $17.3 million of Varistar term debt; and repay $20.8
million in short-term debt outstanding. The remaining proceeds will be used to
fund certain capital expenditures and for general corporate purposes during
2002.
74,480 shares of common stock were issued during 2001 as a result of stock
options exercised under the 1999 Stock Incentive Plan generating proceeds of
$1.3 million. In addition, the Company issued 721,436 unregistered common shares
during 2001 to effect two acquisitions accounted for under the
pooling-of-interests method.
CAPITAL REQUIREMENTS:
The Company's consolidated capital requirements include replacement of
technically obsolete or worn-out equipment, new equipment purchases, and plant
upgrades to accommodate anticipated growth. The electric segment has a
construction and capital investment program to provide facilities necessary to
meet forecasted customer demands and to provide reliable service. The
construction program is subject to review and is revised annually in light of
changes in demands for energy, availability of energy within the power pool,
cost of capacity charges relative to cost of new generation, environmental laws,
regulatory changes, technology, the costs of labor, materials and equipment, and
the Company's consolidated financial condition.
Consolidated capital expenditures for the years 2001, 2000, and 1999 were $53.6
million, $46.3 million, and $35.2 million, respectively. The estimated capital
expenditures for 2002 are $73 million, and the total capital expenditures for
the five-year period 2002 through 2006 are expected to be approximately $181
million.
The breakdown of 2001 actual and 2002 through 2006 estimated capital
expenditures by segment is as follows:
2001 2002 2002-2006
---- ---- ---------
(in millions)
Electric $ 35 $ 50 $113
Plastics 2 1 12
Manufacturing 11 14 34
Health services 3 3 5
Other business operations 3 5 17
---- ---- ----
Total $ 54 $ 73 $181
==== ==== ====
The $15 million increase in capital expenditures for the electric segment for
2002 as compared to 2001 reflects construction of a new gas-fired combustion
turbine plant.
The following table summarizes the Company's contractual obligations at December
31, 2001 and the effect these obligations are expected to have on its liquidity
and cash flow in future periods.
1 2-3 4-5 After 5
December 31, (in millions) Total year years years years
- -------------------------- ----------------------------------------------------------
Long term debt $256 $29 $14 $10 $203
Coal contracts (required minimums) 106 14 29 11 52
Construction program(purchase orders) 16 16 -- -- --
Capacity and energy requirements 70 14 24 21 11
Operating leases 53 16 22 10 5
---------------------------------------------------------
Total contractual cash obligations $501 $89 $89 $52 $271
=========================================================
CAPITAL RESOURCES:
Financial flexibility is provided by unused lines of credit, strong financial
coverages and credit ratings, and alternative financing arrangements such as
leasing.
The Company estimates that funds internally generated net of forecasted dividend
payments, combined with funds on hand, will be sufficient to meet scheduled debt
retirements and almost completely provide for its estimated 2002 through 2006
consolidated capital expenditures. Reduced demand for electricity or in the
products manufactured and sold by the Company could have an effect on funds
internally generated. Additional short-term or long-term financing will be
required in the period 2002 through 2006 in order to complete the planned
capital expenditures, in the event the Company decides to refund or retire early
any of its presently outstanding debt or cumulative preferred shares, to
complete acquisitions, or for other corporate purposes. There can be no
assurance that any additional required financing will be available through bank
borrowings, debt or equity financing or otherwise, or that if such financing is
available, it will be available on terms acceptable to the Company. If adequate
funds are not available on acceptable terms, our business, results of
operations, and financial condition could be adversely affected.
Bank lines of credit are a key source of operating capital and can provide
interim financing of working capital and other capital requirements, if needed.
As of December 31, 2001, the Company had $11.4 million in cash and cash
equivalents and $42 million in three separate unused lines of credit. In
addition to the formal bank lines, the Company can issue commercial paper. The
subsidiaries' notes and credit lines are secured by a pledge of all of the
common stock of the subsidiaries. (See note 9 to consolidated financial
statements.)
The Company's credit ratings affect its access to the capital market. The
current credit ratings for the Company's First Mortgage Bonds at December 31,
2001 are as follows:
Moody's Investors Service Aa3
Fitch Ratings AA
Standard and Poor's A+
Moody's rating outlook has been negative since September 2000. The Company's
disclosure of these security ratings is not a recommendation to buy, sell, or
hold its securities. A downgrade in the Company's credit ratings could adversely
affect its ability to renew existing, or obtain access to new, credit facilities
in the future and could increase the cost of such facilities.
The 6.63 percent Senior Notes due 2011 contain an investment grade put that
could accelerate the maturity date of this series if designated rating agencies
rate the senior debt below a rating of Baa3 for Moody's or BBB- for Standard and
Poor's. If ratings on the Company's senior unsecured debt are downgraded to
"Baa2" or below by Moody's or "BBB" or below by Standard and Poor's and Fitch
Ratings, related to the Pollution Control Refunding Revenue Bonds, the Company
would be required to grant to Ambac Assurance Corporation, under a financial
guaranty insurance policy, a security interest in the assets of the electric
utility. The Company believes the risk of either of these occurring is unlikely
due to the current bond ratings of the Company combined with its strong
debt-to-equity ratio and ability to generate cash from operations.
The Company is in compliance with all covenants or other requirements set forth
in its credit agreements, note documents and indentures. Covenants relate to the
Company's total net worth, current ratios, cash leverage ratio, fixed charge
coverage ratio, and debt-to-equity ratio. The Company's fixed charge coverage
ratio after taxes was 4.1x for 2001 compared to 3.8x for 2000, and the long-term
debt interest coverage ratio before taxes was 5.2x for 2001, compared to 4.8x
for 2000. During 2002 the Company expects these coverages to remain similar to
2001.
The Company did not have any relationships with unconsolidated entities or
financial partnerships at December 31,2001. These entities are often referred to
as structured finance or special purpose entities, which would have been
established for the purpose of facilitating off-balance sheet arrangements or
other contractually narrow or limited purposes. The Company is not exposed to
any financing, liquidity, market or credit risk that could arise if it had such
relationships.
Results of operations:
Consolidated Results of Operations
The Company recorded diluted earnings per share of $1.68 for the year ended
December 31, 2001 compared to $1.59 for the year ended December 31, 2000. Total
operating revenues for 2001 were $654.1 million, compared with $586.9 million
for 2000. Operating income was $77.5 million for the year 2001 compared with
$74.2 million for 2000. Growth in revenues and operating income from the
electric, manufacturing and health services segments offset decreased operating
income from the plastics and other business operations segments.
Electric
Otter Tail Power Company, a division of Otter Tail Corporation, provides
electrical service to more than 126,000 customers in a service territory
exceeding 50,000 square miles.
2001 2000 1999
-------- -------- --------
(in thousands)
Operating revenues $307,684 $262,280 $233,527
Production fuel 41,776 38,546 36,839
Purchased power 99,491 66,121 44,190
Other operation and maintenance expenses 75,531 74,591 71,724
Depreciation and amortization 24,272 23,778 23,366
Property taxes 9,464 9,976 10,174
-------- -------- --------
Operating income $ 57,150 $ 49,268 $ 47,234
======== ======== ========
(bar graph of information in following table)
Electric operating income
(millions)
-------------------------
1999 $47.2
2000 $49.3
2001 $57.2
(end of graph)
Electric operating revenues for 2001 increased 17.3 percent over 2000 due to a
$33.5 million increase in wholesale power revenues, a $10.2 million increase in
retail revenues, and a $1.7 million increase in other electric revenues. The
increase in wholesale power revenues resulted from a 16.4 percent increase in
wholesale prices combined with a 30.2 percent increase in wholesale
kilowatt-hour (kwh) sales. The increase in the wholesale sales is the result of
the electric utility's increased activity and involvement in wholesale markets.
The increase in retail sales revenue is due to a 2.9 percent increase in retail
kwh sales along with a $6.3 million increase in cost-of-energy revenue. In
addition to a $1.9 million refund of fuel costs resulting from a coal contract
arbitration settlement in 2000, the increase in cost-of-energy revenues reflects
increases in fuel and purchased power costs per kwh for system use in 2001 as
compared to 2000. Increases in retail kwh sold occurred in all customer
categories except streetlighting, with commercial having the largest increase.
The $1.7 million increase in other electric revenues reflects an increase
in transmission service revenues and increases in revenues mainly related to
construction service contracts for other utilities.
The $3.2 million (8.4 percent) increase in production fuel expense in 2001 over
2000 is due to the following: a 4.4 percent increase in kwhs generated combined
with a 0.8 percent increase in the fuel cost per kwh generated and a reduction
in 2000 fuel expenses of $1.9 million related to the coal arbitration
settlement. Excluding the impact of this settlement, production fuel expenses
increased 3.3 percent. The 50.5 percent increase in purchased power expense is
the result of a 24.2 percent increase in kwh purchases combined with a 21.2
percent increase in the cost per kwh purchased. While kwh purchases for resale
increased 49.4 percent to provide for the increase in wholesale sales of
electricity, kwh purchases for retail sales were down 26.9 percent in 2001
compared to 2000.
Other operation and maintenance expenses increased 1.3 percent in 2001 compared
to 2000, mainly due to a 3.1 percent increase in operating and maintenance labor
expense. In addition, other operation and maintenance expense for 2000 included
a credit of $1.0 million that was recorded as part of the arbitration settlement
that recovered previously recorded arbitration expenses. (See note 3 to
consolidated financial statements.)
The 2.1 percent increase in depreciation and amortization expense for 2001
compared to 2000 is due to an increase in depreciable plant base as a result of
recent capital expenditures. Property taxes decreased 5.1 percent for 2001
compared to 2000 due to a legislative reduction in tax capacity rates used to
determine Minnesota property taxes. In addition, under a new state law in
Minnesota, generation machinery and attached equipment were exempted for
Minnesota property taxes. This reduction in property taxes will be refunded to
retail electric customers.
No growth is expected in the electric segment in 2002. The warm winter of 2001
and 2002 will limit growth in retail sales, and the depressed wholesale market
will lower sales volumes in 2002.
The 12.3 percent increase in electric operating revenues for 2000 compared to
1999 is due to a $19.8 million increase in wholesale power revenues, a $7.2
million increase in retail revenues and a $1.8 million increase in other
electric revenues. Increased wholesale prices along with increased demand
contributed to the increase in revenues from wholesale power sales. Wholesale
power kwh sales increased 27.8 percent. The electric utility was well positioned
to capitalize on sales into a robust wholesale energy market in 2000 due to
excellent plant availability when on-peak power prices were high. A 3.5 percent
increase in retail kwh sales due primarily to much colder weather during
November and December of 2000 compared to the same months in 1999, was the main
contributor to the $7.2 million increase in retail electric sales revenues.
Retail revenue per kwh sold increased 0.4 percent due to an increase in cost of
energy revenues between 2000 and 1999. The $1.8 million increase in other
electric segment revenues is due mainly to an increase in transmission service
revenues combined with the proceeds from the sale of an algorithm concept
developed by the utility to facilitate customer choice in a competitive retail
electric market.
The 4.6 percent increase in production fuel expense in 2000 compared to 1999
resulted from a $3.6 million increase in fuel costs at the generating plants
offset by a $1.9 million reduction in fuel costs due to the arbitration
settlement with Knife River Coal Mining Company. (See note 3 to consolidated
financial statements for more information on the arbitration settlement.) The
increase in fuel costs at the generating plants reflects a 7.9 percent increase
in the fuel cost per kwh generated combined with a 1.8 percent increase in kwh
generated. The increase in fuel cost per kwh generated is due to slightly higher
coal costs at one of the utility's generating plants and significantly higher
fuel costs at the utility's combustion turbines. Purchased power expense
increased 49.6 percent as a result of a 28.5 percent increase in the volume of
electricity purchased combined with a 16.4 percent increase in the cost per kwh
purchased. The additional electricity purchased and generated was needed to
provide for increased retail and power pool sales
discussed above. The increase in cost per kwh purchased is a function of
increased demand in the wholesale energy market and a general increase in
electricity usage nationwide without a commensurate increase in generation.
Other operation and maintenance expenses for 2000 increased 4.0 percent as
compared to 1999. This increase is due to additional expenses related to
employee benefits, customer service enhancements and maintenance on generating
plants, transmission, and distribution lines. Included in this increase are
credits related to pension cost and the arbitration settlement that recovered
previously recorded arbitration expenses.
The 1.8 percent increase in depreciation and amortization expense for 2000
compared to 1999 is due to an increase in depreciable plant base as a result of
capital expenditures. The 1.9 percent decrease in property taxes for 2000
compared to 1999 is due to a general decline in mill rates for 2000.
Plastics
Plastics consists of businesses involved in the production of polyvinyl chloride
(PVC) pipe in the Upper Midwest and Southwest regions of the United States. On
January 1, 2000, the Company acquired the assets and operations of Vinyltech
Corporation (Vinyltech) under the purchase method of accounting. (See note 2 to
consolidated financial statements.)
2001 2000 1999
------ ------ -------
(in thousands)
Operating revenues $63,216 $82,667 $31,504
Cost of goods sold 57,932 66,286 24,270
Operating expenses 3,446 4,335 2,684
Depreciation and amortization 3,229 3,301 1,168
------- ------- -------
Operating (loss) income $(1,391) $ 8,745 $ 3,382
======= ======= ========
(bar graph of information in following table)
Plastics operating income
(millions)
-------------------------
1999 $ 3.4
2000 $ 8.7
2001 $(1.4)
(end of graph)
The 23.5 percent decrease in operating revenues for 2001 compared with 2000 is
due to a 29.5 percent decline in average sales price per pound offset by an 8.5
percent increase in pounds of PVC pipe sold. The continuing decline in PVC resin
prices combined with an over supply of finished PVC pipe products were the main
factors in the decrease in average sales price per pound. The decrease of 12.6
percent in cost of goods sold reflects a 19.5 percent decrease in the average
cost per pound of PVC pipe sold. The selling price per pound of PVC pipe is
affected directly by the raw material cost of resin. Operating expenses
decreased 20.5 percent primarily due to a reduction in labor costs and selling
expenses.
The acquisition of Vinyltech on January 1, 2000 is the primary driver behind the
increases in operating revenues, cost of goods sold, operating expenses and
operating income for 2000 compared to 1999. Strong demands within the PVC pipe
industry combined with higher sales prices per pound during the first half of
the year also led to increased pipe revenues. The average sales price per pound
of pipe between the periods increased 27.3 percent.
During the second half of 2000 there was a significant softening in demand for
PVC product lines as PVC pipe prices decreased. The reduction in short-term
demand was
due in part to our distributors' reluctance to purchase pipe for inventory while
pipe prices were declining. The general slowing of the economy also reduced the
demand for pipe. Additional resin capacity that came online during 2000 had a
negative impact on resin prices. The continuing decline in PVC resin prices that
started during the second half of 2000 and continued through 2001 combined with
an over supply of finished PVC pipe products has lead to lower sales prices per
pound. The Company expects the trends that are affecting the sales prices of PVC
pipe to continue into the third quarter of 2002.
The gross margin percentage is sensitive to PVC raw material resin prices and
the demand for PVC pipe. Historically, when resin prices are rising or stable,
margins and sales volume have been higher and when resin prices are falling,
sales volumes and margins have been lower. Gross margins also decline when the
supply of PVC pipe increases faster than demand. Due to the commodity nature of
PVC resin and the dynamic supply and demand factors worldwide, it is very
difficult to predict gross margin percentages or assume that historical trends
will continue.
Manufacturing
Manufacturing consists of businesses involved in the production of wind towers,
frame-straightening equipment and accessories for the auto body shop industry,
custom plastic pallets, material and handling trays, and horticultural
containers, fabrication of steel products, contract machining, and metal parts
stamping and fabricating. During 2001 three acquisitions were completed in this
segment. On February 28, 2001 the Company acquired the outstanding common stock
of T.O. Plastics, Inc. On September 28, 2001 the Company acquired the
outstanding common stock of St. George Steel Fabrication, Inc. These two
acquisitions were completed as a pooling-of-interests. On November 1, 2001, the
Company acquired the assets and operations of Titan Steel Corporation using the
purchase method of accounting. (See note 2 to consolidated financial
statements.)
2001 2000 1999
------ ------ -------
(in thousands)
Operating revenues $123,436 $97,506 $87,086
Cost of goods sold 91,360 72,639 64,907
Operating expenses 14,762 13,992 13,255
Depreciation and amortization 5,139 3,930 3,627
-------- ------- -------
Operating income $ 12,175 $ 6,945 $ 5,297
======== ======= =======
(bar graph of information in following table)
Manufacturing operating income
(millions)
------------------------------
1999 $ 5.3
2000 $ 6.9
2001 $12.2
(end of graph)
Operating revenues for the manufacturing segment increased 26.6 percent during
2001 compared to 2000 reflecting increased sales of wind towers combined with
increased sales volumes of metal parts stamping, fabrication and thermoform
plastic products. The 25.8 percent increase in cost of goods sold correlates
with the increased sales volumes. The 5.5 percent increase in operating expenses
reflects increases in general and administrative expenses offset by reductions
in research, development and selling expenses.
Manufacturing operating revenues increased 12.0 percent during 2000 compared to
1999 due primarily to a $10.6 million increase in sales volumes of metal parts
stamping offset by a $4.8 million decrease in operating revenues from the wind
tower manufacturer. During 2000 the agricultural equipment manufacturer
completed a
transition from manufacturing agricultural equipment to manufacturing towers
that are used by the wind energy industry. The 11.9 percent increase in cost of
goods sold for manufacturing operations in 2000 compared to 1999 closely follows
the increase in sales volumes of stamped metal parts offset by the sales
reduction at the agricultural equipment manufacturer. The 5.6 percent increase
in operating expenses during 2000 compared to 1999 primarily is due to an
increase of operating costs at the subsidiary that manufactures products for the
auto body industry.
Health services
Health services include businesses involved in the sale of diagnostic medical
equipment, supplies and accessories. In addition these businesses also provide
service maintenance, mobile diagnostic imaging, mobile PET and nuclear medicine
imaging, portable x-ray imaging and rental of diagnostic medical imaging
equipment. On September 4, 2001, the Company acquired the assets and operations
of Interim Solutions and Sales, Inc. and Midwest Medical Diagnostics, Inc. On
September 10, 2001, the Company acquired the assets and operations of Nuclear
Imaging, Ltd. In June 2000 the Company acquired the assets and operations of
Portable X-Ray & EKG, Inc. (PXE) All of these acquisitions were accounted for
using the purchase method of accounting. (See note 2 to consolidated financial
statements.)
2001 2000 1999
------ ------ ------
(in thousands)
Operating revenues $79,129 $66,319 $68,805
Cost of goods sold 59,388 49,193 52,146
Operating expenses 9,362 8,416 7,479
Depreciation and amortization 3,517 2,981 4,244
------- ------- -------
Operating income $ 6,862 $ 5,729 $ 4,936
======= ======= =======
(bar graph of information in following table)
Health services operating income
millions
--------------------------------
1999 $4.9
2000 $5.7
2001 $6.9
(end of graph)
Operating revenues for the health services segment increased 19.3 percent for
2001 compared to 2000 due to an increase in equipment sales, services and
supplies combined with an increase of 7.4 percent in scans performed. $4.2
million of the revenue increase was the result of the acquisitions completed in
September 2001. Cost of goods sold increased 20.7 percent reflecting increased
costs of materials and supplies used and sold in the diagnostic equipment
imaging business, increased rent expense and additional expenses as a result of
the acquisitions. The operating expense increase related to increased labor
costs, selling expenses, insurance expenses and promotion expenses.
The 3.6 percent decrease in operating revenues for health services for 2000
compared to 1999 is the result of decreased dealer sales. Offsetting the
decreased dealer sales were increases in services and supply and accessory sales
combined with operating revenues from the PXE acquisition and a 9.0 percent
increase in the number of imaging scans performed primarily as a result of
adding more routes. Cost of goods sold decreased 5.7 percent during 2000
compared to 1999 due to a decline in sales and servicing of equipment. The 12.5
percent increase in operating expenses in 2000 compared to 1999 reflects the
results of the PXE acquisition combined with the additional routes and
completion of more imaging scans.
Other business operations
The Company's other business operations include businesses involved in
electrical and telephone construction contracting, transportation,
telecommunications, entertainment, energy services, and natural gas marketing as
well as the portion of corporate administrative and general expenses that are
not allocated to the other segments.
Results of operations for the other business operations segment are as follows:
2001 2000 1999
------ ------ -----
(in thousands)
Operating revenues $80,667 $78,159 $68,322
Cost of goods sold 41,109 40,938 38,954
Operating expenses 30,927 27,088 17,550
Depreciation and amortization 5,943 6,572 4,454
------- ------- -------
Operating income $ 2,688 $ 3,561 $ 7,364
======= ======= =======
(bar graph of information in following table)
Other business operations operating income
(millions)
-----------------------------------------
1999 $7.4
2000 $3.6
2001 $2.7
(end of graph)
The 3.2 percent increase in other business operating revenues reflects a $2.4
million increase in revenues from the energy services company and $1.7 million
from the transportation subsidiary partially offset by a $2.0 million decrease
in revenues from the construction subsidiaries. Both operating revenues and cost
of goods sold increased for the energy services company as a result of the
higher cost of natural gas during the first half of 2001. The increase in cost
of goods sold was offset by reductions in this category from the construction
subsidiaries. Increases in brokerage revenue are primarily the reason for the
increase in revenue from the transportation subsidiary. The decrease in revenues
and cost of goods sold from the construction subsidiaries is due to an overall
decline in the number of projects available for the companies to work on in 2001
as compared to 2000. Operating expenses increased 14.3 percent reflecting
increased payments to owner-operators and increased brokerage fees within the
transportation subsidiary and increases in insurance expenses. The 9.6 percent
decrease in depreciation and amortization reflects the write down in 2000 of
$800,000 of goodwill that was impaired at the energy services company and
charged to amortization expense.
Other business operating revenues increased 14.4 percent during 2000 compared to
1999, reflecting a full year of revenues from the transportation company
compared to only four months during 1999. The increased revenues from the
transportation company combined with increased revenues from the energy services
subsidiary offset decreases in operating revenues from the construction and
telecommunication subsidiaries and the lost revenues from the radio stations,
which were sold in 1999. Cost of goods sold increased 5.1 percent during 2000
compared to 1999 as a result of the increased sales from the energy services
subsidiary offset by a reduction in costs at the construction companies due to
lower volumes of contracted work between the periods. The increase in operating
expenses also reflects a full year of operations from the transportation company
offset by the absence of expenses from the radio stations.
In October 1999 the Company completed the sale of certain assets of the radio
stations and video production company owned by KFGO, Inc., and the radio
stations owned by Western Minnesota Broadcasting Company for $24.1 million.
Operating income includes results of operations for the radio stations through
September 1999. The
gain from this sale is not included in operating income for segment purposes.
For additional information regarding the sale see note 2 to consolidated
financial statements. During 1999 the Company agreed, as part of a settlement
with the Minnesota Pollution Control Agency, to donate all of its assets in its
Quadrant Co. waste incineration plant to the City of Perham, Minnesota. The
plant had ceased operations during the third quarter of 1998. Pro forma
operating income for other business operations without Quadrant and the radio
stations would have been $6,303,000 for 1999.
Gain from sale of radio station assets
The Company recorded a $14.5 million pre-tax gain from the sale of certain
assets of the six radio stations and the video production company owned by KFGO,
Inc., and the two radio stations owned by Western Minnesota Broadcasting Company
on October 1, 1999. The after-tax gain from this sale contributed $0.34 to
earnings per share for 1999.
(bar graph of information in following table)
Other income and deductions
(millions)
---------------------------
1999 $2.3
2000 $2.1
2001 $2.2
(end of graph)
Consolidated interest charges
(bar graph of information in following table)
Interest charges
millions
----------------
1999 $15.2
2000 $17.0
2001 $16.0
(end of graph)
Interest expense decreased 6.0 percent for 2001 compared to 2000 due to
decreases in the average long-term debt outstanding combined with lower interest
rates on the line of credit balances and variable rate debt offset slightly by a
higher daily average line of credit borrowings outstanding. Daily average
outstanding borrowings were $16.7 million for 2001 compared to $12.8 million for
2000. The average interest rate under the line of credit was 5.2 percent for
2001. The 11.8 percent increase in interest charges in 2000 compared to 1999 is
due to increases in long-term debt, higher average borrowings under the line of
credit, and higher interest rates on the line of credit between the periods.
Average interest rates under the line of credit were 8.1 percent for 2000
compared to 7.0 percent for 1999.
Consolidated income taxes
(bar graph of information in following table)
Income taxes
millions
------------
1999 $24.5
2000 $18.4
2001 $20.1
(end of graph)
The 9.4 percent increase in consolidated income taxes for 2001 compared to 2000
follows the $4.3 million increase in income before income taxes. Consolidated
income taxes decreased 25.0 percent during 2000 compared to 1999 primarily due
to the income tax expense of $6.4 million related to the sale of the radio
station assets.
Impact of inflation
The electric utility operates under regulatory provisions that allow price
changes in the cost of fuel and purchased power to be passed to customers
through automatic adjustments to its rate schedules under the cost of energy
adjustment clause. Other increases in the cost of electric service must be
recovered through timely filings for rate relief with the appropriate regulatory
agency.
The Company's plastics, manufacturing, health services, and other business
operations consist almost entirely of unregulated businesses. Increased
operating costs are reflected in product or services pricing with any
limitations on price increases determined by the marketplace. The impact of
inflation on these segments has not been significant during the past few years
because of the relatively low rates of inflation experienced in the United
States. Raw material costs, labor costs, and interest rates are important
components of costs for companies in these segments. Any or all of these
components could be impacted by inflation, with a possible adverse effect on the
Company's profitability, especially in high inflation periods where raw material
and energy cost increases would lead finished product prices.
Factors affecting future earnings
The results of operations discussed above are not necessarily indicative of
future earnings. Factors affecting future earnings include, but are not limited
to, the Company's ongoing involvement in diversification efforts, the timing and
scope of deregulation and open competition, growth of electric revenues, impact
of the investment performance of the Company's pension plan, changes in the
economy, weather conditions, governmental and regulatory action, fuel and
purchased power costs, and environmental issues. Anticipated higher operating
costs and carrying charges on increased capital investment in plant, if not
offset by proportionate increases in operating revenues and other income (either
by appropriate rate increases, increases in unit sales, or increases in
nonelectric operations), will affect future earnings.
Diversification
In 2001 approximately 24 percent of the Company's net earnings were contributed
by diversified operations. The Company plans to make additional acquisitions
through its wholly owned subsidiary, Varistar Corporation. It is possible that
by 2006 nearly 50 percent of the Company's net earnings will be contributed from
diversified operations. The following guidelines are used when considering
acquisitions: emerging or middle market company; proven entrepreneurial
management team that will remain after the acquisition; products and services
intended for commercial rather
than retail consumer use; the ability to provide immediate earnings and future
growth potential; and 100 percent ownership. The Company intends to grow
earnings as a long-term owner of these investments. The Company also assesses
the performance of these investments in accordance with its return on capital
requirements and will consider divesting underperforming investments. Continuing
growth from diversified operations could result in earnings and stock price
volatility.
While the Company cannot predict the success of our current diversified
businesses, we believe opportunities exist for growth in the business segments.
Factors that could affect the results of the diversified businesses include, but
are not limited to, the following: fluctuations in the cost and availability of
raw materials and the ability to maintain favorable supplier arrangements and
relationships; competitive products and pricing pressures and the ability to
gain or maintain market share in trade areas; general economic conditions;
effectiveness of advertising, marketing, and promotional programs; and adverse
weather conditions. The failure of congress to approve extension of the
Production Tax Credit for wind energy in December 2001 could have an unfavorable
impact on the Company's subsidiary that manufactures towers for the wind energy
industry.
Growth of electric revenue
Growth in electric sales will be subject to a number of factors, including the
volume of sales of electricity to other utilities, the effectiveness of
demand-side management programs, weather, competition, the price of alternative
fuels, and the rate of economic growth or decline in the Company's service area.
The Company's electric business depends primarily on the use of electricity by
customers in our service area. The Company's electric kwh sales to retail
customers increased 2.9 percent in 2001, 3.5 percent in 2000, and decreased 2.6
percent in 1999.
Factors beyond the Company's control, such as mergers and acquisitions,
geographical location, transmission costs, unplanned interruptions at the
Company's generating plants, and the effects of deregulation, could lead to
greater volatility in the volume and price of sales of electricity to other
utilities. Activity in the short-term energy market is subject to change based
on a number of factors and it is difficult to predict the quantity of wholesale
power sales or prices for wholesale power although it does appear that market
conditions for wholesale power transactions will be depressed during part of
2002.
Regulation
Rates of return earned on utility operations are subject to review by the
various state commissions that have jurisdiction over the electric rates charged
by the Company. These reviews may result in future revenue reductions when
actual rates of return are deemed by regulators to be in excess of allowed rates
of return.
On December 29, 2000 the North Dakota Public Service Commission (NDPSC) approved
a performance-based ratemaking plan that links allowed earnings in North Dakota
to seven defined performance standards in the areas of price, electric service
reliability, customer satisfaction, and employee safety. The plan is in place
for 2001 through 2005, unless suspended or terminated by the NDPSC or the
Company. In 2001 the utility recorded an estimated $334,000 refund to North
Dakota customers based on 2001 earnings and the utility's 2001 performance
relative to the defined standards of the performance-based ratemaking plan.
In 2001, the Minnesota Legislature exempted certain generation machinery and
attached equipment from a new state personal property tax levy. The law also
requires that any windfall tax savings resulting from this exemption be refunded
to utility customers. As a result of this law, $238,000 in 2001 tax savings will
be refunded to retail electric customers in 2002.
Load Management and Minnesota Conservation Improvement Programs
Load management efforts will continue in all jurisdictions served by the
Company. The goal of load management is to control demand for electricity by
customers at times of peak use in order to alleviate or delay the need for
building or acquiring new generating capacity or to avoid having to purchase
high-priced energy at times
of peak demand. In addition to our load management efforts, we also invest in
conservation improvement programs in Minnesota as mandated by state law.
Conservation improvement programs are designed to encourage and reward the wise
and efficient use of electricity by customers.
Fuel Costs
The Company has an agreement for Big Stone Plant's coal supply through December
31, 2004. The Company has been unable to negotiate a competitive delivery rate
for coal to the Big Stone Plant with rail carriers. Coal is being shipped to Big
Stone Plant under a tariff rate that is set through December 2002. The Company
has commenced a proceeding before the Surface Transportation Board requesting
the Board set a competitive rate. The Company expects the outcome to have a
favorable impact on its fuel costs for the Big Stone Plant.
The Mid-Continent Area Power Pool region has experienced a reduction in
availability of excess generation and transmission capacity, particularly in the
summer season in the recent years. While the availability of the Company's
plants has been excellent, the loss of a major plant could expose the Company to
higher purchased power costs. Two factors significantly mitigate this financial
risk. First, wholesale sale contracts include provisions to release the Company
from its obligations in case of a plant outage; and second, the Company has cost
of energy adjustment clauses that allow pass through of most of the energy costs
to retail customers.
Environmental
Current regulations under the Federal Clean Air Act (the Act) are not expected
to have a significant impact on future capital requirements or operating costs.
However, proposed or future regulations under the Act, changes in the future
coal supply market, and/or other laws and regulations could impact such
requirements or costs. It is anticipated that, under current regulatory
principles, any such costs could be recovered through rates. All of the
Company's electric generating plants operated within the Act's phase two
standards for sulfur-dioxide and nitrogen-oxide emissions in 2001. Ongoing
compliance with the phase two requirements is not expected to significantly
impact operations at any of the Company's plants.
The Act called for Environmental Protection Agency (EPA) studies of the effects
of emissions of listed pollutants by electric steam generating plants. The EPA
has completed the studies and sent reports to Congress. The Act required that
the EPA make a finding as to whether regulation of emissions of hazardous air
pollutants from fossil fuel-fired electric utility generating units is
appropriate and necessary. On December 14, 2000, the EPA announced that it will
regulate mercury emissions from electric generating units. The EPA expects to
propose regulations by December 2003 and issue final rules by December 2004.
Because promulgation of rules by the EPA has not been completed, it is not
possible to assess whether, or to what extent, this regulation will impact the
Company.
The Company is planning to further improve the fine particulate emissions
control at its Big Stone Plant by replacing a major portion of the plant's
electrostatic precipitator in 2002 with a system based on Advanced Hybrid
Particulate Collector technology. The new system will be installed as part of a
demonstration project co-funded by the Department of Energy's National Energy
Technology Laboratory Power Plant Improvement Initiative. The technology is
designed to capture at least 99.99% of fly ash particulates emitted from the
boiler. The Energy Department's share of the $13.4 million project is $6.5
million. The Company's share of the project is approximately $2.9 million with
the remaining portion funded by the plant's co-owners and other industry
participants.
The EPA has targeted electric steam generating units as part of an enforcement
initiative relative to compliance with the Act. The EPA is attempting to
determine if utilities violated certain provisions of the Act by making major
modifications to their facilities without installing state-of-the-art pollution
controls. On January 2, 2001, the Company received a request from the EPA
pursuant to Section 114(a) of the Act requiring the Company to provide certain
information relative to past
operation and capital construction projects at its Big Stone Plant. The Company
has responded to that request and cannot, at this time, determine what, if any,
actions will be taken by the EPA as a result of the Company's response.
At the request of the Minnesota Pollution Control Agency (MPCA) the Company has
an ongoing investigation at the Hoot Lake Plant closed ash disposal sites. The
MPCA continues to monitor site activities under their Voluntary Investigation
and Cleanup Program. In April 2001, Otter Tail submitted a Remedial
Investigation Work Plan to the MPCA describing our plans to further investigate
the environmental impact of the closed portion of the Hoot Lake Plant ash
disposal site. The MPCA approved the plan, with some suggested modifications, in
their letter of July 31, 2001. These tasks have been completed. The MPCA also
asked that we eliminate a ground water seepage that was originating from one of
the disposal areas. That task was completed in early November of 2001. We are
continuing to monitor the site for evidence of further seepage.
Deregulation and legislation
In December 1999 the Federal Energy Regulatory Commission (FERC) issued Order
No. 2000. This order requires public utilities that own, operate, or control
interstate transmission to file by October 15, 2000, a proposal for a regional
transmission organization (RTO) or a description of any efforts made to
participate in an RTO, the reasons for not participating, and any plans for
further work towards participation. The goal is to consolidate control of the
transmission industry into a new structure of independent regional grid
operators.
The electric utility agreed in October 2001 to join the Indianapolis-based
Midwest Independent System Operator (MISO) RTO. In December 2001, MISO received
FERC approval as a regional transmission organization. The MISO began
operational control of the electric utility's transmission facilities above 100
kv on February 1, 2002. The utility continues to own and maintain its
transmission assets as before. As the electric utility transitions to the full
operation of the MISO there could be short-term negative impacts on wholesale
power transactions. During 2002, the electric utility will work within MISO on
evaluating for-profit transmission alliances, incentive for transmission
construction and market design and implementation.
The U.S. Congress ended its 2001 legislative session without taking action on
proposed electric industry restructuring legislation. The Minnesota Legislature
passed an energy bill in 2001. Its primary focus was to streamline the siting
and routing processes for the construction of new electric generation and
transmission projects. The bill also added to utility requirements for renewable
energy and energy conservation. There was no legislative action regarding
electric retail choice in any of the states where the electric utility serves.
No major electricity legislation is expected in the 2002 state legislative
sessions. The Company does not expect retail competition to come to the States
of Minnesota, North Dakota or South Dakota in the foreseeable future unless
there is a federal effort to accomplish this.
Competition in the electric industry
As the electric industry evolves and becomes more competitive, the Company
believes it is well positioned to be successful. The Company's generation
capacity appears poised for competition due to unit heat rate improvements. A
comparison of the Company's electric retail rates to the rates of other
investor-owned utilities, cooperatives, and municipals in the states the Company
serves indicates that its rates are competitive. In addition, the Company would
attempt more flexible pricing strategies under an open, competitive environment.
Key accounting policies and accounting pronouncements
The Company's operations occur within five diverse segments. Three key
accounting polices are revenue recognition, inventory valuations, and use of
estimates. Due to
the diverse business operations of the Company revenue recognition depends on
the product that is produced and sold. Provisions for sale returns and warranty
costs are recorded at the time of the sale based on historical information and
current trends. The majority of the Company's inventory is valued at the lower
of cost or market. Changes in the market conditions could require a write down
of inventory values. The Company uses estimates based on the best information
available in recording transactions and balances resulting from business
operations. Examples of items where estimates are used are unbilled revenues,
collectablilty of accounts receivable, self insurance reserves, pension plan
costs or income, and service contract maintenance costs. As better information
becomes available or actual amounts are known, estimates are revised. Operating
results can be affected by changes made to prior accounting estimates. See note
1 in the notes to consolidated financial statements for more details on
significant accounting polices.
As of January 1, 2001, the Company adopted Statement of Financial Accounting
Standards (SFAS) 133, Accounting for Derivative Instruments and Hedging
Activities, as amended, which requires all derivative instruments be reported on
the consolidated balance sheet at fair value. The adoption of SFAS No. 133 did
not have a material effect on the Company's consolidated financial statements.
The application of SFAS 133 to electric utilities continued to evolve throughout
2001. On December 19, 2001, the Financial Accounting Standards Board revised
SFAS 133 Implementation Issue No. C15 to be effective April 1, 2002 with early
adoption allowed. As of December 31, 2001, the Company early adopted the revised
SFAS 133 Implementation Issue No. C15. The Company has determined that certain
electric energy contracts meet the criteria of a derivative under SFAS 133 but
qualify for the normal purchase and normal sales exception and are not subject
to mark-to-market accounting treatment. SFAS 133 did not have a material effect
on the Company's 2001 consolidated financial statements.
In July 2001 the FASB issued SFAS 141, Business Combinations, which requires the
purchase method of accounting be used for all business combinations initiated
after June 30, 2001. SFAS 141 also specifies that intangible assets acquired in
a business combination, that meet certain criteria, be recognized and reported
apart from goodwill. The Company has adopted this statement as of July 1, 2001
and applied it to the following acquisitions that occurred after July 1, 2001:
Interim Solutions and Sales, Inc, Midwest Medical Diagnostics, Inc., Nuclear
Imaging, Ltd, and Titan Steel Corporation. Adoption of this statement did not
have a material effect on the Company's consolidated financial statements.
In July 2001 the FASB issued SFAS 142, Goodwill and Other Intangible Assets,
which requires goodwill and intangible assets with indefinite useful lives no
longer be amortized. Rather they will be tested for impairment, at least
annually, in accordance with the provisions of SFAS 142. Intangible assets with
finite useful lives will be amortized over their respective estimated useful
lives and will be reviewed for impairment in accordance with SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 142 is
effective January 1, 2002, except for any goodwill arising in a purchase
business combination completed on or after July 1, 2001 which would be subject
immediately to the provisions of SFAS 142. As of December 31, 2001, the Company
had net goodwill of $48.2 million. Included on the Company's consolidated
statement of income for the twelve months ended December 31, 2001 is $3.2
million in goodwill amortization expense. SFAS 142 requires the Company perform
an assessment of goodwill impairment as of the date of adoption. Any impairment
loss resulting from this transition to SFAS 142 would be recognized as a
cumulative effect of a change in accounting principle in the Company's
consolidated income statement at the time of adoption. The Company is continuing
to evaluate the effect that the adoption of this statement may have on its
consolidated financial statements. Based on the work completed to date, the
Company does not expect the implementation of this statement to have a material
impact on its consolidated results of operations and financial position.
In July 2001 the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations, which provides accounting requirements for retirement obligations
associated with tangible long-lived assets. This statement is effective for
fiscal years beginning
after June 15, 2002. The Company is assessing this statement but has not yet
determined the impact of SFAS 143 on its consolidated financial position or
results of operations.
The FASB issued SFAS 144, Accounting for the Impairment or Disposal of
Long-Lived Assets in October 2001. SFAS 144 replaces SFAS 121, Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.
This statement develops one accounting model for long-lived assets to be
disposed of by sale and also broadens the reporting of discontinued operations
to include all components of an entity with operations that can be distinguished
from the rest of the entity in a disposal transaction. The statement is
effective for fiscal years beginning after December 15, 2001. The Company
adopted the accounting model for impairment or disposal of long-lived assets on
January 1, 2002. Adoption of this statement did not have a material effect on
the Company's consolidated financial statements.
Quantitative and Qualitative Disclosures About Market Risk
The Company has limited exposure to market risk associated with interest rates
and commodity prices. The majority of the Company's long-term debt obligations
bear interest at a fixed rate. Variable rate long-term debt bears interest at a
rate that is reset on a periodic basis reflecting current market conditions. The
Company manages its interest rate risk through the issuance of fixed-rate debt
with varying maturities, maintaining consistent credit ratings, through economic
refunding of debt through optional refundings, limiting the amount of variable
interest rate debt, and utilization of short-term borrowings to allow
flexibility in the timing and placement of long-term debt. As of December 31,
2001, the Company had $17.0 million of long-term debt subject to variable
interest rates. Assuming no change in the Company's financial structure, if
variable interest rates were to average 1 percent higher or lower than what the
average variable rate was on December 31, 2001, interest expense and pre-tax
earnings would change by approximately $170,000. The Company has short-term
borrowing arrangements to provide working capital and general corporate funds.
The level of borrowings under these arrangements varies from period to period,
depending upon, among other factors, operating needs and capital expenditures.
The interest rate on the majority of the short-term borrowing arrangements is
variable based on LIBOR.
The electric utility's retail portion of fuel and purchased power costs are
subject to cost of energy adjustment clauses that mitigate the commodity price
risk by allowing a pass through of most of the increase or decrease in energy
costs to retail customers. In addition, the electric utility participates in an
active wholesale power market providing access to commodity transactions that
may serve to mitigate price risk. The electric utility has in place an energy
risk management policy with a primary goal to manage, through the use of defined
risk management practices, price risk and credit risk associated with wholesale
power purchases and sales.
The energy services subsidiary markets natural gas to approximately 150 retail
customers. A portion of these customers are served under fixed-price contracts.
There is price risk associated with this limited number of fixed-price contracts
since the corresponding cost of natural gas is not immediately locked in. This
price risk is not considered material to the Company. In addition, the Company
has in place an energy risk management policy with the primary goal of managing,
through the use of defined risk management practices, price risk and credit risk
associated with the marketing of natural gas.
The plastics companies are exposed to market risk related to changes in
commodity prices for PVC resins, the raw material used to manufacture PVC pipe.
The PVC pipe industry is highly sensitive to commodity raw material pricing
volatility. Currently, margins are very tight due to aggressive competition in a
period of soft demand.
The Company does not use derivative financial instruments for speculative or
trading purposes.
Cautionary Statements
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995, the Company makes the following statements.
The information in this annual report includes forward-looking statements.
Important risks and uncertainties that could cause actual results to differ
materially from those discussed in such forward-looking statements are set forth
above under "Factors affecting future earnings." Other risks and uncertainties
may be presented from time to time in the Company's future Securities and
Exchange Commission filings.
INDEPENDENT AUDITORS' REPORT
To the Shareholders of Otter Tail Corporation
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Otter Tail Corporation and its subsidiaries (the Company) as
of December 31, 2001, and 2000, and the related consolidated statements of
income, common shareholders' equity, and cash flows for each of the three years
in the period ended December 31, 2001. These consolidated financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these consolidated 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 consolidated
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the consolidated financial statement. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 2001,
and 2000, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 1, 2002
OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS, DECEMBER 31 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 11,378 $ 1,259
Accounts receivable:
Trade (less allowance for doubtful accounts:
2001, $1,109,000; 2000, $922,000) 64,215 61,913
Other 5,047 6,813
Inventory, fuel, materials and supplies 39,301 42,263
Deferred income taxes 4,020 3,694
Accrued utility revenues 11,055 11,315
Other 8,878 6,468
-------- --------
Total current assets 143,894 133,725
-------- --------
INVESTMENTS 18,009 17,966
INTANGIBLES--NET 49,805 43,532
OTHER ASSETS 15,687 11,236
DEFERRED DEBITS
Unamortized debt expense and reacquisition premiums 5,646 2,778
Regulatory assets 5,117 5,517
Other 1,406 1,183
-------- --------
Total deferred debits 12,169 9,478
-------- --------
PLANT
Electric plant in service 810,470 795,357
Diversified operations 145,712 129,716
-------- --------
Total 956,182 925,073
Less accumulated depreciation and amortization 441,863 416,419
-------- --------
Plant - net of accumulated depreciation and amortization 514,319 508,654
Construction work in progress 28,658 13,117
-------- --------
Net plant 542,977 521,771
-------- --------
TOTAL $782,541 $737,708
======== ========
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS, DECEMBER 31 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Sinking fund requirements and current maturities of long-term debt $ 28,946 $ 14,288
Accounts payable 54,777 52,525
Accrued salaries and wages 9,491 9,476
Income taxes payable 1,634 3,243
Other accrued taxes 9,854 10,585
Other accrued liabilities 6,090 6,524
--------- ---------
Total current liabilities 110,792 96,641
--------- ---------
NONCURRENT LIABILITIES 32,981 30,181
--------- ---------
COMMITMENTS (NOTE 6)
DEFERRED CREDITS
Deferred income taxes 85,591 86,407
Deferred investment tax credit 13,935 15,112
Regulatory liabilities 9,914 10,618
Other 7,160 6,850
--------- ---------
Total deferred credits 116,600 118,987
--------- ---------
CAPITALIZATION (PAGE 35)
Long-term debt, net of sinking fund and current maturities 227,360 195,128
Cumulative preferred shares 15,500 33,500
Common shares, par value $5 per share -- authorized, 50,000,000 shares;
outstanding, 2001 -- 24,653,490 shares; 2000 -- 24,574,288 shares $ 123,267 $ 122,871
Premium on common shares 1,526 50
Unearned compensation (151) (226)
Retained earnings 156,641 140,796
Accumulated other comprehensive expense (1,975) (220)
--------- ---------
Total common equity 279,308 263,271
Total capitalization 522,168 491,899
--------- ---------
TOTAL $ 782,541 $ 737,708
========= =========
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands, except per-share amounts)
OPERATING REVENUES
Electric $ 307,684 $ 262,280 $ 233,527
Plastics 63,216 82,667 31,504
Manufacturing 123,436 97,506 87,086
Health services 79,129 66,319 68,805
Other business operations 80,667 78,159 68,322
--------- --------- ---------
Total operating revenues 654,132 586,931 489,244
OPERATING EXPENSES
Production fuel 41,776 38,546 36,839
Purchased power 99,491 66,121 44,190
Electric operation and maintenance expenses 75,531 74,591 71,724
Cost of goods sold 249,789 229,056 180,277
Other nonelectric expenses 58,497 53,831 40,964
Depreciation and amortization 42,100 40,562 36,859
Property taxes 9,464 9,976 10,178
--------- --------- ---------
Total operating expenses 576,648 512,683 421,031
OPERATING INCOME
Electric 57,150 49,268 47,234
Plastics (1,391) 8,745 3,382
Manufacturing 12,175 6,945 5,297
Health services 6,862 5,729 4,936
Other business operations 2,688 3,561 7,364
--------- --------- ---------
77,484 74,248 68,213
GAIN FROM SALE OF RADIO STATION ASSETS - - 14,469
OTHER INCOME AND DEDUCTIONS -- NET 2,193 2,154 2,311
INTEREST CHARGES 15,991 17,005 15,209
--------- --------- ---------
INCOME BEFORE INCOME TAXES 63,686 59,397 69,784
INCOME TAXES 20,083 18,355 24,489
--------- --------- ---------
NET INCOME 43,603 41,042 45,295
PREFERRED DIVIDEND REQUIREMENTS 1,993 1,879 2,228
--------- --------- ---------
EARNINGS AVAILABLE FOR COMMON SHARES $ 41,610 $ 39,163 $ 43,067
========= ========= =========
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 24,600 24,572 24,553
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 24,832 24,649 24,575
BASIC EARNINGS PER SHARE $ 1.69 $ 1.59 $ 1.75
DILUTED EARNINGS PER SHARE $ 1.68 $ 1.59 $ 1.75
DIVIDENDS PER COMMON SHARE $ 1.04 $ 1.02 $ 0.99
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
- ------------------------------------------------------------------------------------------------------------------------------------
ACCUMULATED
COMMON PAR VALUE, PREMIUM ON OTHER
SHARES COMMON COMMON UNEARNED RETAINED COMPREHENSIVE TOTAL
OUTSTANDING SHARES SHARES COMPENSATION EARNINGS INCOME/(EXPENSE) EQUITY
----------------------------------------------------------------------------------------
(in thousands, except common shares outstanding)
BALANCE, DECEMBER 31, 1998 11,879,504 $ 59,398 $ 39,919 $ - $ 125,462 $ 297 $225,076
Common stock issuances - net of retirement 45,483 227 1,540 $ (10) 1,757
Unearned compensation - stock options 301 (301) -
Two-for-one stock split - March 15, 2000 11,924,987 59,625 (41,760) (17,865) -
Effects of pooling transactions,
January 1, 1999:
T.O. Plastics, Inc. 451,066 2,255 (1,277) 978
St. George Steel Fabrication, Inc. 270,370 1,352 426 1,778
Comprehensive income:
Net income 45,295 45,295
Reversal of previously recorded
unrealized gains on available-
for-sale securities sold (297) (297)
--------
Total comprehensive income 44,998
Cumulative preferred dividends (2,267) (2,267)
Common dividends (23,554) (23,554)
---------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 1999 24,571,410 $ 122,857 $ - $ (301) $ 126,210 $ - $248,766
Common stock issuances 2,878 14 50 64
Amortization of unearned compensation -
stock options 75 75
Comprehensive income:
Net income 41,042 41,042
Minimum liability adjustment (220) (220)
--------
Total comprehensive income 40,822
Purchase stock for employee purchase
plan on open market (250) (250)
Cumulative preferred dividends (1,878) (1,878)
Common dividends (24,328) (24,328)
---------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2000 24,574,288 $ 122,871 $ 50 $ (226) $ 140,796 $ (220) $263,271
Common stock issuances 79,202 396 1,187 1,583
Amortization of unearned compensation -
stock options 75 75
Comprehensive income:
Net income 43,603 43,603
Minimum liability adjustment (1,755) (1,755)
--------
Total comprehensive income 41,848
Tax benefit for exercise of stock options 302 302
Remove capital stock expense $6.35
preferred shares 246 (246) -
Purchase stock for employee purchase
plan on open market (259) (168) (427)
Cumulative preferred dividends (2,088) (2,088)
Common dividends (25,256) (25,256)
---------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2001 24,653,490 $ 123,267 $ 1,526 $ (151) $ 156,641 $(1,975) $279,308
---------------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Cash flows from operating activities
Net income $ 43,603 $ 41,042 $ 45,295
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 42,100 40,562 36,859
Deferred investment tax credit--net (1,177) (1,183) (1,186)
Deferred income taxes (1,441) (4,655) (3,820)
Change in deferred debits and other assets (8,434) (3,346) (459)
Change in noncurrent liabilities and deferred credits 2,484 4,263 4,727
Allowance for equity (other) funds used during construction (963) (341) (246)
(Gain)/loss on sale of investments and radio station assets (81) 728 (14,455)
Changes in working capital:
Change in receivables, materials, and supplies 4,880 (20,781) (572)
Change in other current assets (432) 537 1,348
Change in payables and other current liabilities (581) 9,904 8,253
Change in interest and income taxes payable (2,429) (4,969) 6,106
--------- -------- --------
Net cash provided by operating activities 77,529 61,761 81,850
--------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Gross capital expenditures (53,596) (46,273) (35,245)
Proceeds from sale of radio station assets - - 24,063
Proceeds from disposal of noncurrent assets 3,298 1,709 1,930
Acquisitions--net of cash acquired (8,948) (34,194) (16,000)
Change in other investments (1,884) (86) (9)
--------- -------- --------
Net cash used in investing activities (61,130) (78,844) (25,261)
--------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Change in short-term debt--net issuances - (50) (4,228)
Proceeds from issuance of long-term debt--net of expenses 119,266 44,814 15,444
Proceeds from issuance of common stock--net - 14 1,757
Proceeds from employee stock plans 1,347 - -
Redemption of preferred stock (18,000) - (5,331)
Payments for retirement of long-term debt (81,549) (24,889) (17,618)
Dividends paid and other distributions (27,344) (26,455) (25,820)
--------- -------- --------
Net cash used in financing activities (6,280) (6,566) (35,796)
--------- -------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS 10,119 (23,649) 20,793
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,259 24,908 4,115
--------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 11,378 $ 1,259 $ 24,908
========= ======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest (net of amount capitalized) $ 16,313 $ 16,075 $ 14,004
Income taxes $ 23,575 $ 28,510 $ 23,077
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION, DECEMBER 31 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Long-term debt
First mortgage bond series:
7.25%, due August 1, 2002 $ 18,200 $ 18,400
8.75%, retired December 2001 - 18,200
8.25%, due August 1, 2022 27,300 27,600
Pollution control series:
6.5-6.9%, Big Stone and Coyote project - retired October 2001 - 25,981
-------- --------
Total first mortgage bond series 45,500 90,181
Senior debentures 6.375%, due December 1, 2007 50,000 50,000
Senior notes 6.63%, due December 1, 2011 90,000 -
Industrial development refunding revenue bonds
5.00% due December 1, 2002 3,010 3,010
Pollution control refunding revenue bonds
variable 1.9% at December 31, 2001, due December 1, 2012 10,400 10,400
Grant County, South Dakota pollution control refunding revenue
bonds 4.65%, due September 1, 2017 5,185 -
Mercer County, North Dakota pollution control refunding revenue
bonds 4.85%, due September 1, 2022 20,790 -
Obligations of Varistar Corporation:
7.80% ten-year term note, due October 31, 2007 9,771 12,021
Variable 8.11% at December 31, 2000, retired December 2001 - 16,640
8.15% five-year term note, due October 31, 2005 5,280 6,600
Variable 3.66% at December 31, 2001, due July 3, 2007 4,479 5,324
Various at 3.25% to 8.4% at December 31, 2001 11,571 15,214
Obligations of Otter Tail Energy Services Company
8.75% ten-year term note, due April 11, 2008 892 994
Other 5 6
-------- --------
Total 256,883 210,390
Less:
Current maturities 28,646 13,293
Sinking fund requirement 300 995
Unamortized debt discount and premium -- net 577 974
-------- --------
Total long-term debt 227,360 195,128
-------- --------
CUMULATIVE PREFERRED SHARES -- without par value (stated and liquidating value
$100 a share) -- authorized 1,500,000 shares; outstanding:
Series subject to mandatory redemption:
Outstanding December 31, 2000 $6.35, 180,000 shares - 18,000
-------- --------
Other series:
$3.60, 60,000 shares 6,000 6,000
$4.40, 25,000 shares 2,500 2,500
$4.65, 30,000 shares 3,000 3,000
$6.75, 40,000 shares 4,000 4,000
-------- --------
Total other preferred 15,500 15,500
-------- --------
CUMULATIVE PREFERENCE SHARES -- without par value, authorized
1,000,000 shares; outstanding: none
TOTAL COMMON SHAREHOLDERS' EQUITY 279,308 263,271
-------- --------
TOTAL CAPITALIZATION $522,168 $491,899
======== ========
See accompanying notes to consolidated financial statements.
Otter Tail Corporation
Notes to consolidated financial statements
For the years ended December 31, 2001, 2000 and 1999
1. Summary of significant accounting policies
Principles of consolidation--The consolidated financial statements include
Otter Tail Corporation and its wholly owned subsidiaries (the Company).
Profits on sales between nonregulated affiliates and from the regulated
electric utility company to nonregulated affiliates are eliminated. However,
profits on sales to the regulated electric utility company from nonregulated
affiliates are not eliminated, in accordance with the requirements of
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation. These amounts are not material.
System of accounts--For regulatory reporting purposes, the electric
utility's internal system of accounts is translated into the accounts of the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission (FERC), the Public Service Commission of North Dakota, and the
Public Utilities Commissions of Minnesota and South Dakota.
Regulation and Statement of Financial Accounting Standards (SFAS) No. 71--As
a regulated entity the Company and the electric utility account for the
financial effects of regulation in accordance with SFAS No. 71. This
statement allows for the recording of a regulatory asset or liability for
costs that will be collected or refunded through the ratemaking process in
the future. Included on the Company's Consolidated Balance Sheets for the
years ended December 31, 2001 and 2000 are regulatory assets and liabilities
that primarily relate to the recording of deferred taxes as required by SFAS
No. 109, Accounting for Income Taxes.
Plant, retirements, and depreciation--Utility plant is stated at original
cost. The cost of additions includes contracted work, direct labor and
materials, allocable overheads, and allowance for funds used during
construction (AFC). AFC, a noncash item, is included in utility construction
work in progress. The amount of AFC capitalized was $1,342,000 for 2001,
$471,000 for 2000, and $344,000 for 1999. The cost of depreciable units of
property retired plus removal costs less salvage is charged to the
accumulated provision for depreciation. Maintenance, repairs, and replacement
of minor items of property are charged to operating expenses. The provisions
for utility depreciation for financial reporting purposes are made on the
straight-line method based on the estimated service lives of the properties.
Such provisions as a percent of the average balance of depreciable electric
utility property were 3.06 percent for 1999 through 2001.
Property and equipment of nonutility and diversified operations are carried
at historical cost or at the current appraised value if acquired in a
business combination accounted for under the purchase method of accounting,
and are depreciated on a straight-line basis over useful lives (3 to 40
years) of the related assets. Replacement and major improvements are
capitalized; maintenance and repairs are expensed as incurred. Gains or
losses on asset dispositions are included in the determination of net income.
Jointly owned plants--The consolidated financial statements include the
Company's 53.9 percent (Big Stone Plant) and 35 percent (Coyote Station)
ownership interests in the assets, liabilities, revenue, and expenses of Big
Stone Plant and Coyote Station, respectively. Amounts at December 31, 2001
and 2000 included in electric plant in service for Big Stone were
$112,898,000 and $111,850,000, respectively, and the accumulated depreciation
was $71,585,000 and $68,269,000, respectively. Amounts at December 31, 2001
and 2000 included in electric plant in service for Coyote were $146,566,000
and $146,292,000, respectively, and the accumulated depreciation was
$74,057,000 and $70,524,000, respectively. The Company's share of direct
revenue and expenses of the jointly owned plants in service is included in
operating revenue and expenses in the Consolidated Statements of Income.
Recoverability of long-lived assets--The Company reviews its long-lived
assets whenever events or changes in circumstances indicate the carrying
amount of the assets may not be recoverable. The Company determines potential
impairment by comparing the carrying value of the assets with net cash flows
expected to be
provided by operating activities of the business or related assets. Should
the sum of the expected future net cash flows be less than the carrying
values, the Company would determine whether an impairment loss should be
recognized. An impairment loss would be quantified by comparing the amount
by which the carrying value exceeds the fair value of the asset where fair
value is based on the discounted cash flows expected to be generated by the
asset.
Income taxes--Comprehensive interperiod income tax allocation is used for
substantially all book and tax temporary differences. Deferred income taxes
arise for all temporary differences between the book and tax basis of
assets and liabilities. Deferred taxes are recorded using the tax rates
scheduled by tax law to be in effect when the temporary differences
reverse. The Company amortizes the investment tax credit over the estimated
lives of the related property.
Revenue recognition--Due to the diverse business operations of the Company
revenue recognition depends on the product produced and sold. However, in
general, the Company recognizes revenue when the earnings process is
complete, evidenced by an agreement with the customer, there has been
delivery and acceptance, and the price is fixed or determinable. In cases
where significant obligations remain after delivery, revenue is deferred
until such obligations are fulfilled. Provisions for sale returns and
warranty costs are recorded at the time of the sale based on historical
information and current trends.
Electric customers' meters are read and bills are rendered on a cycle
basis. Revenue is accrued for electricity consumed but not yet billed. Rate
schedules applicable to substantially all customers include a cost of
energy adjustment clause, under which the rates are adjusted to reflect
changes in average cost of fuels and purchased power, and a surcharge for
recovery of conservation-related expenses.
Revenues on almost all of wholesale sales are recognized when energy is
delivered. The majority of revenue is the result of bilateral agreements
with individual counter-parties.
Plastics operating revenues are recorded when the product is shipped.
Health services operating revenues on major equipment and installation
contracts are recorded when the equipment is delivered. Amounts received in
advance under customer service contracts are deferred and recognized on a
straight-line basis over the contract period. Revenues generated in the
mobile imaging operations are recorded on a fee for scan basis.
Manufacturing operating revenues are recorded when products are shipped and
on a percentage-of-completion basis for construction type contracts.
Other business operations operating revenues are recorded when services are
rendered or products are shipped. In the case of construction contracts,
the percentage-of-completion method is used.
Pre-production costs--As part of the manufacturing process, the Company
incurs costs related to the design and development of molds, dies, and
tools. As of January 1, 2000 the Company adopted prospectively Emerging
Issues Task Force Statement (EITF) 99-5, Accounting for Pre-production
Costs Related to Long-Term Supply Arrangements. The Company capitalizes the
costs related to the design and development of molds, dies, and tools used
to produce products under a long-term supply arrangement, some of which are
owned by the Company. During 2001 and 2000 the amount of costs capitalized
were $1,216,000 and $1,254,000. These costs are amortized over three years.
Stock-based compensation--As described in note 4, the Company has elected
to follow the accounting provisions of Accounting Principle Board Opinion
No. 25 (APB 25), Accounting for Stock Issued to Employees, for stock-based
compensation and to furnish the pro forma disclosures required under SFAS
No. 123, Accounting for Stock-Based Compensation.
Use of estimates--The Company uses estimates based on the best information
available in recording transactions and balances resulting from business
operations. Estimates are used for such items as depreciable lives, tax
provisions, collectability of trade accounts receivable, self insurance
programs, environmental liabilities, unbilled revenues, unscheduled power
exchanges, service contract maintenance costs and actuarially determined
benefit costs. As better information becomes available (or actual amounts
are determinable) the recorded estimates are revised. Consequently,
operating results can be affected by revisions to prior accounting
estimates.
Reclassifications--Certain prior year amounts have been reclassified to
conform to 2001 presentation. Such reclassifications had no impact on net
income, shareholders' equity, or cash flows provided from operations. In
addition, during 2001 the Company completed two acquisitions using the
pooling-of-interests accounting method. Consolidated financial statements
for 1999 and 2000 have been restated to reflect these acquisitions.
Cash equivalents--The Company considers all highly liquid debt instruments
purchased with maturity of 90 days or less to be cash equivalents.
Debt reacquisition premiums--In accordance with regulatory treatment, the
Company defers utility debt redemption premiums and amortizes such costs
over the original life of the reacquired bonds.
Investments--At December 31, 2001 and 2000, the Company had investments of
$6,108,000 and $6,759,000, respectively, in limited partnerships that
invest in tax-credit qualifying affordable housing projects. These
investments provided the Company with tax credits of $1,418,000 and
$1,414,000 in 2001 and 2000, respectively. The balance of investments at
December 31, 2001, consists of $6,058,000 in additional investments
accounted for under the equity method and $5,843,000 in other investments
accounted for under the cost method, with $1,186,000 related to
participation in economic development loan pools. The balance of
investments at December 31, 2000, consists of $5,024,000 in additional
investments accounted for under the equity method and $6,180,000 in other
investments accounted for under the cost method, with $1,263,000 related to
participation in economic development loan pools. (See further discussion
under note 10.)
Inventories--The electric operation inventories are reported at average
cost. The plastics, health services, manufacturing, and other business
operation inventories are stated at the lower of cost (first-in, first-out)
or market.
Short-term debt--There was no short-term debt outstanding as of December
31, 2001 and 2000. The average interest rate paid on short-term debt during
2001 and 2000 was 5.2 percent and 8.1 percent, respectively.
Intangible assets--The majority of the Company's intangible assets consist
of goodwill associated with the acquisition of subsidiaries. Intangible
assets are amortized on a straight-line basis over periods of 40 years for
the telecommunication operations and 15 years or less for all other
goodwill and intangibles.
The Company periodically evaluates the recovery of intangible assets based
on an analysis of undiscounted future cash flows. As a result of changing
market conditions during 2000, the Company completed an evaluation of the
recoverability of the assets of a subsidiary acquired by Otter Tail Energy
Services in 1998. As a result of the evaluation it was determined that
$800,000 of goodwill was impaired and was charged to amortization expense
during 2000. As a result of the writedown, the remaining goodwill related
to the acquisition is $1.0 million as of December 31, 2001.
Total intangibles as of December 31 are as follows:
2001 2000
------ -----
(in thousands)
Goodwill on telecommunications operations $ 7,749 $ 7,749
Other intangible assets, primarily goodwill 56,761 47,288
------ -------
Total 64,510 55,037
Less accumulated amortization 14,705 11,505
------ -------
Intangibles-net $49,805 $43,532
======= =======
Adoption of new accounting pronouncements--The Company adopted Statement
of Financial Accounting Standards (SFAS) 133, Accounting for Derivative
Instruments and Hedging Activities, as amended, on January 1, 2001, which
requires all derivative instruments be reported on the consolidated balance
sheet at fair value. The adoption of SFAS No. 133 did not have a material
effect on the Company's consolidated financial statements. The application
of SFAS 133 to electric utilities continued to evolve throughout 2001. On
December 19, 2001, the Financial Accounting Standards Board revised SFAS
133 Implementation Issue No. C15 to be effective April 1, 2002 with early
adoption allowed. As of December 31, 2001, the Company early adopted the
revised SFAS 133 Implementation Issue No. C15. The Company has determined
that certain electric energy contracts meet the criteria of a derivative
under SFAS 133 but qualify for the normal purchase and normal sales
exception and are not subject to mark-to-market accounting treatment. SFAS
133 did not have a material effect on the Company's 2001 consolidated
financial statements.
In July 2001 the FASB issued SFAS 141, Business Combinations, which
requires the purchase method of accounting be used for all business
combinations initiated after June 30, 2001. SFAS 141 also specifies that
intangible assets acquired in a business combination, that meet certain
criteria, be recognized and reported apart from goodwill. The Company has
adopted this statement as of July 1, 2001 and applied it to the
acquisitions that occurred after July 1, 2001: Interim Solutions and Sales,
Inc., Midwest Medical Diagnostics, Inc., Nuclear Imaging, Ltd., and Titan
Steel Corporation. Adoption of this statement did not have a material
effect on the Company's consolidated financial statements.
In July 2001 the FASB issued SFAS 142, Goodwill and Other Intangible
Assets, which requires goodwill and intangible assets with indefinite
useful lives no longer be amortized. Rather they will be tested for
impairment, at least annually, in accordance with the provisions of SFAS
142. Intangible assets with finite useful lives will be amortized over
their respective estimated useful lives and will be reviewed for impairment
in accordance with SFAS No. 144, Accounting for the Impairment or Disposal
of Long-Lived Assets. SFAS 142 is effective January 1, 2002, except for any
goodwill arising in a purchase business combination completed on or after
July 1, 2001 which would be subject immediately to the provisions of SFAS
142. As of December 31, 2001, the Company had net goodwill of $48.2
million. Included on the Company's consolidated statement of income for the
year ended December 31, 2001 is $3.2 million in goodwill amortization
expense. SFAS 142 requires the Company perform an assessment of goodwill
impairment as of the date of adoption. Any impairment loss resulting from
this transition to SFAS 142 would be recognized as a cumulative effect of a
change in accounting principle in the Company's consolidated income
statement at the time of adoption. The Company is continuing to evaluate
the statement for its impact on the Company's consolidated financial
statements. Based on the work completed to date, the Company does not
expect the implementation of this statement to have a material impact on
its consolidated results of operations and financial position.
In July 2001 the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations, which provides accounting requirements for retirement
obligations associated with tangible long-lived assets. This statement is
effective for fiscal years beginning after June 15, 2002. The Company is
assessing this statement but has not yet determined the impact of SFAS 143
on its consolidated financial position or results of operations.
The FASB issued SFAS 144, Accounting for the Impairment or Disposal of
Long-Lived Assets in October 2001. SFAS 144 replaces SFAS 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of. This statement develops one accounting model for long-lived
assets to be disposed of by sale and also broadens the reporting of
discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity in a
disposal transaction. The statement is effective for fiscal years beginning
after December 15, 2001. The Company adopted the accounting model for
impairment or disposal of long-lived assets starting January 1, 2002.
Adoption of this statement did not have a material effect on the Company's
consolidated financial statements.
2. Business combinations, dispositions and segment information
On February 28, 2001 the Company acquired all of the outstanding common stock
of T.O. Plastics, Inc. in exchange for 451,066 newly issued shares of the
Company's common stock. T.O. Plastics, Inc. custom manufactures returnable
pallets, material and handling trays and horticultural containers. It has
three facilities in Minnesota and one facility in South Carolina. On
September 28, 2001 the Company acquired all of the outstanding common stock
of St. George Steel Fabrication, Inc. in exchange for 270,370 newly issued
shares of the Company's common stock. St. George Steel is a fabricator of
steel products engaged in custom and proprietary operations located in Utah.
These acquisitions were accounted for as a pooling-of-interests. Since the
St. George Steel acquisition was initiated prior to June 30, 2001,
pooling-of-interest accounting was allowed under the transition provision of
Statement of Financial Accounting Standards No. 141. The Company's
consolidated financial statements for 2000 and 1999 have been restated to
reflect the effects of the poolings. The results of operations of the
separate companies and the combined amounts included in the consolidated
financial statement are presented in the table below.
Otter Tail Pooled
Corporation Entities Combined
------------------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
FOR THE YEAR ENDED DECEMBER 31, 1999:
Changes in common equity:
Common shares, par value $ 119,250 $ 3,607 $ 122,857
Premium on common shares -- -- --
Unearned compensation (301) -- (301)
Retained earnings 126,744 (534) 126,210
Accumulated other comprehensive income -- -- --
--------- --------- ---------
Total common equity $ 245,693 $ 3,073 $ 248,766
========= ========= =========
Operating revenues $ 464,577 $ 24,667 $ 489,244
Net Income 44,977 318 45,295
Earnings available for common shares 42,749 318 43,067
Average common shares outstanding-diluted 23,853 722 24,575
Diluted earnings per share $ 1.79 $1.75
FOR THE YEAR ENDED DECEMBER 31, 2000:
Changes in common equity:
Common shares, par value $ 119,264 $ 3,607 $ 122,871
Premium on common shares 50 -- 50
Unearned compensation (226) -- (226)
Retained earnings 140,511 285 140,796
Accumulated other comprehensive income (220) -- (220)
--------- --------- ---------
Total common equity $ 259,379 $ 3,892 $ 263,271
========= ========= =========
Operating revenues $ 559,445 $ 27,486 $ 586,931
Net Income 40,224 818 41,042
Earnings available for common shares 38,346 817 39,163
Average common shares outstanding-diluted 23,928 721 24,649
Diluted earnings per share $ 1.61 $ 1.59
FOR THE THREE MONTHS ENDED MARCH 31, 2001 (1):
Operating revenues $ 155,509 $ 4,145 $ 159,654
Net Income 11,471 529 12,000
Earnings available for common shares 11,002 528 11,530
Average common shares outstanding-diluted 24,506 270 24,776
Diluted earnings per share $ 0.45 $ 0.47
FOR THE THREE MONTHS ENDED JUNE 30, 2001 (1):
Operating revenues $ 152,896 $ 4,436 $ 157,332
Net Income 8,775 382 9,157
Earnings available for common shares 8,305 383 8,688
Average common shares outstanding-diluted 24,529 270 24,799
Diluted earnings per share` $ 0.34 $ 0.35
FOR THE SIX MONTHS ENDED JUNE 30, 2001 (1):
Operating revenues $ 308,405 $ 8,581 $ 316,986
Net Income 20,246 911 21,157
Earnings available for common shares 19,307 911 20,218
Average common shares outstanding-diluted 24,515 270 24,785
Diluted earnings per share` $ 0.79 $ 0.82
(1) St. George Steel Fabrication, Inc. only.
On September 4, 2001 the Company acquired the assets and operations of
Interim Solutions and Sales, Inc. and Midwest Medical Diagnostics, Inc. of
Minneapolis, Minnesota. These companies operate as a division of DMS
Imaging, Inc. and provide mobile diagnostic imaging services on an interim
basis for computed tomography and magnetic resonance imaging, fee-per-exam
options and sales of previously owned imaging equipment. Revenues for 2000
were approximately $3.1 million. The acquisition was accounted for using
the purchase method and the excess of the purchase price over the net
assets acquired was $2.2 million.
On September 10, 2001 the Company acquired the assets and operations of
Nuclear Imaging, Ltd., of Sioux Falls, South Dakota. Nuclear Imaging
provides mobile nuclear medicine, positron emission tomography and bone
densitometry services to more than 120 healthcare facilities in the
Midwest. Nuclear Imaging is a subsidiary of DMS Imaging, Inc. Revenues for
2000 were approximately $6.9 million. The acquisition was accounted for
using the purchase method and the excess of the purchase price over the net
assets acquired was $4.8 million
On November 1, 2001 the Company acquired the assets and operations of Titan
Steel Corporation of Salt Lake City, Utah. Titan is a fabricator of steel
products engaged in custom operations. Titan is an operating division of
St. George Steel Fabrication, Inc. Revenues for 2000 were approximately $9
million. The acquisition was accounted for using the purchase method and
the excess of the purchase price over the net assets acquired was
immaterial.
The acquisitions of Interim Solutions and Sales, Inc., Midwest Medical
Diagnostics, Inc., Nuclear Imaging, Ltd and Titan Steel Corporation were
accounted for using the purchase method of accounting under SFAS 141. Under
the transition provision of SFAS 142 no goodwill was amortized for these
acquisitions during 2001. The pro forma effect of these acquisitions on
2000 and 1999 revenues, net income, or earnings per share was not
significant.
On January 1, 2000 the Company acquired the assets and operations of
Vinyltech Corporation (Vinyltech) located in Phoenix, Arizona. Vinyltech is
a manufacturer of polyvinyl chloride (PVC) pipe and produces approximately
90 million pounds of pipe annually. Annual revenues for 1999 were
approximately $41 million.
On June 1, 2000 the Company acquired the assets and operations of Portable
X-Ray & EKG, Inc. (PXE) located in Minneapolis, Minnesota. PXE is a
provider of mobile x-ray, EKG, ultrasound and echocardiogram services
primarily to patients in long-term care facilities in the Minneapolis/St.
Paul market. Its 1999 annual revenues were approximately $2.8 million.
These acquisitions were accounted for using the purchase method of
accounting. The excess of the purchase price over the net assets acquired
of approximately $24 million is being amortized over 15 years. The pro
forma effect of these acquisitions on 1999 revenues, net income, or
earnings per share was not significant.
On September 1, 1999 the Company acquired the flatbed trucking operations
of E. W. Wylie Corporation (Wylie). The acquisition was accounted for using
the purchase method of accounting. The excess of the purchase price over
net assets acquired of approximately $8 million is being amortized over 15
years. Wylie is located in Fargo, North Dakota, and operates in 48 states
and 6 Canadian provinces. The pro forma effect of the Wylie acquisition on
1999 revenues, net income, or earnings per share was not significant.
On October 1, 1999 the Company completed the sale of certain assets of the
radio stations and video production company owned by KFGO, Inc. and the
radio stations
owned by Western Minnesota Broadcasting Company for $24.1 million. The gain
after income tax was $8.1 million or $0.34 cents per share.
Segment information--The accounting policies of the segments are described
under note 1 - Summary of significant accounting policies. The Company's
business operations consist of five segments based on products and
services. Electric includes the electric utility only and is based in
Minnesota, North Dakota, and South Dakota. Plastics consists of businesses
involved in the production of PVC pipe in the Upper Midwest and Southwest
regions of the United States. Health services include businesses involved
in the sale of diagnostic medical equipment, supplies and accessories. In
addition these businesses also provide service maintenance, mobile
diagnostic imaging, mobile PET and nuclear medicine imaging, portable x-ray
imaging and rental of diagnostic medical imaging equipment to various
medical institutions located in 32 states. Manufacturing operations consist
of businesses involved in the production of wind towers,
frame-straightening equipment and accessories for the auto body shop
industry, custom plastic pallets, material and handling trays, and
horticultural containers, fabrication of steel products, contract
machining, and metal parts stamping and fabrication located in the Upper
Midwest and Utah. Other business operations consist of businesses operating
in electrical and telephone construction contracting, transportation,
telecommunications, entertainment, and energy services and natural gas
marketing as well as the portion of corporate administrative and general
expenses that are not allocated to other segments. The electrical and
telephone construction contracting companies and energy services and
natural gas marketing business operate primarily in the Upper Midwest. The
telecommunications companies operate in central and northeast Minnesota and
the transportation company operates in 48 states and 6 Canadian provinces.
The Company evaluates the performance of its business segments and
allocates resources to them based on earnings contribution and return on
total invested capital. Information for the business segments for 2001,
2000 and 1999 is presented in the following table.
2001 2000 1999
------ ------ ------
(in thousands)
Operating revenue
Electric $307,684 $262,280 $233,527
Plastics 63,216 82,667 31,504
Manufacturing 123,436 97,506 87,086
Health services 79,129 66,319 68,805
Other business operations 80,667 78,159 68,322
-------- -------- --------
Total $654,132 $586,931 $489,244
======== ======== ========
Operating income
Electric $ 57,150 $ 49,268 $ 47,234
Plastics (1,391) 8,745 3,382
Manufacturing 12,175 6,945 5,297
Health services 6,862 5,729 4,936
Other business operations 2,688 3,561 7,364
------ -------- --------
Total $ 77,484 $ 74,248 $ 68,213
======== ======== ========
Depreciation and amortization
Electric $ 24,272 $ 23,778 $ 23,366
Plastics 3,229 3,301 1,168
Manufacturing 5,139 3,930 3,627
Health services 3,517 2,981 4,244
Other business operations 5,943 6,572 4,454
-------- -------- --------
Total $ 42,100 $ 40,562 $ 36,859
======== ======== ========
Capital expenditures
Electric $ 34,992 $ 24,659 $ 21,095
Plastics 1,572 3,361 4,491
Manufacturing 10,516 8,688 4,019
Health services 3,282 2,871 993
Other business operations 3,234 6,694 4,647
-------- -------- --------
Total $ 53,596 $ 46,273 $ 35,245
======== ======== ========
Identifiable assets
Electric $523,948 $531,778 $524,012
Plastics 45,649 49,831 16,477
Manufacturing 67,033 59,130 43,908
Health services 50,560 32,909 29,542
Other business operations 95,351 64,060 80,402
-------- -------- --------
Total $782,541 $737,708 $694,341
======== ======== ========
No single external customer accounts for 10 percent or more of the Company's
revenues. Substantially all sales and long-lived assets of the Company are
within the United States.
3. Rate matters and arbitration settlement.
In 2001 the Minnesota Legislature exempted certain generation machinery and
attached equipment from the new state personal property tax levy. The law
also required that any windfall tax savings resulting from this exemption be
refunded to electric utility customers. As a result of this law, $238,000 in
2001 property tax savings will be refunded to retail electric customers in
2002.
On December 29, 2000, the NDPSC approved a performance-based ratemaking plan
that links allowed earnings in North Dakota to seven defined performance
standards in the areas of price, electric service reliability, customer
satisfaction, and employee safety. The plan is in place for 2001 through
2005, unless suspended or terminated by the NDPSC or the Company. In 2001,
the electric utility recorded an estimated $334,000 refund to North Dakota
customers based on 2001 earnings and the performance relative to the defined
standards of the performance-based ratemaking plan.
During the second quarter of 2000, the Minnesota, South Dakota and North
Dakota utility regulatory agencies approved the accounting treatment of
settlement proceeds related to the Knife River coal contract arbitration. The
settlement proceeds of $3.2 million (including interest) had been recorded as
a liability on the balance sheet since 1999 pending regulatory approval. The
approval allowed the Company to recover arbitration costs of $1.0 million
that had been previously expensed and to recognize as income $308,000 of fuel
cost savings applicable to wholesale power pool sales. The remaining $1.9
million represents a reduction of fuel costs that were returned to the
Company's electric retail customers through the cost of energy adjustment
clause during 2000.
On October 6, 1999, the NDPSC approved a settlement agreement following an
audit of the Company's electric operations in North Dakota. The effect of
this settlement decreased 1999 earnings by approximately $441,000 after taxes
or $0.02 per share. As part of the settlement agreement, the Company was
required to refund to North Dakota customers during 2000 any 1999 regulated
electric operations earnings from North Dakota over a 12.5 percent return on
equity. The amount of the refund was insignificant.
4. Common shares
New issuances--Common stock issuances during 2001 included 721,436
unregistered shares to effect the pooling acquisitions, 74,480 shares issued
as a result of stock options exercised, 3,041 shares issued as director
compensations and 1,681 shares of restricted stock.
Stock split--On March 15, 2000 the Company effected a two-for-one Common
Stock split in the form of a 100 percent stock dividend by issuance of one
additional $5.00 par value Common Share for each $5.00 par value Common Share
outstanding on February 15, 2000. All common share and per share amounts have
been adjusted for 2000 and 1999 to reflect the stock split.
Stock incentive plan--Under the 1999 Stock Incentive Plan (Incentive Plan) a
total of 2,600,000 common shares were authorized for granting of stock
awards. The Incentive Plan provides for the grant of options, performance
awards,
restricted stock, stock appreciation rights and other types of stock grants
or stock-based awards. The exercise price of the stock options is equal to
the fair market value per share at the date of the grant. Options granted
to outside directors are exercisable immediately, and all other options
granted as of December 31, 2001 vest ratably over a four-year period. The
options expire ten years after the date of the grant.
The Company accounts for the Incentive Plan under APB 25. Unearned
compensation relating to the options granted in 1999 was $151,000 at
December 31, 2001, and is included as a reduction of common equity. Had
compensation costs for the stock options issued under the Incentive Plan
been determined based on estimated fair value at the award dates, as
prescribed by SFAS 123, the Company's net income for 1999 through 2001
would have decreased as presented in the table below. This may not be
representative of the pro forma effects for future years if additional
options are granted. Using the Black-Scholes option-pricing model, the
Company's pro forma net income with related assumptions are as follows:
2001 2000 1999
----------------------------------------------------------------------------------------------------------
Net income
As reported $43,603 $41,042 $45,295
Pro forma $42,770 $40,697 $45,132
Diluted earnings per share
As reported $1.68 $1.59 $1.75
Pro forma $1.64 $1.58 $1.75
Risk free interest rate 5.5% 5.2% 5.2%
Expected lives 7 years 7 years 7 years
Expected volatility 24.9% 23.7% 19.3%
Dividend yield 4.0% 4.5% 5.0%
Presented below is a summary of the stock options activity for 2001, 2000,
and 1999.
Stock Option Activity 2001 2000 1999
--------------------------------------------------------------------------------------------------------------------
Average Average Average
exercise exercise exercise
Options price Options price Options price
------- ---- ------- ----- ------- ----
Outstanding,
beginning of year 787,316 $19.55 442,900 $19.25 -- $ --
Granted 582,000 26.33 360,000 19.75 450,700 19.25
Exercised 74,936 19.44 750 19.19 -- --
Forfeited 29,338 22.17 14,834 19.30 7,800 19.19
--------- ------- -------
Outstanding, year end 1,265,042 22.39 787,316 19.55 442,900 19.25
========= ======= =======
Exercisable, year end 257,269 $19.83 127,542 $19.25 -- $ --
Fair value of options
granted during year $ 5.88 $ 3.79 $ 2.79
The following table summarizes information about options outstanding as of
December 31, 2001:
Options outstanding Options exercisable
------------------------------------------------------------------------------
Weighted-
average weighted- Weighted-
Outstanding remaining average Exercisable average
Range of as of contractual exercise as of exercise
exercise prices 12/31/01 life price 12/31/01 price
---------------------------------------------------------------------------------------------------------
$17.84-$20.82 687,542 7.6 $19.46 238,769 $19.38
$20.83-$23.79 7,500 7.6 $21.75 2,500 $21.75
$23.80-$26.77 554,000 9.3 $26.25 16,000 $26.25
$26.78-$29.74 16,000 9.9 $29.34 -- --
In addition to the stock options granted, 1,681, 12,415 and 2,298 shares of
restricted stock were granted during 2001, 2000 and 1999, respectively.
Employee stock purchase plan--The 1999 Employee Stock Purchase Plan
(Purchase Plan) allows eligible employees to purchase the Company's common
shares at 85
percent of the lower market price at either the beginning or the end of each
six-month purchase period. A total of 400,000 common shares are available for
purchase by employees under the Purchase Plan. During 2001 56,612 common
shares and in 2000, 53,630 common shares were purchased from the open market.
Dividend reinvestment and share purchase plan--On August 30, 1996, the
Company filed a shelf registration statement with the Securities and Exchange
Commission for the issuance of up to 2,000,000 common shares pursuant to the
Company's Automatic Dividend Reinvestment and Share Purchase Plan (the Plan),
which permits shares purchased by shareholders or customers who participate
in the Plan to be either new issue common shares or common shares purchased
on the open market. Since June 1999, common shares needed for this Plan have
been purchased from the open market instead of issuing new shares. Prior to
this the Company had been issuing newly issued common shares: 89,238 shares
were issued in 1999.
Shareholder rights plan--On January 27, 1997, the Company's Board of
Directors declared a dividend of one preferred share purchase right (Right)
for each outstanding common share held of record as of February 10, 1997. One
Right was also issued with respect to each common share issued after February
10, 1997. Each Right entitles the holder to purchase from the Company one
one-hundredth of a share of newly created Series A Junior Participating
Preferred Stock at a price of $70, subject to certain adjustment. The Rights
are exercisable when, and are not transferable apart from the Company's
common shares until, a person or group has acquired 15 percent or more, or
commenced a tender or exchange offer for 15 percent or more, of the Company's
common shares. If the specified percentage of the Company's common shares is
acquired, each Right will entitle the holder (other than the acquiring person
or group) to receive, on exercise, common shares of either the Company or the
acquiring company having value equal to two times the exercise price of the
Right. The Rights are redeemable by the Company's Board of Directors in
certain circumstances and expire on January 27, 2007.
5. Retained earnings restriction
The Company's Indenture of Mortgage and Articles of Incorporation, as
amended, contain provisions that limit the amount of dividends that may be
paid to common shareholders. Under the most restrictive of these provisions,
retained earnings at December 31, 2001 were restricted by $9,238,000.
6. Commitments and contingencies
At December 31, 2001, the electric utility had commitments under contracts in
connection with construction programs aggregating approximately $16,234,000.
For capacity and energy requirements the electric utility has agreements
extending through 2006, at annual costs of approximately $14,168,000 in 2002,
$12,241,000 in 2003, $12,261,000 in 2004, $10,762,000 in 2005, and
$10,028,000 in 2006.
The electric utility has contracts providing for the purchase and delivery of
a significant portion of its current coal requirements. These contracts
expire between 2002 and 2016. In total, the electric utility is committed to
the minimum purchase of approximately $105,927,000 or to make payments in
lieu thereof, under these contracts. The cost of energy adjustment process in
the rate-making provision lessens the risk of loss from market price changes
because it provides for recovery of most fuel costs.
The amounts of future operating lease payments are as follows:
Electric Diversified
utility companies Total
-------- ---------- ---------
(in thousands)
2002 $ 1,445 $14,978 $16,423
2003 1,440 11,091 12,531
2004 1,151 7,958 9,109
2005 944 6,213 7,157
2006 944 1,542 2,486
Later years 4,537 584 5,121
------- ------- -------
Total $10,461 $42,366 $52,827
======= ======= =======
Rent expense was $20,242,000, $16,595,000, and $14,233,000, for 2001, 2000,
and 1999, respectively.
The Company is occasionally a party to litigation arising in the normal
course of business. The Company regularly analyzes current information and,
as necessary, provides accruals for probable liabilities on the eventual
disposition of these matters. The Company believes the effect on its
consolidated results of operations and financial position, if any, for the
disposition of all currently pending matters will not be material.
7. Long-term obligations
Long-term debt--All utility property, with certain minor exceptions, is
subject to the lien of the Indenture of Mortgage of the Company securing its
First Mortgage Bonds. The Company is required by the Indenture to make annual
payments (exclusive of redemption premiums) for sinking fund purposes, except
that the requirement with respect to certain series may be satisfied by the
delivery of bonds of such series of equal principal amount. The Company
issued First Mortgage Bonds of its pollution control series to secure payment
of a like principal amount of revenue bonds that were issued by local
governmental units to finance facilities leased or purchased and that the
Company has capitalized. As a requirement of the issuance of the 6.63% Senior
Notes, each of the subsidiaries of the Company has completed a guaranty
agreement. Varistar's term notes and credit line borrowings are secured by a
pledge of all of the common stock of the companies owned by Varistar. The
aggregate amounts of maturities and sinking fund requirements on bonds
outstanding and other long-term obligations at December 31, 2001, for each of
the next five years are $28,946,000 for 2002, $7,378,000 for 2003, $6,851,000
for 2004, $6,122,000 for 2005, and $4,222,000 for 2006.
8. Pension plan and other postretirement benefits
Pension plan--The Company's noncontributory funded pension plan covers
substantially all electric utility and corporate employees. The plan provides
100 percent vesting after 5 vesting years of service and for retirement
compensation at age 65, with reduced compensation in cases of retirement
prior to age 62. The Company reserves the right to discontinue the plan, but
no change or discontinuance may affect the pensions theretofore vested. The
Company's policy is to fund pension costs accrued. All past service costs
have been provided for.
The pension plan has a trustee who is responsible for pension payments to
retirees. Five investment managers are responsible for managing the plan's
assets. In addition, an independent actuary performs the necessary actuarial
valuations for the plan.
Net periodic pension cost/(income) for 2001, 2000, and 1999 includes the
following components:
2001 2000 1999
------ ------ -------
(in thousands)
Service cost--benefit earned during the period $ 2,544 $ 2,458 $ 3,080
Interest cost on projected benefit obligation 8,766 8,439 8,150
Expected return on assets (14,610) (13,662) (12,159)
Amortization of transition asset (235) (235) (235)
Amortization of prior-service cost 1,107 1,107 1,287
Amortization of net gain (1,900) (1,869) (149)
------- ------- -------
Net periodic pension cost/(income) $(4,328) $(3,762) $ (26)
======= ======= =======
The plan assets consist of common stock and bonds of public companies, U.S.
Government Securities, cash, and cash equivalents.
The following tables provide a reconciliation of the changes in the plan's
benefit obligations and fair value of assets over the two-year period
ending December 31, 2001, and a statement of the funded status as of
December 31 of both years:
2001 2000
------ ------
(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1 $116,444 $114,445
Service cost 2,544 2,458
Interest cost 8,766 8,439
Actuarial loss (gain) 4,332 (1,502)
Benefit payments (7,563) (7,396)
--------- ---------
Obligation at December 31 $124,523 $116,444
========= =========
Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1 $153,649 $159,555
Actual return on plan assets (7,292) 1,490
Benefit payments (7,563) (7,396)
--------- ----------
Fair value of plan assets at December 31 $138,794 $153,649
========= =========
Funded status:
Over funded status at December 31 $ 14,271 $ 37,205
Unrecognized transition asset (73) (309)
Unrecognized prior-service cost 6,710 7,816
Unrecognized net actuarial gain (13,831) (41,964)
--------- --------
Net prepaid benefit cost recognized $ 7,077 $ 2,748
========= =========
The following table provides the amounts recognized in the Consolidated
Balance Sheets as of December 31:
2001 2000
------ ------
(in thousands)
Prepaid benefit cost $ 7,077 $ 2,748
The assumptions used for actuarial valuations were:
2001 2000
------ ------
Discount rate 7.75% 7.75%
Rate of increase in future compensation level 4.25% 4.25%
Long-term rate of return on assets 9.50% 9.50%
Executive survivor and supplemental retirement plan--The Company has an
unfunded, nonqualified benefit plan for executive officers and certain key
management employees. This plan provides defined benefit payments to these
employees on their retirements for life or to their beneficiaries on their
death for a 15-year postretirement period. Life insurance carried on the
plan participants is payable to the Company on the employee's death. There
are no plan assets in this nonqualified benefit plan due to the nature of
the plan.
Net periodic pension cost for 2001, 2000, and 1999 includes the following
components:
2001 2000 1999
------ ------ ------
(in thousands)
Service cost--benefit earned during the period $ (76) $ (136) $ (99)
Interest cost on projected benefit obligation 956 798 569
Amortization of transition obligation - 17 17
Amortization of prior service cost 191 191 106
Recognized net actuarial loss 117 1 47
------- ------- ------
Net periodic pension cost $ 1,188 $ 871 $ 640
Early retirement and curtailment -- 711 --
------- ------- -------
Total $ 1,188 $ 1,582 $ 640
======= ======= =======
The following tables provide a reconciliation of the changes in the plan's
benefit obligations over the two-year period ending December 31, 2001 and a
statement of the funded status as of December 31:
2001 2000
-------- --------
(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1 $ 12,713 $ 10,412
Service cost (76) (136)
Interest cost 956 798
Plan amendments (939) (359)
Actuarial loss 2,451 1,732
Early retirement -- 711
Benefit payments (740) (445)
--------- ----------
Obligation at December 31 $ 14,365 $ 12,713
========= ==========
Funded status:
Funded status at December 31 $(14,365) $ (12,713)
Unrecognized transition obligation -- --
Unrecognized prior-service cost 1,104 2,234
Unrecognized net actuarial loss 5,124 2,789
--------- ----------
Net amount recognized $ (8,137) $ (7,690)
========= ==========
The following table provides the amounts recognized in the Consolidated
Balance Sheet as of December 31:
2001 2000
-------- --------
(in thousands)
Accrued benefit liability $ (11,216) $ (10,144)
Intangible asset 1,104 2,234
Accumulated other comprehensive expense 1,975 220
---------- ----------
Net amount recognized $ (8,137) $ (7,690)
========== ==========
The assumptions used for actuarial valuations were:
2001 2000
-------- --------
Discount rate 7.75% 7.75%
Rate of increase in future compensation level 4.50% 4.50%
Postretirement benefits--The Company provides a portion of health insurance
and life insurance benefits for retired electric utility and corporate
employees. Substantially all of the Company's electric utility and
corporate employees may become eligible for health insurance benefits if
they reach age 55 and have 10 years of service. On adoption of SFAS 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, in
January 1993, the Company elected to recognize its transition obligation
related to postretirement benefits earned of approximately $14,964,000 over
a period of 20 years. There are no plan assets.
The net periodic postretirement benefit cost for 2001, 2000, and 1999
includes the following components:
2001 2000 1999
------ ------ ------
(in thousands)
Service cost - benefit earned during the period $ 681 $ 688 $ 753
Interest cost on accumulated postretirement
benefit obligation 1,768 1,701 1,432
Amortization of transition obligation 748 748 748
Amortization of prior service cost 111 111 111
Life insurance benefits -- 865 --
Amortization of net gain (51) -- --
------- ------ ------
Net periodic postretirement benefit cost $3,257 $4,113 $3,044
The following tables provide a reconciliation of the changes in the plan's
benefit obligations over the two-year period ending December 31, 2001 and a
statement of the funded status as of December 31:
2001 2000
------- -------
(in thousands)
Reconciliation of benefit obligation:
Obligation at January 1 $ 24,606 $ 20,251
Service cost 681 688
Interest cost 1,768 1,701
Actuarial loss 3,077 2,396
Benefit payments (2,264) (1,937)
Life insurance benefits -- 865
Participant premium payments 682 642
--------- ---------
Obligation at December 31 $ 28,550 $ 24,606
========= =========
Funded status:
Funded status at December 31 $(28,550) $(24,606)
Unrecognized transition obligation 8,230 8,978
Unrecognized prior service cost 375 486
Unrecognized loss (gain) 1,304 (1,825)
--------- ---------
Net amount recognized $(18,641) $(16,967)
========== =========
The amounts recognized in the Consolidated Balance Sheets as of December 31:
2001 2000
------- -------
(in thousands)
Accrued benefit liability $(18,641) $ (16,967)
The assumed health-care cost-trend rate used in measuring the accumulated
postretirement benefit obligation as of December 31, 2001 was 10.0 percent
for 2002, decreasing linearly each successive year until it reaches 5.0
percent in 2007, after which it remains constant. The assumed discount rate
used in determining the accumulated postretirement benefit obligation as of
December 31, 2001 and 2000, was 7.75 for both years.
Assumed health-care cost-trend rates have a significant effect on the amounts
reported for health care plans. A one-percentage-point change in assumed
health-care cost-trend rates for 2001 would have the following effects:
1 percent 1 percent
increase decrease
-------- --------
(in thousands)
Effect on total of service and interest
cost components $ 402 $ (324)
Effect on the postretirement benefit obligation $3,615 $(3,011)
Leveraged employee stock ownership plan--The Company has a leveraged employee
stock ownership plan for the benefit of all its electric utility and
corporate employees. Contributions made by the Company were $1,100,000 for
2001, $1,130,000 for 2000, and $1,110,000 for 1999.
9. Compensating balances and short-term borrowings
The Company maintains formal bank lines of credit for its electric utility
operations separate from lines of credit maintained by the diversified
companies. The lines of credit make available to the Company bank loans for
short-term financing and provide backup financing for commercial paper notes.
At December 31, 2001, the Company maintained no compensating balances to
support formal bank lines of credit. The Company's bank lines of credit
totaled $42,000,000, none of which was used at December 31, 2001.
10.Fair value of financial instruments
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate
that value:
Cash and short-term investments--The carrying amount approximates fair value
because of the short-term maturity of those instruments.
Other investments--The carrying amount approximates fair value. A portion of
other investments is in financial instruments that have variable interest
rates that reflect fair value. The remainder of other investments is
accounted for by the equity method which, in the case of operating losses,
results in a reduction of the carrying amount.
Redeemable preferred stock--The fair value is estimated based on the current
rates available to the Company for the issuance of redeemable preferred
stock.
Long-term debt--The fair value of the Company's long-term debt is estimated
based on the current rates available to the Company for the issuance of
debt. About $17 million of the Company's long-term debt, which is subject to
variable interest rates, approximates fair value.
2001 2000
------------------ ------------------
(in thousands)
Carrying Fair Carrying Fair
amount value amount value
--------- --------- --------- ---------
Cash and short-term investments $ 11,378 $ 11,378 $ 1,259 $ 1,259
Other investments 18,009 18,009 17,966 17,966
Redeemable preferred stock -- -- (18,000) (18,000)
Long-term debt (227,360) (255,785) (195,128) (202,942)
11. Property, plant, and equipment
2001 2000
------- ------
(December 31, in thousands)
Electric plant:
Production $ 313,013 $ 310,956
Transmission 158,639 155,611
Distribution 258,774 251,753
General 80,044 77,037
--------- ---------
Electric plant 810,470 795,357
Less accumulated depreciation and amortization 376,241 358,301
--------- ---------
Electric plant net of accumulated depreciation 434,229 437,056
Construction work in progress 25,094 10,539
--------- ---------
Net electric plant $ 459,323 $ 447,595
--------- ---------
Diversified operations plant $ 145,712 $ 129,716
Less accumulated depreciation and amortization 65,622 58,118
--------- ---------
Diversified plant net of accumulated depreciation 80,090 71,598
--------- ---------
Construction work in progress 3,564 2,578
--------- ---------
Net diversified operations plant $ 83,654 $ 74,176
--------- ---------
Net plant $ 542,977 $ 521,771
========= =========
12. Income taxes
The total income tax expense differs from the amount computed by applying
the federal income tax rate (35 percent in 2001, 2000 and 1999) to net
income before total income tax expense for the following reasons:
2001 2000 1999
------ ------ ------
(in thousands)
Tax computed at federal statutory rate $22,290 $20,789 $24,424
Increases (decreases) in tax from:
State income taxes net of federal income tax
benefit 2,564 2,279 2,652
Investment tax credit amortization (1,176) (1,183) (1,185)
Differences reversing in excess of federal rates (503) (774) (384)
Dividend received/paid deduction (674) (670) (667)
Affordable housing tax credits (1,418) (1,414) (1,393)
Permanent and other differences (1,000) (672) 1,042
-------- --------- ----------
Total income tax expense $20,083 $18,355 $24,489
======== ========= ==========
Overall effective federal and state income tax rate 31.5% 30.9% 35.1%
Income tax expense includes the following:
Current federal income taxes $21,110 $21,835 $25,875
Current state income taxes 3,107 4,162 5,099
Deferred federal income taxes (2,247) (4,717) (3,431)
Deferred state income taxes 707 (328) (476)
Affordable housing tax credits (1,418) (1,414) (1,393)
Investment tax credit amortization (1,176) (1,183) (1,185)
-------- -------- -------
Total $20,083 $18,355 $24,489
======== ======== ========
The Company's deferred tax assets and liabilities were composed of the
following on December 31, 2001 and 2000:
2001 2000
------ ------
(in thousands)
Deferred tax assets
Amortization of tax credits $ 9,098 $ 9,849
Vacation accrual 1,892 1,623
Unearned revenue 1,850 1,715
Operating reserves 13,552 12,537
Differences related to property 4,394 3,067
Transfer to regulatory liability 577 539
Other 2,025 1,642
---------- ----------
Total deferred tax assets $ 33,388 $ 30,972
---------- ----------
Deferred tax liabilities
Differences related to property (104,764) (105,539)
Excess tax over book pension (2,812) (1,113)
Transfer to regulatory asset (5,053) (5,510)
Other (2,330) (1,523)
---------- ----------
Total deferred tax liabilities $(114,959) $(113,685)
---------- ----------
Deferred income taxes $ (81,571) $ (82,713)
========== ==========
13. Quarterly information (unaudited)
Because of changes in the number of common shares outstanding and the
impact of diluted shares, the sum of the quarterly earnings per common
share may not equal total earnings per common share.
Three Months Ended
March 31 June 30 September 30 December 31
----------------- ----------------- ----------------- -----------------
2001 2000 2001 2000 2001 2000 2001 2000
------ ------ ------ ------ ------ ------ ------ ------
(in thousands except per share data)
Operating revenues $159,654 $140,227 $157,332 $141,436 $177,674 $149,999 $159,472 $155,269
Operating income $ 22,438 $ 20,789 $ 15,720 $ 17,932 $ 20,310 $ 19,796 $ 19,016 $ 15,731
Net income $ 12,000 $ 11,004 $ 9,157 $ 9,303 $ 11,077 $ 10,915 $ 11,369 $ 9,820
Earnings available for
common shares $ 11,530 $ 10,534 $ 8,688 $ 8,833 $ 10,607 $ 10,446 $ 10,785 $ 9,350
Basic earnings per share $ .47 $ .43 $ .35 $ .36 $ .43 $ .43 $ .44 $ .38
Diluted earnings per share $ .47 $ .43 $ .35 $ .36 $ .43 $ .42 $ .43 $ .38
Dividends paid per common
share $ .26 $ .255 $ .26 $ .255 $ .26 $ .255 $ .26 $ .255
Price range:
High $ 31.00 $ 21.31 $ 30.10 $ 27.50 $ 30.00 $ 23.88 $ 29.45 $ 29.00
Low $ 23.00 $ 17.75 $ 24.12 $ 19.00 $ 26.75 $ 20.75 $ 27.50 $ 21.19
Average number of common
shares outstanding--basic 24,577 24,571 24,586 24,571 24,606 24,571 24,633 24,573
Average number of common
shares outstanding--diluted 24,776 24,575 24,799 24,642 24,881 24,645 24,912 24,725
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Stock Listing
Otter Tail Corporation common stock trades on The Nasdaq Stock Market.