.
.
.
Exhibit 13-A
SELECTED CONSOLIDATED FINANCIAL DATA
- ----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 (1) 1999 (1)(2) 1998 (3) 1997 1992
---- ---- -------- ----------- -------- ---- ----
(thousands, except number of shareholders and per-share data)
REVENUES
Electric $307,403 $307,684 $262,280 $233,527 227,477 $205,121 $177,105
Plastics 82,931 63,216 82,667 31,504 24,946 24,953 --
Manufacturing 142,390 123,436 97,506 87,086 62,488 58,221 --
Health services 93,420 79,129 66,319 68,805 69,412 66,859 --
Other business operations 83,972 80,667 78,159 68,322 48,829 44,173 32,433
-------- -------- -------- -------- ------- -------- --------
Total operating revenues $710,116 $654,132 $586,931 $489,244 433,152 $399,327 $209,538
SPECIAL CHARGES -- -- -- -- 9,522 -- --
INCOME FROM CONTINUING OPERATIONS 46,128 43,603 41,042 45,295 30,701 32,346 26,538
CUMULATIVE CHANGE IN ACCOUNTING PRINCIPLE -- -- -- -- 3,819 -- --
CASH FLOW FROM OPERATIONS 76,797 77,529 61,761 81,850 63,959 69,398 44,866
CAPITAL EXPENDITURES 75,533 53,596 46,273 35,245 29,289 41,973 22,616
TOTAL ASSETS 878,736 782,541 737,708 694,341 655,612 655,441 530,456
LONG-TERM DEBT 258,229 227,360 195,128 180,159 181,046 189,973 159,295
REDEEMABLE PREFERRED -- -- 18,000 18,000 18,000 18,000 18,000
BASIC EARNINGS PER SHARE FROM CONTINUING
OPERATIONS(3)(4) 1.80 1.69 1.59 1.75 1.20 1.29 1.08
DILUTED EARNINGS PER SHARE FROM CONTINUING
OPERATIONS(3)(4) 1.79 1.68 1.59 1.75 1.20 1.29 1.08
RETURN ON AVERAGE COMMON EQUITY 15.3% 15.5% 15.4% 18.4% 15.0% 14.9% 15.0%
DIVIDENDS PER COMMON SHARE 1.06 1.04 1.02 0.99 0.96 0.93 0.82
DIVIDEND PAYOUT RATIO 59% 62% 64% 57% 71% 72% 76%
COMMON SHARES OUTSTANDING -YEAR END 25,592 24,653 24,574 24,571 23,759 23,462 22,360
NUMBER OF COMMON SHAREHOLDERS (5) 14,503 14,358 14,103 13,438 13,699 13,753 13,812
- ----------------------------------------------------------------------------------------------------------------------------------
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 from continuing operations does not include 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.
Management's discussion and analysis of
financial condition and results of operations
The primary financial goals of Otter Tail Corporation (the Company) 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 nonelectric 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 ability because of strong credit ratings, 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 its 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 $76.8 million combined with cash on
hand of $11.4 million at December 31, 2001, allowed the Company to pay dividends
and finance 80% of its capital expenditures. Its remaining capital expenditures
were financed through the issuance of long-term debt.
Cash provided by operating activities in 2002 was $76.8 million compared with
cash provided by operating activities of $77.5 million in 2001. The decrease
reflects a combination of a $2.5 million increase in net income, a $4.1 million
change in deferred taxes and a $3.3 million decrease in cash used for deferred
debits and other assets, offset by a $10.4 million increase in cash used for
working capital items.
(side-by-side bar graph of data with cash realization ratio data labels in the
following table)
CASH REALIZATION RATIOS
(millions)
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
Cash flows from operations $64 $82 $62 $78 $77
Net income $35 $45 $41 $44 $46
Cash realization ratios 183% 182% 151% 177% 166%
The cash realization ratio represents cash flows from operations expressed as a
percent of net income.
(end of graph)
(stacked bar graph of data in the following table)
CAPITAL STRUCTURE
(millions)
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
Long-term debt and current maturities $187 $189 $209 $256 $266
Preferred stock $39 $34 $34 $16 $16
Common equity $225 $249 $263 $279 $313
Otter Tail has maintained a balanced capital structure for several years with
common equity staying near 50% of total capital.
(end of graph)
The $18.5 million increase in net cash used in investing activities between 2002
and 2001 reflects an increase in capital expenditures of $21.9 million offset by
a $2.4 million reduction in cash used to complete acquisitions. In the electric
segment, capital expenditures increased by $10.9 million mostly related to
in-progress construction of a new gas-fired combustion turbine and construction
of a new transmission line in North Dakota completed in the fourth quarter of
2002. In the manufacturing segment, capital expenditures increased by $4.5
million reflecting structural modifications and the purchase of new equipment
totaling $8.7 million at the Company's metal parts stamping company and $3.8
million in plant expansion expenditures at the Company's wind tower
manufacturing company. In the plastics segment, capital expenditures increased
by $4.0 million mainly reflecting the purchase of a building that was previously
being rented. Capital expenditures at our transportation company increased by
$1.8 million reflecting the purchase of trucks and trailers for its
company-owned fleet.
In 2002, the Company completed five acquisitions. Three of the acquisitions were
completed through an exchange of 718,321 shares of Company common stock and cash
for the capital stock of the acquired companies. The other two were
cash-for-asset acquisitions. The total cash consideration paid by the Company
for these five acquisitions, net of cash acquired, aggregated $6.6 million.
Net cash provided by financing activities was $1.4 million for 2002 compared
with $6.3 million used in financing activities in 2001. The $7.7 million
increase between the years is due to the following:
- Net proceeds from short-term borrowings were $25.5 million higher in
2002 than in 2001.
- Net proceeds from long-term debt financing activities in 2002 were
$37.4 million less than net proceeds generated from long-term debt
financing activities in 2001.
- The Company retired $18 million in preferred stock in 2001 with the
issuance of long-term debt while no preferred stock was retired in
2002.
- Proceeds from employee stock plans increased by $1.7 million in 2002
over 2001. Dividend payments increased by $0.1 million in 2002.
In 2002, the Company filed with the Securities and Exchange Commission (SEC) a
shelf registration statement for $200 million of unsecured debt securities. On
September 27, 2002 the Company issued $65 million of senior unsecured notes
under the shelf registration statement. The offering consisted of $40 million of
5.625% insured senior notes due 2017 and $25 million of 6.80% senior notes due
2032. Net proceeds from these issues were used to pay off short-term debt that
was used to retire the Company's 7.25% series first mortgage bonds at maturity
on August 1, 2002 in the amount of $18.2 million, and to retire early on October
31, 2002 the Company's outstanding $27.3 million 8.25% series 2022 first
mortgage bonds at an aggregate redemption price of $28.5 million. The remaining
proceeds were used to repay short-term debt used to finance a portion of the
costs related to the new gas-fired combustion turbine plant being constructed by
the electric utility. Proceeds from subsequent debt issuances under the shelf
registration, if any, may be used for other general corporate purposes,
including working capital, capital expenditures, debt repayment, the financing
of possible acquisitions or stock repurchases.
As a result of the financing described above, the Company repaid all of its
outstanding first mortgage bonds and terminated its first mortgage indenture.
On December 2, 2002 the Company retired its 5.00% industrial development
refunding revenue bonds at maturity in the amount of $3.0 million.
During 2002, 131,167 shares of common stock were issued for stock options
exercised under the 1999 Stock Incentive Plan generating proceeds of $2.6
million. Also in 2002, the Company granted 85,800 shares of restricted stock to
certain key executives and nonemployee directors and issued 3,382 common shares
for director compensation under the 1999 Stock Incentive Plan. The Company also
issued 718,321 common shares as consideration in connection with three
acquisitions in 2002.
CAPITAL REQUIREMENTS
The Company has a capital expenditure program for the expansion, upgrade and
improvement of its plants and operating equipment. Typical uses of cash for
capital improvements are investments in electric generation facilities,
transmission and distribution lines, equipment used in the manufacturing
process, acquisitions of diagnostic medical equipment, transportation equipment
and computer hardware and information systems. The capital expenditure program
is subject to review and is revised annually in light of changes in demands for
energy, technology, environmental laws, regulatory changes, the costs of labor,
materials and equipment, and the Company's consolidated financial condition.
Consolidated capital expenditures for the years 2002, 2001 and 2000 were $75.5
million, $53.6 million and $46.3 million, respectively. The estimated capital
expenditures for 2003 are $47.7 million and the total capital expenditures for
the five-year period 2003 through 2007 are expected to be approximately $240
million.
The breakdown of 2002 actual and 2003 through 2007 estimated capital
expenditures by segment is as follows:
2002 2003 2003-2007
---- ---- ---------
(in millions)
Electric $46 $30 $146
Plastics 6 5 14
Manufacturing 15 6 45
Health services 4 3 9
Other business operations 5 4 26
--- --- ----
Total $76 $48 $240
=== === ====
(stacked bar graph of data with interest-bearing debt as a percent of total
capital data labels in the following table)
INTEREST-BEARING DEBT AS A PERCENT OF TOTAL CAPITAL
(millions)
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
Total capital $452 $472 $506 $551 $625
Interest-bearing debt (includes
short-term debt) $188 $189 $209 $256 $296
Interest-bearing debt
as a percent of total capital 42% 40% 41% 46% 47%
Otter Tail has maintained a 40-50% debt to total capital ratio for the past five
years. The increase from 2000 to 2001 reflects the issuance of debt to retire a
preferred stock series.
(end of graph)
(bar graph of data in the following table)
LONG-TERM DEBT INTEREST COVERAGE
(times interest earned before tax)
1998 1999 2000 2001 2002
- ---- ---- ---- ---- ----
4.3 6.0 4.8 5.2 5.1
Otter Tail has maintained coverage ratios in excess of its debt covenant
requirements.
(end of graph)
The $16 million planned decrease in capital expenditures for the electric
segment for 2003 as compared to 2002 reflects completion of the Company-owned
portion of a large transmission line project in North Dakota in 2002 and the
completion of the new gas-fired combustion turbine in 2003. The $9 million
planned decrease in capital expenditures in the manufacturing segment from 2002
to 2003 reflects the completion of major structural modifications and equipment
purchases at the Company's metal parts stamping company and the completion of a
plant expansion project at the Company's wind tower manufacturing company in
2002.
The following table summarizes the Company's contractual obligations at December
31, 2002 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 $266 $ 8 $13 $54 $191
Coal contracts (required minimums) 93 15 20 10 48
Construction program (purchase orders) 7 7 -- -- --
Capacity and energy requirements 67 15 27 25 --
Operating leases 65 20 29 12 4
---- --- --- ---- ----
Total contractual cash obligations $498 $65 $89 $101 $243
==== === === ==== ====
CAPITAL RESOURCES
Financial flexibility is provided by unused lines of credit, strong financial
coverages and credit ratings, and alternative financing arrangements such as
leasing.
For the period 2003 through 2007, 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, provide for its estimated
consolidated capital expenditures and pay off most of its currently outstanding
short-term debt. Reduced demand for electricity or 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 2003
through 2007 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.
The Company has the ability to issue up to an additional $135 million of
unsecured debt securities from time to time under its shelf registration
statement on file with the SEC.
The Company has a $50 million line of credit. This line of credit bears interest
at the rate of LIBOR plus 0.5% and expires on April 29, 2003. The Company does
not anticipate any difficulties in renewing this line of credit. The Company's
bank line of credit is a key source of operating capital and can provide interim
financing of working capital and other capital requirements, if needed. The
Company's obligations under this line of credit are guaranteed by a 100%-owned
subsidiary of the Company that owns substantially all of the Company's
nonelectric companies. As of December 31, 2002, $30 million of the $50 million
line was in use and the Company had $9.9 million in cash and cash equivalents.
The Company's line of credit and its $90 million 6.63% senior notes due 2011
contain a number of covenants that restrict the Company's ability, with
significant exceptions, to: engage in mergers or consolidations; dispose of
assets; create liens on assets; engage in transactions with affiliates; take any
action which would result in a decrease in the ownership interest in any
subsidiary; redeem stock or any subsidiary's stock and pay dividends on stock;
make investments, loans or advances; guaranty the obligations of other persons
or agree to maintain the net worth or working capital of, or provide funds to
satisfy any other financial test applicable to, any other person; and enter into
a contract that requires payment to be made by the Company whether or not
delivery of the materials, supplies or services is ever made under the contract.
In addition, specified financial covenants under the line of credit and the
6.63% senior notes require a debt-to-total capitalization ratio not in excess of
60% and an interest and dividend coverage ratio of at least 1.5 to 1. The 6.63%
senior notes also require that priority debt not be in excess of 20% of total
capitalization.
As of December 31, 2002 the Company was in compliance with all of the covenants
under its line of credit and its other debt obligations.
The interest rate under the line of credit is subject to adjustment in the event
of a change in ratings on the Company's senior unsecured debt, up to LIBOR plus
0.8% if the ratings on the Company's senior unsecured debt fall to BBB+ or below
(Standard & Poor's) or Baa1 or below (Moody's). The line of credit also provides
for accelerated repayment in the event the Company's long-term senior unsecured
debt is rated below BBB- (Standard & Poor's) or Baa3 (Moody's).
The Company's securities ratings at December 31, 2002 are as follows:
Moody's
Fitch Investors Standard
Ratings Service & Poor's
------- ------- --------
Senior unsecured debt A+ A2 A
Preferred stock A Baa1 A-
Outlook Stable Negative Stable
The Company's disclosure of these securities ratings is not a recommendation to
buy, sell or hold its securities. Downgrades in these securities ratings could
adversely affect the Company. Further downgrades could increase borrowing costs
resulting in possible reductions to net income in future periods and increase
the risk of default on the Company's debt obligations.
The Company's 6.63% senior notes contain an investment grade put that could
require the Company to prepay this series with a make-whole premium if the
Company's senior unsecured debt is rated below Baa3 (Moody's) or BBB- (Standard
& Poor's). The Company's obligations under the 6.63% senior notes are guaranteed
by a 100%-owned subsidiary of the Company that owns substantially all of the
Company's nonelectric companies. The Company's Grant County and Mercer County
pollution control refunding revenue bonds require that the Company grant to
Ambac Assurance Corporation, under a financial guaranty insurance policy
relating to the bonds, a security interest in the assets of the electric utility
if the rating on the Company's senior unsecured debt is downgraded to Baa2 or
below (Moody's) or BBB or below (Standard & Poor's and Fitch). The Company
believes the risk of the downgrade events described in this paragraph occurring
is remote based on the current debt ratings of the Company combined with its
strong debt-to-equity ratio and ability to generate cash from operations.
The Company's ratio of earnings to fixed charges was 3.9x for 2002 compared to
4.2x for 2001 and its long-term debt interest coverage ratio before taxes was
5.1x for 2002 compared to 5.2x for 2001. The main reason for the reduction in
these coverage ratios is the refinancing of the Company's $18 million of $6.35
preferred stock with interest-bearing debt in December 2001. During 2003, the
Company expects these coverage ratios to remain similar to 2002.
OFF-BALANCE SHEET ARRANGEMENTS
The Company does not have any relationships with unconsolidated entities or
financial partnerships. These entities are often referred to as structured
finance special purpose entities or variable interest entities, which are
established for the purpose of facilitating off-balance sheet arrangements or
for 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 $1.79 for the year ended
December 31, 2002 compared to $1.68 for the year ended December 31, 2001. In
2001, goodwill amortization reduced diluted earnings per share by $0.09. In
2002, the amortization of goodwill was discontinued in accordance with a new
accounting standard. Total operating revenues for 2002 were $710.1 million
compared with $654.1 million for 2001. Operating income was $82.0 million for
the year 2002 compared with $77.5 million for 2001. Growth in revenues and
operating income from the plastics and health services segments offset decreases
in operating income from the electric, manufacturing and other business
operations segments.
Electric
Otter Tail Power Company, a division of Otter Tail Corporation, provides
electrical service to more than 127,000 customers in a service territory
exceeding 50,000 square miles.
2002 2001 2000
-------- -------- --------
(in thousands)
Operating revenues $307,403 $307,684 $262,280
Production fuel 44,122 41,776 38,546
Purchased power 94,694 99,491 66,121
Other operation and maintenance expenses 80,534 75,531 74,591
Depreciation and amortization 24,910 24,272 23,778
Property taxes 9,423 9,464 9,976
-------- -------- --------
Operating income $ 53,720 $ 57,150 $ 49,268
======== ======== ========
(bar graph of data in the following table)
ELECTRIC OPERATING INCOME
(millions)
2000 2001 2002
---- ---- ----
$49.3 $57.2 $53.7
(end of graph)
While overall electric operating revenues remained essentially the same in 2002
as in 2001, retail sales revenues increased $7.8 million, wholesale power
revenues decreased $16.1 million and other electric revenue increased $8.1
million. The increase in retail revenue reflects a 2.4% increase in retail
kilowatt-hour (kwh) sales along with a $3.9 million increase in cost-of-energy
(COE) revenue.
The increase in retail sales reflects increased usage by residential and
commercial customers partially offset by a decrease in usage by industrial
customers. Heating-degree-days totaled 9,033 in 2002 compared with 8,575 in
2001, an increase of 5.3%. Heating-degree-days are a measure of the total daily
degrees by which daily average temperatures are below 65 degrees Fahrenheit.
With a number of customers heating with electricity, changes in electricity
consumption can often be explained by the magnitude of change in
heating-degree-days. The increase in COE revenues reflects an 11.5% increase in
fuel and purchased power costs per kwh for system use in 2002 compared with 2001
(see discussion below). Wholesale energy revenues decreased 16.4% between the
years. While wholesale kwh sales grew 7.8% between the years, revenue per kwh
sold decreased by 22.5% resulting in a reduction of wholesale energy gross
margins. The decrease in wholesale electric prices may be partially attributable
to peaking generation added in the Mid-Continent Area Power Pool (MAPP) region
since September 2001, as well as regional demand for electricity. The increase
in other electric operating revenues is primarily due to revenue earned on a
large transmission line construction project completed for another regional
utility in 2002.
The 5.6% increase in production fuel expense in 2002 compared with 2001 is
primarily due to a 13.7% increase in fuel costs per kwh produced at the electric
utility's coal-fired generating stations. The increase in fuel costs per kwh
produced is due to higher costs reflected in new coal contracts that went into
effect at the beginning of 2002 and increased freight rates for the shipping of
coal to Big Stone and Hoot Lake Plants. In 2001, coal was being shipped to Big
Stone Plant under a negotiated agreement that expired at the end of 2001.
Currently, coal is being shipped to Big Stone Plant under a tariff rate that is
set through December 2003.
Although the volume of kwh purchases increased by 18.4% in 2002 over 2001,
purchased power expense decreased by 4.8% due to a 19.6% decrease in the cost
per kwh purchased. The volume of power purchased in 2002 increased for both
system use and resale purposes. The increase in kwh purchases was to provide for
the increase in wholesale energy sales, to meet system demand and to replace the
loss of generation at Big Stone Plant during six weeks of scheduled maintenance
in the fall of 2002.
The 6.6% increase in other operation and maintenance expenses includes $3.8
million in material costs incurred in the construction of a transmission line
for another regional utility and $2.0 million in increased employee benefit
expenses offset by a $1.0 million decrease in external services expenses. The
2.6% increase in depreciation and amortization expense for 2002 compared to 2001
is due to an increase in the electric utility's composite depreciation rate from
3.06% in 2001 to 3.08% in 2002 and an increase in depreciable plant base as a
result of recent capital expenditures.
Growth is not expected in the electric segment in 2003. Margins on wholesale
electric sales are expected to remain tight in 2003 due to the added generating
capacity in the MAPP region. Income from electrical construction and maintenance
work for outside entities scheduled for 2003 will not replicate profits earned
on the large transmission project completed for another regional utility in
2002. Another factor affecting the electric segment's financial performance will
be increased pension costs, which are expected to be about $4.1 million before
tax in 2003 compared to net pension income of $1.0 million before tax in 2002.
The reasons for the increase in pension costs are a lower return on plan assets
during 2002, a change in the assumed long-term rate of return from 9.5% in 2002
to 8.5% in 2003 and a decrease in the assumed discount rate from 7.5% in 2002 to
6.75% in 2003. See "Critical accounting policies involving significant estimates
- - Pension and other postretirement benefit obligations and costs."
Electric operating revenues for 2001 increased 17.3% 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% increase in wholesale prices
combined with a 30.2% increase in wholesale kwh sales. The increase in 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%
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 8.4% increase in production fuel expense in 2001 over 2000 is due to the
following: a 4.4% increase in kilowatt-hours generated combined with a 0.8%
increase in the fuel cost per kwh generated and a reduction in 2000 fuel
expenses of $1.9 million related to the Knife River coal arbitration settlement.
Excluding the impact of this settlement, production fuel expenses increased
3.3%. The 50.5% increase in purchased power expense is the result of a 24.2%
increase in kwh purchases combined with a 21.2% increase in the cost per kwh
purchased. While kwh purchases for resale increased 49.4% to provide for the
increase in wholesale sales of electricity, kwh purchases for retail sales were
down 26.9% in 2001 compared to 2000.
Other operation and maintenance expenses increased 1.3% in 2001 compared to
2000, mainly due to a 3.1% 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 Knife River arbitration
settlement that recovered previously recorded arbitration expenses. See note 3
to consolidated financial statements.
The 2.1% 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% 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. The
effect of the reduction in property taxes is refunded to retail electric
customers on an ongoing basis.
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.
2002 2001 2000
------- -------- -------
(in thousands)
Operating revenues $82,931 $ 63,216 $82,667
Cost of goods sold 65,432 57,932 66,286
Operating expenses 4,603 3,446 4,335
Depreciation and amortization 1,760 1,726 1,798
Amortization of goodwill -- 1,503 1,503
------- -------- -------
Operating income (loss) $11,136 $ (1,391) $ 8,745
======= ======== =======
(bar graph of data in the following table)
PLASTICS OPERATING INCOME
(millions)
2000 2001 2002
- ---- ---- ----
$8.7 ($1.4) $11.1
(end of graph)
The 31.2% increase in plastics operating revenues for 2002 compared with 2001
reflects a 23.0% increase in pounds of PVC pipe sold combined with a 6.6%
increase in the average sales price per pound. The 12.9% increase in cost of
goods sold reflects $14.6 million in costs related to the increase in PVC pipe
sold offset by a $7.1 million reduction in costs due to a 7.0% decrease in the
price per pound of PVC resin. Operating expenses increased 33.6% primarily due
to increases in sales commissions and incentive compensation related to
increased profitability in this segment. In 2002, the amortization of goodwill
was discontinued in accordance with a new accounting standard.
The Company does not expect the business conditions that contributed to the
record earnings in the plastics segment in 2002 to be duplicated in 2003. Gross
margins decline when the supply of PVC pipe increases faster than demand. The
gross margin percentage is sensitive to PVC raw material resin prices and the
demand for PVC pipe. 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.
The 23.5% decrease in plastics operating revenues for 2001 compared with 2000 is
due to a 29.5% decline in average sales price per pound offset by an 8.5%
increase in pounds of PVC pipe sold. The decline in PVC resin prices combined
with an oversupply of finished PVC pipe products were the main factors in the
decrease in average sales price per pound. The decrease of 12.6% in cost of
goods sold reflects a 19.5% decrease in the average cost per pound of PVC pipe
sold. The selling price per pound of PVC pipe was affected by the change in raw
material cost of PVC resin. Operating expenses decreased 20.5% primarily due to
a reduction in labor costs and selling expenses.
For 2002, 58.3% of raw material was purchased from two vendors, with 41.2%
supplied by four other vendors. The loss of a key supplier or any interruption
or delay in the supply of PVC resin could have a significant impact on the
operations of the plastics segment.
Manufacturing
Manufacturing consists of businesses involved in the production of waterfront
equipment, 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 2002, two acquisitions were
completed in this segment using the purchase method of accounting. On May 28,
2002 the Company acquired the outstanding stock of ShoreMaster, Inc.
(ShoreMaster). On October 1, 2002 the Company acquired the outstanding stock of
Galva Foam Marine Industries, Inc. (Galva Foam). During 2001, three acquisitions
were completed in this segment. On February 28, 2001 the Company acquired the
outstanding stock of T.O. Plastics, Inc. On September 28, 2001 the Company
acquired the outstanding stock of St. George Steel Fabrication, Inc. These two
acquisitions were completed using the pooling-of-interests method of accounting.
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.
2002 2001 2000
-------- -------- -------
(in thousands)
Operating revenues $142,390 $123,436 $97,506
Cost of goods sold 107,736 91,360 72,639
Operating expenses 18,358 14,762 13,992
Depreciation and amortization 6,525 4,858 3,672
Amortization of goodwill -- 281 258
-------- -------- -------
Operating income $ 9,771 $ 12,175 $ 6,945
======== ======== =======
(bar graph of data in the following table)
MANUFACTURING OPERATING INCOME
(millions)
2000 2001 2002
- ---- ---- ----
$6.9 $12.2 $9.8
(end of graph)
(bar graph of data in the following table)
The 15.4% increase in manufacturing operating revenues for 2002 compared with
2001 reflects the 2002 acquisitions of ShoreMaster and Galva Foam and increased
production and sales of wind towers offset by decreased sales volumes of metal
parts stamping and steel fabrication. Cost of goods sold increased 17.9% due to
the ShoreMaster and Galva Foam acquisitions and increases of $9.3 million in
material and subcontractor costs at the wind tower manufacturing business offset
by a $4.8 million reduction in material costs at the metal parts stamping
companies. The ShoreMaster and Galva Foam acquisitions accounted for $3.4
million of the $3.6 million increase in operating expenses between the periods
and $0.4 million of the increase in depreciation and amortization expense. The
remaining $1.3 million increase in depreciation and amortization expense in 2002
compared with 2001 is due to 2001 and 2002 plant expansions and equipment
purchases at all the manufacturing companies. In 2002, the amortization of
goodwill was discontinued in accordance with a new accounting standard.
The companies in this segment continue to be adversely affected by a slower
economy. Uncertainty in the energy industry has directly affected the steel
fabrication companies that manufacture equipment for power plants and the wind
energy industry.
Manufacturing operating revenues increased 26.6% 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%
increase in cost of goods sold correlates with increased sales volumes. The 5.5%
increase in operating expenses reflects increases in general and administrative
expenses offset by reductions in research, development and selling expenses.
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 May 1, 2002 the Company acquired the outstanding stock of Computed
Imaging Service, Inc. On November 1, 2002 the Company acquired the assets and
operations of Mobile Diagnostic Services, Inc. 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. All of these
acquisitions were accounted for using the purchase method of accounting. See
note 2 to consolidated financial statements.
2002 2001 2000
------- ------- -------
(in thousands)
Operating revenues $93,420 $79,129 $66,319
Cost of goods sold 66,670 59,388 49,193
Operating expenses 13,970 9,362 8,416
Depreciation and amortization 4,410 2,912 2,501
Amortization of goodwill -- 605 480
------- ------- -------
Operating income $ 8,370 $ 6,862 $ 5,729
======= ======= =======
HEALTH SERVICES OPERATING INCOME
(millions)
2000 2001 2002
- ---- ---- ----
$5.7 $6.9 $8.4
(end of graph)
The 18.1% increase in health services operating revenues, 12.3% increase in cost
of goods sold, 49.2% increase in operating expenses and the 51.4% increase in
depreciation and amortization for 2002 compared with 2001 are primarily due to
the acquisitions completed during September 2001 and May 2002. The number of
scans performed increased 19.8% due to the acquisitions while the average fee
per scan increased 7.6% primarily as a result of the addition of new modalities
provided by the companies acquired in September 2001. Revenues from equipment
sales decreased 3.4%.
Operating margins improved slightly between the periods due to increases in
margins on service sales in the diagnostic equipment imaging business and in the
mobile imaging business offset by expenses incurred in the segment's continued
investment in and promotion of fixed-based imaging systems. In 2002, the
amortization of goodwill was discontinued in accordance with a new accounting
standard.
Operating revenues for the health services segment increased 19.3% for 2001
compared with 2000 due to an increase in equipment sales, services and supplies,
combined with an increase of 7.4% in scans performed. $4.2 million of the
revenue increase was the result of the acquisitions completed in September 2001.
As a result of the acquisitions, cost of goods sold increased 20.7% reflecting
increased costs of materials and supplies used and sold in the diagnostic
equipment imaging business, increased rent expense and other additional
expenses. The operating expense increase is related to increased labor costs,
selling expenses, insurance expenses and promotion expenses.
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 general and administrative expenses that are
not allocated to the other segments.
2002 2001 2000
-------- ------- -------
(in thousands)
Operating revenues $ 83,972 $80,667 $78,159
Cost of goods sold 46,415 41,109 40,938
Operating expenses 33,564 30,927 27,088
Depreciation and amortization 5,008 5,093 5,669
Amortization of goodwill -- 850 903
-------- ------- -------
Operating (loss) income $ (1,015) $ 2,688 $ 3,561
======== ======= =======
(bar graph of data in the following table)
OTHER BUSINESS OPERATIONS OPERATING INCOME (millions)
2000 2001 2002
- ---- ---- ----
$3.6 $2.7 ($1.0)
(end of graph)
The 4.1% increase in operating revenues in the other business operations segment
for 2002 compared with 2001 includes increases of $3.1 million at the energy
services company and $1.6 million at the construction subsidiaries, partially
offset by a decrease in revenue of $1.4 million at the transportation
subsidiary. The increase in operating revenue at the energy services company
reflects increased revenue from natural gas sales and increased revenue from the
installation of energy efficient lighting equipment on customer premises in 2002
compared with 2001. The increase in operating revenues at the construction
subsidiaries reflects an increase in the volume of work performed in 2002
compared with 2001. A decrease of 6.1% in miles driven combined with a 2.4%
decrease in revenue per mile led to the decrease in operating revenues at the
transportation subsidiary.
The 12.9% increase in cost of goods sold in the other business operations
segment for 2002 compared with 2001 includes increases in cost of goods sold of
$3.8 million at the energy services company and $1.8 million at the construction
subsidiaries that are directly related to increased revenues at those companies.
Increased costs in excess of increased operating revenues due to smaller margins
on natural gas sales and competition for fewer jobs in the construction segment
related to the recent economic slowdown resulted in a $0.9 million decrease in
operating margins at those companies from 2001 to 2002. Operating expenses
increased 8.5% primarily due to a $1.5 million increase in unallocated corporate
costs, a $1.1 million increase in operating expenses at the energy services
company and a $337,000 increase in operating expenses at the telecommunications
subsidiary mainly due to increases in their provisions for doubtful accounts
related to the WorldCom and Global Crossings bankruptcies. A 5.0% decrease in
the average cost of diesel fuel per gallon at the transportation subsidiary
partially offset the increase in operating expenses at the other companies. In
2002, the amortization of goodwill was discontinued in accordance with a new
accounting standard.
The 3.2% increase in operating revenues in the other business operations segment
for 2001 compared with 2000 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. Increased brokerage revenue is the
primary 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 14.2% reflecting increased payments to owner-operators and increased
brokerage fees within the transportation subsidiary and increases in insurance
expenses. The 10.2% 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.
On September 1, 1999 the Company acquired the flatbed trucking operations of E.
W. Wylie Corporation (Wylie). The Company currently has $6.7 million of goodwill
recorded on its balance sheet relating to this acquisition. Highly competitive
pricing in the trucking industry in recent years has resulted in decreased
operating margins and lower returns on invested capital for Wylie. The Company's
current projections are for operating margins to increase from current levels
over the next three to five years as demand for shipping increases relative to
available shipping capacity and additional revenues are generated from added
terminal locations. If current conditions persist and operating margins do not
increase according to Company projections, the reductions in anticipated cash
flows from transportation operations may indicate that the fair value of Wylie
is less than its book value resulting in an impairment of goodwill and a
corresponding charge against earnings. At December 31, 2002, assessment of Wylie
indicated that its goodwill was not impaired. The Company will continue to
evaluate this reporting unit for impairment as conditions warrant.
(bar graph of data in the following table)
OTHER INCOME AND DEDUCTIONS
(millions)
2000 2001 2002
- ---- ---- ----
$2.2 $2.2 $2.1
(end of graph)
Consolidated interest charges
The $1.9 million (11.6%) increase in interest charges in 2002 over 2001 is due
to higher long-term debt balances outstanding offset by lower interest rates on
less short-term debt outstanding between the years. In late December 2001, the
Company sold $90 million of 6.63% senior notes due 2011 and used part of the
proceeds to retire $18 million of $6.35 cumulative preferred shares, $18 million
of 8.75% first mortgage bonds due 2021, $17.3 million of subsidiary term debt
and $20 million in short-term debt. The net impact of this refinancing resulted
in additional interest expense from the additional long-term debt outstanding
and the shift of $1.2 million from preferred dividend payments in 2001 to
interest expense in 2002. Interest expense on short-term debt decreased from
$1.0 million in 2001 to $0.3 million in 2002. The average daily short-term debt
balance decreased from $16.7 million in 2001 to $13.2 million in 2002 and the
average interest rate paid on short-term debt decreased from 5.2% in 2001 to
2.2% in 2002.
Interest expense decreased 6.0% 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% for 2001.
Consolidated income taxes
The Company's effective tax rate was 30.3% for 2002 compared with 31.5% for
2001. Although net income before taxes was $2.5 million higher in 2002 than in
2001, income taxes remained essentially the same in both years. This reflects
the discontinuance of goodwill amortization in 2002. The nontaxable portion of
goodwill was $1.3 million in 2001. The tax reduction on the remaining $1.2
million in pre-tax income of approximately $0.5 million reflects a reduction of
tax provisions related to the settlement of IRS audits of the Company's 1997 and
1998 tax returns. The 9.4% increase in consolidated income taxes for 2001
compared to 2000 follows the $4.3 million increase in income before income
taxes.
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 most 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 electric rate increases 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.
CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
The Company's significant accounting policies are described in note 1 to the
consolidated financial statements. The discussion and analysis of the financial
statements and results of operations are based on the Company's consolidated
financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of these
consolidated financial statements requires management to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and
expenses, and related disclosure of contingent assets and liabilities.
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, asset impairment evaluations, tax
provisions, collectability of trade accounts receivable, self insurance
programs, environmental liabilities, unbilled electric revenues, unscheduled
power exchanges, service contract maintenance costs, percentage-of-completion
and actuarially determined benefits costs. As better information becomes
available or actual amounts are known, estimates are revised. Operating results
can be affected by revised estimates. Actual results may differ from these
estimates under different assumptions or conditions. Management has discussed
the application of these critical accounting policies and the development of
these estimates with the audit committee of the board of directors. The
following critical accounting policies affect the Company's more significant
judgments and estimates used in the preparation of the consolidated financial
statements.
Pension and other postretirement benefits obligations and costs
Pension and postretirement benefit liabilities and expenses for the Company's
electric utility and corporate employees are determined by actuaries using
assumptions about the discount rate, expected return on plan assets, rate of
compensation increase and health care cost trend rates. Further discussion of
our pension and postretirement benefit plans and related assumptions is included
in note 9 to the consolidated financial statements included in this annual
report.
These benefits, for any individual employee, can be earned and related expenses
can be recognized and a liability accrued over periods of up to forty or more
years. These benefits can be paid out for up to forty or more years after an
employee retires at the extreme end of the scale. Estimates of liabilities and
expenses related to these benefits are among the Company's most critical
accounting estimates. Although deferral and amortization of fluctuations in
actuarially determined benefit obligations and expenses are provided for when
actual results on a year-to-year basis deviate from long-range assumptions,
compensation increases and health care cost increases or a reduction in the
discount rate applied from one year to the next can significantly increase the
Company's benefit expenses in the year of the change. Also, a reduction in the
expected rate of return on pension plan assets in the Company's funded pension
plan or realized rates of return on plan assets that are well below assumed
rates of return could result in significant increases in recognized pension
benefit expenses in the year of the change or for many years thereafter because
actuarial losses can be amortized over the average remaining service lives of
active employees.
A combination of factors has contributed to a significant increase in the
Company's current estimated pension and postretirement benefits obligations
liabilities and its 2003 estimated pension and postretirement benefits costs.
For the Company's pension fund, the average rate of return on assets over the
past five years of 1.8% compared to an assumed rate of 9.5% combined with a
reduction in the discount rate from 7.50% at year-end 2001 to 6.75% at year-end
2002 have contributed to a $46 million decrease in the pension plan's funded
status, a shift from a $14 million unrecognized actuarial gain to a $33 million
unrecognized actuarial loss, a shift from a $7.1 million prepaid pension asset
to a $5.4 million net pension liability and a direct reduction to shareholder's
equity of $7.0 million in the form of an "other comprehensive loss" from
year-end 2001 to year-end 2002. These factors will all contribute to a shift
from $2.6 million in pension income recorded in 2002 to a projected $1.7 million
pension cost in 2003. Company pension costs for the years 2004 through 2007
assuming a 6.75% discount rate are projected to be $3.0 million in 2004, $4.6
million in 2005, $6.3 million in 2006 and $7.2 million in 2007. Subsequent
increases in actual rates of return on plan assets over assumed rates or
increases or decreases in the discount rate could significantly change these
projected costs.
In 2002, the Company's Executive Survivor and Supplemental Retirement Plan
(ES&SRP) accrued benefit liability increased by $3.8 million and shareholder's
equity was reduced by $3.1 million in the form of a direct charge to "other
comprehensive loss." This was the result of an increase in accumulated benefits
earned and an increase in the number of plan participants, but also as a result
of a reduction in the discount rate from 7.50% at December 31, 2001 to 6.75% at
December 31, 2002 and actual increases in executive salaries in excess of
assumed rates of increase. All these factors will contribute to an increase in
the Company's ES&SRP periodic benefit cost from $1.6 million in 2002 to $2.5
million in 2003. ES&SRP costs for the years 2004 through 2007 assuming a 6.75%
discount rate are projected to be $2.7 million in 2004, $2.8 million in 2005,
$2.9 million in 2006 and $3.2 million in 2007.
Increases in health-care costs in excess of the assumed health-care cost trend
rate for 2002 and a decrease in the discount rate from 7.5% at December 31, 2001
to 6.75% at December 31, 2002 contributed to a $10.8 million increase in the
plan's projected benefit obligation and a $9.8 million increase in the plan's
unrecognized actuarial loss from year-end 2001 to year-end 2002. These factors
also contributed to an increase in postretirement health-care benefit costs from
$3.2 million in 2002 to a
projected $4.7 million in 2003. Postretirement health-care expenses for the
years 2004 through 2007 assuming a 6.75% discount rate are projected to be $4.8
million in 2004, $4.9 million in 2005, $5.0 million in 2006 and $5.3 million in
2007. Subsequent increases or decreases in the discount rate or in retiree
health-care cost inflation rates could significantly change these projected
costs.
Revenue recognition
In the electric business, revenue is accrued for electricity consumed but not
yet billed. At the end of each month, revenue is estimated for energy consumed
by customers since their last meter-reading date based on daily generation
volumes, estimated customer usage by class, weather factors, line losses and
applicable customer rates based on regression analysis reflecting historical
consumption patterns. The estimated balance for unbilled electric revenue at the
end of the year is highly sensitive to weather conditions in the month of
December. The estimated December 31st balances have ranged from $10.0 million to
$11.5 million over the last five years as a result of weather conditions and the
timing of meter-reading dates. The estimated unbilled receivable of $10.6
million on December 31, 2002 represents approximately 5% of annual retail
electric revenues. However, the incremental change in unbilled electric revenue
from December 31, 2001 to December 31, 2002 increased by only $85,000 or 0.04%
of retail electric revenue. This estimate is based on known conditions over a
very short period of time, is closely associated with electric generation costs,
is recalculated on a monthly basis and its incremental impact on annual revenue
is generally small.
The construction companies and three manufacturing companies record operating
revenues on a percentage-of-completion basis for fixed-price construction
contracts. The method used to determine the progress of completion is based on
the ratio of costs incurred to total estimated costs. The duration of the
majority of these contracts is less than a year. The Company has recognized $45
million of revenues on jobs in progress as of December 31, 2002. There are no
losses expected on jobs in progress at year-end 2002. The Company believes that
the accounting estimate related to the percentage-of-completion accounting on
uncompleted contracts is critical to the extent that any underestimate of total
expected costs on fixed-price construction contracts could result in reduced
profit margins being recognized on these contracts at the time of completion.
Allowance for doubtful accounts
The Company encounters risks associated with sales and the collection of the
associated accounts receivable. As such, the Company records a monthly provision
for accounts receivable that are considered to be uncollectible. In order to
calculate the appropriate monthly provision, the Company primarily utilizes a
historical rate of accounts receivables written off as a percentage of total
revenue. This historical rate is applied to the current revenues on a monthly
basis. The historical rate is updated periodically based on events that may
change the rate such as a significant increase or decrease in collection
performance and timing of payments as well as the calculated total exposure in
relation to the allowance. Periodically, the Company compares the identified
credit risks with the allowance that has been established using historical
experience and adjusts the allowance accordingly. In circumstances where the
Company is aware of a specific customer's inability to meet its financial
obligations, the Company records a specific allowance for bad debts to reduce
the net recognized receivable to the amount we reasonably believe will be
collected.
The Company believes the accounting estimate related to the allowance for
doubtful accounts is critical because the underlying assumptions used for the
allowance can change from period to period and could potentially cause a
material impact to the income statement and working capital.
During 2002, $1.6 million of bad debts expense was incurred and the allowance
for doubtful accounts was $3.8 million (4.7% of trade accounts receivable) as of
December 31, 2002. General economic conditions and specific geographic concerns
are major factors that may affect the adequacy of the allowance and may result
in a change in the annual bad debt expense. An increase or decrease of one
percentage-point in the Company's allowance for doubtful accounts at December
31, 2002 would result in an $822,000 increase or decrease in bad debts expense.
Although an estimated allowance for doubtful accounts on the Company's accounts
receivable is provided for, the allowance for doubtful accounts on the electric
segment's wholesale electric sales is insignificant in proportion to annual
revenues from these sales ($82 million in 2002). The electric segment has not
experienced a bad debt related to wholesale electric sales due largely to
stringent risk management criteria related to these sales. However, nonpayment
on a single wholesale electric sale could result in a significant bad debt
expense.
Depreciation expense and depreciable lives
The provisions for depreciation of electric utility property for financial
reporting purposes are made on the straight-line method based on the estimated
service lives (5 to 65 years) of the properties. Such provisions as a percent of
the average balance of depreciable electric utility property were 3.08% in 2002
and 3.06% in both 2001 and 2000. Depreciation rates on electric utility property
are subject to annual regulatory review and approval and depreciation expense is
recovered through rates set by ratemaking authorities. Although the useful lives
of electric utility properties are estimated, the recovery of their cost is
dependent on the ratemaking process. Deregulation of the electric industry could
result in changes to the estimated useful lives of electric utility property
that could impact depreciation expense.
Property and equipment of nonelectric 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. The
Company believes that the lives and methods of determining depreciation are
reasonable, however, changes in economic conditions affecting the industries in
which our companies operate or innovations in technology could result in a
reduction of the estimated useful lives of the Company's property plant and
equipment or in an impairment write-down of the carrying value of these
properties.
Asset impairment
The Company is required to test for asset impairment relating to property and
equipment whenever events or changes in circumstances indicate that the carrying
value of an asset might not be recoverable. The Company applies Statement of
Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets in order to determine whether or not an asset is
impaired. This standard requires an impairment analysis when indicators of
impairment are present. If such indicators are present, the standard requires
that if the sum of the future expected cash flows from a company's asset,
undiscounted and without interest charges, is less than the carrying value, an
asset impairment must be recognized in the financial statements. The amount of
the impairment is the difference between the fair value of the asset and the
carrying value of the asset.
The Company believes that the accounting estimates related to an asset
impairment are critical because they are highly susceptible to change from
period to period reflecting changing business cycles, they require management to
make assumptions about future cash flows over future years and the impact of
recognizing an impairment could have a significant effect on operations.
Management's assumptions about future cash flows require significant judgment
because actual operating levels have fluctuated in the past and are expected to
continue to do so in the future.
As of December 31, 2002, an assessment of the carrying values of the Company's
long-lived assets and other intangibles indicated that these assets were not
impaired.
Goodwill impairment
Beginning in 2002, goodwill is required to be evaluated annually for impairment,
according to SFAS No. 142, Goodwill and Other Intangible Assets. The standard
requires a two-step process be performed to analyze whether or not goodwill has
been impaired. Step one is to test for potential impairment, and requires that
the fair
value of the reporting unit be compared to its book value including goodwill. If
the fair value is higher than the book value, no impairment is recognized. If
the fair value is lower than the book value, a second step must be performed.
The second step is to measure the amount of impairment loss, if any, and
requires that a hypothetical purchase price allocation be done to determine the
implied fair value of goodwill. This fair value is then compared to the carrying
value of goodwill. If the implied fair value is lower than the carrying value,
an impairment must be recorded.
The Company believes that accounting estimates related to goodwill impairment
are critical because the underlying assumptions used for the discounted cash
flow can change from period to period and could potentially cause a material
impact to the income statement. Management's assumptions about inflation rates
and other internal and external economic conditions, such as earnings growth
rate, require significant judgment based on fluctuating rates and expected
revenues. Additionally, SFAS No. 142 requires that the goodwill be analyzed for
impairment on an annual basis using the assumptions that apply at the time the
analysis is updated.
As of December 31, 2002, an assessment of the carrying values of the Company's
goodwill indicated no impairment.
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 diversification efforts, growth of electric revenues, the
timing and scope of deregulation and open competition, Federal Energy Regulatory
Commission (FERC) mandated operational changes to the electricity transmission
grid, 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.
ELECTRIC OPERATIONS
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 2.4% in 2002, 2.9% in 2001, and 3.5% in 2000.
Factors beyond the Company's control, such as mergers and acquisitions,
geographical location, transmission reservation 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 appears that market
conditions for wholesale power transactions will be depressed in the future
because of generating unit additions in the power pool and the advent of
transmission system operators mandated by the FERC.
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 and income 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.
The electric utility's 2002 rate of return is expected to be within the
allowable range defined in the plan.
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. 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 slight increase in
availability of excess generation and transmission capacity due to the addition
of peaking capacity. 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 mitigate this financial risk. First,
wholesale sales 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. However, increases in fuel costs or regional generating
capacity could have a negative impact on wholesale electric sales and profit
margins.
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. The Company anticipates 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 2002. 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 would
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 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 the
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, the Company 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 and
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. Site work was
completed in early November 2001, however, seepage reappeared in a new location
in the spring of 2002. We initiated additional studies to further characterize
the site and that report will be submitted to the MPCA for their review and
comment. The Company does not anticipate that the MPCA's review will result in
actions that will have a material impact on the utility's results of operations
or financial condition.
Deregulation and legislation
In December 1999, FERC issued Order No. 2000, with the goal to consolidate
control of the transmission network into a new structure of independent regional
grid operators. The Midwest Independent Transmission System Operator (MISO),
based in Carmel, Indiana, transitioned into operational control of a broad
Midwest region of transmission in February 2002. Their nondiscriminatory
operation of the transmission system satisfies FERC's Order No. 2000. As the
transmission provider and security coordinator for the region, MISO offers
available capacity, accepts schedules, and provides settlement for transmission
services. As a transmission owner within MISO, Otter Tail Power Company received
$1.35 million in transmission service revenue while its load-based charge for
MISO operating costs totaled $0.7 million, or $0.00017 per kwh, in 2002.
In July 2002, FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard
Market Design (SMD). Its purpose is to insure standard commercial rules for the
operation of competitive markets for electricity. The SMD NOPR calls for markets
to be operational across the United States by the end of 2004. A final rule on
the SMD is expected by June of 2003. MISO, with strong FERC encouragement, has
established the end of 2003 as a target for MISO markets to be operational
within its geographical area of operation.
Consolidation of adjacent North American Electric Reliability Council (NERC)
regional reliability councils is expected to move forward during 2003. The
anticipated legal authorization to evolve the NERC, a voluntary utility effort
born in the aftermath of outages in the late 1960s, into the North American
Electric Reliability Organization (NAERO) is awaiting the passage of an
all-encompassing energy bill. NAERO represents the creation of an independent
and self-regulatory reliability organization to establish and enforce compliance
with mandatory rules for the reliable operation of the transmission system
within the United States under the oversight of FERC.
The United States Congress ended its 2002 legislative session without taking
action on electric industry restructuring legislation. The Congress did consider
a broad energy bill, but failed to pass it prior to the November elections.
There was no legislative action regarding electric retail choice in any of the
states the Company serves and no major electricity legislation is expected in
the 2003 legislative sessions in those states. The Company does not expect
retail competition to come to the states of Minnesota, North Dakota or South
Dakota in the foreseeable future.
Competition in the electric industry
As the electric industry evolves and becomes more competitive, the Company
believes it is well positioned to be successful. 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.
NONELECTRIC OPERATIONS
In 2002, approximately 31% of the Company's net income was contributed by
nonelectric operations. The Company plans to make additional acquisitions. 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% ownership. The Company intends to grow earnings as a
long-term owner of its operating companies. The Company also assesses the
performance of its operating companies' return on capital and will consider
divesting under-performing operating companies. Continuing growth from
nonelectric operations could result in earnings, cash flow and stock price
volatility.
While the Company cannot predict the success of our current nonelectric
businesses, we believe opportunities exist for growth in these business
segments. Factors that could affect the results of our nonelectric 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; the impact of government regulation; effectiveness of advertising,
marketing, and promotional programs; impairment of goodwill recorded in
connection with the acquisition of nonelectric businesses; adverse weather
conditions; and competition in the transportation industry. The failure of
Congress to pass a broad energy bill in 2003 could have an unfavorable impact on
the Company's operations that manufacture towers for the wind energy industry.
KEY ACCOUNTING PRONOUNCEMENTS
The Company adopted SFAS No. 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 Company has determined that certain electric energy contracts meet
the criteria of a derivative under SFAS No. 133 but qualify for the normal
purchase and normal sales exception and are not subject to mark-to-market
accounting treatment. SFAS No. 133 did not have a material effect on the
Company's 2001 or 2002 consolidated results of operations, financial position or
cash flows.
In October 2002, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board (FASB) reached a consensus on EITF Issue No. 02-3,
Issues Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. Any contracts within the scope of SFAS No. 133 that are
trading or held for trading and are settled physically should be reported on a
net basis. Any contracts within the scope of SFAS No. 133 that are not
considered trading and are settled physically should be reported on a gross
basis. As of December 31, 2002, none of the electric utility's completed or open
energy-only contracts were determined to be trading or held for trading
purposes.
The FASB has issued SFAS No. 143, Accounting for Asset Retirement Obligations
(ARO), 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 adopted SFAS No. 143 on
January 1, 2003. Retirement obligations associated with long-lived assets
included within the scope of SFAS No. 143 are those for which there is a legal
obligation to settle under existing or enacted law, statute, written or oral
contract or by legal constructions under the doctrine of promissory estoppel.
Adoption of SFAS No. 143 will change the accounting for ARO costs of the
utility's generating plants as well as certain other long-lived assets.
Currently, estimated net salvage amounts are part of depreciation expense
accruals collected in the utility's rates and reported in accumulated
depreciation. SFAS No. 143 requires the present value of the future
decommissioning cost to be recognized as a liability on the balance sheet with
an offsetting amount being added to the capitalized cost of the related
long-lived asset. The liability will be accreted to its present value each
period and the capitalized cost will be depreciated over the useful life of the
related asset. The FERC issued a proposed rulemaking on Accounting, Financial
Reporting, and Rate Filing Requirements for Asset Retirement Obligations on
October 30, 2002.
The Company is in the process of evaluating what assets may have associated
retirement costs as defined by SFAS No. 143, and what the prescribed accounting
treatment will be under FERC rules. Preliminary calculations indicate that
estimated costs of current legal obligations associated with asset retirement
are already included in existing accumulated depreciation. The estimated amount
added to the generating plant assets would be under $0.7 million. The estimated
future obligation under SFAS No. 143 is under $4.3 million, primarily for steam
generating plants, and the estimated current liability at the end of 2002 would
be near $2.2 million. The $1.5 million difference between the increase in plant
assets and the present value of the future ARO obligation represents the
cumulative effect of amounts that would have been accreted to the liability from
the time the generating assets were first placed in service through December 31,
2002. The Company expects regulatory rules to be adopted that will allow the
cumulative effect of the accretion expense on net income resulting from the
adoption of SFAS No. 143 to be offset by a credit to income and a charge to the
accumulated reserve for depreciation account or to a proposed regulatory asset
account. Through 2002, the Company has accrued $14.4 million in its depreciation
reserve accounts for all legal and other expected obligations at retirement of
their steam generating plants. Since the Company is already recovering these
estimated legal obligations and they are already recognized as recoverable for
rate regulation, the Company does not expect any impact on earnings as a result
of adopting SFAS No. 143.
The FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets in October 2001. SFAS No. 144 replaces SFAS No.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 results of operations, financial position or cash flows.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation--Transition and Disclosure. This Statement amends SFAS No. 123,
Accounting for Stock-Based Compensation, to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. In addition, this Statement amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on reported
results. Certain amendments to SFAS No. 123 of this Statement shall be effective
for financial statements for fiscal years ending after December 15, 2002. The
Company currently follows the accounting provisions of Accounting Principle
Board Opinion No. 25, Accounting for Stock Issued to Employees, for stock-based
compensation and provides the pro forma disclosures required under SFAS No. 123
as amended by SFAS No. 148.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
At December 31, 2002 the Company had limited exposure to market risk associated
with interest rates and commodity prices and no exposure to market risk
associated with changes in foreign currency exchange rates.
The majority of the Company's long-term debt has fixed interest rates. The
interest on variable rate long-term debt 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, through economic
refunding of debt through optional refundings, limiting the amount of variable
interest rate debt, and the utilization of short-term borrowings to allow
flexibility in the timing and
placement of long-term debt. As of December 31, 2002 the Company had $15.5
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 percentage-point higher or lower than the average variable rate on December
31, 2002, interest expense and pre-tax earnings would change by approximately
$155,000.
The Company has not used interest rate swaps to manage net exposure to interest
rate changes related to the Company's portfolio of borrowings. The Company
maintains a ratio of fixed rate debt to total debt within a certain range. It is
the Company's policy to enter into interest rate transactions and other
financial instruments only to the extent considered necessary to meet its stated
objectives. The Company does not enter into transactions for speculative or
trading purposes.
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 energy resources that may
serve to mitigate price risk. The Company has in place an energy risk management
policy with a goal to manage, through the use of defined risk management
practices, price risk and credit risk associated with wholesale power purchases
and sales.
The Company's energy services subsidiary markets natural gas to approximately
150 retail customers. Some of these customers are served under fixed-price
contracts. There is price risk associated with a 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.
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. 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 to assume that historical trends will continue.
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 "Critical accounting policies involving significant estimates" and
"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, 2002, and 2001, 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, 2002. 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, 2002,
and 2001, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, effective January 1, 2002,
the Company changed its method of accounting for goodwill and other intangible
assets.
DELOITTE & TOUCHE LLP
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
January 29, 2003
OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS, DECEMBER 31 2002 2001
- ---------------------------------------- ---- ----
(in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 9,937 $ 11,378
Accounts receivable:
Trade (less allowance for doubtful accounts of
$3,833,000 for 2002 and $1,109,000 for 2001) 81,670 64,215
Other 1,466 5,047
Inventories 44,154 39,301
Deferred income taxes 4,487 4,020
Accrued utility revenues 11,633 11,055
Other 10,866 8,878
---------- --------
Total current assets 164,213 143,894
---------- --------
INVESTMENTS 18,439 18,009
GOODWILL--NET 64,557 48,221
INTANGIBLES--NET 5,592 1,584
OTHER ASSETS 17,696 15,687
DEFERRED DEBITS
Unamortized debt expense and reacquisition premiums 8,895 5,646
Regulatory assets 10,238 5,117
Other 1,220 1,406
---------- --------
Total deferred debits 20,353 12,169
---------- --------
PLANT
Electric plant in service 835,382 810,470
Nonelectric operations 178,656 145,712
---------- --------
Total 1,014,038 956,182
Less accumulated depreciation and amortization 467,759 441,863
---------- --------
Plant - net of accumulated depreciation and amortization 546,279 514,319
Construction work in progress 41,607 28,658
---------- --------
Net plant 587,886 542,977
---------- --------
TOTAL $ 878,736 $782,541
========== ========
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS, DECEMBER 31 2002 2001
- ---------------------------------------- ---- ----
(in thousands)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt $ 30,000 $ --
Sinking fund requirements and current maturities of long-term debt 7,690 28,946
Accounts payable 52,430 46,871
Accrued salaries and wages 18,194 17,397
Accrued federal and state income taxes -- 1,634
Other accrued taxes 10,150 9,854
Other accrued liabilities 5,760 6,090
--------- ---------
Total current liabilities 124,224 110,792
--------- ---------
NONCURRENT LIABILITIES 43,821 32,981
--------- ---------
COMMITMENTS (NOTE 7)
DEFERRED CREDITS
Deferred income taxes 94,147 85,591
Deferred investment tax credit 12,782 13,935
Regulatory liabilities 9,133 9,914
Other 7,435 7,160
--------- ---------
Total deferred credits 123,497 116,600
--------- ---------
CAPITALIZATION (PAGE 37)
Long-term debt, net of sinking fund and current maturities 258,229 227,360
Cumulative preferred shares 15,500 15,500
Common shares, par value $5 per share -- authorized, 50,000,000 shares;
outstanding, 2002 -- 25,592,160 shares; 2001 -- 24,653,490 shares 127,961 123,267
Premium on common shares 24,135 1,526
Unearned compensation (1,946) (151)
Retained earnings 175,304 156,641
Accumulated other comprehensive loss (11,989) (1,975)
--------- ---------
Total common equity 313,465 279,308
Total capitalization 587,194 522,168
--------- ---------
TOTAL $ 878,736 $ 782,541
========= =========
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31 2002 2001 2000
- ------------------------------- ---- ---- ----
(in thousands, except per-share amounts)
OPERATING REVENUES
Electric $ 307,403 $ 307,684 $262,280
Plastics 82,931 63,216 82,667
Manufacturing 142,390 123,436 97,506
Health services 93,420 79,129 66,319
Other business operations 83,972 80,667 78,159
--------- --------- --------
Total operating revenues 710,116 654,132 586,931
OPERATING EXPENSES
Production fuel 44,122 41,776 38,546
Purchased power 94,694 99,491 66,121
Electric operation and maintenance expenses 80,534 75,531 74,591
Cost of goods sold 286,253 249,789 229,056
Other nonelectric expenses 70,495 58,497 53,831
Depreciation and amortization 42,613 42,100 40,562
Property taxes 9,423 9,464 9,976
--------- --------- --------
Total operating expenses 628,134 576,648 512,683
OPERATING INCOME
Electric 53,720 57,150 49,268
Plastics 11,136 (1,391) 8,745
Manufacturing 9,771 12,175 6,945
Health services 8,370 6,862 5,729
Other business operations (1,015) 2,688 3,561
--------- --------- --------
Total operating income 81,982 77,484 74,248
OTHER INCOME AND DEDUCTIONS -- NET 2,057 2,193 2,154
INTEREST CHARGES 17,850 15,991 17,005
--------- --------- --------
INCOME BEFORE INCOME TAXES 66,189 63,686 59,397
INCOME TAXES 20,061 20,083 18,355
--------- --------- --------
NET INCOME 46,128 43,603 41,042
PREFERRED DIVIDEND REQUIREMENTS 736 1,993 1,879
--------- --------- --------
EARNINGS AVAILABLE FOR COMMON SHARES $ 45,392 $ 41,610 $ 39,163
========= ========= ========
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 25,176 24,600 24,572
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 25,397 24,832 24,649
BASIC EARNINGS PER SHARE $ 1.80 $ 1.69 $ 1.59
DILUTED EARNINGS PER SHARE $ 1.79 $ 1.68 $ 1.59
DIVIDENDS PER COMMON SHARE $ 1.06 $ 1.04 $ 1.02
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/(LOSS) EQUITY
-----------------------------------------------------------------------------------------
(in thousands, except common shares outstanding)
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
Common stock issuances 938,670 4,694 22,094 (2,674) 24,114
Amortization of unearned
compensation - stock options 879 879
Comprehensive income:
Net income 46,128 46,128
Minimum liability adjustment (10,014) (10,014)
---------
Total comprehensive income 36,114
Tax benefit for exercise of
stock options 720 720
Purchase stock for employee purchase
plan on open market (205) (205)
Cumulative preferred dividends (736) (736)
Common dividends (26,729) (26,729)
-----------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2002 25,592,160 $ 127,961 $ 24,135 $ (1,946) $ 175,304 $ (11,989) $ 313,465
=========================================================================================
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31 2002 2001 2000
- ------------------------------- ---- ---- ----
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 46,128 $ 43,603 $ 41,042
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 42,613 42,100 40,562
Deferred investment tax credit - net (1,153) (1,177) (1,183)
Deferred income taxes 2,669 (1,441) (4,655)
Change in deferred debits and other assets (5,178) (8,434) (3,346)
Change in noncurrent liabilities and deferred credits 1,049 2,484 4,263
Allowance for equity (other) funds used during construction (1,742) (963) (341)
Other - net 1,399 (81) 728
Cash provided by (used for) current assets and current liabilities:
Change in receivables, materials and supplies (4,192) 4,880 (20,781)
Change in other current assets (2,512) (432) 537
Change in payables and other current liabilities 2,288 (581) 9,904
Change in interest and income taxes payable (4,572) (2,429) (4,969)
-------- --------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 76,797 77,529 61,761
-------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (75,533) (53,596) (46,273)
Proceeds from disposal of noncurrent assets 2,462 3,298 1,709
Acquisitions, net of cash acquired (6,591) (8,948) (34,194)
Sale (purchase) of other investments 5 (1,884) (86)
-------- --------- --------
NET CASH USED IN INVESTING ACTIVITIES (79,657) (61,130) (78,844)
-------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings under line of credit 25,507 -- (50)
Proceeds from employee stock plans 3,091 1,347 14
Proceeds from issuance of long-term debt 65,124 121,146 44,814
Payments for retirement of long-term debt (62,161) (81,549) (24,889)
Payments for debt issuance expenses (2,677) (1,880) --
Redemption of preferred stock -- (18,000) --
Dividends paid and other distributions (27,465) (27,344) (26,455)
-------- --------- --------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 1,419 (6,280) (6,566)
-------- --------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,441) 10,119 (23,649)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 11,378 1,259 24,908
-------- --------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 9,937 $ 11,378 $ 1,259
======== ========= ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest (net of amount capitalized) $ 16,831 $ 16,313 $ 16,075
Income taxes $ 22,835 $ 23,575 $ 28,510
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION, DECEMBER 31 2002 2001
- ------------------------------------------------------ ---- ----
(in thousands)
LONG-TERM DEBT
First mortgage bond series:
7.25%, retired August 1, 2002 $ -- $ 18,200
8.25%, retired October 31, 2002 -- 27,300
-------- --------
Total first mortgage bond series -- 45,500
Senior debentures 6.375%, due December 1, 2007 50,000 50,000
Senior notes 6.63%, due December 1, 2011 90,000 90,000
Insured senior notes 5.625%, due October 1, 2017 40,000 --
Senior notes 6.80%, due October 1, 2032 25,000 --
Industrial development refunding revenue bonds 5.00% retired December 2, 2002 -- 3,010
Pollution control refunding revenue bonds variable 1.8% at December 31, 2002, 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 5,185
Mercer County, North Dakota pollution control refunding revenue bonds 4.85%, due September 1, 2022 20,790 20,790
Obligations of Varistar Corporation:
8.15% five-year term note, due October 31, 2005 3,531 5,280
7.80% ten-year term note, due October 31, 2007 6,712 9,771
Variable 3.07% at December 31, 2002, due July 3, 2007 3,634 4,479
Various up to 12.67% at December 31, 2002 11,022 11,571
Obligations of Otter Tail Energy Services Company 8.75% ten-year term note, retired February 2002 -- 892
Other -- 5
-------- --------
Total 266,274 256,883
Less:
Current maturities 7,690 28,646
Sinking fund requirement -- 300
Unamortized debt discount 355 577
-------- --------
Total long-term debt 258,229 227,360
-------- --------
CUMULATIVE PREFERRED SHARES -- without par value (stated and
liquidating value $100 a share) -- authorized 1,500,000 shares;
Series outstanding:
$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 preferred 15,500 15,500
-------- --------
CUMULATIVE PREFERENCE SHARES -- without par value, authorized 1,000,000 shares; outstanding: none
TOTAL COMMON SHAREHOLDERS' EQUITY 313,465 279,308
-------- --------
TOTAL CAPITALIZATION $587,194 $522,168
======== ========
See accompanying notes to consolidated financial statements
Otter Tail Corporation
Notes to consolidated financial statements
For the years ended December 31, 2002, 2001 and 2000
1. Summary of significant accounting policies
Principles of consolidation--The consolidated financial statements of
Otter Tail Corporation and its wholly owned subsidiaries (the Company)
include the accounts of the following segments: electric, plastics,
manufacturing, health services and other business operations. The electric
segment is regulated while the other segments are not regulated. See note
2 to the consolidated financial statements for further descriptions of the
Company's business segments. All significant intercompany balances and
transactions have been eliminated in consolidation except profits on sales
to the regulated electric utility company from nonregulated affiliates,
which is in accordance with the requirements of Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types
of Regulation. These amounts are not material.
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. In accordance with regulatory treatment, the
Company defers utility debt redemption premiums and amortizes such costs
over the original life of the reacquired bonds. See note 4 for further
discussion.
The Company's regulated business is subject to various state and federal
agency regulations. The accounting policies followed by this business is
subject to the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC). These accounting policies differ in some respects from
those used by the Company's nonregulated businesses.
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
$2,636,000 for 2002, $1,342,000 for 2001 and $471,000 for 2000. 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 3.08% in
2002 and 3.06% in both 2001 and 2000. Gains or losses on asset
dispositions are taken to the accumulated provision for depreciation
reserve and impact current and future depreciation rates.
Property and equipment of nonelectric operations are carried at historical
cost or at the then 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% (Big Stone Plant) and 35% (Coyote Station) ownership
interests in the assets, liabilities, revenue and expenses of Big Stone
Plant and Coyote Station. Amounts at December 31, 2002 and 2001 included
in electric plant in service for Big Stone were $113,731,000 and
$112,898,000, respectively, and the accumulated depreciation was
$74,533,000 and $71,585,000, respectively. Amounts at December 31, 2002
and 2001 included in electric plant in service for Coyote were
$146,739,000 and $146,566,000, respectively, and the accumulated
depreciation was $77,855,000 and $74,057,000, respectively. The Company's
share of direct revenue and expenses of the jointly owned plants 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. 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.
For those operating businesses recognizing revenue when shipped, the
operating businesses have no further obligation to provide services
related to such product. The shipping terms used in these instances are
FOB shipping point.
Electric customers' meters are read and bills are rendered monthly.
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. Revenue is
accrued for fuel and purchased power costs incurred in excess of amounts
recovered in base rates but not yet billed through the cost-of-energy
adjustment clause.
Revenues on wholesale electricity 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-per-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.
Some of the operating businesses enter into fixed-price construction
contracts. Revenues under these contracts are recognized on a
percentage-of-completion basis. The method used to determine the progress
of completion is based on the ratio of costs incurred to total estimated
costs. If a loss is indicated at a point in time during a contract, a
projected loss for the entire contract is estimated and recognized. The
following summarizes costs incurred and billings on uncompleted contracts:
December 31, December 31,
(in thousands) 2002 2001
-------------- ------------ ------------
Costs incurred on uncompleted contracts $ 42,768 $ 27,808
Less billings to date (44,572) (38,808)
Plus earnings recognized 6,340 5,672
-------- --------
$ 4,536 $ (5,328)
======== ========
The following costs incurred and billings are included in the Company's
consolidated balance sheet under Other current assets and Accounts
payable:
December 31, December 31,
(in thousands) 2002 2001
-------------- ------------ ------------
Costs in excess of billings on uncompleted contracts $ 5,529 $ 1,951
Billings in excess of costs on uncompleted contracts (993) (7,279)
------- -------
$ 4,536 $(5,328)
======= =======
Pre-production costs--The Company incurs costs related to the design and
development of molds, dies and tools as part of the manufacturing process.
The Company accounts for these costs under 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. The balance of pre-production costs deferred on the balance
sheet was $1,621,000 as of December 31, 2002 and $1,595,000 as of December
31, 2001.
Shipping and handling costs--The Company includes revenues received for
shipping and handling in operating revenues. Expenses paid for shipping
and handling are recorded as part of cost of goods sold.
Stock-based compensation--As described in note 5, the Company has elected
to follow the accounting provisions of Accounting Principle Board Opinion
No. 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.
Had compensation costs for the stock options issued been determined based
on estimated fair value at the award dates, as prescribed by SFAS No. 123,
the Company's net income for 2000 through 2002 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.
2002 2001 2000
--------- --------- ---------
(in thousands)
Net income
As reported $ 46,128 $ 43,603 $ 41,042
Total stock-based employee compensation
expense determined under fair value
based method for all awards net of
related tax effects (1,038) (833) (345)
--------- --------- ---------
Pro forma $ 45,090 $ 42,770 $ 40,697
Basic earnings per share
As reported $ 1.80 $ 1.69 $ 1.59
Pro forma $ 1.76 $ 1.66 $ 1.58
Diluted earnings per share
As reported $ 1.79 $ 1.68 $ 1.59
Pro forma $ 1.75 $ 1.64 $ 1.57
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, asset impairment evaluations, tax provisions, collectability of
trade accounts receivable, self insurance programs, environmental
liabilities, unbilled electric revenues, unscheduled power exchanges,
service contract maintenance costs, percentage-of-completion and
actuarially determined benefit costs. As better information becomes
available (or actual amounts are known), 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 2002 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 2000 were restated in 2001 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.
Investments--At December 31, 2002 and 2001, the Company had investments of
$5,359,000 and $6,108,000, 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 in both
2002 and 2001 and $1,414,000 in 2000. The balance of investments at
December 31, 2002, consists of $6,135,000 in additional investments
accounted for under the equity method and $6,945,000 in other investments
accounted for under the cost method, with $1,303,000 related to
participation in economic development loan pools. 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. 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.
Inventories consist of the following:
December 31, December 31,
(in thousands) 2002 2001
-------------- ------------ ------------
Finished goods $15,795 $12,644
Work in process 1,438 1,732
Raw material, fuel and supplies 26,921 24,925
Total inventories $44,154 $39,301
Short-term debt--There was $30,000,000 in short-term debt outstanding as
of December 31, 2002 and no short-term debt outstanding as of December 31,
2001. The average interest rate paid on short-term debt during 2002 and
2001 was 2.2% and 5.2%, respectively.
Intangible assets--SFAS No. 142, Goodwill and Other Intangible Assets,
provides that goodwill and other intangible assets with indefinite lives
will not be amortized, but will be tested for impairment on an annual
basis. Intangible assets with finite useful lives will be amortized over
their respective estimated useful lives and reviewed for impairment in
accordance with SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets. The Company adopted SFAS No. 142 on January 1, 2002.
The Company determined that as of January 1, 2002 goodwill was not
impaired and therefore no write-off was necessary. If goodwill had not
been amortized in 2001 and 2000, net income would have increased by $2.45
million in 2001 and $2.35 million in 2000. The following table presents
the effects of not amortizing goodwill on reported net income and basic
and diluted earnings per share.
(in thousands, except per share amounts) 2002 2001 2000
---------------------------------------- ---- ---- ----
Net income:
Reported net income $46,128 $43,603 $41,042
Add back: goodwill amortization, net of tax -- 2,449 2,353
------- ------- -------
Adjusted net income $46,128 $46,052 $43,395
======= ======= =======
Basic earnings per share:
Reported basic earnings per share $ 1.80 $ 1.69 $ 1.59
Add back: goodwill amortization, net of tax -- 0.10 0.10
------- ------- -------
Adjusted basic earnings per share $ 1.80 $ 1.79 $ 1.69
======= ======= =======
Diluted earnings per share:
Reported diluted earnings per share $ 1.79 $ 1.68 $ 1.59
Add back: goodwill amortization, net of tax -- 0.09 0.09
------- ------- -------
Adjusted diluted earnings per share $ 1.79 $ 1.77 $ 1.68
======= ======= =======
The changes in the carrying amount of goodwill by segment are as follows:
Adjustment to
Balance goodwill Goodwill Balance
December 31, acquired in acquired December 31,
(in thousands) 2001 2001 in 2002 2002
-------------- ------------ ------------- -------- ------------
Plastics $19,302 $ -- $ -- $19,302
Manufacturing 1,627 40 6,942 8,609
Health services 13,311 1,885 7,213 22,409
Other business operations 13,981 6 250 14,237
------- ------ ------- -------
Total $48,221 $1,931 $14,405 $64,557
======= ====== ======= =======
Intangible assets with finite lives are being amortized over average lives
that vary from one to five years. The amortization expense for these
intangible assets was $535,000 for 2002, $414,000 for 2001 and $357,000
for 2000. The estimated annual amortization expense for these intangible
assets for the next five years is: $525,000 for 2003, $486,000 for 2004,
$366,000 for 2005, $219,000 for 2006 and $107,000 for 2007.
Total other intangibles as of December 31 are as follows:
Gross Net
carrying Accumulated carrying
2002 (in thousands) amount amortization amount
------------------- --------- ------------ --------
Amortized intangible assets:
Covenants not to compete $1,920 $1,143 $ 777
Other intangible assets including contracts 2,079 884 1,195
------ ------ ------
Total $3,999 $2,027 $1,972
====== ====== ======
Non-amortized intangible assets:
Brandname $3,620 $ -- $3,620
====== ====== ======
2001 (in thousands)
-------------------
Amortized intangible assets:
Covenants not to compete $1,575 $ 933 $ 642
Other intangible assets including contracts 1,511 569 942
------ ------ ------
Total $3,086 $1,502 $1,584
====== ====== ======
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, 2002.
Adoption of new accounting pronouncements--The Company adopted SFAS No.
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 Company has
determined that certain electric energy contracts meet the criteria of a
derivative under SFAS No. 133 but qualify for the normal purchase and
normal sales exception and are not subject to mark-to-market accounting
treatment. SFAS No. 133 did not have a material effect on the Company's
2001 or 2002 consolidated results of operations, financial position or
cash flows.
In October 2002, the EITF of the Financial Accounting Standards Board
(FASB) reached a consensus on EITF Issue No. 02-3, Issues Related to
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. Any contracts within the scope of SFAS No. 133 that are
trading or held for trading and are settled physically should be reported
on a net basis. Any contracts within the scope of SFAS No. 133 that are
not considered trading and are settled physically should be reported on a
gross basis. As of December 31, 2002, none of the electric utility's
completed or open energy-only contracts were determined to be trading or
held for trading purposes.
The FASB has issued SFAS No. 143, Accounting for Asset Retirement
Obligations (ARO), 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
adopted SFAS No. 143 on January 1, 2003. Retirement obligations associated
with long-lived assets included within the scope of SFAS No. 143 are those
for which there is a legal obligation to settle under existing or enacted
law, statute, written or oral contract or by legal constructions under the
doctrine of promissory estoppel. Adoption of SFAS No. 143 will change the
accounting for ARO costs of the utility's generating plants as well as
certain other long-lived assets. Currently, estimated net salvage amounts
are part of depreciation expense accruals collected in the utility's rates
and reported in accumulated depreciation. SFAS No. 143 requires the
present value of the future decommissioning cost to be recognized as a
liability on the balance sheet with an offsetting amount being added to
the capitalized cost of the related long-lived asset. The liability will
be accreted to its present value each period and the capitalized cost will
be depreciated over the useful life of the related asset. The FERC issued
a proposed rulemaking on Accounting, Financial Reporting, and Rate Filing
Requirements for Asset Retirement Obligations on October 30, 2002.
The Company is in the process of evaluating what assets may have
associated retirement costs as defined by SFAS No. 143, and what the
prescribed accounting treatment will be under FERC rules. Preliminary
calculations indicate that estimated costs of current legal obligations
associated with asset retirement are already included in existing
accumulated depreciation. The estimated amount added to the generating
plant assets would be under $0.7 million. The estimated future obligation
under SFAS No. 143 is under $4.3 million, primarily for steam generating
plants, and the estimated current liability at the end of 2002 would be
near $2.2 million. The $1.5 million difference between the increase in
plant assets and the present value of the future ARO obligation represents
the cumulative effect of amounts that would have been accreted to the
liability from the time the generating assets were first placed in service
through December 31, 2002. The Company expects regulatory rules to be
adopted that will allow the cumulative effect of the accretion expense on
net income resulting from the adoption of SFAS No. 143 to be offset by a
credit to income and a charge to the accumulated reserve for depreciation
account or to a proposed regulatory asset account. Through 2002, the
Company has accrued $14.4 million in its depreciation reserve accounts for
all legal and other expected obligations at retirement of their steam
generating plants. Since the Company is already recovering these estimated
legal obligations and they are already recognized as recoverable for rate
regulation, the Company does not expect any impact on earnings as a result
of adopting SFAS No. 143.
The FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, in October 2001. SFAS No. 144 replaces SFAS No. 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 results of operations, financial position or
cash flows.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation--Transition and Disclosure. This Statement amends SFAS No.
123, Accounting for Stock-Based Compensation, to provide alternative
methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. In addition,
this Statement amends the disclosure requirements of SFAS No. 123 to
require prominent disclosures in both annual and interim financial
statements about the method of accounting for stock-based employee
compensation and the effect of the method used on reported results.
Certain amendments to SFAS No. 123 of this Statement shall be effective
for financial statements for fiscal years ending after December 15, 2002.
The Company currently follows the accounting provisions of APB 25,
Accounting for Stock Issued to Employees, for stock-based compensation and
provides the pro forma disclosures required under SFAS No. 123 as amended
by SFAS No. 148.
2. Business combinations, dispositions and segment information
On May 1, 2002 the Company acquired 100% of the outstanding stock of
Computed Imaging Service, Inc. (CIS) of Houston, Texas for 158,257 shares
of Otter Tail Corporation common stock and approximately $1.2 million in
cash. CIS provides computed tomography and magnetic resonance imaging
mobile services, interim rental, and sales and service of new, used and
refurbished diagnostic imaging equipment. CIS serves hospitals and other
healthcare facilities in the south central United States. The acquisition
of CIS allows the Company to expand its existing health services
operations into another region of the country. CIS annual revenues were
approximately $5.9 million in 2001.
On May 28, 2002 the Company acquired 100% of the outstanding stock of
ShoreMaster, Inc. (ShoreMaster), of Fergus Falls, Minnesota for 303,124
shares of Otter Tail Corporation common stock and $2.3 million in cash.
ShoreMaster is a leading manufacturer of waterfront equipment ranging from
residential-use boatlifts and docks to commercial marina systems. The
acquisition of ShoreMaster is expected to provide diversification and
growth opportunities for the Company's manufacturing segment.
ShoreMaster's annual revenues were approximately $20 million in 2001.
On October 1, 2002 the Company acquired 100% of the outstanding stock of
Galva Foam Marine Industries, Inc. (Galva Foam), of Camdenton, Missouri
for 256,940 shares of Otter Tail Corporation common stock and
approximately $1.0 million in cash. Galva Foam is a leading manufacturer
of waterfront equipment ranging from residential boatlifts and docks to
commercial marina systems. The acquisition of Galva Foam in combination
with the May 2002 acquisition of ShoreMaster will expand the market reach
of the Company's waterfront manufacturing product line nationwide with
both saltwater and freshwater products. Galva Foam had annual revenues of
approximately $13 million in 2001.
In 2002, the Company also acquired two other businesses, neither of which
was individually material, one in energy management services and the other
in health services. The total purchase price for these businesses was
approximately $2 million in cash.
All of the 2002 acquisitions were accounted for using the purchase method
of accounting. The pro forma effect of these acquisitions on 2001 and 2000
revenues, net income or earnings per share was not significant.
Below is a condensed balance sheet disclosing the fair value assigned to
each major asset and liability category of the acquired companies.
(in thousands) CIS ShoreMaster Galva Foam Others
-------------- --- ----------- ---------- ------
Assets
Current assets $ 1,439 $ 9,510 $4,953 $ 131
Plant 3,975 4,599 1,713 298
Goodwill 5,847 4,292 2,650 1,616
Other intangible assets 30 4,461 41 60
------- ------- ------ ------
Total assets $11,291 $22,862 $9,357 $2,105
======= ======= ====== ======
Liabilities and equity
Current liabilities $ 1,747 $ 9,642 $2,304 $ 32
Long-term debt 2,584 2,723 -- --
Other long-term liabilities 707 797 372 --
Equity 6,253 9,700 6,681 2,073
------- ------- ------ ------
Total liabilities and equity $11,291 $22,862 $9,357 $2,105
======= ======= ====== ======
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 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 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 excess of the purchase price over the net
assets acquired was immaterial.
The above 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 No. 141. Under the transition provision of SFAS No. 142, no
goodwill was amortized for these acquisitions during 2001. The pro forma
effect of these acquisitions on 2000 revenues, net income, or earnings per
share was not significant.
On February 28, 2001 the Company acquired all of the outstanding 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 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.
The above two acquisitions were accounted for as 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 SFAS No. 141. The Company's consolidated financial statements
for 2000 were restated to reflect the effects of the poolings.
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.
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 operating 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.
Manufacturing consists of businesses involved in the production of
waterfront equipment, wind towers, frame-straightening equipment and
accessories for the auto repair industry, custom plastic pallets, material
and handling trays, horticultural containers, fabrication of steel
products, contract machining, and metal parts stamping and fabrication
located in the Upper Midwest, Missouri and Utah.
Health services include businesses involved in the sale of diagnostic
medical equipment, supplies and accessories. These businesses also provide
service maintenance, mobile diagnostic imaging, mobile positron emission
tomography and nuclear medicine imaging, portable x-ray imaging and rental
of diagnostic medical imaging equipment to various medical institutions
located in 40 states.
Other business operations consists of businesses 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 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 2002,
2001 and 2000 is presented in the following table.
2002 2001 2000
--------- --------- --------
(in thousands)
Operating revenue
Electric $ 307,403 $ 307,684 $262,280
Plastics 82,931 63,216 82,667
Manufacturing 142,390 123,436 97,506
Health services 93,420 79,129 66,319
Other business operations 83,972 80,667 78,159
--------- --------- --------
Total $ 710,116 $ 654,132 $586,931
========= ========= ========
Operating income
Electric $ 53,720 $ 57,150 $ 49,268
Plastics 11,136 (1,391) 8,745
Manufacturing 9,771 12,175 6,945
Health services 8,370 6,862 5,729
Other business operations (1,015) 2,688 3,561
--------- --------- --------
Total operating income $ 81,982 $ 77,484 $ 74,248
Other income and deductions - net 2,057 2,193 2,154
Interest charges 17,850 15,991 17,005
--------- --------- --------
Income before income taxes $ 66,189 $ 63,686 $ 59,397
========= ========= ========
Depreciation and amortization
Electric $ 24,910 $ 24,272 $ 23,778
Plastics 1,760 3,229 3,301
Manufacturing 6,525 5,139 3,930
Health services 4,410 3,517 2,981
Other business operations 5,008 5,943 6,572
--------- --------- --------
Total $ 42,613 $ 42,100 $ 40,562
========= ========= ========
Capital expenditures
Electric $ 45,842 $ 34,992 $ 24,659
Plastics 5,592 1,572 3,361
Manufacturing 15,049 10,516 8,688
Health services 3,874 3,282 2,871
Other business operations 5,176 3,234 6,694
--------- --------- --------
Total $ 75,533 $ 53,596 $ 46,273
========= ========= ========
Identifiable assets
Electric $ 550,855 $ 523,948 $531,778
Plastics 54,926 45,649 49,831
Manufacturing 114,120 67,033 59,130
Health services 64,785 50,560 32,909
Other business operations 94,050 95,351 64,060
--------- --------- --------
Total $ 878,736 $ 782,541 $737,708
========= ========= ========
No single external customer accounts for 10% 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 state personal property tax. The law also
requires that any property tax savings resulting from this exemption be
refunded to utility customers. As a result of this law, $272,600 in 2001
property tax savings was refunded to Minnesota retail electric customers
in 2002. On January 1, 2003 a Property Tax Reduction Rider became
effective which reduces base electric rates by 0.27% to reflect ongoing
tax savings.
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. This plan provides the opportunity
for the electric utility to raise its allowed rate of return and shares
income with customers when earnings exceed the allowed return. During
2001, the electric utility achieved a rate of return on equity that
exceeded targets under the plan which resulted in a sharing of the income
between shareholders and customers and led to a $662,300 refund to North
Dakota retail electric customers in 2002. The electric utility's 2002 rate
of return is expected to be within the allowable range defined in the
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.
4. Regulatory assets and liabilities
The following table indicates the amount of regulatory assets and
liabilities recorded on the Company's consolidated balance sheet:
December 31, December 31,
(in thousands) 2002 2001
-------------- ------------ ------------
Regulatory assets:
Deferred income taxes $10,238 $ 5,117
Debt expenses and reacquisition premiums 4,323 3,353
Deferred conservation program costs 844 1,059
Plant acquisition costs 329 373
Accrued cost-of-energy revenue 768 --
------- -------
Total regulatory assets $16,502 $ 9,902
------- -------
Regulatory liabilities:
Deferred income taxes $ 8,960 $ 9,735
Gain on sale of division office building 173 179
------- -------
Total regulatory liabilities $ 9,133 $ 9,914
------- -------
Net regulatory position $ 7,369 $ (12)
======= =======
The regulatory assets and liabilities related to deferred income taxes are
the result of the adoption of SFAS No. 109, Accounting for Income Taxes.
Deferred conservation program costs included in Deferred debits - Other
represent mandated conservation expenditures recoverable through rates
over the next 1.5 years. Plant acquisition costs included in Deferred
debits - Other will be amortized over the next eight years. Accrued
cost-of-energy revenue included in Accrued utility revenues will be
recovered over the next six months. The remaining regulatory assets and
liabilities are being recovered from electric customers over the next 32
years.
If for any reason, the Company's regulated businesses cease to meet the
criteria for application of SFAS No. 71 for all or part of their
operations, the regulatory assets and liabilities that no longer meet such
criteria would be removed from the consolidated balance sheet and included
in the consolidated statement of income as an extraordinary item in the
period in which the application of SFAS No. 71 ceases.
5. Common shares and earnings per share
New issuances--Common stock issuances during 2002 included 718,321
unregistered shares exchanged in acquisitions, 131,167 shares issued as a
result of stock options exercised, 3,382 shares issued as directors'
compensation and 85,800 shares of restricted stock issued as officers' and
directors' compensation.
Stock incentive plan--Under the 1999 Stock Incentive Plan (Incentive Plan)
a total of 2,600,000 common shares were authorized for granting 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, 2002 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 $75,000
at December 31, 2002, and is included as a reduction of common equity.
Presented below is a summary of the stock options activity:
Stock Option Activity 2002 2001 2000
-------------------- -------------------- ------------------
Average Average Average
exercise exercise exercise
Options price Options price Options price
------- ----- ------- ----- ------- -----
Outstanding, beginning of year 1,265,042 $22.62 787,316 $19.55 442,900 $19.25
Granted 278,750 31.34 582,000 26.33 360,000 19.75
Exercised 130,797 19.71 74,936 19.44 750 19.19
Forfeited 52,274 22.83 29,338 22.17 14,834 19.30
---------- ------ ---------- ------ --------- ------
Outstanding, year end 1,360,721 24.68 1,265,042 22.62 787,316 19.55
---------- ------ ---------- ------ --------- ------
Exercisable, year end 449,385 $21.75 257,269 $19.83 127,542 $19.25
Fair value of options
granted during year $ 7.07 $ 5.88 $ 3.79
The fair value of the options granted were estimated using the Black-Scholes
option-pricing model under the following assumptions:
2002 2001 2000
---- ---- ----
Risk free interest rate 5.2% 5.5% 5.2%
Expected lives 7 years 7 years 7 years
Expected volatility 26.0% 24.9% 23.7%
Dividend yield 4.0% 4.0% 4.5%
The following table summarizes information about options outstanding as of
December 31, 2002:
Options outstanding Options exercisable
--------------------------------------------------------------------------------
Weighted-
average Weighted- Weighted-
Outstanding remaining average Exercisable average
Range of as of contractual exercise as of exercise
exercise prices 12/31/02 life (yrs) price 12/31/02 price
- --------------- ----------- ----------- --------- ----------- ---------
$18.80-$21.94 539,596 6.6 $ 19.47 297,510 $ 19.41
$21.95-$25.07 -- -- -- -- --
$25.08-$26.77 526,375 8.3 $ 26.25 147,875 $ 26.25
$26.78-$31.34 294,750 9.2 $ 31.23 4,000 $ 29.34
In addition to the stock options granted, 85,800, 1,681 and 12,415 shares
of restricted stock were granted during 2002, 2001 and 2000, respectively.
The total compensation cost recognized in income for stock-based employee
compensation awards was $879,000 in 2002, $125,000 in 2001 and $314,000 in
2000. See note 1 for pro forma stock option information.
Employee stock purchase plan--The 1999 Employee Stock Purchase Plan
(Purchase Plan) allows eligible employees to purchase the Company's common
shares at 85% 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. To provide
shares for the Purchase Plan, common shares were purchased in the open
market totaling 57,997 shares in 2002, 56,612 shares in 2001 and 53,630
shares in 2000.
Dividend reinvestment and share purchase plan--On August 30, 1996 the
Company filed a shelf registration statement with the Securities and
Exchange Commission (SEC) 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 in the open market. Since June 1999,
common shares needed for the Plan have been purchased in the open market.
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% or more,
or commenced a tender or exchange offer for 15% 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.
Earnings per share--Basic earnings per common share are calculated by
dividing earnings available for common shares by the average number of
common shares outstanding during the period. Diluted earnings per common
share are calculated by adjusting outstanding shares, assuming conversion
of all potentially dilutive stock options.
6. Retained earnings restriction
The Company's Articles of Incorporation, as amended, contain provisions
that limit the amount of dividends that may be paid to common shareholders
by the amount of any declared but unpaid dividends to holders of the
Company's cumulative preferred shares. Under these provisions none of the
Company's retained earnings were restricted at December 31, 2002.
7. Commitments and contingencies
At December 31, 2002 the electric utility had commitments under contracts
in connection with construction programs aggregating approximately
$6,563,000. For capacity and energy requirements the electric utility has
agreements extending through 2007, at annual costs of approximately
$15,104,000 in 2003, $14,435,000 in 2004, $12,932,000 in 2005, $12,200,000
in 2006 and $12,217,000 in 2007.
The electric utility has contracts providing for the purchase and delivery
of a significant portion of its current coal requirements. These contracts
expire between 2003 and 2016. In total, the electric utility is committed
to the minimum purchase of approximately $92,674,000 or to make payments
in lieu thereof, under these contracts. The cost-of-energy adjustment
mechanism 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 Nonelectric
utility companies Total
------- --------- -----
(in thousands)
2003 $ 1,799 $17,995 $19,794
2004 1,592 14,576 16,168
2005 1,302 11,856 13,158
2006 1,302 6,444 7,746
2007 1,302 2,401 3,703
Later years 3,547 650 4,197
------- ------- -------
Total $10,844 $53,922 $64,766
======= ======= =======
Rent expense was $22,282,000, $20,242,000 and $16,595,000, for 2002, 2001
and 2000, respectively.
The Company occasionally is 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, financial position and cash flows,
if any, for the disposition of all currently pending matters will not be
material.
8. Short-term and Long-term borrowings
Short-term debt--The Company has a $50 million line of credit. This line
of credit bears interest at the rate of LIBOR plus 0.5% and expires on
April 29, 2003. The Company does not anticipate any difficulties in
renewing this line of credit. The Company's bank line of credit is a key
source of operating capital and can provide interim financing of working
capital and other capital requirements, if needed. The Company's
obligations under this line of credit are guaranteed by a 100%-owned
subsidiary of the Company that owns substantially all of the Company's
nonelectric companies. As of December 31, 2002, $30 million of the $50
million line was in use.
The interest rate under the line of credit is subject to adjustment in the
event of a change in ratings on the Company's senior unsecured debt, up to
LIBOR plus 0.8% if the ratings on the Company's senior unsecured debt fall
to BBB+ or below (Standard & Poor's) or Baa1 or below (Moody's). The line
of credit also provides for accelerated repayment in the event the
Company's long-term senior unsecured debt is rated below BBB- (Standard &
Poor's) or Baa3 (Moody's).
Long-term debt--In 2002, the Company filed with the SEC a shelf
registration statement for $200 million of unsecured debt securities. On
September 27, 2002 the Company issued $65 million of senior unsecured
notes under the shelf registration statement. The offering consisted of
$40 million of 5.625% insured senior notes due 2017 and $25 million of
6.80% senior notes due 2032. Net proceeds from these issues were used to
pay off short-term debt that was used to retire the Company's 7.25% series
first mortgage bonds at maturity on August 1, 2002 in the amount of $18.2
million, and to retire early on October 31, 2002 the Company's outstanding
$27.3 million 8.25% series 2022 first mortgage bonds at an aggregate
redemption price of $28.5 million. The remaining proceeds were used to
repay short-term debt used to finance a portion of the costs related to
the new gas-fired combustion turbine plant being constructed by the
electric utility.
As a result of the financing described above, the Company repaid all of
its outstanding first mortgage bonds and terminated its first mortgage
indenture. The Company has the ability to issue up to an additional $135
million of unsecured debt securities from time to time under its shelf
registration statement on file with the SEC. Proceeds from subsequent debt
issuances under the shelf registration, if any, may be used for other
general corporate purposes, including working capital, capital
expenditures, debt repayment, the financing of possible acquisitions or
stock repurchases.
The Company's 6.63% senior notes contain an investment grade put that
could require the Company to prepay this series with a make-whole premium
if the Company's senior unsecured debt is rated below Baa3 (Moody's) or
BBB- (Standard & Poor's). The Company's obligations under the 6.63% senior
notes are guaranteed by a 100%-owned subsidiary of the Company that owns
substantially all of the Company's nonelectric companies. The Company's
Grant County and Mercer County pollution control refunding revenue bonds
require that the Company grant to Ambac Assurance Corporation, under a
financial guaranty insurance policy relating to the bonds, a security
interest in the assets of the electric utility if the rating on the
Company's senior unsecured debt is downgraded to Baa2 or below (Moody's)
or BBB or below (Standard & Poor's and Fitch). The Company believes the
risk of the downgrade events described in this paragraph occurring is
remote based on the current bond ratings of the Company combined with its
strong debt-to-equity ratio and ability to generate cash from operations.
The aggregate amounts of maturities on bonds outstanding and other
long-term obligations at December 31, 2002 for each of the next five years
are $7,827,000 for 2003, $7,194,000 for 2004, $5,678,000 for 2005,
$3,301,000 for 2006 and $50,837,000 for 2007.
Covenants--The Company's line of credit and its $90 million 6.63% senior
notes due 2011 contain a number of covenants that restrict the Company's
ability, with significant exceptions, to: engage in mergers or
consolidations; dispose of assets; create liens on assets; engage in
transactions with affiliates; take any action which would result in a
decrease in the ownership interest in any subsidiary; redeem stock or any
subsidiary's stock and pay dividends on stock; make investments, loans or
advances; guaranty the obligations of other persons or
agree to maintain the net worth or working capital of, or provide funds to
satisfy any other financial test applicable to, any other person; and
enter into a contract that requires payment to be made by the Company
whether or not delivery of the materials, supplies or services is ever
made under the contract. In addition, specified financial covenants under
the line of credit and the 6.63% senior notes require a debt-to-total
capitalization ratio not in excess of 60% and an interest and dividend
coverage ratio of at least 1.5 to 1. The 6.63% senior notes also require
that priority debt not be in excess of 20% of total capitalization.
As of December 31, 2002 the Company was in compliance with all of the
covenants under its line of credit and its other debt obligations.
9. 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% 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. Four investment managers are responsible for managing the plan's
assets. An independent actuary performs the necessary actuarial valuations
for the plan.
Net periodic pension cost/(income) for 2002, 2001 and 2000 includes the
following components:
2002 2001 2000
-------- -------- --------
(in thousands)
Service cost--benefit earned during the period $ 3,120 $ 2,544 $ 2,458
Interest cost on projected benefit obligation 9,269 8,766 8,439
Expected return on assets (14,957) (14,610) (13,662)
Amortization of transition asset (73) (235) (235)
Amortization of prior-service cost 1,285 1,107 1,107
Amortization of net gain (1,284) (1,900) (1,869)
-------- -------- --------
Net periodic pension cost/(income) $ (2,640) $ (4,328) $ (3,762)
======== ======== ========
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, 2002 and a statement of the funded status as of
December 31 of both years:
2002 2001
--------- ---------
Reconciliation of benefit obligation: (in thousands)
Obligation at January 1 $ 124,523 $ 116,444
Service cost 3,120 2,544
Interest cost 9,269 8,766
Benefit payments (7,760) (7,563)
Plan amendments 2,770 --
Actuarial loss 13,340 4,332
--------- ---------
Obligation at December 31 $ 145,262 $ 124,523
========= =========
Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1 $ 138,794 $ 153,649
Actual return on plan assets (17,231) (7,292)
Benefit payments (7,760) (7,563)
--------- ---------
Fair value of plan assets at December 31 $ 113,803 $ 138,794
========= =========
Reconciliation of funded status:
Accumulated benefit obligation $(119,235) $ (95,390)
Projected benefit obligation (145,262) (124,523)
Market value of fund assets 113,803 138,794
--------- ---------
Funded status (31,459) 14,271
Unrecognized transition asset -- (73)
Unrecognized prior-service cost 8,195 6,710
Unrecognized net loss/(gain) 32,981 (13,831)
--------- ---------
Prepaid pension cost 9,717 7,077
Additional minimum liability (15,149) --
--------- ---------
Net pension (liability)/asset $ (5,432) $ 7,077
========= =========
The following table provides the amounts recognized in the Consolidated
Balance Sheets as of December 31 of both years:
2002 2001
------- ------
(in thousands)
Net pension (liability)/asset $(5,432) $7,077
Intangible asset 8,195 --
Accumulated other comprehensive loss 6,954 --
------- ------
Net amount recognized $ 9,717 $7,077
======= ======
The assumptions used for actuarial valuations were:
2002 2001
---- ----
Discount rate
Used for net periodic pension cost 7.50% 7.75%
Used to value pension (liability)/asset at year end 6.75% 7.50%
Rate of increase in future compensation level 4.25% 4.25%
Long-term rate of return on assets 9.50% 9.50%
The assumed rate of return on pension fund assets for the determination of 2003
net periodic pension cost is 8.5%.
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 2002, 2001 and 2000 includes the following
components:
2002 2001 2000
------- ------- -------
(in thousands)
Service cost--benefit earned during the period $ (51) $ (76) $ (136)
Interest cost on projected benefit obligation 1,175 956 798
Amortization of transition obligation -- -- 17
Amortization of prior-service cost 86 191 191
Recognized net actuarial loss 398 117 1
------- ------- -------
Net periodic pension cost $ 1,608 $ 1,188 $ 871
Early retirement benefit 240 -- 711
------- ------- -------
Total $ 1,848 $ 1,188 $ 1,582
======= ======= =======
The following tables provide a reconciliation of the changes in the plan's
benefit obligations over the two-year period ending December 31, 2002 and
a statement of the funded status as of December 31 of both years:
2002 2001
-------- --------
Reconciliation of benefit obligation: (in thousands)
Obligation at January 1 $ 14,365 $ 12,713
Service cost (51) (76)
Interest cost 1,175 956
Plan amendments (182) (939)
Actuarial loss 5,566 2,451
Early retirement 240 --
Benefit payments (804) (740)
-------- --------
Obligation at December 31 $ 20,309 $ 14,365
======== ========
Funded status:
Funded status at December 31 $(20,309) $(14,365)
Unrecognized prior-service cost 836 1,104
Unrecognized net actuarial loss 10,292 5,124
-------- --------
Net amount recognized $ (9,181) $ (8,137)
======== ========
The following table provides the amounts recognized in the Consolidated
Balance Sheets as of December 31:
2002 2001
-------- --------
(in thousands)
Accrued benefit liability $(15,052) $(11,216)
Intangible asset 836 1,104
Accumulated other comprehensive loss 5,035 1,975
-------- --------
Net amount recognized $ (9,181) $ (8,137)
======== ========
The assumptions used for actuarial valuations were:
2002 2001
---- ----
Discount rate
Used for net periodic pension cost 7.50% 7.75%
Used to value pension liability at year end 6.75% 7.50%
Rate of increase in future compensation level 5.63% 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 No.
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 2002, 2001 and 2000
includes the following components:
2002 2001 2000
------- ------- ------
(in thousands)
Service cost--benefit earned during the period $ 615 $ 681 $ 688
Interest cost on accumulated
postretirement benefit obligation 2,166 1,768 1,701
Amortization of transition obligation 748 748 748
Amortization of prior-service cost (305) 111 111
Life insurance benefits -- -- 865
Amortization of net gain -- (51) --
------- ------- ------
Net periodic postretirement benefit cost $ 3,224 $ 3,257 $4,113
======= ======= ======
The following tables provide a reconciliation of the changes in the plan's
benefit obligations over the two-year period ending December 31, 2002 and
a statement of the funded status as of December 31 of both years:
2002 2001
-------- --------
Reconciliation of benefit obligation: (in thousands)
Obligation at January 1 $ 28,550 $ 24,606
Service cost 615 681
Interest cost 2,166 1,768
Benefit payments (2,436) (2,264)
Participant premium payments 953 682
Plan amendments (285) --
Actuarial loss 9,755 3,077
-------- --------
Obligation at December 31 $ 39,318 $ 28,550
======== ========
Funded status:
Funded status at December 31 $(39,318) $(28,550)
Unrecognized transition obligation 7,482 8,230
Unrecognized prior-service cost 395 375
Unrecognized loss 11,059 1,304
-------- --------
Net amount recognized $(20,382) $(18,641)
======== ========
The following table provides the amounts recognized in the Consolidated
Balance Sheets as of December 31:
2002 2001
-------- --------
(in thousands)
Accrued benefit liability $(20,382) $(18,641)
The assumed health-care cost-trend rate used in measuring the accumulated
postretirement benefit obligation as of December 31, 2002 was 12.0% for
2003, decreasing linearly each successive year until it reaches 5.0% in
2010, after which it remains constant. The assumed discount rate used in
determining the accumulated postretirement benefit obligation was 6.75% as
of December 31, 2002 and 7.50% as of December 31, 2001.
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 2002 would have the following
effects:
1 point 1 point
increase decrease
-------- --------
(in thousands)
Effect on total of service and interest
cost components $ 361 $ (309)
Effect on the postretirement benefit obligation $4,662 $(3,894)
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 both 2002 and 2001 and $1,130,000 for 2000.
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.
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 $15.5 million of the Company's long-term debt,
which is subject to variable interest rates, approximates fair value.
2002 2001
------------------------ ------------------------
(in thousands)
Carrying Fair Carrying Fair
amount value amount value
--------- --------- --------- ---------
Cash and short-term investments $ 9,937 $ 9,937 $ 11,378 $ 11,378
Other investments 18,439 18,439 18,009 18,009
Long-term debt (258,229) (277,261) (227,360) (255,785)
11. Property, plant and equipment
2002 2001
-------- --------
(December 31, in thousands)
Electric plant:
Production $314,093 $313,013
Transmission 172,610 158,639
Distribution 268,400 258,774
General 80,279 80,044
-------- --------
Electric plant 835,382 810,470
Less accumulated depreciation and amortization 392,931 376,241
-------- --------
Electric plant net of accumulated depreciation 442,451 434,229
Construction work in progress 39,123 25,094
-------- --------
Net electric plant $481,574 $459,323
-------- --------
Nonelectric operations plant $178,656 $145,712
Less accumulated depreciation and amortization 74,828 65,622
-------- --------
Nonelectric plant net of accumulated depreciation 103,828 80,090
Construction work in progress 2,484 3,564
-------- --------
Net nonelectric operations plant $106,312 $ 83,654
-------- --------
Net plant $587,886 $542,977
======== ========
The estimated service lives for rate-regulated properties is 5 to 65 years. For
nonelectric property the estimated useful lives are from 3 to 40 years.
Service Life Range
------------------
(years) Low High
------- --- ----
Electric fixed assets:
Production plant 34 62
Transmission plant 40 55
Distribution plant 15 55
General plant 5 65
Nonelectric fixed assets 3 40
12. Income taxes
The total income tax expense differs from the amount computed by applying
the federal income tax rate (35% in 2002, 2001 and 2000) to net income
before total income tax expense for the following reasons:
2002 2001 2000
-------- -------- --------
(in thousands)
Tax computed at federal statutory rate $ 23,167 $ 22,290 $ 20,789
Increases (decreases) in tax from:
State income taxes net of federal income tax
benefit 2,441 2,564 2,279
Investment tax credit amortization (1,152) (1,176) (1,183)
Differences reversing in excess of federal rates (1,055) (503) (774)
Dividend received/paid deduction (699) (674) (670)
Affordable housing tax credits (1,418) (1,418) (1,414)
Permanent and other differences (1,223) (1,000) (672)
-------- -------- --------
Total income tax expense $ 20,061 $ 20,083 $ 18,355
======== ======== ========
Overall effective federal and state income tax rate 30.3% 31.5% 30.9%
Income tax expense includes the following:
Current federal income taxes $ 18,651 $ 21,110 $ 21,835
Current state income taxes 3,856 3,107 4,162
Deferred federal income taxes 15 (2,247) (4,717)
Deferred state income taxes 109 707 (328)
Affordable housing tax credits (1,418) (1,418) (1,414)
Investment tax credit amortization (1,152) (1,176) (1,183)
-------- -------- --------
Total $ 20,061 $ 20,083 $ 18,355
======== ======== ========
The Company's deferred tax assets and liabilities were composed of the
following on December 31, 2002 and 2001:
2002 2001
--------- ---------
(in thousands)
Deferred tax assets
Amortization of tax credits $ 8,345 $ 9,098
Vacation accrual 1,836 1,892
Unearned revenue 1,420 1,850
Operating reserves 15,690 13,552
Differences related to property 5,239 4,394
Transfer to regulatory liability 618 577
Other 2,956 2,025
--------- ---------
Total deferred tax assets $ 36,104 $ 33,388
========= =========
Deferred tax liabilities
Differences related to property (109,224) (104,764)
Excess tax over book pension (3,855) (2,812)
Transfer to regulatory asset (10,237) (5,053)
Other (2,448) (2,330)
--------- ---------
Total deferred tax liabilities $(125,764) $(114,959)
--------- ---------
Deferred income taxes $ (89,660) $ (81,571)
========= =========
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
------------------- ------------------- ------------------- -------------------
2002 2001 2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- -------- -------- --------
(in thousands, except per share data)
Operating revenues $157,733 $159,654 $176,572 $157,332 $185,750 $177,674 $190,061 $159,472
Operating income 18,935 22,438 19,848 15,720 23,008 20,310 20,191 19,016
Net income 10,032 12,000 10,587 9,157 12,882 11,077 12,627 11,369
Earnings available for common shares 9,848 11,530 10,403 8,688 12,698 10,607 12,443 10,785
Basic earnings per share $ .40 $ .47 $ .41 $ .35 $ .50 $ .43 $ .49 $ .44
Diluted earnings per share .40 .47 .41 .35 .50 .43 .48 .43
Dividends paid per common share .265 .26 .265 .26 .265 .26 .265 .26
Price range:
High $ 31.80 $ 31.00 $ 34.90 $ 30.10 $ 31.50 $ 30.00 $ 29.23 $ 29.45
Low 25.75 23.00 28.50 24.12 22.82 26.75 25.22 27.50
Average number of common shares
outstanding--basic 24,668 24,577 25,117 24,586 25,328 24,606 25,589 24,633
Average number of common shares
outstanding--diluted 24,919 24,776 25,412 24,799 25,497 24,881 25,781 24,912
Otter Tail Corporation Stock Listing
Otter Tail Corporation common stock trades on The Nasdaq Stock Market.