##### 



Exhibit 13-A Selected Consolidated Financial Data (thousands, except number of shareholders and per-share data)
    
    2003
    
    2002
    
    2001
    
    2000 (1)
    
    1999 (1) (2)
    
    1998 (3)
    
    1993RevenuesElectric (7)
    
    $
    267,494
    
    
    $
    244,005
    
    
    $
    232,720
    
    
    $
    219,718
    
    
    $
    203,393
    
    
    $
    206,895
    
    
    $
    180,912Plastics
    
    
    86,009
    
    
    
    82,931
    
    
    
    63,216
    
    
    
    82,667
    
    
    
    31,504
    
    
    
    24,946
    
    
    
    Manufacturing
    
    
    177,805
    
    
    
    142,390
    
    
    
    123,436
    
    
    
    97,506
    
    
    
    87,086
    
    
    
    62,488
    
    
    
    8,473Health services
    
    
    100,912
    
    
    
    93,420
    
    
    
    79,129
    
    
    
    66,319
    
    
    
    68,805
    
    
    
    69,412
    
    
    
    32,068Other business operations
    
    
    123,475
    
    
    
    84,627
    
    
    
    80,667
    
    
    
    78,159
    
    
    
    68,322
    
    
    
    48,829
    
    
    
    32,396Intersegment eliminations
    
    
    (2,456
    )
    
    
    (1,036
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total operating revenues
    
    $
    753,239
    
    
    $
    646,337
    
    
    $
    579,168
    
    
    $
    544,369
    
    
    $
    459,110
    
    
    $
    412,570
    
    
    $
    253,849Special charges
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,522
    
    
    
    Income from continuing operations
    
    
    39,656
    
    
    
    46,128
    
    
    
    43,603
    
    
    
    41,042
    
    
    
    45,295
    
    
    
    30,701
    
    
    
    27,369Cumulative change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,819
    
    
    
    Cash flow from operations
    
    
    76,955
    
    
    
    76,797
    
    
    
    77,529
    
    
    
    61,761
    
    
    
    81,850
    
    
    
    63,959
    
    
    
    53,255Capital expenditures
    
    
    50,734
    
    
    
    75,533
    
    
    
    53,596
    
    
    
    46,273
    
    
    
    35,245
    
    
    
    29,289
    
    
    
    30,894Total assets (6)
    
    
    986,423
    
    
    
    914,112
    
    
    
    817,778
    
    
    
    772,562
    
    
    
    729,118
    
    
    
    690,189
    
    
    
    597,482Long-term debt
    
    
    265,193
    
    
    
    258,229
    
    
    
    227,360
    
    
    
    195,128
    
    
    
    180,159
    
    
    
    181,046
    
    
    
    166,563Redeemable preferred
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18,000
    
    
    
    18,000
    
    
    
    18,000
    
    
    
    18,000Basic
earnings per share from continuingoperations (4)
    
    
    1.52
    
    
    
    1.80
    
    
    
    1.69
    
    
    
    1.59
    
    
    
    1.75
    
    
    
    1.20
    
    
    
    1.11Diluted
earnings per share from continuing
operations (4)
    
    
    1.51
    
    
    
    1.79
    
    
    
    1.68
    
    
    
    1.59
    
    
    
    1.75
    
    
    
    1.20
    
    
    
    1.11Return on average common equity
    
    
    12.2
    %
    
    
    15.3
    %
    
    
    15.5
    %
    
    
    15.4
    %
    
    
    18.4
    %
    
    
    15.0
    %
    
    
    14.9
    %Dividends per common share
    
    
    1.08
    
    
    
    1.06
    
    
    
    1.04
    
    
    
    1.02
    
    
    
    0.99
    
    
    
    0.96
    
    
    
    0.84Dividend payout ratio
    
    
    72
    %
    
    
    59
    %
    
    
    62
    %
    
    
    64
    %
    
    
    57
    %
    
    
    71
    %
    
    
    76
    %Common shares outstanding  year end
    
    
    25,724
    
    
    
    25,592
    
    
    
    24,653
    
    
    
    24,574
    
    
    
    24,571
    
    
    
    23,759
    
    
    
    22,360Number of common shareholders (5)
    
    
    14,723
    
    
    
    14,503
    
    
    
    14,358
    
    
    
    14,103
    
    
    
    13,438
    
    
    
    13,699
    
    
    
    13,634
 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)
    
    1999 results include the sale of radio station assets 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.(6)
    
    Prior years are restated to reflect reclassification of reserve for estimated removal costs from accumulated depreciation to a regulatory liability.(7)
    
    Prior years are restated to reflect implementation of a new accounting standard, EITF Issue 03-11. See note 1 to consolidated financial statements for more information.




---



##### 



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 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 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-term and
long-term debt ratings assigned by independent rating agencies, which in part
are based on certain credit measures such as interest coverage and leverage
ratios. The Company has achieved a high degree of long-term liquidity by maintaining
desired capitalization ratios and strong credit ratings, implementing
cost-containment programs, and investing in projects that provide returns in
excess of the Companys weighted average cost of capital. Cash provided by operating activities of $77.0 million for the year ended
December 31, 2003 combined with cash on hand of $9.9 million at December 31,
2002 allowed the Company to pay dividends and finance all of its capital
expenditures in 2003. Cash provided by operating activities in 2003 was $77.0 million compared with
$76.8 million in 2002. The slight increase in cash from operations includes a
$7.0 million increase in noncurrent liabilities and deferred credits and a $3.3
million increase in noncash depreciation and amortization expense offset by a
$6.5 million decrease in net income and a $4.5 million increase in cash used
for working capital items. The $19.2 million decrease in net cash used in investing activities between
2003 and 2002 reflects a decrease in capital expenditures of $24.8 million and
$1.6 million in cash from redemption of other investments offset by a $6.3
million increase in cash used to complete acquisitions and a $0.8 million
decrease in cash from disposal of assets. The decrease in consolidated capital
expenditures reflects a high level of capital expenditures in 2002, a year that
saw major plant additions and equipment purchases in all segments including the
electric utilitys expenditures for a new transmission line completed in 2002
and a new gas-fired combustion turbine that came online in June 2003. In 2003, the Company completed three acquisitions: Two medical equipment
companies were purchased for an aggregate of $1.9 million in cash. In November
2003, the Company acquired the assets and operations of Foley Company, a
mechanical and prime contracting firm based in Kansas City, Missouri, for $12.3
million in cash.




---



##### 



Net cash used in financing activities was $19.2 million in 2003 compared with
$1.4 million provided by financing activities in 2002. The $20.6 million
decrease between the years is due to the following:  
    
    Net short-term borrowings were $25.5 million less in 2003 than in
2002.
    
    Net proceeds from the issuance and retirement of long-term debt,
including debt issuance expenses, were $8.4 million higher in 2003 than
in 2002.
    
    Proceeds from employee stock plans decreased by $2.0 million in 2003
compared to 2002 due to a 64% reduction in the number of stock options
exercised in 2003.
    
    Dividends paid and other distributions increased by $1.5 million in
2003. On September 24, 2003 the Company borrowed $16.3 million under a loan agreement
with Lombard US Equipment Finance Corporation in the form of an unsecured note.
The note bears interest at a variable rate of 3-month LIBOR plus 1.43% on the
unpaid principal balance. The Company used proceeds from the note to pay down
borrowings under the Companys line of credit that were used to finance
acquisitions and capital expenditures of its nonelectric subsidiaries. The
covenants associated with the note are consistent with existing credit
facilities. There are no rating triggers associated with this note. During 2003, 47,552 shares of common stock were issued for stock options
exercised under the 1999 Stock Incentive Plan generating proceeds of $1.0
million. Also in 2003, in noncash transactions, the Company granted 90,900
shares of restricted stock to certain key executives and directors and issued
2,169 common shares for director compensation under the 1999 Stock Incentive
Plan. 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 2003, 2002 and 2001 were $50.7
million, $75.5 million and $53.6 million, respectively. The estimated capital
expenditures for 2004 are $40.8 million and the total capital expenditures for
the five-year period 2004 through 2008 are estimated to be approximately $208
million. (side-by-side bar graph of data with cash realization ratio data labels in the
following table) CASH REALIZATION RATIOS
(millions) 2001
    
    2002
    
    2003Cash flows from operations
    
    $
    78
    
    
    $
    77
    
    
    $
    77Net income
    
    $
    44
    
    
    $
    46
    
    
    $
    40Cash realization ratios
    
    
    178
    %
    
    
    166
    %
    
    
    194
    %
 The cash realization ratio represents cash flows from operations expressed as a
percent of net income. (end of graph)




---



##### 



(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) 2001
    
    2002
    
    2003Total capital
    
    $
    551
    
    
    $
    625
    
    
    $
    654Interest-bearing debt (includes
short-term debt)
    
    $
    256
    
    
    $
    296
    
    
    $
    305Interest-bearing debt
as a percent of total capital
    
    
    46
    %
    
    
    47
    %
    
    
    47
    %
 (end of graph) The breakdown of 2001, 2002 and 2003 actual and 2004 through 2008 estimated
capital expenditures by segment is as follows: 2001
    
    2002
    
    2003
    
    2004
    
    2004-2008(in millions)Electric
    
    $
    35
    
    
    $
    46
    
    
    $
    28
    
    
    $
    27
    
    
    $
    132Plastics
    
    
    2
    
    
    
    6
    
    
    
    4
    
    
    
    2
    
    
    
    12Manufacturing
    
    
    11
    
    
    
    15
    
    
    
    10
    
    
    
    5
    
    
    
    43Health services
    
    
    3
    
    
    
    4
    
    
    
    6
    
    
    
    3
    
    
    
    5Other business operations
    
    
    3
    
    
    
    5
    
    
    
    3
    
    
    
    4
    
    
    
    16Total
    
    $
    54
    
    
    $
    76
    
    
    $
    51
    
    
    $
    41
    
    
    $
    208
 The following table summarizes the Companys contractual obligations at
December 31, 2003 and the effect these obligations are expected to have on its
liquidity and cash flow in future periods. Less than
    
    1-3
    
    3-5
    
    More thanTotal
    
    1 year
    
    years
    
    years
    
    5 years(in millions)Long-term debt
    
    $
    275
    
    
    $
    10
    
    
    $
    22
    
    
    $
    51
    
    
    $
    192Coal contracts (required minimums)
    
    
    86
    
    
    
    29
    
    
    
    11
    
    
    
    11
    
    
    
    35Capacity and energy requirements
    
    
    147
    
    
    
    17
    
    
    
    30
    
    
    
    30
    
    
    
    70Other purchase obligations
    
    
    3
    
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    Operating leases
    
    
    65
    
    
    
    21
    
    
    
    30
    
    
    
    10
    
    
    
    4Total contractual cash obligations
    
    $
    576
    
    
    $
    80
    
    
    $
    93
    
    
    $
    102
    
    
    $
    301
 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 2004 through 2008, 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 its currently
outstanding short-term debt. Reduced demand for electricity, reductions in
wholesale sales of electricity or margins on wholesale sales, or declines in
the number of 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 2004 through 2008 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, the
Companys business, results of operations, and financial condition could be
adversely affected.




---



##### 



In order to maintain a balanced capital structure consistent with the risk
profile of the Companys diversified mix of businesses, the Company began
issuing new shares of common stock in January 2004 to meet the requirements of
its dividend reinvestment program and share purchase plan rather than
purchasing shares on the open market. The Company estimates this change will
generate approximately $9 million in equity funding in 2004. 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. On August 25, 2003 the Companys line of credit was increased from $50 million
to $70 million. This line is available to support borrowings of the Companys
nonelectric operations. The Company anticipates the electric utilitys cash
requirements will be provided for by cash flows from electric utility
operations. This line bears interest at the rate of LIBOR plus 0.5% and expires
on April 28, 2004. 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, 2003, $30 million of the $70 million line was in use and the Company had
$7.3 million in cash and cash equivalents. The Companys line of credit, its $90 million 6.63% senior notes and Lombard
US Equipment Finance note contain the following covenants: 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, 2003
the Company was in compliance with all of the covenants under its financing
agreements. 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). On September 18, 2003 Standard & Poors Ratings Services lowered its rating on
the Companys senior unsecured debt from A to A-, lowered its rating on the
Companys preferred stock from A- to BBB and changed its outlook on the Company
from stable to negative. According to Standard & Poors, the rating action
reflects the Companys increased business risk profile due to the increasing
size of its nonelectric businesses and concerns associated with the future
financial performance of the Companys manufacturing and health services
segments. The ratings changes did not require any action under rating triggers
and did not increase interest rates on current outstanding debt. The Companys securities ratings at December 31, 2003 are: MoodysInvestors
    
    StandardService
    
    & PoorsSenior unsecured debt
Preferred stock
Outlook
    
    A2
Baa1
Negative
    
    A-
BBB
Negative
 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). 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. (bar graph of data in the following table) LONG-TERM DEBT INTEREST COVERAGE
(times interest earned before tax) 2001
    
    
    2002
    
    
    
    20035.2
    
    
    5.1
    
    
    
    4.4
 (end of graph) The Companys ratio of earnings to fixed charges was 3.5x for 2003 compared to
3.9x for 2002 and its long-term debt interest coverage ratio before taxes was
4.4x for 2003 compared to 5.1x for 2002. The main reason for the reduction in
these coverage ratios is an $11.6 million reduction in income before interest
and income taxes in 2003 compared to 2002. During 2004, the Company expects
these coverage ratios to increase over 2003 levels if net income reaches
management expectations. Off-Balance-Sheet Arrangements The Company does not have any off-balance-sheet arrangements or 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 $1.51 for the year ended
December 31, 2003 compared to $1.79 for the year ended December 31, 2002. Total
operating revenues for 2003 were $753.2 million compared with $646.3 million
for 2002. Operating income was $71.2 million for 2003 compared with $82.3
million for 2002. Amounts presented in the following tables for 2003 and 2002 operating revenues,
electric operation and maintenance expenses, cost of goods sold and nonelectric
segment operating expenses will not agree with amounts presented in the
Consolidated Statements of Income due to the elimination of intersegment
transactions. The total intersegment eliminations include: $2,456,000 in
operating revenues, $202,000 in electric operation and maintenance expenses,
$495,000 in cost of goods sold and $1,759,000 in other nonelectric expenses in
2003; and $1,036,000 in operating revenues, $222,000 in electric operation and
maintenance expenses, $446,000 in cost




---



##### 



of goods sold and $368,000 in other nonelectric expenses in 2002. In 2001,
intersegment eliminations were included in segment reporting due to
immateriality. 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. In the third quarter of 2003, the electric utility began applying
mark-to-market accounting to its forward contracts for the purchase or sale of
energy that did not meet the definition of a capacity contract as a result of
the issuance of Statement of Financial Accounting Standards (SFAS) No. 149,
Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
With the issuance of SFAS No. 149, any forward contracts for the purchase or
sale of energy entered into after June 30, 2003 that do not meet the definition
of a capacity contract and are subject to unplanned netting, referred to as a
book out in the utility industry, are not eligible for the normal purchases and
sales exception provided for under SFAS No. 133 and modified by SFAS No. 149. In 2003, a consensus was reached on Emerging Issues Task Force (EITF) Issue
03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are
Subject to FASB Statement No. 133, and Not Held for Trading Purposes as
Defined in Issue No. 02-3. The reporting requirements of EITF Issue 03-11 are
applicable to financial statement presentation in the fourth quarter of 2003.
The Company determined that the net method of reporting was appropriate for the
electric utilitys forward energy contracts. Revenue from the electric
utilitys wholesale sales of energy purchased from other suppliers is now
reflected net of the related purchase power costs in electric revenues on the
Companys consolidated statements of income for the years 2003, 2002 and 2001.
The effects of the application of EITF Issue 03-11 and reclassification of
prior years reported revenues are reflected in the table below. See note 1 to
consolidated financial statements. 2003
    
    2002
    
    2001(in thousands)Retail sales revenues
    
    $
    217,611
    
    
    $
    207,039
    
    
    $
    199,262Wholesale revenues:Sales off company-owned generation
    
    
    18,428
    
    
    
    11,941
    
    
    
    13,760Net margins on purchased power resold
    
    
    9,045
    
    
    
    6,354
    
    
    
    9,495Net unrealized marked-to-market gains
    
    
    2,057
    
    
    
    
    
    
    
    Other revenues
    
    
    20,353
    
    
    
    18,671
    
    
    
    10,203Total operating revenue
    
    $
    267,494
    
    
    $
    244,005
    
    
    $
    232,720Production fuel
    
    
    51,163
    
    
    
    44,122
    
    
    
    41,776Purchased power  retail use
    
    
    36,002
    
    
    
    30,915
    
    
    
    24,527Other operation and maintenance expenses
    
    
    87,186
    
    
    
    80,756
    
    
    
    75,531Depreciation and amortization
    
    
    26,008
    
    
    
    24,910
    
    
    
    24,272Property taxes
    
    
    9,598
    
    
    
    9,423
    
    
    
    9,464Operating income
    
    $
    57,537
    
    
    $
    53,879
    
    
    $
    57,150
 The increase of $10.6 million in retail revenue from 2002 to 2003 is mainly due
to a $9.4 million increase in cost-of-energy (COE) revenue. The remaining
increase in retail revenue was due to a 0.7% increase in retail kilowatt-hour
(kwh) sales. The increase in retail sales reflects minor increases (less than
1%) in residential, commercial and industrial kwh sales. Heating-degree-days
totaled 9,071 in 2003 compared with 9,033 in 2002 and were not a discernable
factor contributing to 2003 sales variances. The increase in COE revenues
reflects a 13.2% increase in fuel and purchased power costs per kwh for retail
use in 2003 compared with 2002. Wholesale revenue from sales of company-owned generation increased 54.3% in
2003 compared with 2002 due to a 19.6% increase in kwh sales combined with a
29.0% increase in revenue per kwh of generation sold. Gross margins on resales
of purchased power increased 42.4% between 2003 and 2002 as a result of a 25.1%
increase in kwh




---



##### 



sales combined with a 14.1% increase in the margin per kwh resold. The 36.1%
increase in overall wholesale electric prices reflects increased demand for
electricity in the Mid-Continent Area Power Pool (MAPP) region. Higher prices
in the wholesale power markets also reflect generally increasing generation
costs, reduced generation from regional hydro facilities due to lower spring
runoff and the lack of summer rainfall and high-cost generation from natural
gas-fired peaking units. The higher prices combined with increased availability
of electric utility-owned generation and well-timed energy purchases in 2003
compared to 2002 put the electric utility in a favorable position to respond to
the increased demand for electricity resulting in the increase in wholesale
electric sales. Wholesale revenue reflects $2.1 million in unrealized
marked-to-market gains on forward energy contracts at year-end 2003. Other electric operating revenues increased $1.7 million or 9.0% between 2003
and 2002. The increase reflects $2.5 million in increased transmission related
revenues from control area services, transmission tariffs and shared use
deficiency payments, and a $1.3 million increase in revenue from the sale of
steam to an ethanol plant that began operations in the third quarter of 2002,
offset by a $2.1 million reduction in revenue from contract work. Revenue from
major projects included $7.6 million from regional wind generation projects in
2003 compared to $9.9 million from work on a North Dakota transmission line for
another area utility that was completed in the fourth quarter of 2002. The 16.0% increase in production fuel expense in 2003 compared with 2002 is due
to an increase in fuel costs and generation at the electric utilitys
coal-fired generating stations, and an increase in fuel costs from combustion
turbine generation. A 12.0% increase in the fuel cost per kwh generated
reflects increases in fuel cost per kwh at all of the electric utilitys
generating units including fuel costs for the Companys new combustion turbine
brought online in June 2003. The 16.5% increase in purchased power costs for
retail use in 2003 compared with 2002 was the result of a 21.3% increase in the
cost per kwh purchased offset by a 4.0% decrease in kwh purchases for retail
use. The 8.0% increase in other operation and maintenance expenses in 2003 compared
with 2002 includes increased labor related expenses of $2.7 million as a result
of annual wage increases of about 3.5% and increases in employee benefit costs.
Pole maintenance and tree-trimming costs increased $1.0 million and
transportation and travel-related expenses increased $1.0 million between the
years. Insurance costs including provisions for damages were up $0.8 million.
Fuel procurement costs increased $0.5 million, mainly related to litigation
before the Surface Transportation Board. Uncollectible accounts expense
increased $0.4 million. The 4.4% increase in depreciation and amortization expense for 2003 compared to
2002 is due to an increase in depreciable plant base as a result of recent
capital expenditures. The Company expects the electric segment to have a solid year financially, but
does not expect electric segment results in 2004 to equal those of 2003. The $7.8 million increase in retail sales from 2001 to 2002 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%. An 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. Wholesale revenue from sales of company-owned
generation decreased $1.8 million or 13.2% on a 3.0% decrease in kwhs sold and
a 10.5% decrease in revenue per kwh of generation sold. Net margins on
purchased power resold declined $3.1 million or 33.1% between 2002 and 2001
despite a 10.2% increase in kwh sales mainly as a result of a 39.2% decrease in
the margin per kwh resold. The 23% decrease in overall wholesale electric
prices may be partially attributable to peaking generation added in the MAPP
region since September 2001, as well as lower regional demand for electricity.
The increase in other electric operating revenues of $8.5 million is primarily
due to revenue earned on a large transmission line construction project
completed for another regional utility in 2002.




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##### 



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. The 26.0% increase in purchased power costs for retail use in 2002 over 2001
was the result of a 52.6% increase in kwh purchases for retail use offset by a
17.4% decrease in the cost per kwh purchased. The volume of power purchased in
2002 increased for both system use and resale purposes. Purchased power for
retail use increased 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 in 2002 compared
with 2001 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. Plastics Plastics consists of businesses involved in the production of polyvinyl
chloride (PVC) and polyethylene (PE) pipe in the Upper Midwest and Southwest
regions of the United States. 2003
    
    2002
    
    2001(in thousands)Operating revenues
    
    $
    86,009
    
    
    $
    82,931
    
    
    $
    63,216Cost of goods sold
    
    
    76,046
    
    
    
    65,628
    
    
    
    57,932Operating expenses
    
    
    3,824
    
    
    
    4,702
    
    
    
    3,446Depreciation and amortization
    
    
    2,126
    
    
    
    1,760
    
    
    
    1,726Amortization of goodwill
    
    
    
    
    
    
    
    
    
    
    1,503Operating income (loss)
    
    $
    4,013
    
    
    $
    10,841
    
    
    $
    (1,391
    )
 Plastics operating revenues increased 3.7% in 2003 compared with 2002 due to an
8.2% increase in the average sales price per pound of pipe sold. The increase
was partially offset by a 4.2% decrease in pounds sold between the years. The
increased revenue was more than offset by a 15.9% increase in cost of goods
sold reflecting a 20.9% increase in the average cost per pound of pipe sold.
The average cost per pound of resin, the raw material used to produce PVC pipe,
increased 26.3% between the periods. Operating expenses decreased 18.7% between
the periods primarily due to decreased compensation directly related to the
decrease in gross margins. The 20.8% increase in depreciation and amortization
expense is related to a $4.4 million increase in depreciable plant in 2002 and
a $3.5 million increase in depreciable plant in 2003. The Company cannot predict if the tight operating margins experienced in the
plastics segment in 2003 will continue into 2004. Gross margins generally
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 31.2% increase in plastics operating revenues for 2002 compared with 2001




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##### 



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 13.3% increase in cost of
goods sold reflects $14.6 million in costs related to the increase in PVC pipe
sold offset by a $7.0 million reduction in costs due to a 7.0% decrease in the
price per pound of PVC resin. Operating expenses increased 36.4% 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. In 2003, 96.4% of raw material was purchased from two vendors. In 2002, 58.3%
of raw material was purchased from two vendors and in 2001, 74.9% of raw
material was purchased from two vendors. The Company believes relationships
with their key raw material vendors are good. However, the loss of a key
supplier or any interruption or delay in the supply of PVC resin could have a
significant impact on 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 and 2001 the following
acquisitions were completed. See note 2 to consolidated financial statements. Year
    
    BusinessAcquisition
    
    Acquired
    
    CombinationShoreMaster,Inc.
    
    May-02
    
    PurchaseGalva Foam Marine Industries, Inc.
    
    Oct-02
    
    PurchaseT.O. Plastics, Inc.
    
    Feb-01
    
    Pooling of interestsSt. George Steel Fabrication, Inc.
    
    Sept-01
    
    Pooling of interestsTitan Steel Corporation
    
    Nov-01
    
    Purchase
 2003
    
    2002
    
    2001(in thousands)Operating revenues
    
    $
    177,805
    
    
    $
    142,390
    
    
    $
    123,436Cost of goods sold
    
    
    139,720
    
    
    
    107,977
    
    
    
    91,360Operating expenses
    
    
    22,244
    
    
    
    18,411
    
    
    
    14,762Depreciation and amortization
    
    
    7,708
    
    
    
    6,525
    
    
    
    4,858Amortization of goodwill
    
    
    
    
    
    
    
    
    
    
    281Operating income
    
    $
    8,133
    
    
    $
    9,477
    
    
    $
    12,175
 The 24.9% increase in manufacturing operating revenues for 2003 compared with
2002
includes a $25.7 million increase in revenue from the waterfront equipment
companies acquired in 2002. Revenues from the Companys manufacturer of
thermoformed plastic and horticultural products increased $8.0 million on an
increase in the volume of products sold. Revenue at the metal parts stamping
and fabrication company increased $3.0 million and the Companys manufacturer
of wind towers recorded $1.5 million in increased revenue. These increases were
offset by decreases in revenue of $2.5 million from the manufacturer of
structural steel products and $0.3 million from the manufacturer of automobile
frame-straightening equipment. The 29.4% increase in cost of goods sold in 2003 compared with 2002 primarily
reflects a $19.1 million increase in costs of goods sold at the waterfront
equipment companies combined with increased costs of $6.0 million at the
Companys manufacturer of wind towers mostly in material costs, $5.3 million
from the Companys manufacturer of thermoformed plastic and horticultural
products related to increased sales, and $2.5 million from the metal parts
stamping and fabrication company primarily related to material costs. These
increases were offset by a reduction in cost of goods sold of $0.4 million at
the manufacturer of structural steel products, mainly related to reduced labor
expenses, and $0.1 million from the manufacturer of automobile
frame-straightening equipment. The 18.1% increase in




---



##### 



depreciation and amortization expense in 2003 compared with 2002 is due to 2002
and 2003 plant expansions and equipment purchases at all the manufacturing
companies. While the Company does not expect the business conditions that contributed to
decreased earnings from the manufacturing segment in 2003 to continue in 2004,
the uncertainty of the economy and the Production Tax Credit in the wind
energy business, and the impact of steel pricing could adversely impact this
segments performance in 2004. 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 18.2% 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. Health Services Health services include businesses involved in the sale of diagnostic medical
equipment, patient monitoring equipment, and related 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. During 2003, 2002
and 2001 the following acquisitions were completed. See note 2 to consolidated
financial statements. Year
    
    BusinessAcquisition
    
    Acquired
    
    CombinationTopline Medical/North Star Medical Systems
    
    May/July 2003
    
    PurchaseComputed Imaging Service, Inc.
    
    May-02
    
    PurchaseMobile Diagnostic Services, Inc.
    
    Nov-02
    
    PurchaseInterim Solutions/Midwest Medical Diagnostics
    
    Sept-01
    
    PurchaseNuclear Imaging, Ltd.
    
    Sept-01
    
    Purchase
 2003
    
    2002
    
    2001(in thousands)Operating revenues
    
    $
    100,912
    
    
    $
    93,420
    
    
    $
    79,129Cost of goods sold
    
    
    75,085
    
    
    
    66,680
    
    
    
    59,388Operating expenses
    
    
    15,442
    
    
    
    13,676
    
    
    
    9,362Depreciation and amortization
    
    
    5,137
    
    
    
    4,410
    
    
    
    2,912Amortization of goodwill
    
    
    
    
    
    
    
    
    
    
    605Operating income
    
    $
    5,248
    
    
    $
    8,654
    
    
    $
    6,862
 The 8.0% increase in health services operating revenues for 2003 compared with
2002 reflects $6.7 million in additional scan and other services revenue,
mostly from the acquisitions that occurred in 2002. Revenues from the sale of
diagnostic imaging equipment increased $0.8 million between the periods in part
due to recent acquisitions in 2003. The number of scans performed increased
12.6% mainly due to the 2002 acquisitions, while the average fee per scan
decreased 1.8%. Although revenues from imaging services increased by $6.7 million, the increase
was more than offset by increases in equipment and infrastructure costs
incurred to support expected revenue growth. While operating income for 2003
was significantly less than operating income in 2002, the segments 2003
results have improved significantly from early 2003 in part due to steps taken
by management to address




---



##### 



increases in operating expenses of the diagnostic imaging operations. The
company that sells and services medical diagnostic and monitoring equipment had
a good year financially, but the results from imaging services were
disappointing, primarily due to aggressive growth combined with subsequent
integration challenges. Management continues to address the cost structure of
the diagnostic imaging operations and hired a new president/chief operating
officer in the fourth quarter of 2003 to lead the imaging part of the health
services segment. In December 2003, the DMS Health Group renewed its dealership
agreement with Philips Medical Systems. The 18.1% increase in health services operating revenues, 12.3% increase in
cost of goods sold, 46.1% increase in operating expenses and 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. Other Business Operations The Companys other business operations include businesses involved in
electrical and telephone construction contracting, specialty contracting
including design and build services for new construction, 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. On November 1, 2003 the Company
acquired the assets and operations of Foley Company (Foley), a mechanical and
prime contracting firm based in Kansas City, Missouri. See note 2 to
consolidated financial statements. 2003
    
    2002
    
    2001(in thousands)Operating revenues
    
    $
    123,475
    
    
    $
    84,627
    
    
    $
    80,667Cost of goods sold
    
    
    82,378
    
    
    
    46,414
    
    
    
    41,109Operating expenses
    
    
    39,885
    
    
    
    33,739
    
    
    
    30,927Depreciation and amortization
    
    
    4,983
    
    
    
    5,008
    
    
    
    5,093Amortization of goodwill
    
    
    
    
    
    
    
    
    
    
    850Operating (loss) income
    
    $
    (3,771
    )
    
    $
    (534
    )
    
    $
    2,688
 The 45.9% increase in operating revenues in 2003 compared with 2002 was mostly
due to a $13.8 million increase in revenues from natural gas sales at the
Companys energy services company related to an increase in natural gas prices.
In addition, construction revenues increased by $21.4 million, of which $7.9
million came from Foley, acquired in November 2003. Transportation revenues
increased by $2.3 million between the periods as a result of an 85.6% increase
in brokered miles. The 77.5% increase in cost of goods sold reflects a $14.4
million increase in the cost of natural gas sold by the energy services company
and a $21.6 million increase in construction costs at the construction
companies, of which $6.5 million is attributable to Foley. The 18.2% increase in operating expenses between the periods reflects a $2.4
million increase in transportation operating expenses mainly related to
increased brokerage activity. The construction companies reported $1.0 million
in increased operating expenses with $0.5 million of the increase related to
Foley. Operating expenses also reflect $3.3 million in increased operating
expenses related to unallocated corporate overhead costs mainly due to
increased employee benefit costs and increases in self-insurance costs.
Operating expense at the energy services company decreased $1.9 million from
2002 to 2003 as a result of decreased activity. The Company had recorded
$250,000 in goodwill related to the acquisition of an energy




---



##### 



management firm in 2002. Based on an offer to purchase this entity in the
fourth quarter of 2003, the Company determined that the goodwill related to
this entity was impaired and, accordingly, recorded a $250,000 charge to
operating income in the fourth quarter of 2003. Construction margins have declined due to the sluggish economy and increased
competition for available work. A decrease of $1.2 million in construction
operating income was offset by a $1.3 million decrease in operating losses from
the energy services company. The telecommunications company reported a 4.7%
decrease in operating income in 2003. The transportation companys operating
income increased by 6.1% in 2003 but it is still faced with continuing pressure
on operating margins because of increased fuel and insurance costs and highly
competitive pricing. The 4.9% 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, $1.6 million at the construction subsidiaries and $0.5
million in corporate services revenue, partially offset by a decrease in
revenue of $1.2 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 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 Company currently has $1.0 million of goodwill recorded on its balance
sheet related to its energy services subsidiary that markets natural gas to
approximately 150 retail customers. A recent evaluation of projected cash flows
from this operation indicated that the related goodwill was not impaired.
However, actual and projected cash flows from this operation are subject to
fluctuations due to low profit margins on natural gas sales combined with high
volatility of natural gas prices. Reductions in profit margins or the volume of
natural gas sales could result in an impairment of all or a portion of its
related goodwill. The Company will continue to evaluate this reporting unit for
impairment on an annual basis and as conditions warrant. The Company currently has $6.7 million of goodwill recorded on its balance
sheet relating to the acquisition of E.W. Wylie Corporation (Wylie) its flatbed
trucking company. 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, 2003, assessment of
Wylie indicated that its goodwill was not impaired. The Company will continue
to evaluate this reporting unit for impairment on an annual basis and as
conditions warrant. Consolidated Interest Charges As a result of lower variable interest rates, interest expense increased only
$21,000 in 2003 compared to 2002. The average interest rate paid on short-term
debt decreased from 2.2% in 2002 to 1.7% in 2003. 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. Consolidated Income Taxes The Companys effective tax rate was 27.4% for 2003 compared with 30.3% for
2002. The reduction reflects the impact of R&D tax credits claimed in 2003.
Without these credits, the 2003 effective tax rate would have been 28.5%. The
remaining 1.8% difference in the effective tax rate for 2003 compared to 2002
is a function of the level of fixed deductions and credits in proportion to
lower net income before tax in 2003 compared to 2002. See note 13 to
consolidated financial statements. 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. 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.




---



##### 



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, realization of
recognized but unrealized market valuation gains on forward energy contracts,
market valuation of forward energy contracts, availability of resin supliers,
resin prices, 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, the rate of economic growth or decline in the electric utilitys service
area and potential acquisitions of other systems. The electric utilitys
business depends primarily on the use of electricity by customers in its
service area and the demands of its wholesale customers. Electric kwh sales to
retail customers increased 0.7% in 2003, 2.4% in 2002 and 2.9% in 2001. Otter Tail Power Company has indicated interest in the South Dakota-based
electric and gas operations of NorthWestern Corporation, which filed for
bankruptcy in the fall of 2003 and is currently restructuring. Merrill Lynch
has been retained as the financial advisor to negotiate with NorthWesterns
unsecured creditors in the event of a sale of assets. Otter Tail Power Company
co-owns two plants with NorthWestern and also has proximity to and a degree of
overlap with NorthWestern service areas. Otter Tail Power Companys interest
does not include NorthWesterns Montana properties or operations. The
acquisition of the South Dakota assets would increase the number of utility
customers by roughly 45%. Because the process has just begun, it is not
possible to determine the liklihood of the acquisition being completed. Factors beyond the electric utilitys control, such as mergers and
acquisitions, geographical location, transmission reservation costs, unplanned
interruptions at the electric utilitys generating plants, fluctuations in
market prices of open forward energy contracts subject to mark-to-market
accounting 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 not be as robust in the future because of generating
unit additions in the power pool and the advent of transmission system
operators mandated by the FERC. Regulation Electric utility operations remain regulated in all jurisdictions in which
Otter Tail Power Company operates. 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 could 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




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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 2003 rate of return is expected to be within
the allowable range defined in the plan. Fuel Costs The electric utility has an agreement for Big Stone Plants coal supply through
December 31, 2004. The Company is in negotiations with a new coal supplier for
a long-term contract beginning in 2005. The electric utility 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
electric utility has commenced a proceeding before the Surface Transportation
Board requesting the Board set a competitive rate, with a decision expected
early in 2005. The electric utility expects the outcome to have a favorable
impact on its fuel costs for Big Stone Plant. The MAPP region has experienced a very slight increase in availability of
surplus generation capacity due to the addition of peaking capacity. However,
energy availability has declined due to a regional drought that has
significantly reduced hydro generation in Manitoba and on the Missouri River
Basin. The region is also experiencing increasing transmission system
congestion, impacting the wholesale power market. While the availability of the
electric utilitys plants has been excellent, the loss of a major plant could
expose the electric utility to higher purchased power costs. Two factors
mitigate this financial risk. First, wholesale sales contracts include
provisions to release the electric utility from its obligations in the event of
a plant outage; and second, the electric utility has COE adjustment clauses
that allow pass through of most of the increased 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 electric utility anticipates that, under current
regulatory principles, any such costs could be recovered through rates. All of
the electric utilitys electric generating plants operated within the Acts
phase two standards for sulfur-dioxide and nitrogen-oxide emissions in 2003.
Ongoing compliance with the phase two requirements is not expected to
significantly impact operations at any of the electric utility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
Administrator signed the proposed mercury rule on December 15, 2003. The
proposal included two options for regulating mercury emission from coal-fired
electric generating units. One option would set technology-based maximum
achievable control technology standards under paragraph 112(d) of the Act. The
other option embodies a market-based cap and trade approach to emissions
reduction. The electric utility is currently evaluating the proposal. Because
promulgation of rules by the EPA has not been completed, it is not possible to
assess to what extent this regulation will impact the electric utility. 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 electric utility received a request from the
EPA pursuant to Section 114(a) of the Act requiring the electric utility to
provide certain




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information relative to past operation and capital construction projects at the
Big Stone Plant. The electric utility has responded to that request. In March
2003, the EPA conducted a review of the plants outage records as a follow-up
to their January 2001 data request. Copies of the designated documents were
provided to the EPA on March 21, 2003. At this time, the electric utility
cannot determine what, if any, actions will be taken by the EPA. At the request of the Minnesota Pollution Control Agency (MPCA), the electric
utility 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 electric utility
submitted a Remedial Investigation Work Plan to the MPCA describing its 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 the electric utility 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. The electric utility initiated additional studies to further characterize
the site and its report was submitted to the MPCA in March 2003 for their
review and comment. The MPCA approved portions of the remediation measures that
the electric utility proposed and those were implemented in 2003. Although the
electric utility is still evaluating various options, its preliminary estimate
of remediation costs to address the ash disposal site issues over the next
three years is not expected to have a material impact on the Companys
consolidated net income, financial position or cash flows. Deregulation and Legislation In the aftermath of the August 14, 2003 blackout, the FERC is contemplating how
to enforce reliability standards, with or without energy legislation giving
them explicit authority to do so. On the electricity market front, FERCs 2002
Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) met
significant political resistance, especially from the Southeast and Western
regions of the United States. As a direct result, FERC published a Wholesale
Market Platform (WMP) white paper that provides for regional flexibility and
state regulator involvement through Regional State Committees (RSCs). The state regulators in the Midwest Independent Transmission System Operator
(MISO) region initiated the startup of an RSC called the Organization of MISO
States (OMS). The OMS has no regulatory authority. The purpose of the OMS is to
coordinate regulatory oversight among the states, including recommendations to
MISO, the MISO Board of Directors, the FERC, other relevant government entities
and state commissions as appropriate. MISO has delayed startup of its electricity markets until December 1, 2004.
The integration of the electric utilitys electric facilities with its regions
nonjurisdictional utilities presents a challenge for a MISO market startup.
MISO plans to implement a Locational Marginal Pricing (LMP) market on December
1, 2004. The Company is making preparations in advance of market
implementation. Those preparations include participation in MISO working groups
and committees, evaluation of software to assist in market operations, purchase
of LMP forecasting software, and staff additions to meet the needs of a new
market. LMP intends to manage transmission congestion more effectively than
current processes, improve reliability of the grid, increase market efficiency,
and provide greater price transparency to regulators. However, a recent
Department of Energy study shows that wholesale market prices in the MAPP
region will increase 10% from 2005-2010, remain unchanged from
2011-2015, and fall by 1% from 2016-2020. The study raises doubts
about benefits of LMP in the MAPP region. Increased market efficiency and price
transparency may reduce wholesale electric sales margins from current levels. Electric retail deregulation was not a subject debated in any of the state
legislatures in the electric utilitys service territory (Minnesota, North
Dakota, and South Dakota) in 2003. Further, none of these state legislatures
passed significant new requirements negatively affecting the ownership or
operation of




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investor-owned utility assets in 2003. Nonelectric Operations In 2003, approximately 14% 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. 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 its current nonelectric
businesses, the Company believes opportunities exist for growth in these
business segments. Factors that could affect the results of its 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; interest rates and their impact on housing starts;
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 2004 could have an unfavorable impact on the Companys
operations that manufacture towers for the wind energy industry. Critical Accounting Policies Involving Significant Estimates The Companys significant accounting policies are described in note 1 to
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, valuation of forward energy contracts,
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 healthcare cost-trend rates. Further discussion of
the Companys pension and postretirement benefit plans and related assumptions
is included in note 10 to consolidated financial statements.




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These benefits, for any individual employee, can be earned and related expenses
can be recognized and a liability accrued over periods of up to 40 or more
years. These benefits can be paid out for up to 40 or more years after an
employee retires. 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
healthcare 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. For the Companys pension fund, the average rate of return on assets over the
past five years of 7.6% compared to an average assumed rate of 9.3% combined
with a reduction in the discount rate from 7.5% at year-end 2001 to 6.25% at
year-end 2003 contributed to a shift from a $14 million unrecognized actuarial
gain as of December 31, 2001 to a $23 million unrecognized actuarial loss as of
December 31, 2003. A 22.9% return on plan assets in 2003 was a major factor
contributing to a shift from $5.4 million net pension liability and an
accumulated other comprehensive loss of $7 million as of December 31, 2002 to a
prepaid pension asset of $8 million and elimination of the $7 million
accumulated other comprehensive loss as of December 31, 2003. Pension benefit
costs for 2004 are expected to be $2.1 million compared to $1.5 million in
2003. The impact on 2004 pension benefit costs of the change in the estimated
discount rate from 6.75% at year-end 2002 to 6.25% at year-end 2003 will be
more than offset by the reduction in the assumed rate of increase in future
compensation levels from 4.25% at year-end 2002 to 3.75% at year-end 2003. Subsequent increases or decreases in actual rates of return on plan assets over
assumed rates or increases or decreases in the discount rate or rate of
increase in future compensation levels could significantly change projected
costs. For 2003, all other factors being held constant: a 0.25 increase (or
decrease) in the discount rate would have decreased (or increased) the 2003
pension benefit cost by $277,000; a 0.25 increase (or decrease) in the assumed
rate of increase in future compensation levels would have increased (or
decreased) the 2003 pension benefit cost by $355,000; a 0.25 increase (or
decrease) in the expected long-term rate of return on plan assets would have
decreased (or increased) the 2003 pension benefit cost by $380,000. In 2003, the Companys Executive Survivor and Supplemental Retirement Plan
(ES&SRP) accrued benefit liability increased by $1.9 million as a result of an
increase in accumulated benefits earned and a reduction in the discount rate
from 6.75% at year-end 2002 to 6.25% at year-end 2003. Shareholders equity
increased by $0.6 million in the form of a reduction to other comprehensive
loss due to plan amendments that resulted in an increase in unrecognized prior
service costs. The 0.50 decrease in the assumed discount rate and the 0.25
increase in the assumed rate of increase in future compensation levels as of
December 31, 2003 will contribute to increases in the Companys ES&SRP periodic
benefit costs which are currently projected to be $3.1 million in 2004, $3.2
million in 2005, $3.4 million in 2006, $3.5 million in 2007 and $3.7 million in
2008. A decrease in the discount rate from 6.75% at December 31, 2002 to 6.25% at
December 31, 2003 contributed to a $2.7 million increase in the postretirement
medical benefit plans projected benefit obligation and a $0.3 million increase
in the plans unrecognized actuarial loss from year-end 2002 to year-end 2003.
The changes in these factors will be offset by updates to actuarial tables
resulting in a minor increase in postretirement healthcare benefit costs from
$4.78 million in 2003 to a projected $4.83 million in 2004. Subsequent
increases or decreases in the




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discount rate or in retiree healthcare cost inflation rates could significantly
change these projected costs. A 0.25 increase (or decrease) in the discount
rate would have decreased (or increased) the 2003 postretirement medical
benefit cost by $132,000. See note 10 to consolidated financial statements for
the cost impact of a change in medical cost inflation rates. Revenue Recognition 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. Revenues recognized, including
revenues recognized by Foley prior to acquisition, on jobs in progress as of
December 31, 2003 were $138 million. There are no losses expected on jobs in
progress at year-end 2003. 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. Forward Energy Contracts Classified as Derivatives The electric utilitys forward contracts for the purchase and sale of energy
are considered derivatives subject to mark-to-market accounting under generally
accepted accounting principles. The market prices used to value the electric
utilitys forward contracts for the purchases and sales of electricity are
determined by survey of counterparties by the electric utilitys power services
personnel responsible for contract pricing and, as such, are estimates. Over
69% of the forward purchase and sales contracts that are marked to market as of
December 31, 2003 are offsetting in terms of volumes and delivery periods. Over
93% of these forward energy transactions by volume are scheduled for settlement
prior to May 1, 2004. Due to the nature of electricity and the physical aspects of the electricity
transmission system, unanticipated events affecting the transmission grid can
result in transmission constraints and the cancellation of scheduled
transactions by the independent transmission system operator. In these
situations, which are relatively infrequent in occurrence, the counterparties
to the cancelled transaction are generally not made whole for the difference in
the contract price and the market price of the electricity at the time of
cancellation. In some instances the electric utility may deliver on a sale
where its offsetting purchase has been cancelled or take delivery on a purchase
where its offsetting sale has been cancelled. All forward energy transactions
are subject to a small, and likely unquantifiable, risk of cancellation by the
independent transmission system operator due to unanticipated physical
constraints on the transmission system. At the time of cancellation, the
electric utility could be in a gain or loss position depending on the market
price of electricity relative to the contract price and the electric utilitys
position in the transaction. 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




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allowance for bad debts to reduce the net recognized receivable to the amount
the Company reasonably believes 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 2003, $1.0 million of bad debt expense was recorded and the allowance
for doubtful accounts was $2.5 million (2.3% of trade accounts receivable) as
of December 31, 2003. 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 based
on outstanding receivables at December 31, 2003 would result in a $1.1 million
increase or decrease in bad debt 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. 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 3.07% in
2003, 3.08% in 2002 and 3.06% in 2001. 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 its 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 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




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reflecting changing business cycles and 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, 2003 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, 2003 an assessment of the carrying values of the Companys
goodwill indicated no impairment. Key Accounting Pronouncements SFAS No. 143:The Financial Accounting Standards Board (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. 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 changed the accounting for ARO costs of the utilitys generating plants.
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 month and the capitalized
cost will be depreciated over the useful life of the related asset. The Companys asset retirement obligations include site restoration, the
closure of ash pits and the removal of storage tanks and asbestos at certain
electric utility generating plants. The Company has legal obligations
associated with retirement of other long-lived assets used in its electric
operations that cannot be reasonably estimated because the useful lives of
those assets are not determinable. There are no assets legally restricted for
the settlement of any of the Companys asset retirement obligations. The
Company reclassified $35.4 million in accumulated reserves related to estimated
removal costs from accumulated depreciation and amortization to a regulatory
liability on the face of its Consolidated Balance Sheet as of December 31,
2002. Disclosure requirements under SFAS No. 143 are included in note 1 to
consolidated financial statements.




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SFAS No. 149:The FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities, in April 2003. The statement
amends and clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. This statement is effective for
contracts entered into or modified after June 30, 2003. With the issuance of
SFAS No.149, any forward contracts for the purchase or sale of energy entered
into after June 30, 2003 that do not meet the definition of a capacity contract
and are subject to unplanned netting, referred to as a book out in the utility
industry, are not eligible for the normal purchases and sales exception
provided for under SFAS No. 133 and modified by SFAS No. 149. These contracts
are considered derivatives and are now subject to mark-to-market accounting.
This classification applies to virtually all of the electric utilitys forward
wholesale purchases and sales of energy, which, prior to the issuance of SFAS
No. 149, qualified for the normal purchases and sales exception from
mark-to-market accounting treatment on the basis that it was probable that
these contracts would not settle net and would result in physical delivery. As
a result of the issuance of SFAS No. 149, unrealized gains and losses on
forward purchases and sales of energy are now recorded by the electric utility.
All provisions of this statement have been applied prospectively. The electric utility recorded $4.1 million in net marked-to-market gains on
derivative energy contracts in 2003, which reflects the difference between the
contracted prices for forward purchases and sales of energy and the fair market
values of contracts with matching terms and characteristics from the time the
contracts are entered into until they are settled. As of December 31, 2003,
$2.1 million in recognized marked-to-market net gains was unrealized. The
electric utility expects these gains to be realized within the first six months
of 2004. A portion of the marked-to-market value of derivative assets and
liabilities is not reflected in current income but has been deferred under
regulatory accounting treatment until realized at the time of physical
delivery. EITF Issue 03-11:At the July 31, 2003 EITF meeting, EITF Issue 03-11,
Reporting Realized Gains and Losses on Derivative Instruments That Are Subject
to FASB Statement No. 133, and Not Held for Trading Purposes as Defined in
Issue No. 02-3, was discussed. The EITF reached a consensus by agreeing that
determining whether realized gains and losses on derivative contracts not held
for trading purposes should be reported on a net or gross basis is a matter of
judgment that depends on the relevant facts and circumstances. The FASB
ratified the EITF consensus at its August 13, 2003 meeting. The reporting
requirements of EITF Issue 03-11 are applicable to financial statement
presentation in the fourth quarter of 2003. The electric utility determined
that the net method of reporting was appropriate for its forward energy
contracts. Revenue from the electric utilitys wholesale sales of energy
purchased from other suppliers are now reflected net of the related purchase
power costs in electric revenues on the Companys consolidated statements of
income for the years 2003, 2002 and 2001. The effects of the application of
EITF Issue 03-11 and reclassification of prior years reported revenues are
shown in the table under Revenue Recognition in note 1 to consolidated
financial statements. The application of the reporting requirements of EITF
Issue 03-11 had no effect on the Companys consolidated net income, financial
position or cash flows. FASB Interpretation (FIN) No. 46 (revised December 2003), Consolidation of
Variable Interest Entities, is an interpretation of Accounting Research
Bulletin No. 51, that addresses consolidation by business enterprises of
variable interest entities which have certain characteristics related to equity
at risk and rights and obligations to profits and losses. The effective date
for application of certain provisions of FIN 46 has been deferred until the
first quarter of 2004 for interests in variable interest entities created
before February 1, 2003 and held by a public entity that has not previously
applied the provisions of FIN 46. Implementation of FIN 46 will have no impact
on the Companys consolidated net income, financial position or cash flows.




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SFAS No. 132 (revised 2003), Employers Disclosures about Pensions and Other
Postretirement Benefits, was revised in 2003 to require additional footnote
disclosures about the assets, obligations, cash flows and net periodic benefit
cost to defined benefit pension plans and other defined benefit postretirement
plans. The additional disclosures include information describing the types of
plan assets, investment strategy, measurement dates, plan obligations, cash
flows, and components of net periodic benefit cost recognized during interim
periods. This statement is effective for financial statements with fiscal years
ending after December 15, 2003. See note 10 to consolidated financial
statements. Quantitative and Qualitative Disclosures About Market Risk At December 31, 2003 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 rate 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, 2003 the Company had $30.6 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 one percentage point higher or lower
than the average variable rate on December 31, 2003 interest expense and pretax
earnings would change by approximately $306,000. 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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 these 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. These contracts call for the physical delivery of natural gas and are
considered executory contracts for accounting purposes. Current accounting
guidance requires losses on firmly committed executory contracts to be
recognized when realized. 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.




---



##### 



The electric utility has market, price and credit risk associated with forward
contracts for the purchase and sale of energy. As of December 31, 2003 the
electric utility had recognized, on a pretax basis, $2.1 million in net
unrealized gains on open forward contracts for the purchase and sale of energy.
Due to the nature of electricity and the physical aspects of the electricity
transmission system, unanticipated events affecting the transmission grid can
result in transmission constraints and the cancellation of scheduled
transactions by the independent transmission system operator. In these
situations, the counterparties to the cancelled transaction are generally not
made whole for the difference in the contract price and the market price of the
electricity at the time of cancellation. In some instances the electric utility
may deliver on a sale where its offsetting purchase has been cancelled or is
undeliverable, or take delivery on a purchase where its offsetting sale has
been cancelled or is undeliverable. All forward energy transactions are subject
to a small, and likely unquantifiable, risk of cancellation by the independent
transmission system operator due to unanticipated physical constraints on the
transmission system. At the time of cancellation, the electric utility could be
in a gain or loss position depending on the market price of electricity
relative to the contract price and the electric utilitys position in the
transaction. The market prices used to value the electric utilitys forward contracts for
the purchases and sales of electricity are determined by survey of
counterparties by the electric utilitys power services personnel responsible
for contract pricing with adjustment for transmission costs required to move
energy from its purchase point to its delivery point. Over 69% of the forward
purchase and sales contracts that are marked to market as of December 31, 2003
are offsetting in terms of volumes and delivery periods. 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. These policies
require that most forward sales of electricity in wholesale markets be covered
by offsetting forward purchases of electricity with matching terms and delivery
dates or by the portion of company-owned generation projected to be in excess
of retail load requirements. Currently, a portion of marked-to-market gains or
losses on a sales contract will be offset by a marked-to-market loss or gain on
the offsetting purchase contract. The Companys energy risk management policy allows for long open positions with
limitations on the aggregate marked-to-market value of open positions. These
positions are closely monitored and covered with offsetting sales when the risk
of loss exceeds predefined limits. The exposure to price risk of these open
positions as of December 31, 2003 was not material.




---



##### 



The following table shows the effect of marking-to-market forward contracts for
the purchase and sale of energy on the Companys Consolidated Balance Sheet as
of December 31, 2003 and the change in its Consolidated Balance Sheet position
from December 31, 2002 to December 31, 2003: December 31,(in thousands)
    
    2003Current asset  marked-to-market gain
    
    $
    5,443Regulatory asset  deferred marked-to-market loss
    
    
    1,802Total assets
    
    
    7,245Current liability  marked-to-market loss
    
    
    (3,504
    )Regulatory liability  deferred marked-to-market gain
    
    
    (1,684
    )Total liabilities
    
    
    (5,188
    )Net fair value of marked-to-market energy contracts
    
    $
    2,057
 Year Ended(in thousands)
    
    December 31, 2003Fair value at beginning of year
    
    $
    Amount realized on contracts delivered in 2003
    
    
    (2,001
    )Changes in fair value
    
    
    4,058Net fair value at end of period
    
    
    2,057Net change recorded as marked-to-market
    
    $
    2,057
 The $2.1 million in recognized but unrealized net gains on the forward energy
purchases and sales marked-to-market on December 31, 2003 is expected to be
realized on physical settlement as scheduled over the following quarters in the
amounts listed: 1st
    
    2nd
    
    4thQuarter
    
    Quarter
    
    Quarter(in thousands)
    
    2004
    
    2004
    
    2004
    
    TotalNet gain
    
    $
    2,026
    
    
    $
    11
    
    
    $
    20
    
    
    $
    2,057
 The electric utility has credit risk associated with the nonperformance or
nonpayment by counterparties to its forward energy purchases and sales
agreements. The Company has established guidelines and limits to manage credit
risk associated with wholesale power purchases and sales. Specific limits are
determined by a counterpartys financial strength. The Companys credit risk
with its largest counterparty on delivered and marked-to-market forward
contracts as of December 31, 2003 was $9.3 million. As of December 31, 2003 the
Company had a net credit risk exposure of $1.6 million from 32
counterparties with investment grade credit ratings. The $1.6 million credit risk exposure includes net amounts due to the electric
utility on receivables/payables from completed transactions billed and unbilled
plus marked-to-market gains/losses on forward contracts for the purchase and
sale of energy scheduled for delivery after December 31, 2003. Individual
counterparty exposures are offset according to legally enforceable netting
arrangements. Counterparties with investment grade credit ratings have minimum credit ratings
of BBB- (Standard & Poors), Baa3 (Moodys) or BBB- (Fitch).




---



##### 



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, 2003 and 2002, 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, 2003. 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, 2003
and 2002, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2003, in conformity with
accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated financial statements, effective in
2003 the Company adopted Statement of Financial Accounting Standards (SFAS) No.
143, Accounting for Asset Retirement Obligationsand SFAS No. 149, Amendment of
Financial Accounting Standards Board Statement No. 133 on Derivative and
Hedging Activities,and in 2002 the Company changed its method of accounting
for goodwill and other intangible assets. DELOITTE & TOUCHE LLP /s/ Deloitte & Touche LLP Minneapolis, Minnesota
February 23, 2004




---



##### 



Otter Tail Corporation Consolidated Statements of IncomeFor the Years Ended December 31 ( in thousands, except per-share amounts)
    
    2003
    
    2002
    
    2001Operating revenues
    
    $
    753,239
    
    
    $
    646,337
    
    
    $
    579,168Operating expensesProduction fuel
    
    
    51,163
    
    
    
    44,122
    
    
    
    41,776Purchased power
    
    
    36,002
    
    
    
    30,915
    
    
    
    24,527Electric operation and maintenance expenses
    
    
    86,984
    
    
    
    80,534
    
    
    
    75,531Cost of goods sold
    
    
    372,734
    
    
    
    286,253
    
    
    
    249,789Other nonelectric expenses
    
    
    79,636
    
    
    
    70,160
    
    
    
    58,497Depreciation and amortization
    
    
    45,962
    
    
    
    42,613
    
    
    
    42,100Property taxes
    
    
    9,598
    
    
    
    9,423
    
    
    
    9,464Total operating expenses
    
    
    682,079
    
    
    
    564,020
    
    
    
    501,684Operating income
    
    
    71,160
    
    
    
    82,317
    
    
    
    77,484Other
income and deductions  net
    
    
    1,292
    
    
    
    1,717
    
    
    
    2,193Interest charges
    
    
    17,866
    
    
    
    17,845
    
    
    
    15,991Income before income taxes
    
    
    54,586
    
    
    
    66,189
    
    
    
    63,686Income taxes
    
    
    14,930
    
    
    
    20,061
    
    
    
    20,083Net income
    
    
    39,656
    
    
    
    46,128
    
    
    
    43,603Preferred dividend requirements
    
    
    735
    
    
    
    736
    
    
    
    1,993Earnings available for common shares
    
    $
    38,921
    
    
    $
    45,392
    
    
    $
    41,610Average number of common shares outstandingbasic
    
    
    25,673
    
    
    
    25,176
    
    
    
    24,600Average number of common shares outstandingdiluted
    
    
    25,826
    
    
    
    25,397
    
    
    
    24,832Basic earnings per share
    
    $
    1.52
    
    
    $
    1.80
    
    
    $
    1.69Diluted earnings per share
    
    $
    1.51
    
    
    $
    1.79
    
    
    $
    1.68Dividends per common share
    
    $
    1.08
    
    
    $
    1.06
    
    
    $
    1.04
 See accompanying notes to consolidated financial statements.




---



##### 



Otter Tail Corporation Consolidated Balance Sheets, December 31 (in thousands)
    
    2003
    
    2002AssetsCurrent assetsCash and cash equivalents
    
    $
    7,305
    
    
    $
    9,937Accounts receivable:Trade (less allowance for doubtful accounts of
$2,510,000 for 2003 and $3,833,000 for 2002)
    
    
    107,634
    
    
    
    81,670Other
    
    
    7,830
    
    
    
    1,466Inventories
    
    
    56,966
    
    
    
    44,154Deferred income taxes
    
    
    3,532
    
    
    
    4,487Accrued utility revenues
    
    
    14,866
    
    
    
    11,633Costs and estimated earnings in excess of billings
    
    
    4,591
    
    
    
    5,529Other
    
    
    10,385
    
    
    
    5,337Total current assets
    
    
    213,109
    
    
    
    164,213Investments and other assets
    
    
    35,987
    
    
    
    36,135Goodwillnet
    
    
    72,556
    
    
    
    64,557Other intangiblesnet
    
    
    7,096
    
    
    
    5,592Deferred debitsUnamortized debt expense and reacquisition premiums
    
    
    8,081
    
    
    
    8,895Regulatory assets
    
    
    14,669
    
    
    
    10,238Other
    
    
    1,600
    
    
    
    1,220Total deferred debits
    
    
    24,350
    
    
    
    20,353PlantElectric plant in service
    
    
    875,364
    
    
    
    835,382Nonelectric operations
    
    
    193,858
    
    
    
    178,656Total
    
    
    1,069,222
    
    
    
    1,014,038Less accumulated depreciation and amortization
    
    
    453,791
    
    
    
    432,383Plantnet of accumulated depreciation and amortization
    
    
    615,431
    
    
    
    581,655Construction work in progress
    
    
    17,894
    
    
    
    41,607Net plant
    
    
    633,325
    
    
    
    623,262Total
    
    $
    986,423
    
    
    $
    914,112
 See accompanying notes to consolidated financial statements.




---



##### 



Otter Tail Corporation Consolidated Balance Sheets, December 31 (in
thousands)
    
    2003
    
    2002Liabilities and EquityCurrent liabilitiesShort-term debt
    
    $
    30,000
    
    
    $
    30,000Current maturities of long-term debt
    
    
    9,718
    
    
    
    7,690Accounts payable
    
    
    83,338
    
    
    
    52,430Accrued salaries and wages
    
    
    14,677
    
    
    
    18,194Accrued federal and state income taxes
    
    
    4,152
    
    
    
    Other accrued taxes
    
    
    10,491
    
    
    
    10,150Other accrued liabilities
    
    
    10,003
    
    
    
    5,760Total current liabilities
    
    
    162,379
    
    
    
    124,224Pensions benefit liability
    
    
    16,919
    
    
    
    20,484Other postretirement benefits liability
    
    
    23,230
    
    
    
    20,382Other noncurrent liabilities
    
    
    11,102
    
    
    
    7,840Commitments (note 8)Deferred creditsDeferred income taxes
    
    
    101,596
    
    
    
    94,147Deferred investment tax credit
    
    
    11,630
    
    
    
    12,782Regulatory liabilities
    
    
    42,926
    
    
    
    44,509Other
    
    
    2,061
    
    
    
    2,550Total deferred credits
    
    
    158,213
    
    
    
    153,988Capitalization (page 36)Long-term debt, net of current maturities
    
    
    265,193
    
    
    
    258,229Cumulative preferred shares
    
    
    15,500
    
    
    
    15,500Common
shares, par value $5 per shareauthorized, 50,000,000 shares;
outstanding, 200325,723,814 shares; 200225,592,160 shares
    
    
    128,619
    
    
    
    127,961Premium on common shares
    
    
    26,515
    
    
    
    24,135Unearned compensation
    
    
    (3,313
    )
    
    
    (1,946
    )Retained earnings
    
    
    186,495
    
    
    
    175,304Accumulated other comprehensive loss
    
    
    (4,429
    )
    
    
    (11,989
    )Total common equity
    
    
    333,887
    
    
    
    313,465Total capitalization
    
    
    614,580
    
    
    
    587,194Total
    
    $
    986,423
    
    
    $
    914,112
 See accompanying notes to consolidated financial statements.




---



##### 



Otter Tail Corporation Consolidated Statements of Common Shareholders Equity AccumulatedCommon
    
    Par value,
    
    Premium on
    
    
    
    
    
    
    
    
    
    othershares
    
    common
    
    common
    
    Unearned
    
    Retained
    
    comprehensive
    
    Totaloutstanding
    
    shares
    
    shares
    
    compensation
    
    earnings
    
    income/(loss)
    
    equity( in thousands, except common shares outstanding)Balance, December 31, 2000
    
    
    24,574,288
    
    
    $
    122,871
    
    
    $
    50
    
    
    $
    (226
    )
    
    $
    140,796
    
    
    $
    (220
    )
    
    $
    263,271Common stock issuances
    
    
    79,202
    
    
    
    396
    
    
    
    1,187
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,583Amortization of unearned compensationstock awards
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    75
    
    
    
    
    
    
    
    
    
    
    
    75Comprehensive income:Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    43,603
    
    
    
    
    
    
    
    43,603Minimum liability adjustment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,755
    )
    
    
    (1,755
    )Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    41,848Tax benefit for exercise of stock options
    
    
    
    
    
    
    
    
    
    
    302
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    302Remove capital stock expense $6.35 preferred shares
    
    
    
    
    
    
    
    
    
    
    246
    
    
    
    
    
    
    
    (246
    )
    
    
    
    
    
    
    Purchase stock for employee purchase plan
    
    
    
    
    
    
    
    
    
    
    (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
    )
    
    
    279,308Common stock issuances
    
    
    938,670
    
    
    
    4,694
    
    
    
    22,094
    
    
    
    (2,674
    )
    
    
    
    
    
    
    
    
    
    
    24,114Amortization of unearned compensationstock awards
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    879
    
    
    
    
    
    
    
    
    
    
    
    879Comprehensive income:Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    46,128
    
    
    
    
    
    
    
    46,128Minimum liability adjustment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (10,014
    )
    
    
    (10,014
    )Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    36,114Tax benefit for exercise of stock options
    
    
    
    
    
    
    
    
    
    
    720
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    720Purchase stock for employee purchase plan
    
    
    
    
    
    
    
    
    
    
    (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
    )
    
    
    313,465Common stock issuances
    
    
    140,621
    
    
    
    703
    
    
    
    2,793
    
    
    
    (2,477
    )
    
    
    
    
    
    
    
    
    
    
    1,019Common stock retirements
    
    
    (8,967
    )
    
    
    (45
    )
    
    
    (225
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (270
    )Amortization of unearned compensationstock awards
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,110
    
    
    
    
    
    
    
    
    
    
    
    1,110Comprehensive income:Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    39,656
    
    
    
    
    
    
    
    39,656Minimum liability adjustment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7,560
    
    
    
    7,560Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    47,216Tax benefit for exercise of stock options
    
    
    
    
    
    
    
    
    
    
    111
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    111Purchase stock for employee purchase plan
    
    
    
    
    
    
    
    
    
    
    (299
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (299
    )Cumulative preferred dividends
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (735
    )
    
    
    
    
    
    
    (735
    )Common dividends
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (27,730
    )
    
    
    
    
    
    
    (27,730
    )Balance, December 31, 2003
    
    
    25,723,814
    
    
    $
    128,619
    
    
    $
    26,515
    
    
    $
    (3,313
    )
    
    $
    186,495
    
    
    $
    (4,429
    )
    
    $
    333,887
 See accompanying notes to consolidated financial statements.




---



##### 



Otter Tail Corporation Consolidated Statements of Cash FlowsFor the Years Ended December 31 (in thousands)
    
    2003
    
    2002
    
    2001Cash flows from operating activitiesNet income
    
    $
    39,656
    
    
    $
    46,128
    
    
    $
    43,603Adjustments to reconcile net income to net cash provided
by operating activities:Depreciation and amortization
    
    
    45,962
    
    
    
    42,613
    
    
    
    42,100Deferred investment tax creditnet
    
    
    (1,152
    )
    
    
    (1,153
    )
    
    
    (1,177
    )Deferred income taxes
    
    
    3,078
    
    
    
    2,669
    
    
    
    (1,441
    )Change in deferred debits and other assets
    
    
    (3,324
    )
    
    
    (5,178
    )
    
    
    (8,434
    )Change in noncurrent liabilities and deferred credits
    
    
    8,026
    
    
    
    1,049
    
    
    
    2,484Allowance for equity (other) funds used during construction
    
    
    (1,355
    )
    
    
    (1,742
    )
    
    
    (963
    )Unrealized (gains)/losses on derivatives net of regulatory deferral
    
    
    (2,057
    )
    
    
    
    
    
    
    Othernet
    
    
    1,629
    
    
    
    1,399
    
    
    
    (81
    )Cash provided by (used for) current assets and current liabilities:Change in receivables and inventories
    
    
    (35,451
    )
    
    
    (4,192
    )
    
    
    4,880Change in other current assets
    
    
    (2,499
    )
    
    
    (2,512
    )
    
    
    (432
    )Change in payables and other current liabilities
    
    
    19,260
    
    
    
    2,288
    
    
    
    (581
    )Change in interest and income taxes payable
    
    
    5,182
    
    
    
    (4,572
    )
    
    
    (2,429
    )Net cash provided by operating activities
    
    
    76,955
    
    
    
    76,797
    
    
    
    77,529Cash flows from investing activitiesCapital expenditures
    
    
    (50,734
    )
    
    
    (75,533
    )
    
    
    (53,596
    )Proceeds from disposal of noncurrent assets
    
    
    1,621
    
    
    
    2,462
    
    
    
    3,298Acquisitionsnet of cash acquired
    
    
    (12,896
    )
    
    
    (6,591
    )
    
    
    (8,948
    )Decreases/(increases) in other investments
    
    
    1,601
    
    
    
    5
    
    
    
    (1,884
    )Net cash used in investing activities
    
    
    (60,408
    )
    
    
    (79,657
    )
    
    
    (61,130
    )Cash flows from financing activitiesNet borrowings under line of credit
    
    
    
    
    
    
    25,507
    
    
    
    Proceeds from employee stock plans
    
    
    1,072
    
    
    
    3,091
    
    
    
    1,347Proceeds from issuance of long-term debt
    
    
    18,690
    
    
    
    65,124
    
    
    
    121,146Payments for retirement of long-term debt
    
    
    (9,906
    )
    
    
    (62,161
    )
    
    
    (81,549
    )Payments for debt issuance expenses
    
    
    (98
    )
    
    
    (2,677
    )
    
    
    (1,880
    )Redemption of preferred stock
    
    
    
    
    
    
    
    
    
    
    (18,000
    )Dividends paid and other distributions
    
    
    (28,937
    )
    
    
    (27,465
    )
    
    
    (27,344
    )Net cash (used in) provided by financing activities
    
    
    (19,179
    )
    
    
    1,419
    
    
    
    (6,280
    )Net change in cash and cash equivalents
    
    
    (2,632
    )
    
    
    (1,441
    )
    
    
    10,119Cash and cash equivalents at beginning of year
    
    
    9,937
    
    
    
    11,378
    
    
    
    1,259Cash and cash equivalents at end of year
    
    $
    7,305
    
    
    $
    9,937
    
    
    $
    11,378Supplemental disclosures of cash flow informationCash paid during the year for:Interest (net of amount capitalized)
    
    $
    16,781
    
    
    $
    16,831
    
    
    $
    16,313Income taxes
    
    $
    8,437
    
    
    $
    22,835
    
    
    $
    23,575
 See accompanying notes to consolidated financial statements.




---



##### 



Otter Tail Corporation Consolidated Statements of Capitalization, December 31 (in thousands)
    
    2003
    
    2002Long-term debtLombard US Equipment Finance note, variable, 2.59% at December 31, 2003, due October 2, 2006
    
    $
    16,300
    
    
    $
    Senior debentures 6.375%, due December 1, 2007
    
    
    50,000
    
    
    
    50,000Senior notes 6.63%, due December 1, 2011
    
    
    90,000
    
    
    
    90,000Insured senior notes 5.625%, due October 1, 2017
    
    
    40,000
    
    
    
    40,000Senior notes 6.80%, due October 1, 2032
    
    
    25,000
    
    
    
    25,000Pollution control refunding revenue bonds, variable, 1.35% at December 31, 2003, due December 1, 2012
    
    
    10,400
    
    
    
    10,400Grant County, South Dakota pollution control refunding revenue bonds 4.65%, due September 1, 2017
    
    
    5,185
    
    
    
    5,185Mercer County, North Dakota pollution control refunding revenue bonds 4.85%, due September 1, 2022
    
    
    20,765
    
    
    
    20,790Obligations of Varistar Corporation:8.15% five-year term note, due October 31, 2005
    
    
    1,957
    
    
    
    3,5317.80% ten-year term note, due October 31, 2007
    
    
    3,960
    
    
    
    6,712Variable 2.87% at December 31, 2003, due July 3, 2007
    
    
    2,789
    
    
    
    3,634Various up to 12.67% at December 31, 2003
    
    
    8,839
    
    
    
    11,022Total
    
    
    275,195
    
    
    
    266,274Less:Current maturities
    
    
    9,718
    
    
    
    7,690Unamortized debt discount
    
    
    284
    
    
    
    355Total long-term debt
    
    
    265,193
    
    
    
    258,229Cumulative preferred shareswithout par value (stated and
liquidatingvalue $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
    
    
    
    4,000Total preferred
    
    
    15,500
    
    
    
    15,500Cumulative preference shareswithout par value, authorized 1,000,000 shares; outstanding: noneTotal common shareholders equity
    
    
    333,887
    
    
    
    313,465Total capitalization
    
    $
    614,580
    
    
    $
    587,194
 See accompanying notes to consolidated financial statements.




---



##### 



Otter Tail Corporation
Notes to consolidated financial statements
For the years ended December 31, 2003, 2002 and 2001  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 (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation. These amounts are
not material.Regulation and Statement of Financial Accounting Standards 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 are
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 nonelectric 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 $1,970,000 for 2003,
$2,636,000 for 2002 and $1,342,000 for 2001. The cost of depreciable units of
property retired less salvage is charged to accumulated depreciation. Removal
costs, when incurred, are charged against the accumulated reserve for
estimated removal costs, a regulatory liability. 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 3.07% in 2003, 3.08% in 2002 and
3.06% in 2001. 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 operating 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, 2003 and 2002 included in the
consolidated balance sheet are as follows: Big Stone
    
    Coyote(in thousands)
    
    Plant
    
    StationDecember 31, 2003Electric plant in service
    
    $
    116,240
    
    
    $
    146,431Accumulated depreciation
    
    
    (68,387
    )
    
    
    (72,946
    )Net plant
    
    $
    47,853
    
    
    $
    73,485December 31, 2002Electric plant in service
    
    $
    113,731
    
    
    $
    146,739Accumulated depreciation
    
    
    (67,993
    )
    
    
    (74,610
    )Net plant
    
    $
    45,738
    
    
    $
    72,129
  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. In the case of
derivative instruments, such as the electric utilitys forward energy
contracts, the Company recognizes gains and losses on changes in the fair
market value of derivative instruments over the period held on a net basis,
in revenue, in accordance with the requirements of SFAS No. 133 as amended by
SFAS No. 149 and, when realized, on a net basis in a manner prescribed by
Emerging Issues Task Force (EITF) Issue 03-11. Gains and losses on forward
energy contracts subject to regulatory treatment are deferred and recognized
on a net basis in revenue in the period realized.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 from Company-owned generating units
are recognized when energy is delivered.As of July 1, 2003 the Companys unrealized gains and losses on forward
energy contracts, not meeting the definition of capacity contracts, are
marked-to-market and reflected on a net basis in electric revenue on the
Companys consolidated statement of income. Prior to the issuance of SFAS No.
149 in 2003, these forward energy contracts qualified for the normal
purchases and sales exception in SFAS No. 133 as amended by SFAS No. 138;
revenues on forward energy sales were recognized on delivery and costs
related to forward energy purchases were recognized as purchased power
expenses when the energy was received. With the issuance of SFAS No. 149, the
Companys forward energy contracts not meeting the definition of a capacity
contract and subject to unplanned netting no longer qualify for the normal
purchase and sales exception. The Company is required to mark-to-market these
forward energy contracts and recognize changes in the fair value of these
contracts as components of income over the life of the contracts.In the fourth quarter of 2003, the FASB reached a consensus on EITF Issue
03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are
Subject to FASB Statement No. 133, and Not Held for Trading Purposes. The
Company determined that the net basis prescribed in EITF Issue 03-11 is the
appropriate treatment for reporting its realized gains and losses on forward
energy contracts. Accordingly, the Company has reclassified prior period
purchased power expenses related to forward energy contracts as components of
electric operating revenue. The effects of the reclassification on prior
period income statements are shown in the following table. (in thousands)
    
    2002
    
    2001Operating revenue previously reported
    
    $
    710,116
    
    
    $
    654,132Less: Cost of forward energy purchases for resale
    
    
    (63,779
    )
    
    
    (74,964
    )Operating revenue under net reporting method
    
    $
    646,337
    
    
    $
    579,168Purchased power expense previously reported
    
    $
    94,694
    
    
    $
    99,491Less: Cost of forward energy purchases for resale
    
    
    (63,779
    )
    
    
    (74,964
    )Purchased power expense under net reporting method
    
    $
    30,915
    
    
    $
    24,527
  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 or when installation
is completed and accepted. 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 when the scan is performed.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 and estimated earnings recognized on uncompleted
contracts: December 31,
    
    December 31,(in thousands)
    
    2003
    
    2002Costs incurred on uncompleted contracts
    
    $
    124,839
    
    
    $
    42,768Less billings to date
    
    
    (137,881
    )
    
    
    (44,572
    )Plus estimated earnings recognized
    
    
    13,611
    
    
    
    6,340$
    569
    
    
    $
    4,536
  The following costs and estimated earnings in excess of billings are included
in the Companys Consolidated Balance Sheet. Billings in excess of costs and
estimated earnings on uncompleted contracts are included in accounts payable. December 31,
    
    December 31,(in thousands)
    
    2003
    
    2002Costs and estimated earnings in excess of billings on uncompleted contracts
    
    $
    4,591
    
    
    $
    5,529Billings in excess of costs and estimated earnings on uncompleted contracts
    
    
    (4,022
    )
    
    
    (993
    )$
    569
    
    
    $
    4,536
  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 EITF Issue 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 $1,489,000 as of December 31, 2003 and
$1,621,000 as of December 31, 2002. These costs are amortized over a
three-year period and evaluated annually for impairment.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 6, the Company has elected to
follow the accounting provisions of Accounting Principles Board (APB) 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 2001 through 2003 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. 2003
    
    2002
    
    2001(in thousands, except per share amounts)Net incomeAs reported
    
    $
    39,656
    
    
    $
    46,128
    
    
    $
    43,603Total stock-based employee compensation
expense determined under fair value-based
method for all awards net of related
tax effects
    
    
    (984
    )
    
    
    (1,038
    )
    
    
    (833
    )Pro forma
    
    $
    38,672
    
    
    $
    45,090
    
    
    $
    42,770Basic earnings per shareAs reported
    
    $
    1.52
    
    
    $
    1.80
    
    
    $
    1.69Pro forma
    
    $
    1.48
    
    
    $
    1.76
    
    
    $
    1.66Diluted earnings per shareAs reported
    
    $
    1.51
    
    
    $
    1.79
    
    
    $
    1.68Pro forma
    
    $
    1.47
    
    
    $
    1.75
    
    
    $
    1.64
  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, valuations of forward energy contracts, 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 2003 presentation. Such reclassifications had no impact on net
income, shareholders equity or cash flows provided from operations.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, 2003 and 2002 the Company had investments of
$4,616,000 and $5,359,000, respectively, in limited partnerships that invest
in tax-credit qualifying affordable housing projects. These investments
provided the Company with tax credits of $1,412,000 in 2003 and $1,418,000 in
both 2002 and 2001. The balance of investments at December 31, 2003 consists
of $2,378,000 in additional investments accounted for under the equity method
and $4,149,000 in other investments accounted for under the cost method, with
$837,000 related to participation in economic development loan pools. The
balance of investments at December 31, 2002 consists of $2,476,000 in
additional investments accounted for under the equity method and $6,055,000
in other investments accounted for under the cost method, with $1,303,000
related to participation in economic development loan pools. See further
discussion under note 11.




---



##### 



Inventories  The electric segment inventories are reported at average cost.
All other segments 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)
    
    2003
    
    2002Finished goods
    
    $
    20,349
    
    
    $
    15,795Work in process
    
    
    6,234
    
    
    
    1,438Raw material, fuel and supplies
    
    
    30,383
    
    
    
    26,921Total inventories
    
    $
    56,966
    
    
    $
    44,154
  Short-Term Debt  There was $30,000,000 in short-term debt outstanding as of
December 31, 2003 and 2002. The average interest rate paid on short-term debt
was 1.7% in 2003 and 2.2% in 2002. The interest rate on short-term debt
outstanding on December 31, 2003 was 1.5%.Goodwill and Intangible Assets  The Company adopted SFAS No. 142, Goodwill and
Other Intangible Assets, on January 1, 2002. SFAS No. 142 eliminates the
requirement to amortize goodwill and indefinite-lived intangible assets,
requiring instead that those assets be measured for impairment at least
annually, and more often when events indicate that an impairment exists.
Intangible assets with finite lives will continue to be amortized over their
estimated useful lives and reviewed for impairment in accordance with SFAS
No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.In adopting SFAS No. 142, the Company has performed the transitional
reassessment and impairment tests required as of January 1, 2002 and
determined that goodwill was not impaired and therefore no write-off was
necessary. If goodwill had not been amortized in 2001, net income would have
been higher by $2.45 million that year. 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)
    
    2003
    
    2002
    
    2001Net income:Reported net income
    
    $
    39,656
    
    
    $
    46,128
    
    
    $
    43,603Add back: goodwill amortization, net of tax
    
    
    
    
    
    
    
    
    
    
    2,449Adjusted net income
    
    $
    39,656
    
    
    $
    46,128
    
    
    $
    46,052Basic earnings per share:Reported basic earnings per share
    
    $
    1.52
    
    
    $
    1.80
    
    
    $
    1.69Add back: goodwill amortization, net of tax
    
    
    
    
    
    
    
    
    
    
    0.10Adjusted basic earnings per share
    
    $
    1.52
    
    
    $
    1.80
    
    
    $
    1.79Diluted earnings per share:Reported diluted earnings per share
    
    $
    1.51
    
    
    $
    1.79
    
    
    $
    1.68Add back: goodwill amortization, net of tax
    
    
    
    
    
    
    
    
    
    
    0.09Adjusted diluted earnings per share
    
    $
    1.51
    
    
    $
    1.79
    
    
    $
    1.77




---



##### 



The changes in the carrying amount of goodwill by segment are as follows: Balance
    
    Adjustment to
    
    Goodwill
    
    Goodwill
    
    BalanceDecember 31,
    
    goodwill acquired
    
    acquired
    
    impairment
    
    December 31,(in thousands)
    
    2002
    
    in 2002
    
    in 2003
    
    in 2003
    
    2003Plastics
    
    $
    19,302
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    19,302Manufacturing
    
    
    8,609
    
    
    
    (377
    )
    
    
    
    
    
    
    
    
    
    
    8,232Health services
    
    
    22,409
    
    
    
    
    
    
    
    1,924
    
    
    
    
    
    
    
    24,333Other business operations
    
    
    14,237
    
    
    
    
    
    
    
    6,702
    
    
    
    (250
    )
    
    
    20,689Total
    
    $
    64,557
    
    
    $
    (377
    )
    
    $
    8,626
    
    
    $
    (250
    )
    
    $
    72,556
  The Company had recorded $250,000 in goodwill related to the acquisition of
an energy management firm in 2002. Based on an offer to purchase this entity
in the fourth quarter of 2003, the Company determined the goodwill related to
this entity was impaired and, accordingly, recorded a $250,000 charge to
operating income in the fourth quarter of 2003.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 $630,000 for 2003, $535,000 for 2002 and $414,000 for
2001. The estimated annual amortization expense for these intangible assets
for the next five years is: $709,000 for 2004, $502,000 for 2005, $365,000
for 2006, $241,000 for 2007 and $189,000 for 2008.Total other intangibles as of December 31 are as follows: Gross
    
    
    
    
    
    Netcarrying
    
    Accumulated
    
    carryingamount
    
    amortization
    
    amount2003 (in thousands)Amortized intangible assets:Covenants not to compete
    
    $
    2,610
    
    
    $
    1,483
    
    
    $
    1,127Other intangible assets including contracts
    
    
    2,367
    
    
    
    1,118
    
    
    
    1,249Total
    
    $
    4,977
    
    
    $
    2,601
    
    
    $
    2,376Nonamortized intangible assets:Brand/trade name
    
    $
    4,720
    
    
    $
    
    
    
    $
    4,7202002 (in thousands)Amortized intangible assets:Covenants not to compete
    
    $
    1,920
    
    
    $
    1,143
    
    
    $
    777Other intangible assets including contracts
    
    
    2,079
    
    
    
    884
    
    
    
    1,195Total
    
    $
    3,999
    
    
    $
    2,027
    
    
    $
    1,972Nonamortized intangible assets:Brand name
    
    $
    3,620
    
    
    $
    
    
    
    $
    3,620
  The Company periodically evaluates the recovery of intangible assets based on
an analysis of undiscounted future cash flows. Evaluations of all intangible
assets including goodwill completed in January 2004 indicated that none of
the intangible assets reported on the Companys consolidated balance sheet as
of December 31, 2003 is impaired.




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##### 



Adoption of New Accounting Pronouncements  SFAS No. 143:The FASB issued SFAS
No. 143, Accounting for Asset Retirement Obligations (ARO), which provides
accounting requirements for retirement obligations associated with tangible
long-lived assets. 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 changed the accounting for ARO costs of the utilitys generating
plants. 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 month and the
capitalized cost will be depreciated over the useful life of the related
asset.The Companys asset retirement obligations include site restoration, the
closure of ash pits and the removal of storage tanks and asbestos at certain
electric utility generating plants. The Company has legal obligations
associated with retirement of other long-lived assets used in its electric
operations that cannot be reasonably estimated because the useful lives of
those assets are not determinable. There are no assets legally restricted for
the settlement of any of the Companys asset retirement obligations. The
Company reclassified $35.4 million in accumulated reserves related to
estimated removal costs from accumulated depreciation and amortization to a
regulatory liability on the face of its Consolidated Balance Sheet as of
December 31, 2002.The present value of the legal asset retirement obligations as of December
31, 2003 of $1,595,000 is included in Other noncurrent liabilities on the
Companys December 31, 2003 Consolidated Balance Sheet. The $1,595,000
liability includes the original obligation of $377,000 plus accumulated
accretion expense of $1,113,000 from the date the obligation arose through
January 1, 2003, plus $105,000 of additional accumulated accretion expense
for 2003. Since the recovery of these estimated removal costs, which include
accretion, has been provided for through the recovery of depreciation expense
included as a component of current electric retail rates, there is no
cumulative effect on income to be recorded related to the adoption of this
accounting principle. The difference between current accretion expense and
depreciation expense based on approved rates will accumulate as a regulatory
asset until the actual cost to settle the asset retirement obligation has
been incurred. At that time, the associated regulatory asset will be
transferred to the associated regulatory liability account as required by
regulatory accounting rules. The effects of the transitional noncash
transactions described above are not reflected in the Companys consolidated
statement of cash flows for the year ended December 31, 2003.The following table shows the amount of the asset retirement obligation
liability that would have been included in Other noncurrent liabilities in
prior periods had the requirements of SFAS No. 143 been in effect in those
periods. As of December 31,(in thousands)
    
    2002
    
    2001As reported
    
    
    
    
    
    
    Pro forma
    
    $
    1,490
    
    
    $
    1,392
  SFAS No. 149:The FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities, in April 2003. The statement
amends and clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. This statement is effective
for contracts entered into or modified after June 30, 2003. With the issuance
of SFAS No. 149, any forward contracts for the purchase or sale of energy
entered into after June 30, 2003 that do not meet the definition of a
capacity contract and are subject to unplanned netting, referred to as a book
out in the utility industry, are not eligible for the normal purchases and
sales exception provided for under SFAS No. 133 and modified by SFAS No. 149.
These contracts are considered derivatives and




---



##### 



are now subject to mark-to-market accounting. This classification applies to
virtually all of the Companys forward wholesale purchases and sales of
energy, which, prior to the issuance of SFAS No. 149, qualified for the
normal purchases and sales exception from mark-to-market accounting treatment
on the basis that it was probable that these contracts would not settle net
and would result in physical delivery. As a result of the issuance of SFAS
No. 149, unrealized gains and losses on forward purchases and sales of energy
are now recorded by the Company. All provisions of this statement have been
applied prospectively.The Company recorded $4.1 million in net marked-to-market gains on derivative
energy contracts in 2003, which reflects the difference between the
contracted prices for forward purchases and sales of energy and the fair
market values of contracts with matching terms and characteristics from the
time the contracts are entered into until they are settled. As of December
31, 2003, $2.1 million in recognized marked-to-market net gains was
unrealized. The Company expects 98% of these gains to be realized within the
first six months of 2004. A portion of net unrealized marked-to-market gains
is not reflected in current income but has been deferred under regulatory
accounting treatment until realized at the time of physical delivery.EITF Issue 03-11:At the July 31, 2003 EITF meeting, EITF Issue 03-11,
Reporting Realized Gains and Losses on Derivative Instruments That Are
Subject to FASB Statement No. 133, and Not Held for Trading Purposes as
Defined in Issue No. 02-3, was discussed. The EITF reached a consensus by
agreeing that determining whether realized gains and losses on derivative
contracts not held for trading purposes should be reported on a net or
gross basis is a matter of judgment that depends on the relevant facts and
circumstances. The FASB ratified the EITF consensus at its August 13, 2003
meeting. The reporting requirements of EITF Issue 03-11 are applicable to
financial statement presentation in the fourth quarter of 2003. The Company
determined that the net method of reporting was appropriate for its forward
energy contracts. Revenue from the Companys wholesale sales of energy
purchased from other suppliers is now reflected net of the related purchase
power costs in electric revenues on the Companys Consolidated Statements of
Income for the years 2003, 2002 and 2001. The effects of the application of
EITF Issue 03-11 and reclassification of prior years reported revenues are
shown in the table under Revenue Recognition in note 1. The application of
the reporting requirements of EITF Issue 03-11 had no effect on the Companys
consolidated net income, financial position or cash flows.FASB Interpretation (FIN) No. 46 (revised December 2003), Consolidation of
Variable Interest Entities, is an interpretation of Accounting Research
Bulletin No. 51, that addresses consolidation by business enterprises of
variable interest entities which have certain characteristics related to
equity at risk and rights and obligations to profits and losses. The
effective date for application of certain provisions of FIN 46 has been
deferred until the first quarter of 2004 for interests in variable interest
entities created before February 1, 2003 and held by a public entity that has
not previously applied the provisions of FIN 46. Implementation of FIN 46
will have no impact on the Companys consolidated net income, financial
position, or cash flows.SFAS No. 132 (revised 2003), Employers Disclosures about Pensions and Other
Postretirement Benefits, was revised in 2003 to require additional footnote
disclosures about the assets, obligations, cash flows and net periodic
benefit cost to defined benefit pension plans and other defined benefit
postretirement plans. The additional disclosures include information
describing the types of plan assets, investment strategy, measurement dates,
plan obligations, cash flows and components of net periodic benefit cost
recognized during interim periods. This statement is effective for financial
statements with fiscal years ending after December 15, 2003. The additional
disclosures required under SFAS No. 132 are included in note 10 to these
financial statements.




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##### 



2.
    
    Business Combinations, Dispositions and Segment InformationOn November 1, 2003 the Company acquired the assets and operations of Foley
Company (Foley) for $12.3 million in cash. Foley is a mechanical and prime
contracting firm based in Kansas City, Missouri, that provides a range of
specialty contracting including design-and-build services for new
construction, retrofitting, process piping, equipment settings, and
instrumentation and control systems. Major clients include water and
wastewater treatment plants, hospital and pharmaceutical facilities, power
generation plants, and other industrial and manufacturing projects across a
multi-state service area. Foley Company had gross revenues of $44.8 million
in 2002. This acquisition expands the Companys construction services to a
broader geographic region. Foley is included in the other business operations
segment.In 2003, the Company also acquired Topline Medical, Inc. and North Star
Medical Systems, Inc. The aggregate price paid for the companies in 2003,
neither of which was individually material, was $1.9 million in cash. These
acquisitions will allow the health services segment to increase sales
opportunities with an expanded line of products.Below is a condensed balance sheet disclosing the preliminary allocation of
the purchase price assigned to each major asset and liability category for
the companies acquired in 2003. (in thousands)
    
    Foley
    
    OthersAssetsCurrent assets
    
    $
    9,847
    
    
    $
    675Plant
    
    
    3,793
    
    
    
    45Goodwill
    
    
    6,702
    
    
    
    1,924Other intangible assets
    
    
    1,653
    
    
    
    102Total assets
    
    $
    21,995
    
    
    $
    2,746Liabilities and equityCurrent liabilities
    
    $
    8,618
    
    
    $
    669Long-term debt
    
    
    
    
    
    
    136Other long-term liabilities
    
    
    1,095
    
    
    
    Equity
    
    
    12,282
    
    
    
    1,941Total liabilities and equity
    
    $
    21,995
    
    
    $
    2,746
  The above allocations are subject to adjustment. Goodwill related to the
Foley acquisition is not deductible for income tax purposes. The goodwill
related to the other acquisitions is deductible for income tax purposes over
15 years. Other intangible assets related to the Foley acquisition includes a
$1,100,000 nonamortizable trade name and $553,000 in intangible assets being
amortized over 5 years. Other intangible assets related to the other
acquisitions are being amortized over 4 years.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 expands 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.Below is a condensed balance sheet disclosing the fair value assigned to each
major asset and liability category for the companies acquired in 2002. (in thousands)
    
    CIS
    
    ShoreMaster
    
    Galva Foam
    
    OthersAssetsCurrent assets
    
    $
    1,439
    
    
    $
    9,510
    
    
    $
    4,953
    
    
    $
    131Plant
    
    
    3,975
    
    
    
    4,599
    
    
    
    1,713
    
    
    
    298Goodwill
    
    
    5,847
    
    
    
    4,292
    
    
    
    2,650
    
    
    
    1,616Other intangible assets
    
    
    30
    
    
    
    4,461
    
    
    
    41
    
    
    
    60Total assets
    
    $
    11,291
    
    
    $
    22,862
    
    
    $
    9,357
    
    
    $
    2,105Liabilities and equityCurrent liabilities
    
    $
    1,747
    
    
    $
    9,642
    
    
    $
    2,304
    
    
    $
    32Long-term debt
    
    
    2,584
    
    
    
    2,723
    
    
    
    
    
    
    
    Other long-term liabilities
    
    
    707
    
    
    
    797
    
    
    
    372
    
    
    
    Equity
    
    
    6,253
    
    
    
    9,700
    
    
    
    6,681
    
    
    
    2,073Total liabilities and equity
    
    $
    11,291
    
    
    $
    22,862
    
    
    $
    9,357
    
    
    $
    2,105
  All of the 2003 and 2002 acquisitions were accounted for using the purchase
method of accounting. The pro forma effect of these acquisitions on 2002 and
2001 revenues, net income or earnings per share was not significant.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.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.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
polyvinylchloride (PVC) and polyethylene (PE) 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, patient monitoring equipment, and related 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 42 states.Other business operations consists of businesses in electrical and telephone
construction contracting, specialty contracting including design and build
services for new construction, transportation, telecommunications,
entertainment, energy services, and natural gas marketing, as well as the
portion of corporate administrative and general expenses that is not
allocated to other segments. The electrical and telephone construction
contracting companies and energy services and natural gas marketing business
operate primarily in the central region of the Unites States. 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 2003, 2002 and 2001 is
presented in the following table. 2003
    
    2002
    
    2001(in thousands)Operating revenueElectric
    
    $
    267,494
    
    
    $
    244,005
    
    
    $
    232,720Plastics
    
    
    86,009
    
    
    
    82,931
    
    
    
    63,216Manufacturing
    
    
    177,805
    
    
    
    142,390
    
    
    
    123,436Health services
    
    
    100,912
    
    
    
    93,420
    
    
    
    79,129Other business operations
    
    
    123,475
    
    
    
    84,627
    
    
    
    80,667Intersegment eliminations
    
    
    (2,456
    )
    
    
    (1,036
    )
    
    
    Total
    
    $
    753,239
    
    
    $
    646,337
    
    
    $
    579,168Depreciation and amortizationElectric
    
    $
    26,008
    
    
    $
    24,910
    
    
    $
    24,272Plastics
    
    
    2,126
    
    
    
    1,760
    
    
    
    3,229Manufacturing
    
    
    7,708
    
    
    
    6,525
    
    
    
    5,139Health services
    
    
    5,137
    
    
    
    4,410
    
    
    
    3,517Other business operations
    
    
    4,983
    
    
    
    5,008
    
    
    
    5,943Total
    
    $
    45,962
    
    
    $
    42,613
    
    
    $
    42,100Operating incomeElectric
    
    $
    57,537
    
    
    $
    53,879
    
    
    $
    57,150Plastics
    
    
    4,013
    
    
    
    10,841
    
    
    
    (1,391
    )Manufacturing
    
    
    8,133
    
    
    
    9,477
    
    
    
    12,175Health services
    
    
    5,248
    
    
    
    8,654
    
    
    
    6,862Other business operations
    
    
    (3,771
    )
    
    
    (534
    )
    
    
    2,688Total operating income
    
    $
    71,160
    
    
    $
    82,317
    
    
    $
    77,484Other income and deductions  net
    
    
    1,292
    
    
    
    1,717
    
    
    
    2,193Interest charges
    
    
    17,866
    
    
    
    17,845
    
    
    
    15,991Income before income taxes
    
    $
    54,586
    
    
    $
    66,189
    
    
    $
    63,686Earnings available for common sharesElectric
    
    $
    33,411
    
    
    $
    31,244
    
    
    $
    31,065Plastics
    
    
    2,019
    
    
    
    5,668
    
    
    
    (1,628
    )Manufacturing
    
    
    3,885
    
    
    
    4,524
    
    
    
    6,117Health services
    
    
    2,464
    
    
    
    4,555
    
    
    
    4,213Other business operations
    
    
    (2,858
    )
    
    
    (599
    )
    
    
    1,843Total
    
    $
    38,921
    
    
    $
    45,392
    
    
    $
    41,610Capital expendituresElectric
    
    $
    28,177
    
    
    $
    45,842
    
    
    $
    34,992Plastics
    
    
    3,984
    
    
    
    5,592
    
    
    
    1,572Manufacturing
    
    
    9,903
    
    
    
    15,049
    
    
    
    10,516Health services
    
    
    5,427
    
    
    
    3,874
    
    
    
    3,282Other business operations
    
    
    3,243
    
    
    
    5,176
    
    
    
    3,234Total
    
    $
    50,734
    
    
    $
    75,533
    
    
    $
    53,596Identifiable assetsElectric
    
    $
    609,190
    
    
    $
    586,231
    
    
    $
    559,185Plastics
    
    
    58,538
    
    
    
    54,926
    
    
    
    45,649Manufacturing
    
    
    138,493
    
    
    
    114,120
    
    
    
    67,033Health services
    
    
    67,587
    
    
    
    64,785
    
    
    
    50,560Other business operations
    
    
    112,615
    
    
    
    94,050
    
    
    
    95,351Total
    
    $
    986,423
    
    
    $
    914,112
    
    
    $
    817,778
  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 MattersIn 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. Because the electric utilitys 2002 rate
of return was within the allowable range defined in the plan, no sharing
occurred in 2003. The electric utilitys 2003 rate of return is expected to
be within the allowable range defined in the plan.4.
    
    Regulatory Assets and LiabilitiesThe following table indicates the amount of regulatory assets and liabilities
recorded on the Companys Consolidated Balance Sheets: December 31,
    
    December 31,(in thousands)
    
    2003
    
    2002Regulatory assets:Deferred income taxes
    
    $
    12,750
    
    
    $
    10,238Debt expenses and reacquisition premiums
    
    
    3,863
    
    
    
    4,323Deferred conservation program costs
    
    
    882
    
    
    
    844Plant acquisition costs
    
    
    285
    
    
    
    329Deferred marked-to-market losses
    
    
    1,802
    
    
    
    Accrued cost-of-energy revenue
    
    
    3,693
    
    
    
    768Accumulated ARO accretion/depreciation adjustment
    
    
    117
    
    
    
    Total regulatory assets
    
    $
    23,392
    
    
    $
    16,502Regulatory liabilities:Accumulated reserve for estimated removal costs
    
    $
    33,579
    
    
    $
    35,376Deferred income taxes
    
    
    7,496
    
    
    
    8,960Deferred marked-to-market gains
    
    
    1,684
    
    
    
    Gain on sale of division office building
    
    
    167
    
    
    
    173Total regulatory liabilities
    
    $
    42,926
    
    
    $
    44,509Net regulatory liability position
    
    $
    19,534
    
    
    $
    28,007
  The regulatory assets and liabilities related to deferred income taxes are
the result of the adoption of SFAS No. 109, Accounting for Income Taxes. Debt
expenses and reacquisition premiums are being recovered from customers over
the remaining original lives of the reacquired debt issues, the longest of
which is 19 years. Deferred conservation program costs included in Deferred
debits  Other represent mandated conservation expenditures recoverable
through retail electric rates over the next 1.5 years. Plant acquisition
costs included in Deferred debits  Other will be amortized over the next 7
years. Accrued cost-of-energy revenue included in Accrued utility revenues
will be recovered over the next nine




---



##### 



months. All deferred marked-to-market gains and losses are related to forward
purchases and sales of energy scheduled for delivery in 2004. The accumulated
reserve for estimated removal costs is reduced for actual removal costs
incurred. The remaining regulatory assets and liabilities are being recovered
from electric customers over the next 30 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 expense or income item
in the period in which the application of SFAS No. 71 ceases.5.
    
    Forward Energy Contracts Classified as DerivativesWith the issuance of SFAS No. 149, all of the electric utilitys wholesale purchases
and sales of energy under forward contracts that do not meet the definition of
capacity contracts are considered derivatives subject to mark-to-market accounting.
The electric utilitys objective in entering into forward contracts for the purchase
and sale of energy is to optimize the use of its generating and transmission
facilities and leverage its knowledge of wholesale energy markets in the region to
maximize financial returns for the benefit of both its customers and shareholders. The
electric utilitys intent upon entering into these contracts is to settle them through
the physical delivery of energy when physically possible and economically feasible.
Although these contracts are classified as derivatives, the electric utility does not
use them for hedging and does not presently hold these contracts for trading purposes.In 2003, the electric utility recorded wholesale sales of electricity totaling
3,782,899 mwhs. Of this total, 597,870 mwhs (15.8%) came from company-owned generation
and 3,185,029 mwhs (84.2%) came from wholesale purchases. Net settlements, or book
outs, constituted 9.5% of 2003 mwh sales by volume. Electric revenues for 2003 include
$29,530,000 related to wholesale electric sales and net unrealized derivative gains on
forward energy contracts broken down as follows: (in thousands)Wholesale sales from companyowned generation
    
    
    
    
    
    $
    18,428Wholesale sales of purchased power at contract and market
    
    $
    121,303Contract and market cost of purchased power resold
    
    
    (114,259
    )Net margins on wholesale sales of purchased power
    
    
    
    
    
    
    7,044Marked-to-market gains on settled contracts
    
    
    2,978Marked-to-market losses on settled contracts
    
    
    (977
    )Net marked-to-market gain on settled contracts
    
    
    
    
    
    
    2,001Unrealized marked-to-market gains on open contracts
    
    
    6,338Unrealized marked-to-market losses on open contracts
    
    
    (4,281
    )Net unrealized marked-to-market gain on open contracts
    
    
    
    
    
    
    2,057Wholesale electric revenue
    
    
    
    
    
    $
    29,530
  A portion of gains and losses related to open forward energy contracts marked
to market as derivative assets and derivative liabilities on the Companys
Consolidated Balance Sheet at December 31, 2003 are deferred under regulatory
accounting treatment. There is a $5,443,000 derivative asset and $1,684,000
deferred derivative gain and regulatory liability, and a $3,504,000
derivative liability and $1,802,000 deferred derivative loss and regulatory
asset related to open forward energy contracts on the Companys Consolidated
Balance Sheet at December 31, 2003. The derivative asset and derivative
liability represent the difference between the contracted price and December
31, 2003 market price of forward energy contracts, of which over 93% are
scheduled for settlement prior to May 1, 2004.




---



##### 



6.
    
    Common Shares and Earnings Per ShareNew Issuances  Common stock issuances during 2003 included 47,552 shares
issued as a result of stock options exercised, 2,169 shares issued as
directors compensation and 90,900 shares of restricted stock issued as
officers and directors compensation. In order to maintain a balanced
capital structure consistent with the risk profile of the Companys
diversified mix of businesses, the Company began issuing new shares of common
stock in January 2004 to meet the requirements of its employee stock purchase
plan and dividend reinvestment program and share purchase plan rather than
purchasing shares on the open market.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 and
restricted stock granted as of December 31, 2003 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 No. 25. Presented below is a summary of the stock options activity: Stock Option Activity 2003
    
    2002
    
    2001Average
    
    
    
    
    
    Average
    
    
    
    
    
    Averageexercise
    
    
    
    
    
    exercise
    
    
    
    
    
    exerciseOptions
    
    price
    
    Options
    
    price
    
    Options
    
    priceOutstanding,
beginning of year
    
    
    1,360,721
    
    
    $
    24.68
    
    
    
    1,265,042
    
    
    $
    22.62
    
    
    
    787,316
    
    
    $
    19.55Granted
    
    
    222,750
    
    
    
    27.24
    
    
    
    278,750
    
    
    
    31.34
    
    
    
    582,000
    
    
    
    26.33Exercised
    
    
    47,700
    
    
    
    20.21
    
    
    
    130,797
    
    
    
    19.71
    
    
    
    74,936
    
    
    
    19.44Forfeited
    
    
    4,646
    
    
    
    23.09
    
    
    
    52,274
    
    
    
    22.83
    
    
    
    29,338
    
    
    
    22.17Outstanding, year-end
    
    
    1,531,125
    
    
    $
    25.16
    
    
    
    1,360,721
    
    
    
    24.68
    
    
    
    1,265,042
    
    
    
    22.62Exercisable, year-end
    
    
    791,661
    
    
    $
    22.97
    
    
    
    449,385
    
    
    $
    21.75
    
    
    
    257,369
    
    
    $
    19.83Fair value of options
granted during year
    
    $
    5.42
    
    
    
    
    
    
    $
    7.07
    
    
    
    
    
    
    $
    5.88
 The fair values of the options granted were estimated using the Black-Scholes
option-pricing model under the following assumptions: 2003
    
    2002
    
    2001Risk-free interest rate
    
    
    3.7
    %
    
    
    5.2
    %
    
    
    5.5
    %Expected lives
    
    7 years
    
    7 years
    
    7 yearsExpected volatility
    
    
    26.3
    %
    
    
    26.0
    %
    
    
    24.9
    %Dividend yield
    
    
    4.0
    %
    
    
    4.0
    %
    
    
    4.0
    %
 The following table summarizes information about options outstanding as of
December 31, 2003: Options outstanding
    
    Options exercisableWeighted-average
    
    Weighted-
    
    
    
    
    
    Weighted-Outstanding
    
    remaining
    
    average
    
    Exercisable
    
    averageRange of
    
    as of
    
    contractual
    
    exercise
    
    as of
    
    exerciseexercise prices
    
    12/31/03
    
    life (yrs)
    
    price
    
    12/31/03
    
    price$18.80-$21.94
    
    
    495,125
    
    
    
    5.7
    
    
    $
    19.48
    
    
    
    437,250
    
    
    $
    19.44$21.95-$25.07
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $25.08-$26.77
    
    
    520,750
    
    
    
    7.3
    
    
    $
    26.25
    
    
    
    276,750
    
    
    $
    26.25$26.78-$31.34
    
    
    515,250
    
    
    
    8.7
    
    
    $
    29.53
    
    
    
    77,661
    
    
    $
    31.13
  In addition to the stock options granted, 90,900, 85,800 and 1,681 shares of
restricted stock were granted during 2003, 2002 and 2001, respectively. The
total compensation cost recognized in income for stock-based employee
compensation awards was $1,110,000 in 2003, $879,000 in 2002 and $125,000 in
2001. 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. Of the 400,000 common shares authorized for
purchase under the Purchase Plan, 131,225 were still available for purchase
as of January 1, 2004. To provide shares for the Purchase Plan, common shares
were purchased in the open market totaling 66,724 shares in 2003,
57,997 shares in 2002 and 56,612 shares in 2001.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. From June 1999 through
December 2002, common shares needed for the Plan were 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.7.
    
    Retained Earnings RestrictionThe 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, 2003.8.
    
    Commitments and ContingenciesAt December 31, 2003 the electric utility had commitments under contracts in
connection with construction programs aggregating approximately $2,929,000.
For capacity and energy requirements, the electric utility has agreements
extending through 2008 at annual costs of approximately $16,708,000 in 2004,
$15,307,000 in 2005, $14,755,000 in 2006, $14,771,000 in 2007 and $14,848,000
in 2008.The electric utility has contracts providing for the purchase and delivery of
a significant portion of its current coal requirements. These contracts
expire between 2004 and 2016. In total, the electric utility is committed to
the minimum purchase of approximately $85,893,000 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
    
    Total(in thousands)2004
    
    $
    1,661
    
    
    $
    19,033
    
    
    $
    20,6942005
    
    
    1,661
    
    
    
    16,144
    
    
    
    17,8052006
    
    
    1,661
    
    
    
    10,364
    
    
    
    12,0252007
    
    
    1,661
    
    
    
    5,815
    
    
    
    7,4762008
    
    
    1,661
    
    
    
    1,651
    
    
    
    3,312Later years
    
    
    1,377
    
    
    
    2,508
    
    
    
    3,885Total
    
    $
    9,682
    
    
    $
    55,515
    
    
    $
    65,197
  Rent expense was $25,684,000, $22,282,000 and $20,242,000, for 2003, 2002 and
2001, 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.9.
    
    Short-Term and Long-Term BorrowingsShort-term debt  On August 25, 2003 the Companys line of credit was
increased from $50 million to $70 million. This line is available to support
borrowings of the Companys nonelectric operations. This line of credit bears
interest at the rate of LIBOR plus 0.5% and expires on April 28, 2004. 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,
2003, $30 million of the $70 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  On September 24, 2003, the Company borrowed $16.3 million
under a loan agreement with Lombard US Equipment Finance Corporation in the
form of an unsecured note. The terms of the note require quarterly principal
payments in the amount of $582,143 commencing in January 2004 with a final
installment due on October 2, 2006, the stated maturity date of the note. The
term of the note can be extended for additional one-year periods following
the stated maturity date through October 1, 2010. The note bears interest at
a variable rate of 3-month LIBOR plus 1.43% on the unpaid principal balance
with interest payments due quarterly commencing on October 1, 2003 until the
principal balance is repaid in full. The Company used proceeds from the note
to pay down borrowings under the Companys line of credit that were used to
finance acquisitions and capital expenditures of its nonelectric
subsidiaries. The covenants associated with the note are consistent with
existing credit facilities. There are no rating triggers associated with this
note.In 2003, $25,000 of Mercer County, North Dakota pollution control refunding
revenue bonds 4.85%, due September 1, 2022 were redeemed for estate
settlement purposes and retired.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 retire the Companys remaining first mortgage bonds and
to repay short-term debt used to finance a portion of the costs related to
the new gas-fired combustion turbine plant constructed by the electric
utility.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). 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, 2003 for each of the next five years are
$9,718,000 for 2004, $7,420,000 for 2005, $14,872,000 for 2006, $50,985,000
for 2007 and $445,000 for 2008.Covenants  The Companys line of credit, its $90 million 6.63% senior notes
due 2011 and Lombard US Equipment Finance note contain covenants that require
the Company to maintain 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, 2003 the Company was in compliance with all of the
covenants under its line of credit and its other debt obligations.10.
    
    Pension Plan and Other Postretirement BenefitsPension Plan  The Companys noncontributory funded pension plan covers
substantially all electric utility and corporate employees. The plan provides
100% vesting after five 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.The plan assets consist of common stock and bonds of public companies, U.S.
government securities, cash and cash equivalents. None of the plan assets are
invested in common stock, preferred stock or debt securities of the Company.




---



##### 



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 ended
December 31, 2003 and a statement of the funded status as of December 31 of
both years: 2003
    
    2002(in thousands)Reconciliation of benefit obligation:Obligation at January 1
    
    $
    145,262
    
    
    $
    124,523Service cost
    
    
    3,779
    
    
    
    3,120Interest cost
    
    
    9,491
    
    
    
    9,269Benefit payments
    
    
    (8,190
    )
    
    
    (7,760
    )Plan amendments
    
    
    
    
    
    
    2,770Actuarial loss
    
    
    3,817
    
    
    
    13,340Obligation at December 31
    
    $
    154,159
    
    
    $
    145,262Reconciliation of fair value of plan assets:Fair value of plan assets at January 1
    
    $
    113,803
    
    
    $
    138,794Actual return on plan assets
    
    
    27,198
    
    
    
    (17,231
    )Benefit payments
    
    
    (8,190
    )
    
    
    (7,760
    )Fair value of plan assets at December 31
    
    $
    132,811
    
    
    $
    113,803Funded status
    
    $
    (21,348
    )
    
    $
    (31,459
    )Unrecognized net actuarial loss
    
    
    22,533
    
    
    
    32,981Unrecognized prior service cost
    
    
    7,025
    
    
    
    8,195Net amount recognized
    
    $
    8,210
    
    
    $
    9,717
  The following table provides the amounts recognized in the Consolidated Balance Sheets as of December 31: 2003
    
    2002(in thousands)Prepaid pension cost
    
    $
    8,210
    
    
    
    9,717Additional minimum liability
    
    
    
    
    
    
    (15,149
    )Net pension asset/(liability)
    
    $
    8,210
    
    
    $
    (5,432
    )Intangible asset
    
    
    
    
    
    
    8,195Accumulated other comprehensive loss
    
    
    
    
    
    
    6,954Net amount recognized
    
    $
    8,210
    
    
    $
    9,717
  Additional information on the status of the pension plan as of December 31: 2003
    
    2002(in thousands)Projected benefit obligation
    
    $
    154,159
    
    
    $
    145,262Accumulated benefit obligation
    
    
    130,072
    
    
    
    119,235Fair value of plan assets
    
    
    132,811
    
    
    
    113,803
  Components of net periodic pension benefit cost: 2003
    
    2002
    
    2001(in thousands)Service costbenefit earned during the period
    
    $
    3,779
    
    
    $
    3,120
    
    
    $
    2,544Interest cost on projected benefit obligation
    
    
    9,491
    
    
    
    9,269
    
    
    
    8,766Expected return on assets
    
    
    (12,933
    )
    
    
    (14,957
    )
    
    
    (14,610
    )Amortization of transition asset
    
    
    
    
    
    
    (73
    )
    
    
    (235
    )Amortization of prior-service cost
    
    
    1,170
    
    
    
    1,285
    
    
    
    1,107Amortization of net gain
    
    
    
    
    
    
    (1,284
    )
    
    
    (1,900
    )Net periodic pension cost/(income)
    
    $
    1,507
    
    
    $
    (2,640
    )
    
    $
    (4,328
    )
  The change in the additional minimum liability included in other
comprehensive loss was ($6,954,000) in 2003 and $6,954,000 in 2002.




---



##### 



Weighted-average assumptions used to determine benefit obligations at December
31: 2003
    
    2002Discount rate
    
    
    6.25
    %
    
    
    6.75
    %Rate of increase in future compensation level
    
    
    3.75
    %
    
    
    4.25
    %
 Weighted-average assumptions used to determine net periodic pension cost for
the year ended December 31: 2003
    
    2002Discount rate
    
    
    6.75
    %
    
    
    7.50
    %Long-term rate of return on plan assets
    
    
    8.50
    %
    
    
    9.50
    %Rate of increase in future compensation level
    
    
    4.25
    %
    
    
    4.25
    %
  To develop the expected long-term rate of return on assets assumption, the
Company considered the historical returns and the future expectations for
returns for each asset class, as well as the target asset allocation of the
pension portfolio.The assumed rate of return on pension fund assets for the determination of
2004 net periodic pension cost is 8.5%.The Companys pension plan weighted-average asset allocations at December 31,
2003 and 2002, by asset category are as follows: Asset Category
    
    2003
    
    2002Enhanced core equity securities
    
    
    53.3
    %
    
    
    47.4
    %Small capitalization equity securities
    
    
    10.6
    %
    
    
    8.7
    %International equity securities
    
    
    13.1
    %
    
    
    10.6
    %Total equity securities
    
    
    77.0
    %
    
    
    66.7
    %Fixed-income securities
    
    
    23.0
    %
    
    
    33.3
    %100.0
    %
    
    
    100.0
    %
  The following objectives guide the decisions and investment strategy of the
Companys pension committee for the pension plan (the Plan).  
    
    The Plan is managed to operate in perpetuity.
    
    The Plan will meet the pension benefit obligation payments of Otter
Tail Corporation.
    
    The Plans assets should be invested with the objective of meeting
current and future payment requirements while minimizing annual
contributions and their volatility.
    
    The asset strategy reflects the desire to meet current and future
benefit payments.  The asset allocation strategy developed by the Companys pension committee is
based on the current needs of the Plan, the investment objectives listed
above, the investment preferences and risk tolerance of the committee and a
desired degree of diversification.The asset allocation strategy contains guideline percentages, at market
value, of the total Plan invested in various asset classes. The strategic
target allocation shown in the table below is a guide that will at times not
be reflected in actual asset allocations that may be dictated by prevailing
market conditions, independent actions of the pension committee and/or
investment managers, and required cash flows to and from the Plan. The
tactical range shown below provides flexibility for the investment managers
portfolios to vary around the target allocation without the need for
immediate rebalancing. The Companys pension committee monitors actual asset
allocations and directs contributions and withdrawals toward maintaining the
targeted allocation percentages listed in the table below. Security class
    
    Strategic Target
    
    Tactical RangeEnhanced core equity securities
    
    
    48
    %
    
    
    40%-55
    %Small capitalization equity securities
    
    
    12
    %
    
    
    9%-15
    %International equity securities
    
    
    10
    %
    
    
    5%-15
    %Total equity securities
    
    
    70
    %
    
    
    60%-80
    %Fixed-income securities
    
    
    30
    %
    
    
    20%-40
    %




---



##### 



Cash Flows: The Company is not required to make a contribution to the pension
plan in 2004, but is currently considering future funding options.Executive Survivor and Supplemental Retirement Plan (ES&SRP)  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
certain 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.The following tables provide a reconciliation of the changes in the plans
benefit obligations over the two-year period ended December 31, 2003 and a
statement of the funded status as of December 31 of both years: 2003
    
    2002(in thousands)Reconciliation of benefit obligation:Obligation at January 1
    
    $
    20,309
    
    
    $
    14,365Service cost
    
    
    417
    
    
    
    (51
    )Interest cost
    
    
    1,426
    
    
    
    1,175Plan amendments
    
    
    1,083
    
    
    
    (182
    )Actuarial loss
    
    
    2,242
    
    
    
    5,566Early retirement
    
    
    
    
    
    
    240Benefit payments
    
    
    (1,026
    )
    
    
    (804
    )Obligation at December 31
    
    $
    24,451
    
    
    $
    20,309Funded status:Funded status at December 31
    
    $
    (24,451
    )
    
    $
    (20,309
    )Unrecognized prior-service cost
    
    
    1,772
    
    
    
    836Unrecognized net actuarial loss
    
    
    11,961
    
    
    
    10,292Net amount recognized
    
    $
    (10,718
    )
    
    $
    (9,181
    )
  The following table provides the amounts recognized in the Consolidated Balance Sheets as of December
31: 2003
    
    2002(in thousands)Accrued benefit liability
    
    $
    (16,919
    )
    
    $
    (15,052
    )Intangible asset
    
    
    1,772
    
    
    
    836Accumulated other comprehensive loss
    
    
    4,429
    
    
    
    5,035Net amount recognized
    
    $
    (10,718
    )
    
    $
    (9,181
    )
  Additional information on the ES&SRP defined benefit pension plan as of December 31: 2003
    
    2002(in thousands)Projected benefit obligation
    
    $
    24,451
    
    
    $
    20,309Accumulated benefit obligation
    
    
    16,919
    
    
    
    15,052Fair value of plan assets
    
    
    
    
    
    
    
 Components of net periodic pension benefit cost: 2003
    
    2002
    
    2001(in thousands)Service costbenefit earned during the period
    
    $
    417
    
    
    $
    (51
    )
    
    $
    (76
    )Interest cost on projected benefit obligation
    
    
    1,426
    
    
    
    1,175
    
    
    
    956Amortization of prior-service cost
    
    
    147
    
    
    
    86
    
    
    
    191Recognized net actuarial loss
    
    
    573
    
    
    
    398
    
    
    
    117Net periodic pension cost
    
    $
    2,563
    
    
    $
    1,608
    
    
    $
    1,188Early retirement benefit
    
    
    
    
    
    
    240
    
    
    
    Total
    
    $
    2,563
    
    
    $
    1,848
    
    
    $
    1,188
  The change in the additional minimum liability included in other
comprehensive loss was ($606,000) in 2003 and $3,060,000 in 2002.




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##### 



Weighted-average assumptions used to determine benefit obligations at December 31: 2003
    
    2002Discount rate
    
    
    6.25
    %
    
    
    6.75
    %Rate of increase in future compensation level
    
    
    5.88
    %
    
    
    5.63
    %
  Weighted-average assumptions used to determine net periodic pension cost for the year ended December 31: 2003
    
    2002Discount rate
    
    
    6.75
    %
    
    
    7.50
    %Rate of increase in future compensation level
    
    
    5.63
    %
    
    
    4.50
    %
  Cash Flows: The ES&SRP is unfunded and has no assets; contributions are equal
to the benefits paid to plan participants. The Company expects to make
contributions/benefit payments of $1,147,000 to plan participants in 2004.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 following tables provide a reconciliation of the changes in the plans
benefit obligations over the two-year period ended December 31, 2003 and a
statement of the funded status as of December 31 of both years: 2003
    
    2002(in thousands)Reconciliation of benefit obligation:Obligation at January 1
    
    $
    39,318
    
    
    $
    28,550Service cost
    
    
    1,009
    
    
    
    615Interest cost
    
    
    2,619
    
    
    
    2,166Benefit payments
    
    
    (2,981
    )
    
    
    (2,436
    )Participant premium payments
    
    
    1,051
    
    
    
    953Plan amendments
    
    
    
    
    
    
    (285
    )Actuarial loss
    
    
    992
    
    
    
    9,755Obligation at December 31
    
    $
    42,008
    
    
    $
    39,318Funded status:Funded status at December 31
    
    $
    (42,008
    )
    
    $
    (39,318
    )Unrecognized transition obligation
    
    
    6,734
    
    
    
    7,482Unrecognized prior-service cost
    
    
    700
    
    
    
    395Unrecognized loss
    
    
    11,344
    
    
    
    11,059Net amount recognized
    
    $
    (23,230
    )
    
    $
    (20,382
    )
  The net amounts recognized are shown on the Consolidated Balance Sheets as of
December 31, 2003 and 2002 under the title of Other postretirement benefits
liability.Components of net periodic postretirement benefit cost: 2003
    
    2002
    
    2001(in thousands)Service cost
    
    $
    1,009
    
    
    $
    615
    
    
    $
    681Interest cost
    
    
    2,619
    
    
    
    2,166
    
    
    
    1,768Amortization of transition obligation
    
    
    748
    
    
    
    748
    
    
    
    748Amortization of prior-service cost
    
    
    (305
    )
    
    
    (305
    )
    
    
    111Amortization of net loss/(gain)
    
    
    708
    
    
    
    
    
    
    
    (51
    )Net periodic postretirement benefit cost
    
    $
    4,779
    
    
    $
    3,224
    
    
    $
    3,257
  Weighted-average assumptions used to determine benefit obligations at December
31: 2003
    
    2002Discount rate
    
    
    6.25
    %
    
    
    6.75
    %




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##### 



Weighted-average assumptions used to determine net periodic postretirement
benefit cost for the year ended December 31: 2003
    
    2002Discount rate
    
    
    6.75
    %
    
    
    7.50
    %
  Assumed healthcare cost-trend rates as of December 31: 2003
    
    2002Healthcare cost-trend rate assumed for next year
    
    
    11.0

    %
    
    
    12.0
    %Rate at which the cost-trend rate is assumed to decline
    
    
    5.0
    %
    
    
    5.0
    %Year that the rate reaches the ultimate trend rate
    
    
    2010
    
    
    
    2010
  Assumed healthcare cost-trend rates have a significant effect on the amounts
reported for healthcare plans. A one-percentage-point change in assumed
healthcare cost-trend rates for 2003 would have the following effects: 1 point
    
    1 pointincrease
    
    decrease(in thousands)Effect on total of service and interest cost
    
    $
    528
    
    
    $
    (611
    )Effect on the postretirement benefit obligation
    
    $
    5,153
    
    
    $
    (4,263
    )
  Cash Flows: The Company expects to contribute $2.4 million net of expected employee
contributions for the payment of retiree medical benefits in 2004.Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the
Act)  The Companys postretirement medical plan provides prescription drug
coverage for Medicare-eligible retirees. The Companys accumulated
postretirement benefit obligation (APBO) and net cost recognized for other
postemployment benefits (OPEB) do not reflect the effects of the Act. The
provisions of the Act provide for a federal subsidy for plans that provide
prescription drug benefits and meet certain qualifications, and alternatively
would allow prescription drug plan sponsors to coordinate with the Medicare
benefit. Specific authoritative guidance is pending from the FASB and Federal
Government, and when that guidance is issued, it could require the Company to
change its actuarially determined APBO and net cost for OPEB.Leveraged Employee Stock Ownership Plan  The Company has a leveraged employee
stock ownership plan for the benefit of all its electric utility employees.
Contributions made by the Company were $1,030,000 for 2003 and $1,100,000 for
both 2002 and 2001.




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##### 



11.
    
    Fair Value of Financial InstrumentsThe 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 $30.6 million of the Companys long-term debt, which is subject to
variable interest rates, approximates fair value. December 31, 2003
    
    December 31, 2002(in thousands)Carrying
    
    Fair
    
    Carrying
    
    Fairamount
    
    value
    
    amount
    
    valueCash and short-term investments
    
    $
    7,305
    
    
    $
    7,305
    
    
    $
    9,937
    
    
    $
    9,937Other investments
    
    
    11,143
    
    
    
    11,143
    
    
    
    13,890
    
    
    
    13,890Long-term debt
    
    
    (265,193
    )
    
    
    (292,604
    )
    
    
    (258,229
    )
    
    
    (277,261
    )
  12.
    
    Property, Plant and Equipment 2003
    
    2002(December 31, in thousands)Electric plant:Production
    
    $
    346,890
    
    
    $
    314,093Transmission
    
    
    175,953
    
    
    
    172,610Distribution
    
    
    272,909
    
    
    
    268,400General
    
    
    79,612
    
    
    
    80,279Electric plant
    
    
    875,364
    
    
    
    835,382Less accumulated depreciation and amortization
    
    
    368,899
    
    
    
    357,555Electric plant net of accumulated depreciation
    
    
    506,465
    
    
    
    477,827Construction work in progress
    
    
    13,938
    
    
    
    39,123Net electric plant
    
    $
    520,403
    
    
    $
    516,950Nonelectric operations plant
    
    $
    193,858
    
    
    $
    178,656Less accumulated depreciation and amortization
    
    
    84,892
    
    
    
    74,828Nonelectric plant net of accumulated depreciation
    
    
    108,966
    
    
    
    103,828Construction work in progress
    
    
    3,956
    
    
    
    2,484Net nonelectric operations plant
    
    $
    112,922
    
    
    $
    106,312Net plant
    
    $
    633,325
    
    
    $
    623,262
 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
    
    HighElectric fixed assets:Production plant
    
    
    34
    
    
    
    62Transmission plant
    
    
    40
    
    
    
    55Distribution plant
    
    

    15
    
    
    
    55General plant
    
    
    5
    
    
    
    65Nonelectric fixed assets
    
    
    3
    
    
    
    40




---



##### 



13.
    
    Income TaxesThe total income tax expense differs from the amount computed by applying the
federal income tax rate (35% in 2003, 2002 and 2001) to net income before
total income tax expense for the following reasons: 2003
    
    2002
    
    2001(in thousands)Tax computed at federal statutory rate
    
    $
    19,105
    
    
    $
    23,167
    
    
    $
    22,290Increases (decreases) in tax from:State income taxes net of federal income tax

benefit
    
    
    2,011
    
    
    
    2,441
    
    
    
    2,564Investment tax credit amortization
    
    
    (1,152
    )
    
    
    (1,152
    )
    
    
    (1,176
    )Differences reversing in excess of federal rates
    
    
    (1,283
    )
    
    
    (1,055
    )
    
    
    (503
    )Dividend received/paid deduction
    
    
    (707
    )
    
    
    (699
    )
    
    
    (674
    )Affordable housing tax credits
    
    
    (1,412
    )
    
    
    (1,418
    )
    
    
    (1,418
    )Permanent and other differences
    
    
    (1,632
    )
    
    
    (1,223
    )
    
    
    (1,000
    )Total income tax expense
    
    $
    14,930
    
    
    $
    20,061
    
    
    $
    20,083Overall effective federal and state income tax rate
    
    
    27.4
    %
    
    
    30.3
    %
    
    
    31.5
    %Income tax expense includes the following:Current federal income taxes
    
    $
    11,665
    
    
    $
    18,651
    
    
    $
    21,110Current state income taxes
    
    
    3,141
    
    
    
    3,856
    
    
    
    3,107Deferred federal income taxes
    
    
    2,709
    
    
    
    15
    
    
    
    (2,247
    )Deferred state income taxes
    
    
    (21
    )
    
    
    109
    
    
    
    707Affordable housing tax credits
    
    
    (1,412
    )
    
    
    (1,418
    )
    
    
    (1,418
    )Investment tax credit amortization
    
    
    (1,152
    )
    
    
    (1,152
    )
    
    
    (1,176
    )Total
    
    $
    14,930
    
    
    $
    20,061
    
    
    $
    20,083
  The Companys deferred tax assets and liabilities were composed of the following on December 31, 2003
and 2002: 2003
    
    2002(in thousands)Deferred tax assetsAmortization of tax credits
    
    $
    7,437
    
    
    $
    8,345Vacation accrual
    
    
    1,926
    
    
    
    1,836Unearned revenue
    
    
    1,592
    
    
    
    1,420Benefit liabilities
    
    
    18,085
    
    
    
    15,690Cost of removal
    
    
    13,096
    
    
    
    13,797Differences related to property
    
    
    6,079
    
    
    
    5,239Transfer to regulatory liability
    
    
    63
    
    
    
    618Other
    
    
    2,068
    
    
    
    2,956Total deferred tax assets
    
    $
    50,346
    
    
    $
    49,901Deferred tax
liabilitiesDifferences related to property
    
    $
    (129,076
    )
    
    $
    (123,021
    )Excess tax over book pension
    
    
    (3,260
    )
    
    
    (3,855
    )Transfer to regulatory asset
    
    
    (12,751
    )
    
    
    (10,237
    )Other
    
    
    (3,323
    )
    
    
    (2,448
    )Total deferred tax liabilities
    
    $
    (148,410
    )
    
    $
    (139,561
    )Deferred income taxes
    
    $
    (98,064
    )
    
    $
    (89,660
    )




---



##### 



14.
    
    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 EndedMarch 31
    
    June 30
    
    September 30
    
    December 312003
    
    2002
    
    2003
    
    2002
    
    2003
    
    2002
    
    2003
    
    2002(in thousands, except per share data)Operating revenues (a)
    
    $
    172,149
    
    
    $
    145,262
    
    
    $
    180,057
    
    
    $
    160,001
    
    
    $
    200,895
    
    
    $
    166,399
    
    
    $
    200,138
    
    
    $
    174,675Operating income
    
    
    18,302
    
    
    
    18,935
    
    
    
    14,920
    
    
    
    19,848
    
    
    
    22,302
    
    
    
    22,979
    
    
    
    15,636
    
    
    
    20,555Net income
    
    
    9,862
    
    
    
    10,032
    
    
    
    8,434
    
    
    
    10,587
    
    
    
    11,961
    
    
    
    12,882
    
    
    
    9,399
    
    
    
    12,627Earnings available for common shares
    
    
    9,678
    
    
    
    9,848
    
    
    
    8,250
    
    
    
    10,403
    
    
    
    11,777
    
    
    
    12,698
    
    
    
    9,216
    
    
    
    12,443Basic earnings per share
    
    $
    .38
    
    
    $
    .40
    
    
    $
    .32
    
    
    $
    .41
    
    
    $
    .46
    
    
    $
    .50
    

    
    $
    .36
    
    
    $
    .49Diluted earnings per share
    
    
    .38
    
    
    
    .40
    
    
    
    .32
    
    
    
    .41
    
    
    
    .46
    
    
    
    .50
    
    
    
    .36
    
    
    
    .48Dividends paid per common share
    
    
    .27
    
    
    
    .265
    
    
    
    .27
    
    
    
    .265
    
    
    
    .27
    
    
    
    .265
    
    
    
    .27
    
    
    
    .265Price range:High
    
    $
    28.59
    
    
    $
    31.80
    
    
    $
    28.90
    
    
    $
    34.90
    
    
    $
    28.41
    
    
    $
    31.50
    
    
    $
    28.50
    
    
    $
    29.23Low
    
    
    23.76
    
    
    
    25.75
    
    
    
    25.27
    
    
    
    28.50
    
    
    
    25.60
    
    
    
    22.82
    
    
    
    25.92
    
    
    
    25.22Average number of common shares
outstandingbasic
    
    
    25,592
    
    
    
    24,668
    
    
    
    25,673
    
    
    
    25,117
    
    
    
    25,708
    
    
    
    25,328
    
    
    
    25,719
    
    
    
    25,589Average number of common shares
outstandingdiluted
    
    
    25,730
    
    
    
    24,919
    
    
    
    25,855
    
    
    
    25,412
    
    
    
    25,869
    
    
    
    25,497
    
    
    
    25,876
    
    
    
    25,781
 (a) Restated to reflect EITF Issue 03-11 reporting requirements.




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##### 



Stock Listing Otter Tail Corporation common stock trades on The Nasdaq Stock Market.