EX-13.A 7 c68205ex13-a.txt PORTIONS OF 2001 ANNUAL REPORT TO SHAREHOLDERS EXHIBIT 13-A SELECTED CONSOLIDATED FINANCIAL DATA
---------------------------------------------------------------------------------------------------------------------------- 2001 2000 (1) 1999 (1)(2) 1998 (3) 1997 1996 1991 -------- -------- -------- -------- -------- -------- -------- (thousands, except number of shareholders and per-share data) REVENUES Electric $307,684 $262,280 $233,527 $227,477 $205,121 $199,345 $179,456 Plastics 63,216 82,667 31,504 24,946 24,953 22,049 -- Manufacturing 123,436 97,506 87,086 62,488 58,221 42,519 -- Health services 79,129 66,319 68,805 69,412 66,859 61,697 -- Other business operations 80,667 78,159 68,322 48,829 44,173 45,323 20,389 -------- -------- -------- -------- -------- -------- -------- Total operating revenues $654,132 $586,931 $489,244 $433,152 $399,327 $370,933 $199,845 SPECIAL CHARGES -- -- -- 9,522 -- -- -- CUMULATIVE CHANGE IN ACCOUNTING PRINCIPLE -- -- -- 3,819 -- -- -- NET INCOME 43,603 41,042 45,295 34,520 32,346 30,624 26,096 CASH FLOW FROM OPERATIONS 77,529 61,761 81,850 63,959 69,398 68,611 46,667 CAPITAL EXPENDITURES 53,596 46,273 35,245 29,289 41,973 64,823 24,642 TOTAL ASSETS 782,541 737,708 694,341 655,612 655,441 669,704 491,633 LONG-TERM DEBT 227,360 195,128 180,159 181,046 189,973 163,176 146,326 REDEEMABLE PREFERRED -- 18,000 18,000 18,000 18,000 18,000 13,150 BASIC EARNINGS PER SHARE (4) (6) 1.69 1.59 1.75 1.36 1.29 1.23 1.07 DILUTED EARNINGS PER SHARE (4) (6) 1.68 1.59 1.75 1.36 1.29 1.23 1.07 RETURN ON AVERAGE COMMON EQUITY 15.5% 15.4% 18.4% 15.0% 14.9% 14.9% 15.4% DIVIDENDS PER COMMON SHARE (6) 1.04 1.02 0.99 0.96 0.93 0.90 0.80 DIVIDEND PAYOUT RATIO 62% 64% 57% 71% 72% 73% 74% COMMON SHARES OUTSTANDING -YEAR END (6) 24,653 24,574 24,571 23,759 23,462 23,072 22,370 NUMBER OF COMMON SHAREHOLDERS (5) 14,358 14,103 13,438 13,699 13,753 13,829 13,928 -----------------------------------------------------------------------------------------------------------------------------
Notes: (1) Restated to reflect the effects of two 2001 acquisitions accounted for under the pooling-of-interests method. The impact of the poolings on years prior to 1999 is not material. (2) During 1999 radio station assets were sold for a net gain of $8.1 million or 34 cents per share. (3) In the first quarter of 1998 the Company changed its method of electric revenue recognition in the states of Minnesota and South Dakota from meter-reading dates to energy-delivery dates. Basic and diluted earnings per share includes 16 cents per share related to the cumulative effect of the change in accounting principle. (4) Based on average number of shares outstanding. (5) Holders of record at year end. (6) Common shares outstanding and per-share data reflect the effect of the two-for-one stock split effective March 15, 2000. Management's discussion and analysis of financial condition and results of operations Otter Tail Corporation's primary financial goals are to maximize its earnings and cash flows and to allocate capital profitably toward growth opportunities that will increase shareholder value. Management meets these objectives by earning the returns regulators allow in electric operations combined with successfully growing diversified operations. Meeting these objectives enables the Company to preserve and enhance its financial capability by maintaining optimal capitalization ratios and a strong interest coverage position, and preserving strong credit ratings on outstanding securities, which in the form of lower interest rates benefits both the Company's customers and shareholders. LIQUIDITY: The Company believes its financial condition is strong and that its cash, other liquid assets, operating cash flows, access to equity capital markets and borrowing capital, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. However, the Company's operating cash flow and access to capital markets can be impacted by macroeconomic factors outside its control. In addition, the Company's borrowing costs can be impacted by short and long-term debt ratings assigned by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios. The Company has achieved a high degree of long-term liquidity by maintaining desired capitalization ratios and strong credit ratings, implementing cost-containment programs, and investing in projects that provide returns in excess of the Company's weighted average cost of capital. Cash provided by operating activities of $77.5 million combined with cash on hand of $1.3 million at December 31, 2000, allowed the Company to pay dividends, meet sinking fund payment requirements, and partially finance capital expenditures. The $15.8 million increase in cash provided by operating activities between 2001 and 2000 reflects an increase in net income of $2.6 million, a $1.5 million increase in depreciation and amortization expense, a $3.2 million change in deferred taxes, a $5.1 million decrease in deferred debits and other assets primarily reflecting the change in the pension asset and $16.7 million increase in working capital. The $17.7 million decrease in net cash used in investing activities between 2001 and 2000 reflects an increase in capital expenditures of $7.3 million offset by a $25.2 million reduction in cash used to complete acquisitions. The majority of the increase in capital expenditures occurred in the electric segment as a result of in-progress construction of a new gas-fired combustion turbine and construction of a new transmission line in North Dakota. In 2001 the Company completed six acquisitions. Two of the acquisitions were completed by issuing Company common stock. The remaining four were funded with cash which aggregated $8.9 million in merger consideration. Net cash used in financing activities was $6.3 million for 2001 compared with $6.6 million for 2000. The slight decrease between the years was due to the following. The Company received net proceeds from employee stock plans of $1.3 million. Dividends paid increased $889,000 and the net change in the issuance of long-term debt over the retirement of long-term debt and preferred stock decreased $208,000 between the periods. The Company sold $20.79 million of Pollution Control Refunding Revenue Bonds, Mercer County, ND 4.85 percent Series due 2022 and $5.185 million of Pollution Control Refunding Revenue Bonds, Grant County, SD 4.65 percent Series due in 2017 in September 2001. The proceeds were used to redeem the 2019 Series Mercer County (Coyote project) Pollution Control Refunding Revenue Bonds and the 2006 Series Grant County (Big Stone project) Pollution Control Refunding Revenue Bonds in October 2001. The Company sold $90 million of Senior Notes, 6.63 percent Series due 2011 in December 2001. The proceeds from the sale were used to retire the 8.75 percent Series First Mortgage Bonds at the aggregate redemption price of $19.3 million; retire the $6.35 Cumulative Preferred Shares at the aggregate redemption price of $18.2 million; retire $17.3 million of Varistar term debt; and repay $20.8 million in short-term debt outstanding. The remaining proceeds will be used to fund certain capital expenditures and for general corporate purposes during 2002. 74,480 shares of common stock were issued during 2001 as a result of stock options exercised under the 1999 Stock Incentive Plan generating proceeds of $1.3 million. In addition, the Company issued 721,436 unregistered common shares during 2001 to effect two acquisitions accounted for under the pooling-of-interests method. CAPITAL REQUIREMENTS: The Company's consolidated capital requirements include replacement of technically obsolete or worn-out equipment, new equipment purchases, and plant upgrades to accommodate anticipated growth. The electric segment has a construction and capital investment program to provide facilities necessary to meet forecasted customer demands and to provide reliable service. The construction program is subject to review and is revised annually in light of changes in demands for energy, availability of energy within the power pool, cost of capacity charges relative to cost of new generation, environmental laws, regulatory changes, technology, the costs of labor, materials and equipment, and the Company's consolidated financial condition. Consolidated capital expenditures for the years 2001, 2000, and 1999 were $53.6 million, $46.3 million, and $35.2 million, respectively. The estimated capital expenditures for 2002 are $73 million, and the total capital expenditures for the five-year period 2002 through 2006 are expected to be approximately $181 million. The breakdown of 2001 actual and 2002 through 2006 estimated capital expenditures by segment is as follows:
2001 2002 2002-2006 ---- ---- --------- (in millions) Electric $ 35 $ 50 $113 Plastics 2 1 12 Manufacturing 11 14 34 Health services 3 3 5 Other business operations 3 5 17 ---- ---- ---- Total $ 54 $ 73 $181 ==== ==== ====
The $15 million increase in capital expenditures for the electric segment for 2002 as compared to 2001 reflects construction of a new gas-fired combustion turbine plant. The following table summarizes the Company's contractual obligations at December 31, 2001 and the effect these obligations are expected to have on its liquidity and cash flow in future periods.
1 2-3 4-5 After 5 December 31, (in millions) Total year years years years -------------------------- ---------------------------------------------------------- Long term debt $256 $29 $14 $10 $203 Coal contracts (required minimums) 106 14 29 11 52 Construction program(purchase orders) 16 16 -- -- -- Capacity and energy requirements 70 14 24 21 11 Operating leases 53 16 22 10 5 --------------------------------------------------------- Total contractual cash obligations $501 $89 $89 $52 $271 =========================================================
CAPITAL RESOURCES: Financial flexibility is provided by unused lines of credit, strong financial coverages and credit ratings, and alternative financing arrangements such as leasing. The Company estimates that funds internally generated net of forecasted dividend payments, combined with funds on hand, will be sufficient to meet scheduled debt retirements and almost completely provide for its estimated 2002 through 2006 consolidated capital expenditures. Reduced demand for electricity or in the products manufactured and sold by the Company could have an effect on funds internally generated. Additional short-term or long-term financing will be required in the period 2002 through 2006 in order to complete the planned capital expenditures, in the event the Company decides to refund or retire early any of its presently outstanding debt or cumulative preferred shares, to complete acquisitions, or for other corporate purposes. There can be no assurance that any additional required financing will be available through bank borrowings, debt or equity financing or otherwise, or that if such financing is available, it will be available on terms acceptable to the Company. If adequate funds are not available on acceptable terms, our business, results of operations, and financial condition could be adversely affected. Bank lines of credit are a key source of operating capital and can provide interim financing of working capital and other capital requirements, if needed. As of December 31, 2001, the Company had $11.4 million in cash and cash equivalents and $42 million in three separate unused lines of credit. In addition to the formal bank lines, the Company can issue commercial paper. The subsidiaries' notes and credit lines are secured by a pledge of all of the common stock of the subsidiaries. (See note 9 to consolidated financial statements.) The Company's credit ratings affect its access to the capital market. The current credit ratings for the Company's First Mortgage Bonds at December 31, 2001 are as follows: Moody's Investors Service Aa3 Fitch Ratings AA Standard and Poor's A+ Moody's rating outlook has been negative since September 2000. The Company's disclosure of these security ratings is not a recommendation to buy, sell, or hold its securities. A downgrade in the Company's credit ratings could adversely affect its ability to renew existing, or obtain access to new, credit facilities in the future and could increase the cost of such facilities. The 6.63 percent Senior Notes due 2011 contain an investment grade put that could accelerate the maturity date of this series if designated rating agencies rate the senior debt below a rating of Baa3 for Moody's or BBB- for Standard and Poor's. If ratings on the Company's senior unsecured debt are downgraded to "Baa2" or below by Moody's or "BBB" or below by Standard and Poor's and Fitch Ratings, related to the Pollution Control Refunding Revenue Bonds, the Company would be required to grant to Ambac Assurance Corporation, under a financial guaranty insurance policy, a security interest in the assets of the electric utility. The Company believes the risk of either of these occurring is unlikely due to the current bond ratings of the Company combined with its strong debt-to-equity ratio and ability to generate cash from operations. The Company is in compliance with all covenants or other requirements set forth in its credit agreements, note documents and indentures. Covenants relate to the Company's total net worth, current ratios, cash leverage ratio, fixed charge coverage ratio, and debt-to-equity ratio. The Company's fixed charge coverage ratio after taxes was 4.1x for 2001 compared to 3.8x for 2000, and the long-term debt interest coverage ratio before taxes was 5.2x for 2001, compared to 4.8x for 2000. During 2002 the Company expects these coverages to remain similar to 2001. The Company did not have any relationships with unconsolidated entities or financial partnerships at December 31,2001. These entities are often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company is not exposed to any financing, liquidity, market or credit risk that could arise if it had such relationships. Results of operations: Consolidated Results of Operations The Company recorded diluted earnings per share of $1.68 for the year ended December 31, 2001 compared to $1.59 for the year ended December 31, 2000. Total operating revenues for 2001 were $654.1 million, compared with $586.9 million for 2000. Operating income was $77.5 million for the year 2001 compared with $74.2 million for 2000. Growth in revenues and operating income from the electric, manufacturing and health services segments offset decreased operating income from the plastics and other business operations segments. Electric Otter Tail Power Company, a division of Otter Tail Corporation, provides electrical service to more than 126,000 customers in a service territory exceeding 50,000 square miles.
2001 2000 1999 -------- -------- -------- (in thousands) Operating revenues $307,684 $262,280 $233,527 Production fuel 41,776 38,546 36,839 Purchased power 99,491 66,121 44,190 Other operation and maintenance expenses 75,531 74,591 71,724 Depreciation and amortization 24,272 23,778 23,366 Property taxes 9,464 9,976 10,174 -------- -------- -------- Operating income $ 57,150 $ 49,268 $ 47,234 ======== ======== ========
(bar graph of information in following table) Electric operating income (millions) ------------------------- 1999 $47.2 2000 $49.3 2001 $57.2 (end of graph) Electric operating revenues for 2001 increased 17.3 percent over 2000 due to a $33.5 million increase in wholesale power revenues, a $10.2 million increase in retail revenues, and a $1.7 million increase in other electric revenues. The increase in wholesale power revenues resulted from a 16.4 percent increase in wholesale prices combined with a 30.2 percent increase in wholesale kilowatt-hour (kwh) sales. The increase in the wholesale sales is the result of the electric utility's increased activity and involvement in wholesale markets. The increase in retail sales revenue is due to a 2.9 percent increase in retail kwh sales along with a $6.3 million increase in cost-of-energy revenue. In addition to a $1.9 million refund of fuel costs resulting from a coal contract arbitration settlement in 2000, the increase in cost-of-energy revenues reflects increases in fuel and purchased power costs per kwh for system use in 2001 as compared to 2000. Increases in retail kwh sold occurred in all customer categories except streetlighting, with commercial having the largest increase. The $1.7 million increase in other electric revenues reflects an increase in transmission service revenues and increases in revenues mainly related to construction service contracts for other utilities. The $3.2 million (8.4 percent) increase in production fuel expense in 2001 over 2000 is due to the following: a 4.4 percent increase in kwhs generated combined with a 0.8 percent increase in the fuel cost per kwh generated and a reduction in 2000 fuel expenses of $1.9 million related to the coal arbitration settlement. Excluding the impact of this settlement, production fuel expenses increased 3.3 percent. The 50.5 percent increase in purchased power expense is the result of a 24.2 percent increase in kwh purchases combined with a 21.2 percent increase in the cost per kwh purchased. While kwh purchases for resale increased 49.4 percent to provide for the increase in wholesale sales of electricity, kwh purchases for retail sales were down 26.9 percent in 2001 compared to 2000. Other operation and maintenance expenses increased 1.3 percent in 2001 compared to 2000, mainly due to a 3.1 percent increase in operating and maintenance labor expense. In addition, other operation and maintenance expense for 2000 included a credit of $1.0 million that was recorded as part of the arbitration settlement that recovered previously recorded arbitration expenses. (See note 3 to consolidated financial statements.) The 2.1 percent increase in depreciation and amortization expense for 2001 compared to 2000 is due to an increase in depreciable plant base as a result of recent capital expenditures. Property taxes decreased 5.1 percent for 2001 compared to 2000 due to a legislative reduction in tax capacity rates used to determine Minnesota property taxes. In addition, under a new state law in Minnesota, generation machinery and attached equipment were exempted for Minnesota property taxes. This reduction in property taxes will be refunded to retail electric customers. No growth is expected in the electric segment in 2002. The warm winter of 2001 and 2002 will limit growth in retail sales, and the depressed wholesale market will lower sales volumes in 2002. The 12.3 percent increase in electric operating revenues for 2000 compared to 1999 is due to a $19.8 million increase in wholesale power revenues, a $7.2 million increase in retail revenues and a $1.8 million increase in other electric revenues. Increased wholesale prices along with increased demand contributed to the increase in revenues from wholesale power sales. Wholesale power kwh sales increased 27.8 percent. The electric utility was well positioned to capitalize on sales into a robust wholesale energy market in 2000 due to excellent plant availability when on-peak power prices were high. A 3.5 percent increase in retail kwh sales due primarily to much colder weather during November and December of 2000 compared to the same months in 1999, was the main contributor to the $7.2 million increase in retail electric sales revenues. Retail revenue per kwh sold increased 0.4 percent due to an increase in cost of energy revenues between 2000 and 1999. The $1.8 million increase in other electric segment revenues is due mainly to an increase in transmission service revenues combined with the proceeds from the sale of an algorithm concept developed by the utility to facilitate customer choice in a competitive retail electric market. The 4.6 percent increase in production fuel expense in 2000 compared to 1999 resulted from a $3.6 million increase in fuel costs at the generating plants offset by a $1.9 million reduction in fuel costs due to the arbitration settlement with Knife River Coal Mining Company. (See note 3 to consolidated financial statements for more information on the arbitration settlement.) The increase in fuel costs at the generating plants reflects a 7.9 percent increase in the fuel cost per kwh generated combined with a 1.8 percent increase in kwh generated. The increase in fuel cost per kwh generated is due to slightly higher coal costs at one of the utility's generating plants and significantly higher fuel costs at the utility's combustion turbines. Purchased power expense increased 49.6 percent as a result of a 28.5 percent increase in the volume of electricity purchased combined with a 16.4 percent increase in the cost per kwh purchased. The additional electricity purchased and generated was needed to provide for increased retail and power pool sales discussed above. The increase in cost per kwh purchased is a function of increased demand in the wholesale energy market and a general increase in electricity usage nationwide without a commensurate increase in generation. Other operation and maintenance expenses for 2000 increased 4.0 percent as compared to 1999. This increase is due to additional expenses related to employee benefits, customer service enhancements and maintenance on generating plants, transmission, and distribution lines. Included in this increase are credits related to pension cost and the arbitration settlement that recovered previously recorded arbitration expenses. The 1.8 percent increase in depreciation and amortization expense for 2000 compared to 1999 is due to an increase in depreciable plant base as a result of capital expenditures. The 1.9 percent decrease in property taxes for 2000 compared to 1999 is due to a general decline in mill rates for 2000. Plastics Plastics consists of businesses involved in the production of polyvinyl chloride (PVC) pipe in the Upper Midwest and Southwest regions of the United States. On January 1, 2000, the Company acquired the assets and operations of Vinyltech Corporation (Vinyltech) under the purchase method of accounting. (See note 2 to consolidated financial statements.)
2001 2000 1999 ------ ------ ------- (in thousands) Operating revenues $63,216 $82,667 $31,504 Cost of goods sold 57,932 66,286 24,270 Operating expenses 3,446 4,335 2,684 Depreciation and amortization 3,229 3,301 1,168 ------- ------- ------- Operating (loss) income $(1,391) $ 8,745 $ 3,382 ======= ======= ========
(bar graph of information in following table) Plastics operating income (millions) ------------------------- 1999 $ 3.4 2000 $ 8.7 2001 $(1.4) (end of graph) The 23.5 percent decrease in operating revenues for 2001 compared with 2000 is due to a 29.5 percent decline in average sales price per pound offset by an 8.5 percent increase in pounds of PVC pipe sold. The continuing decline in PVC resin prices combined with an over supply of finished PVC pipe products were the main factors in the decrease in average sales price per pound. The decrease of 12.6 percent in cost of goods sold reflects a 19.5 percent decrease in the average cost per pound of PVC pipe sold. The selling price per pound of PVC pipe is affected directly by the raw material cost of resin. Operating expenses decreased 20.5 percent primarily due to a reduction in labor costs and selling expenses. The acquisition of Vinyltech on January 1, 2000 is the primary driver behind the increases in operating revenues, cost of goods sold, operating expenses and operating income for 2000 compared to 1999. Strong demands within the PVC pipe industry combined with higher sales prices per pound during the first half of the year also led to increased pipe revenues. The average sales price per pound of pipe between the periods increased 27.3 percent. During the second half of 2000 there was a significant softening in demand for PVC product lines as PVC pipe prices decreased. The reduction in short-term demand was due in part to our distributors' reluctance to purchase pipe for inventory while pipe prices were declining. The general slowing of the economy also reduced the demand for pipe. Additional resin capacity that came online during 2000 had a negative impact on resin prices. The continuing decline in PVC resin prices that started during the second half of 2000 and continued through 2001 combined with an over supply of finished PVC pipe products has lead to lower sales prices per pound. The Company expects the trends that are affecting the sales prices of PVC pipe to continue into the third quarter of 2002. The gross margin percentage is sensitive to PVC raw material resin prices and the demand for PVC pipe. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower. Gross margins also decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or assume that historical trends will continue. Manufacturing Manufacturing consists of businesses involved in the production of wind towers, frame-straightening equipment and accessories for the auto body shop industry, custom plastic pallets, material and handling trays, and horticultural containers, fabrication of steel products, contract machining, and metal parts stamping and fabricating. During 2001 three acquisitions were completed in this segment. On February 28, 2001 the Company acquired the outstanding common stock of T.O. Plastics, Inc. On September 28, 2001 the Company acquired the outstanding common stock of St. George Steel Fabrication, Inc. These two acquisitions were completed as a pooling-of-interests. On November 1, 2001, the Company acquired the assets and operations of Titan Steel Corporation using the purchase method of accounting. (See note 2 to consolidated financial statements.)
2001 2000 1999 ------ ------ ------- (in thousands) Operating revenues $123,436 $97,506 $87,086 Cost of goods sold 91,360 72,639 64,907 Operating expenses 14,762 13,992 13,255 Depreciation and amortization 5,139 3,930 3,627 -------- ------- ------- Operating income $ 12,175 $ 6,945 $ 5,297 ======== ======= =======
(bar graph of information in following table) Manufacturing operating income (millions) ------------------------------ 1999 $ 5.3 2000 $ 6.9 2001 $12.2 (end of graph) Operating revenues for the manufacturing segment increased 26.6 percent during 2001 compared to 2000 reflecting increased sales of wind towers combined with increased sales volumes of metal parts stamping, fabrication and thermoform plastic products. The 25.8 percent increase in cost of goods sold correlates with the increased sales volumes. The 5.5 percent increase in operating expenses reflects increases in general and administrative expenses offset by reductions in research, development and selling expenses. Manufacturing operating revenues increased 12.0 percent during 2000 compared to 1999 due primarily to a $10.6 million increase in sales volumes of metal parts stamping offset by a $4.8 million decrease in operating revenues from the wind tower manufacturer. During 2000 the agricultural equipment manufacturer completed a transition from manufacturing agricultural equipment to manufacturing towers that are used by the wind energy industry. The 11.9 percent increase in cost of goods sold for manufacturing operations in 2000 compared to 1999 closely follows the increase in sales volumes of stamped metal parts offset by the sales reduction at the agricultural equipment manufacturer. The 5.6 percent increase in operating expenses during 2000 compared to 1999 primarily is due to an increase of operating costs at the subsidiary that manufactures products for the auto body industry. Health services Health services include businesses involved in the sale of diagnostic medical equipment, supplies and accessories. In addition these businesses also provide service maintenance, mobile diagnostic imaging, mobile PET and nuclear medicine imaging, portable x-ray imaging and rental of diagnostic medical imaging equipment. On September 4, 2001, the Company acquired the assets and operations of Interim Solutions and Sales, Inc. and Midwest Medical Diagnostics, Inc. On September 10, 2001, the Company acquired the assets and operations of Nuclear Imaging, Ltd. In June 2000 the Company acquired the assets and operations of Portable X-Ray & EKG, Inc. (PXE) All of these acquisitions were accounted for using the purchase method of accounting. (See note 2 to consolidated financial statements.)
2001 2000 1999 ------ ------ ------ (in thousands) Operating revenues $79,129 $66,319 $68,805 Cost of goods sold 59,388 49,193 52,146 Operating expenses 9,362 8,416 7,479 Depreciation and amortization 3,517 2,981 4,244 ------- ------- ------- Operating income $ 6,862 $ 5,729 $ 4,936 ======= ======= =======
(bar graph of information in following table) Health services operating income millions -------------------------------- 1999 $4.9 2000 $5.7 2001 $6.9 (end of graph) Operating revenues for the health services segment increased 19.3 percent for 2001 compared to 2000 due to an increase in equipment sales, services and supplies combined with an increase of 7.4 percent in scans performed. $4.2 million of the revenue increase was the result of the acquisitions completed in September 2001. Cost of goods sold increased 20.7 percent reflecting increased costs of materials and supplies used and sold in the diagnostic equipment imaging business, increased rent expense and additional expenses as a result of the acquisitions. The operating expense increase related to increased labor costs, selling expenses, insurance expenses and promotion expenses. The 3.6 percent decrease in operating revenues for health services for 2000 compared to 1999 is the result of decreased dealer sales. Offsetting the decreased dealer sales were increases in services and supply and accessory sales combined with operating revenues from the PXE acquisition and a 9.0 percent increase in the number of imaging scans performed primarily as a result of adding more routes. Cost of goods sold decreased 5.7 percent during 2000 compared to 1999 due to a decline in sales and servicing of equipment. The 12.5 percent increase in operating expenses in 2000 compared to 1999 reflects the results of the PXE acquisition combined with the additional routes and completion of more imaging scans. Other business operations The Company's other business operations include businesses involved in electrical and telephone construction contracting, transportation, telecommunications, entertainment, energy services, and natural gas marketing as well as the portion of corporate administrative and general expenses that are not allocated to the other segments. Results of operations for the other business operations segment are as follows:
2001 2000 1999 ------ ------ ----- (in thousands) Operating revenues $80,667 $78,159 $68,322 Cost of goods sold 41,109 40,938 38,954 Operating expenses 30,927 27,088 17,550 Depreciation and amortization 5,943 6,572 4,454 ------- ------- ------- Operating income $ 2,688 $ 3,561 $ 7,364 ======= ======= =======
(bar graph of information in following table) Other business operations operating income (millions) ----------------------------------------- 1999 $7.4 2000 $3.6 2001 $2.7 (end of graph) The 3.2 percent increase in other business operating revenues reflects a $2.4 million increase in revenues from the energy services company and $1.7 million from the transportation subsidiary partially offset by a $2.0 million decrease in revenues from the construction subsidiaries. Both operating revenues and cost of goods sold increased for the energy services company as a result of the higher cost of natural gas during the first half of 2001. The increase in cost of goods sold was offset by reductions in this category from the construction subsidiaries. Increases in brokerage revenue are primarily the reason for the increase in revenue from the transportation subsidiary. The decrease in revenues and cost of goods sold from the construction subsidiaries is due to an overall decline in the number of projects available for the companies to work on in 2001 as compared to 2000. Operating expenses increased 14.3 percent reflecting increased payments to owner-operators and increased brokerage fees within the transportation subsidiary and increases in insurance expenses. The 9.6 percent decrease in depreciation and amortization reflects the write down in 2000 of $800,000 of goodwill that was impaired at the energy services company and charged to amortization expense. Other business operating revenues increased 14.4 percent during 2000 compared to 1999, reflecting a full year of revenues from the transportation company compared to only four months during 1999. The increased revenues from the transportation company combined with increased revenues from the energy services subsidiary offset decreases in operating revenues from the construction and telecommunication subsidiaries and the lost revenues from the radio stations, which were sold in 1999. Cost of goods sold increased 5.1 percent during 2000 compared to 1999 as a result of the increased sales from the energy services subsidiary offset by a reduction in costs at the construction companies due to lower volumes of contracted work between the periods. The increase in operating expenses also reflects a full year of operations from the transportation company offset by the absence of expenses from the radio stations. In October 1999 the Company completed the sale of certain assets of the radio stations and video production company owned by KFGO, Inc., and the radio stations owned by Western Minnesota Broadcasting Company for $24.1 million. Operating income includes results of operations for the radio stations through September 1999. The gain from this sale is not included in operating income for segment purposes. For additional information regarding the sale see note 2 to consolidated financial statements. During 1999 the Company agreed, as part of a settlement with the Minnesota Pollution Control Agency, to donate all of its assets in its Quadrant Co. waste incineration plant to the City of Perham, Minnesota. The plant had ceased operations during the third quarter of 1998. Pro forma operating income for other business operations without Quadrant and the radio stations would have been $6,303,000 for 1999. Gain from sale of radio station assets The Company recorded a $14.5 million pre-tax gain from the sale of certain assets of the six radio stations and the video production company owned by KFGO, Inc., and the two radio stations owned by Western Minnesota Broadcasting Company on October 1, 1999. The after-tax gain from this sale contributed $0.34 to earnings per share for 1999. (bar graph of information in following table) Other income and deductions (millions) --------------------------- 1999 $2.3 2000 $2.1 2001 $2.2 (end of graph) Consolidated interest charges (bar graph of information in following table) Interest charges millions ---------------- 1999 $15.2 2000 $17.0 2001 $16.0 (end of graph) Interest expense decreased 6.0 percent for 2001 compared to 2000 due to decreases in the average long-term debt outstanding combined with lower interest rates on the line of credit balances and variable rate debt offset slightly by a higher daily average line of credit borrowings outstanding. Daily average outstanding borrowings were $16.7 million for 2001 compared to $12.8 million for 2000. The average interest rate under the line of credit was 5.2 percent for 2001. The 11.8 percent increase in interest charges in 2000 compared to 1999 is due to increases in long-term debt, higher average borrowings under the line of credit, and higher interest rates on the line of credit between the periods. Average interest rates under the line of credit were 8.1 percent for 2000 compared to 7.0 percent for 1999. Consolidated income taxes (bar graph of information in following table) Income taxes millions ------------ 1999 $24.5 2000 $18.4 2001 $20.1 (end of graph) The 9.4 percent increase in consolidated income taxes for 2001 compared to 2000 follows the $4.3 million increase in income before income taxes. Consolidated income taxes decreased 25.0 percent during 2000 compared to 1999 primarily due to the income tax expense of $6.4 million related to the sale of the radio station assets. Impact of inflation The electric utility operates under regulatory provisions that allow price changes in the cost of fuel and purchased power to be passed to customers through automatic adjustments to its rate schedules under the cost of energy adjustment clause. Other increases in the cost of electric service must be recovered through timely filings for rate relief with the appropriate regulatory agency. The Company's plastics, manufacturing, health services, and other business operations consist almost entirely of unregulated businesses. Increased operating costs are reflected in product or services pricing with any limitations on price increases determined by the marketplace. The impact of inflation on these segments has not been significant during the past few years because of the relatively low rates of inflation experienced in the United States. Raw material costs, labor costs, and interest rates are important components of costs for companies in these segments. Any or all of these components could be impacted by inflation, with a possible adverse effect on the Company's profitability, especially in high inflation periods where raw material and energy cost increases would lead finished product prices. Factors affecting future earnings The results of operations discussed above are not necessarily indicative of future earnings. Factors affecting future earnings include, but are not limited to, the Company's ongoing involvement in diversification efforts, the timing and scope of deregulation and open competition, growth of electric revenues, impact of the investment performance of the Company's pension plan, changes in the economy, weather conditions, governmental and regulatory action, fuel and purchased power costs, and environmental issues. Anticipated higher operating costs and carrying charges on increased capital investment in plant, if not offset by proportionate increases in operating revenues and other income (either by appropriate rate increases, increases in unit sales, or increases in nonelectric operations), will affect future earnings. Diversification In 2001 approximately 24 percent of the Company's net earnings were contributed by diversified operations. The Company plans to make additional acquisitions through its wholly owned subsidiary, Varistar Corporation. It is possible that by 2006 nearly 50 percent of the Company's net earnings will be contributed from diversified operations. The following guidelines are used when considering acquisitions: emerging or middle market company; proven entrepreneurial management team that will remain after the acquisition; products and services intended for commercial rather than retail consumer use; the ability to provide immediate earnings and future growth potential; and 100 percent ownership. The Company intends to grow earnings as a long-term owner of these investments. The Company also assesses the performance of these investments in accordance with its return on capital requirements and will consider divesting underperforming investments. Continuing growth from diversified operations could result in earnings and stock price volatility. While the Company cannot predict the success of our current diversified businesses, we believe opportunities exist for growth in the business segments. Factors that could affect the results of the diversified businesses include, but are not limited to, the following: fluctuations in the cost and availability of raw materials and the ability to maintain favorable supplier arrangements and relationships; competitive products and pricing pressures and the ability to gain or maintain market share in trade areas; general economic conditions; effectiveness of advertising, marketing, and promotional programs; and adverse weather conditions. The failure of congress to approve extension of the Production Tax Credit for wind energy in December 2001 could have an unfavorable impact on the Company's subsidiary that manufactures towers for the wind energy industry. Growth of electric revenue Growth in electric sales will be subject to a number of factors, including the volume of sales of electricity to other utilities, the effectiveness of demand-side management programs, weather, competition, the price of alternative fuels, and the rate of economic growth or decline in the Company's service area. The Company's electric business depends primarily on the use of electricity by customers in our service area. The Company's electric kwh sales to retail customers increased 2.9 percent in 2001, 3.5 percent in 2000, and decreased 2.6 percent in 1999. Factors beyond the Company's control, such as mergers and acquisitions, geographical location, transmission costs, unplanned interruptions at the Company's generating plants, and the effects of deregulation, could lead to greater volatility in the volume and price of sales of electricity to other utilities. Activity in the short-term energy market is subject to change based on a number of factors and it is difficult to predict the quantity of wholesale power sales or prices for wholesale power although it does appear that market conditions for wholesale power transactions will be depressed during part of 2002. Regulation Rates of return earned on utility operations are subject to review by the various state commissions that have jurisdiction over the electric rates charged by the Company. These reviews may result in future revenue reductions when actual rates of return are deemed by regulators to be in excess of allowed rates of return. On December 29, 2000 the North Dakota Public Service Commission (NDPSC) approved a performance-based ratemaking plan that links allowed earnings in North Dakota to seven defined performance standards in the areas of price, electric service reliability, customer satisfaction, and employee safety. The plan is in place for 2001 through 2005, unless suspended or terminated by the NDPSC or the Company. In 2001 the utility recorded an estimated $334,000 refund to North Dakota customers based on 2001 earnings and the utility's 2001 performance relative to the defined standards of the performance-based ratemaking plan. In 2001, the Minnesota Legislature exempted certain generation machinery and attached equipment from a new state personal property tax levy. The law also requires that any windfall tax savings resulting from this exemption be refunded to utility customers. As a result of this law, $238,000 in 2001 tax savings will be refunded to retail electric customers in 2002. Load Management and Minnesota Conservation Improvement Programs Load management efforts will continue in all jurisdictions served by the Company. The goal of load management is to control demand for electricity by customers at times of peak use in order to alleviate or delay the need for building or acquiring new generating capacity or to avoid having to purchase high-priced energy at times of peak demand. In addition to our load management efforts, we also invest in conservation improvement programs in Minnesota as mandated by state law. Conservation improvement programs are designed to encourage and reward the wise and efficient use of electricity by customers. Fuel Costs The Company has an agreement for Big Stone Plant's coal supply through December 31, 2004. The Company has been unable to negotiate a competitive delivery rate for coal to the Big Stone Plant with rail carriers. Coal is being shipped to Big Stone Plant under a tariff rate that is set through December 2002. The Company has commenced a proceeding before the Surface Transportation Board requesting the Board set a competitive rate. The Company expects the outcome to have a favorable impact on its fuel costs for the Big Stone Plant. The Mid-Continent Area Power Pool region has experienced a reduction in availability of excess generation and transmission capacity, particularly in the summer season in the recent years. While the availability of the Company's plants has been excellent, the loss of a major plant could expose the Company to higher purchased power costs. Two factors significantly mitigate this financial risk. First, wholesale sale contracts include provisions to release the Company from its obligations in case of a plant outage; and second, the Company has cost of energy adjustment clauses that allow pass through of most of the energy costs to retail customers. Environmental Current regulations under the Federal Clean Air Act (the Act) are not expected to have a significant impact on future capital requirements or operating costs. However, proposed or future regulations under the Act, changes in the future coal supply market, and/or other laws and regulations could impact such requirements or costs. It is anticipated that, under current regulatory principles, any such costs could be recovered through rates. All of the Company's electric generating plants operated within the Act's phase two standards for sulfur-dioxide and nitrogen-oxide emissions in 2001. Ongoing compliance with the phase two requirements is not expected to significantly impact operations at any of the Company's plants. The Act called for Environmental Protection Agency (EPA) studies of the effects of emissions of listed pollutants by electric steam generating plants. The EPA has completed the studies and sent reports to Congress. The Act required that the EPA make a finding as to whether regulation of emissions of hazardous air pollutants from fossil fuel-fired electric utility generating units is appropriate and necessary. On December 14, 2000, the EPA announced that it will regulate mercury emissions from electric generating units. The EPA expects to propose regulations by December 2003 and issue final rules by December 2004. Because promulgation of rules by the EPA has not been completed, it is not possible to assess whether, or to what extent, this regulation will impact the Company. The Company is planning to further improve the fine particulate emissions control at its Big Stone Plant by replacing a major portion of the plant's electrostatic precipitator in 2002 with a system based on Advanced Hybrid Particulate Collector technology. The new system will be installed as part of a demonstration project co-funded by the Department of Energy's National Energy Technology Laboratory Power Plant Improvement Initiative. The technology is designed to capture at least 99.99% of fly ash particulates emitted from the boiler. The Energy Department's share of the $13.4 million project is $6.5 million. The Company's share of the project is approximately $2.9 million with the remaining portion funded by the plant's co-owners and other industry participants. The EPA has targeted electric steam generating units as part of an enforcement initiative relative to compliance with the Act. The EPA is attempting to determine if utilities violated certain provisions of the Act by making major modifications to their facilities without installing state-of-the-art pollution controls. On January 2, 2001, the Company received a request from the EPA pursuant to Section 114(a) of the Act requiring the Company to provide certain information relative to past operation and capital construction projects at its Big Stone Plant. The Company has responded to that request and cannot, at this time, determine what, if any, actions will be taken by the EPA as a result of the Company's response. At the request of the Minnesota Pollution Control Agency (MPCA) the Company has an ongoing investigation at the Hoot Lake Plant closed ash disposal sites. The MPCA continues to monitor site activities under their Voluntary Investigation and Cleanup Program. In April 2001, Otter Tail submitted a Remedial Investigation Work Plan to the MPCA describing our plans to further investigate the environmental impact of the closed portion of the Hoot Lake Plant ash disposal site. The MPCA approved the plan, with some suggested modifications, in their letter of July 31, 2001. These tasks have been completed. The MPCA also asked that we eliminate a ground water seepage that was originating from one of the disposal areas. That task was completed in early November of 2001. We are continuing to monitor the site for evidence of further seepage. Deregulation and legislation In December 1999 the Federal Energy Regulatory Commission (FERC) issued Order No. 2000. This order requires public utilities that own, operate, or control interstate transmission to file by October 15, 2000, a proposal for a regional transmission organization (RTO) or a description of any efforts made to participate in an RTO, the reasons for not participating, and any plans for further work towards participation. The goal is to consolidate control of the transmission industry into a new structure of independent regional grid operators. The electric utility agreed in October 2001 to join the Indianapolis-based Midwest Independent System Operator (MISO) RTO. In December 2001, MISO received FERC approval as a regional transmission organization. The MISO began operational control of the electric utility's transmission facilities above 100 kv on February 1, 2002. The utility continues to own and maintain its transmission assets as before. As the electric utility transitions to the full operation of the MISO there could be short-term negative impacts on wholesale power transactions. During 2002, the electric utility will work within MISO on evaluating for-profit transmission alliances, incentive for transmission construction and market design and implementation. The U.S. Congress ended its 2001 legislative session without taking action on proposed electric industry restructuring legislation. The Minnesota Legislature passed an energy bill in 2001. Its primary focus was to streamline the siting and routing processes for the construction of new electric generation and transmission projects. The bill also added to utility requirements for renewable energy and energy conservation. There was no legislative action regarding electric retail choice in any of the states where the electric utility serves. No major electricity legislation is expected in the 2002 state legislative sessions. The Company does not expect retail competition to come to the States of Minnesota, North Dakota or South Dakota in the foreseeable future unless there is a federal effort to accomplish this. Competition in the electric industry As the electric industry evolves and becomes more competitive, the Company believes it is well positioned to be successful. The Company's generation capacity appears poised for competition due to unit heat rate improvements. A comparison of the Company's electric retail rates to the rates of other investor-owned utilities, cooperatives, and municipals in the states the Company serves indicates that its rates are competitive. In addition, the Company would attempt more flexible pricing strategies under an open, competitive environment. Key accounting policies and accounting pronouncements The Company's operations occur within five diverse segments. Three key accounting polices are revenue recognition, inventory valuations, and use of estimates. Due to the diverse business operations of the Company revenue recognition depends on the product that is produced and sold. Provisions for sale returns and warranty costs are recorded at the time of the sale based on historical information and current trends. The majority of the Company's inventory is valued at the lower of cost or market. Changes in the market conditions could require a write down of inventory values. The Company uses estimates based on the best information available in recording transactions and balances resulting from business operations. Examples of items where estimates are used are unbilled revenues, collectablilty of accounts receivable, self insurance reserves, pension plan costs or income, and service contract maintenance costs. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by changes made to prior accounting estimates. See note 1 in the notes to consolidated financial statements for more details on significant accounting polices. As of January 1, 2001, the Company adopted Statement of Financial Accounting Standards (SFAS) 133, Accounting for Derivative Instruments and Hedging Activities, as amended, which requires all derivative instruments be reported on the consolidated balance sheet at fair value. The adoption of SFAS No. 133 did not have a material effect on the Company's consolidated financial statements. The application of SFAS 133 to electric utilities continued to evolve throughout 2001. On December 19, 2001, the Financial Accounting Standards Board revised SFAS 133 Implementation Issue No. C15 to be effective April 1, 2002 with early adoption allowed. As of December 31, 2001, the Company early adopted the revised SFAS 133 Implementation Issue No. C15. The Company has determined that certain electric energy contracts meet the criteria of a derivative under SFAS 133 but qualify for the normal purchase and normal sales exception and are not subject to mark-to-market accounting treatment. SFAS 133 did not have a material effect on the Company's 2001 consolidated financial statements. In July 2001 the FASB issued SFAS 141, Business Combinations, which requires the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS 141 also specifies that intangible assets acquired in a business combination, that meet certain criteria, be recognized and reported apart from goodwill. The Company has adopted this statement as of July 1, 2001 and applied it to the following acquisitions that occurred after July 1, 2001: Interim Solutions and Sales, Inc, Midwest Medical Diagnostics, Inc., Nuclear Imaging, Ltd, and Titan Steel Corporation. Adoption of this statement did not have a material effect on the Company's consolidated financial statements. In July 2001 the FASB issued SFAS 142, Goodwill and Other Intangible Assets, which requires goodwill and intangible assets with indefinite useful lives no longer be amortized. Rather they will be tested for impairment, at least annually, in accordance with the provisions of SFAS 142. Intangible assets with finite useful lives will be amortized over their respective estimated useful lives and will be reviewed for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 142 is effective January 1, 2002, except for any goodwill arising in a purchase business combination completed on or after July 1, 2001 which would be subject immediately to the provisions of SFAS 142. As of December 31, 2001, the Company had net goodwill of $48.2 million. Included on the Company's consolidated statement of income for the twelve months ended December 31, 2001 is $3.2 million in goodwill amortization expense. SFAS 142 requires the Company perform an assessment of goodwill impairment as of the date of adoption. Any impairment loss resulting from this transition to SFAS 142 would be recognized as a cumulative effect of a change in accounting principle in the Company's consolidated income statement at the time of adoption. The Company is continuing to evaluate the effect that the adoption of this statement may have on its consolidated financial statements. Based on the work completed to date, the Company does not expect the implementation of this statement to have a material impact on its consolidated results of operations and financial position. In July 2001 the FASB issued SFAS 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for retirement obligations associated with tangible long-lived assets. This statement is effective for fiscal years beginning after June 15, 2002. The Company is assessing this statement but has not yet determined the impact of SFAS 143 on its consolidated financial position or results of operations. The FASB issued SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets in October 2001. SFAS 144 replaces SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. This statement develops one accounting model for long-lived assets to be disposed of by sale and also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity in a disposal transaction. The statement is effective for fiscal years beginning after December 15, 2001. The Company adopted the accounting model for impairment or disposal of long-lived assets on January 1, 2002. Adoption of this statement did not have a material effect on the Company's consolidated financial statements. Quantitative and Qualitative Disclosures About Market Risk The Company has limited exposure to market risk associated with interest rates and commodity prices. The majority of the Company's long-term debt obligations bear interest at a fixed rate. Variable rate long-term debt bears interest at a rate that is reset on a periodic basis reflecting current market conditions. The Company manages its interest rate risk through the issuance of fixed-rate debt with varying maturities, maintaining consistent credit ratings, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt. As of December 31, 2001, the Company had $17.0 million of long-term debt subject to variable interest rates. Assuming no change in the Company's financial structure, if variable interest rates were to average 1 percent higher or lower than what the average variable rate was on December 31, 2001, interest expense and pre-tax earnings would change by approximately $170,000. The Company has short-term borrowing arrangements to provide working capital and general corporate funds. The level of borrowings under these arrangements varies from period to period, depending upon, among other factors, operating needs and capital expenditures. The interest rate on the majority of the short-term borrowing arrangements is variable based on LIBOR. The electric utility's retail portion of fuel and purchased power costs are subject to cost of energy adjustment clauses that mitigate the commodity price risk by allowing a pass through of most of the increase or decrease in energy costs to retail customers. In addition, the electric utility participates in an active wholesale power market providing access to commodity transactions that may serve to mitigate price risk. The electric utility has in place an energy risk management policy with a primary goal to manage, through the use of defined risk management practices, price risk and credit risk associated with wholesale power purchases and sales. The energy services subsidiary markets natural gas to approximately 150 retail customers. A portion of these customers are served under fixed-price contracts. There is price risk associated with this limited number of fixed-price contracts since the corresponding cost of natural gas is not immediately locked in. This price risk is not considered material to the Company. In addition, the Company has in place an energy risk management policy with the primary goal of managing, through the use of defined risk management practices, price risk and credit risk associated with the marketing of natural gas. The plastics companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Currently, margins are very tight due to aggressive competition in a period of soft demand. The Company does not use derivative financial instruments for speculative or trading purposes. Cautionary Statements In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, the Company makes the following statements. The information in this annual report includes forward-looking statements. Important risks and uncertainties that could cause actual results to differ materially from those discussed in such forward-looking statements are set forth above under "Factors affecting future earnings." Other risks and uncertainties may be presented from time to time in the Company's future Securities and Exchange Commission filings. INDEPENDENT AUDITORS' REPORT To the Shareholders of Otter Tail Corporation We have audited the accompanying consolidated balance sheets and statements of capitalization of Otter Tail Corporation and its subsidiaries (the Company) as of December 31, 2001, and 2000, and the related consolidated statements of income, common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2001, and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP /s/ Deloitte & Touche LLP Minneapolis, Minnesota February 1, 2002 OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS, DECEMBER 31 2001 2000 ---------------------------------------------------------------------------------------------------------------------------------- (in thousands) ASSETS CURRENT ASSETS Cash and cash equivalents $ 11,378 $ 1,259 Accounts receivable: Trade (less allowance for doubtful accounts: 2001, $1,109,000; 2000, $922,000) 64,215 61,913 Other 5,047 6,813 Inventory, fuel, materials and supplies 39,301 42,263 Deferred income taxes 4,020 3,694 Accrued utility revenues 11,055 11,315 Other 8,878 6,468 -------- -------- Total current assets 143,894 133,725 -------- -------- INVESTMENTS 18,009 17,966 INTANGIBLES--NET 49,805 43,532 OTHER ASSETS 15,687 11,236 DEFERRED DEBITS Unamortized debt expense and reacquisition premiums 5,646 2,778 Regulatory assets 5,117 5,517 Other 1,406 1,183 -------- -------- Total deferred debits 12,169 9,478 -------- -------- PLANT Electric plant in service 810,470 795,357 Diversified operations 145,712 129,716 -------- -------- Total 956,182 925,073 Less accumulated depreciation and amortization 441,863 416,419 -------- -------- Plant - net of accumulated depreciation and amortization 514,319 508,654 Construction work in progress 28,658 13,117 -------- -------- Net plant 542,977 521,771 -------- -------- TOTAL $782,541 $737,708 ======== ========
See accompanying notes to consolidated financial statements. OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS, DECEMBER 31 2001 2000 ------------------------------------------------------------------------------------------------------------------------------------ (in thousands) LIABILITIES AND EQUITY CURRENT LIABILITIES Sinking fund requirements and current maturities of long-term debt $ 28,946 $ 14,288 Accounts payable 54,777 52,525 Accrued salaries and wages 9,491 9,476 Income taxes payable 1,634 3,243 Other accrued taxes 9,854 10,585 Other accrued liabilities 6,090 6,524 --------- --------- Total current liabilities 110,792 96,641 --------- --------- NONCURRENT LIABILITIES 32,981 30,181 --------- --------- COMMITMENTS (NOTE 6) DEFERRED CREDITS Deferred income taxes 85,591 86,407 Deferred investment tax credit 13,935 15,112 Regulatory liabilities 9,914 10,618 Other 7,160 6,850 --------- --------- Total deferred credits 116,600 118,987 --------- --------- CAPITALIZATION (PAGE 35) Long-term debt, net of sinking fund and current maturities 227,360 195,128 Cumulative preferred shares 15,500 33,500 Common shares, par value $5 per share -- authorized, 50,000,000 shares; outstanding, 2001 -- 24,653,490 shares; 2000 -- 24,574,288 shares $ 123,267 $ 122,871 Premium on common shares 1,526 50 Unearned compensation (151) (226) Retained earnings 156,641 140,796 Accumulated other comprehensive expense (1,975) (220) --------- --------- Total common equity 279,308 263,271 Total capitalization 522,168 491,899 --------- --------- TOTAL $ 782,541 $ 737,708 ========= =========
See accompanying notes to consolidated financial statements. OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------------------ (in thousands, except per-share amounts) OPERATING REVENUES Electric $ 307,684 $ 262,280 $ 233,527 Plastics 63,216 82,667 31,504 Manufacturing 123,436 97,506 87,086 Health services 79,129 66,319 68,805 Other business operations 80,667 78,159 68,322 --------- --------- --------- Total operating revenues 654,132 586,931 489,244 OPERATING EXPENSES Production fuel 41,776 38,546 36,839 Purchased power 99,491 66,121 44,190 Electric operation and maintenance expenses 75,531 74,591 71,724 Cost of goods sold 249,789 229,056 180,277 Other nonelectric expenses 58,497 53,831 40,964 Depreciation and amortization 42,100 40,562 36,859 Property taxes 9,464 9,976 10,178 --------- --------- --------- Total operating expenses 576,648 512,683 421,031 OPERATING INCOME Electric 57,150 49,268 47,234 Plastics (1,391) 8,745 3,382 Manufacturing 12,175 6,945 5,297 Health services 6,862 5,729 4,936 Other business operations 2,688 3,561 7,364 --------- --------- --------- 77,484 74,248 68,213 GAIN FROM SALE OF RADIO STATION ASSETS - - 14,469 OTHER INCOME AND DEDUCTIONS -- NET 2,193 2,154 2,311 INTEREST CHARGES 15,991 17,005 15,209 --------- --------- --------- INCOME BEFORE INCOME TAXES 63,686 59,397 69,784 INCOME TAXES 20,083 18,355 24,489 --------- --------- --------- NET INCOME 43,603 41,042 45,295 PREFERRED DIVIDEND REQUIREMENTS 1,993 1,879 2,228 --------- --------- --------- EARNINGS AVAILABLE FOR COMMON SHARES $ 41,610 $ 39,163 $ 43,067 ========= ========= ========= AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 24,600 24,572 24,553 AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 24,832 24,649 24,575 BASIC EARNINGS PER SHARE $ 1.69 $ 1.59 $ 1.75 DILUTED EARNINGS PER SHARE $ 1.68 $ 1.59 $ 1.75 DIVIDENDS PER COMMON SHARE $ 1.04 $ 1.02 $ 0.99
See accompanying notes to consolidated financial statements. OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY ------------------------------------------------------------------------------------------------------------------------------------ ACCUMULATED COMMON PAR VALUE, PREMIUM ON OTHER SHARES COMMON COMMON UNEARNED RETAINED COMPREHENSIVE TOTAL OUTSTANDING SHARES SHARES COMPENSATION EARNINGS INCOME/(EXPENSE) EQUITY ---------------------------------------------------------------------------------------- (in thousands, except common shares outstanding) BALANCE, DECEMBER 31, 1998 11,879,504 $ 59,398 $ 39,919 $ - $ 125,462 $ 297 $225,076 Common stock issuances - net of retirement 45,483 227 1,540 $ (10) 1,757 Unearned compensation - stock options 301 (301) - Two-for-one stock split - March 15, 2000 11,924,987 59,625 (41,760) (17,865) - Effects of pooling transactions, January 1, 1999: T.O. Plastics, Inc. 451,066 2,255 (1,277) 978 St. George Steel Fabrication, Inc. 270,370 1,352 426 1,778 Comprehensive income: Net income 45,295 45,295 Reversal of previously recorded unrealized gains on available- for-sale securities sold (297) (297) -------- Total comprehensive income 44,998 Cumulative preferred dividends (2,267) (2,267) Common dividends (23,554) (23,554) --------------------------------------------------------------------------------------- BALANCE, DECEMBER 31, 1999 24,571,410 $ 122,857 $ - $ (301) $ 126,210 $ - $248,766 Common stock issuances 2,878 14 50 64 Amortization of unearned compensation - stock options 75 75 Comprehensive income: Net income 41,042 41,042 Minimum liability adjustment (220) (220) -------- Total comprehensive income 40,822 Purchase stock for employee purchase plan on open market (250) (250) Cumulative preferred dividends (1,878) (1,878) Common dividends (24,328) (24,328) --------------------------------------------------------------------------------------- BALANCE, DECEMBER 31, 2000 24,574,288 $ 122,871 $ 50 $ (226) $ 140,796 $ (220) $263,271 Common stock issuances 79,202 396 1,187 1,583 Amortization of unearned compensation - stock options 75 75 Comprehensive income: Net income 43,603 43,603 Minimum liability adjustment (1,755) (1,755) -------- Total comprehensive income 41,848 Tax benefit for exercise of stock options 302 302 Remove capital stock expense $6.35 preferred shares 246 (246) - Purchase stock for employee purchase plan on open market (259) (168) (427) Cumulative preferred dividends (2,088) (2,088) Common dividends (25,256) (25,256) --------------------------------------------------------------------------------------- BALANCE, DECEMBER 31, 2001 24,653,490 $ 123,267 $ 1,526 $ (151) $ 156,641 $(1,975) $279,308 ---------------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements. OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------------------ (in thousands) Cash flows from operating activities Net income $ 43,603 $ 41,042 $ 45,295 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 42,100 40,562 36,859 Deferred investment tax credit--net (1,177) (1,183) (1,186) Deferred income taxes (1,441) (4,655) (3,820) Change in deferred debits and other assets (8,434) (3,346) (459) Change in noncurrent liabilities and deferred credits 2,484 4,263 4,727 Allowance for equity (other) funds used during construction (963) (341) (246) (Gain)/loss on sale of investments and radio station assets (81) 728 (14,455) Changes in working capital: Change in receivables, materials, and supplies 4,880 (20,781) (572) Change in other current assets (432) 537 1,348 Change in payables and other current liabilities (581) 9,904 8,253 Change in interest and income taxes payable (2,429) (4,969) 6,106 --------- -------- -------- Net cash provided by operating activities 77,529 61,761 81,850 --------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Gross capital expenditures (53,596) (46,273) (35,245) Proceeds from sale of radio station assets - - 24,063 Proceeds from disposal of noncurrent assets 3,298 1,709 1,930 Acquisitions--net of cash acquired (8,948) (34,194) (16,000) Change in other investments (1,884) (86) (9) --------- -------- -------- Net cash used in investing activities (61,130) (78,844) (25,261) --------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Change in short-term debt--net issuances - (50) (4,228) Proceeds from issuance of long-term debt--net of expenses 119,266 44,814 15,444 Proceeds from issuance of common stock--net - 14 1,757 Proceeds from employee stock plans 1,347 - - Redemption of preferred stock (18,000) - (5,331) Payments for retirement of long-term debt (81,549) (24,889) (17,618) Dividends paid and other distributions (27,344) (26,455) (25,820) --------- -------- -------- Net cash used in financing activities (6,280) (6,566) (35,796) --------- -------- -------- NET CHANGE IN CASH AND CASH EQUIVALENTS 10,119 (23,649) 20,793 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,259 24,908 4,115 --------- -------- -------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 11,378 $ 1,259 $ 24,908 ========= ======== ======== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid during the year for: Interest (net of amount capitalized) $ 16,313 $ 16,075 $ 14,004 Income taxes $ 23,575 $ 28,510 $ 23,077
See accompanying notes to consolidated financial statements. OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION, DECEMBER 31 2001 2000 ------------------------------------------------------------------------------------------------------------------------------------ (in thousands) Long-term debt First mortgage bond series: 7.25%, due August 1, 2002 $ 18,200 $ 18,400 8.75%, retired December 2001 - 18,200 8.25%, due August 1, 2022 27,300 27,600 Pollution control series: 6.5-6.9%, Big Stone and Coyote project - retired October 2001 - 25,981 -------- -------- Total first mortgage bond series 45,500 90,181 Senior debentures 6.375%, due December 1, 2007 50,000 50,000 Senior notes 6.63%, due December 1, 2011 90,000 - Industrial development refunding revenue bonds 5.00% due December 1, 2002 3,010 3,010 Pollution control refunding revenue bonds variable 1.9% at December 31, 2001, due December 1, 2012 10,400 10,400 Grant County, South Dakota pollution control refunding revenue bonds 4.65%, due September 1, 2017 5,185 - Mercer County, North Dakota pollution control refunding revenue bonds 4.85%, due September 1, 2022 20,790 - Obligations of Varistar Corporation: 7.80% ten-year term note, due October 31, 2007 9,771 12,021 Variable 8.11% at December 31, 2000, retired December 2001 - 16,640 8.15% five-year term note, due October 31, 2005 5,280 6,600 Variable 3.66% at December 31, 2001, due July 3, 2007 4,479 5,324 Various at 3.25% to 8.4% at December 31, 2001 11,571 15,214 Obligations of Otter Tail Energy Services Company 8.75% ten-year term note, due April 11, 2008 892 994 Other 5 6 -------- -------- Total 256,883 210,390 Less: Current maturities 28,646 13,293 Sinking fund requirement 300 995 Unamortized debt discount and premium -- net 577 974 -------- -------- Total long-term debt 227,360 195,128 -------- -------- CUMULATIVE PREFERRED SHARES -- without par value (stated and liquidating value $100 a share) -- authorized 1,500,000 shares; outstanding: Series subject to mandatory redemption: Outstanding December 31, 2000 $6.35, 180,000 shares - 18,000 -------- -------- Other series: $3.60, 60,000 shares 6,000 6,000 $4.40, 25,000 shares 2,500 2,500 $4.65, 30,000 shares 3,000 3,000 $6.75, 40,000 shares 4,000 4,000 -------- -------- Total other preferred 15,500 15,500 -------- -------- CUMULATIVE PREFERENCE SHARES -- without par value, authorized 1,000,000 shares; outstanding: none TOTAL COMMON SHAREHOLDERS' EQUITY 279,308 263,271 -------- -------- TOTAL CAPITALIZATION $522,168 $491,899 ======== ========
See accompanying notes to consolidated financial statements. Otter Tail Corporation Notes to consolidated financial statements For the years ended December 31, 2001, 2000 and 1999 1. Summary of significant accounting policies Principles of consolidation--The consolidated financial statements include Otter Tail Corporation and its wholly owned subsidiaries (the Company). Profits on sales between nonregulated affiliates and from the regulated electric utility company to nonregulated affiliates are eliminated. However, profits on sales to the regulated electric utility company from nonregulated affiliates are not eliminated, in accordance with the requirements of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. These amounts are not material. System of accounts--For regulatory reporting purposes, the electric utility's internal system of accounts is translated into the accounts of the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC), the Public Service Commission of North Dakota, and the Public Utilities Commissions of Minnesota and South Dakota. Regulation and Statement of Financial Accounting Standards (SFAS) No. 71--As a regulated entity the Company and the electric utility account for the financial effects of regulation in accordance with SFAS No. 71. This statement allows for the recording of a regulatory asset or liability for costs that will be collected or refunded through the ratemaking process in the future. Included on the Company's Consolidated Balance Sheets for the years ended December 31, 2001 and 2000 are regulatory assets and liabilities that primarily relate to the recording of deferred taxes as required by SFAS No. 109, Accounting for Income Taxes. Plant, retirements, and depreciation--Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads, and allowance for funds used during construction (AFC). AFC, a noncash item, is included in utility construction work in progress. The amount of AFC capitalized was $1,342,000 for 2001, $471,000 for 2000, and $344,000 for 1999. The cost of depreciable units of property retired plus removal costs less salvage is charged to the accumulated provision for depreciation. Maintenance, repairs, and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated service lives of the properties. Such provisions as a percent of the average balance of depreciable electric utility property were 3.06 percent for 1999 through 2001. Property and equipment of nonutility and diversified operations are carried at historical cost or at the current appraised value if acquired in a business combination accounted for under the purchase method of accounting, and are depreciated on a straight-line basis over useful lives (3 to 40 years) of the related assets. Replacement and major improvements are capitalized; maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of net income. Jointly owned plants--The consolidated financial statements include the Company's 53.9 percent (Big Stone Plant) and 35 percent (Coyote Station) ownership interests in the assets, liabilities, revenue, and expenses of Big Stone Plant and Coyote Station, respectively. Amounts at December 31, 2001 and 2000 included in electric plant in service for Big Stone were $112,898,000 and $111,850,000, respectively, and the accumulated depreciation was $71,585,000 and $68,269,000, respectively. Amounts at December 31, 2001 and 2000 included in electric plant in service for Coyote were $146,566,000 and $146,292,000, respectively, and the accumulated depreciation was $74,057,000 and $70,524,000, respectively. The Company's share of direct revenue and expenses of the jointly owned plants in service is included in operating revenue and expenses in the Consolidated Statements of Income. Recoverability of long-lived assets--The Company reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment by comparing the carrying value of the assets with net cash flows expected to be provided by operating activities of the business or related assets. Should the sum of the expected future net cash flows be less than the carrying values, the Company would determine whether an impairment loss should be recognized. An impairment loss would be quantified by comparing the amount by which the carrying value exceeds the fair value of the asset where fair value is based on the discounted cash flows expected to be generated by the asset. Income taxes--Comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect when the temporary differences reverse. The Company amortizes the investment tax credit over the estimated lives of the related property. Revenue recognition--Due to the diverse business operations of the Company revenue recognition depends on the product produced and sold. However, in general, the Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue is deferred until such obligations are fulfilled. Provisions for sale returns and warranty costs are recorded at the time of the sale based on historical information and current trends. Electric customers' meters are read and bills are rendered on a cycle basis. Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include a cost of energy adjustment clause, under which the rates are adjusted to reflect changes in average cost of fuels and purchased power, and a surcharge for recovery of conservation-related expenses. Revenues on almost all of wholesale sales are recognized when energy is delivered. The majority of revenue is the result of bilateral agreements with individual counter-parties. Plastics operating revenues are recorded when the product is shipped. Health services operating revenues on major equipment and installation contracts are recorded when the equipment is delivered. Amounts received in advance under customer service contracts are deferred and recognized on a straight-line basis over the contract period. Revenues generated in the mobile imaging operations are recorded on a fee for scan basis. Manufacturing operating revenues are recorded when products are shipped and on a percentage-of-completion basis for construction type contracts. Other business operations operating revenues are recorded when services are rendered or products are shipped. In the case of construction contracts, the percentage-of-completion method is used. Pre-production costs--As part of the manufacturing process, the Company incurs costs related to the design and development of molds, dies, and tools. As of January 1, 2000 the Company adopted prospectively Emerging Issues Task Force Statement (EITF) 99-5, Accounting for Pre-production Costs Related to Long-Term Supply Arrangements. The Company capitalizes the costs related to the design and development of molds, dies, and tools used to produce products under a long-term supply arrangement, some of which are owned by the Company. During 2001 and 2000 the amount of costs capitalized were $1,216,000 and $1,254,000. These costs are amortized over three years. Stock-based compensation--As described in note 4, the Company has elected to follow the accounting provisions of Accounting Principle Board Opinion No. 25 (APB 25), Accounting for Stock Issued to Employees, for stock-based compensation and to furnish the pro forma disclosures required under SFAS No. 123, Accounting for Stock-Based Compensation. Use of estimates--The Company uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, tax provisions, collectability of trade accounts receivable, self insurance programs, environmental liabilities, unbilled revenues, unscheduled power exchanges, service contract maintenance costs and actuarially determined benefit costs. As better information becomes available (or actual amounts are determinable) the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Reclassifications--Certain prior year amounts have been reclassified to conform to 2001 presentation. Such reclassifications had no impact on net income, shareholders' equity, or cash flows provided from operations. In addition, during 2001 the Company completed two acquisitions using the pooling-of-interests accounting method. Consolidated financial statements for 1999 and 2000 have been restated to reflect these acquisitions. Cash equivalents--The Company considers all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents. Debt reacquisition premiums--In accordance with regulatory treatment, the Company defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. Investments--At December 31, 2001 and 2000, the Company had investments of $6,108,000 and $6,759,000, respectively, in limited partnerships that invest in tax-credit qualifying affordable housing projects. These investments provided the Company with tax credits of $1,418,000 and $1,414,000 in 2001 and 2000, respectively. The balance of investments at December 31, 2001, consists of $6,058,000 in additional investments accounted for under the equity method and $5,843,000 in other investments accounted for under the cost method, with $1,186,000 related to participation in economic development loan pools. The balance of investments at December 31, 2000, consists of $5,024,000 in additional investments accounted for under the equity method and $6,180,000 in other investments accounted for under the cost method, with $1,263,000 related to participation in economic development loan pools. (See further discussion under note 10.) Inventories--The electric operation inventories are reported at average cost. The plastics, health services, manufacturing, and other business operation inventories are stated at the lower of cost (first-in, first-out) or market. Short-term debt--There was no short-term debt outstanding as of December 31, 2001 and 2000. The average interest rate paid on short-term debt during 2001 and 2000 was 5.2 percent and 8.1 percent, respectively. Intangible assets--The majority of the Company's intangible assets consist of goodwill associated with the acquisition of subsidiaries. Intangible assets are amortized on a straight-line basis over periods of 40 years for the telecommunication operations and 15 years or less for all other goodwill and intangibles. The Company periodically evaluates the recovery of intangible assets based on an analysis of undiscounted future cash flows. As a result of changing market conditions during 2000, the Company completed an evaluation of the recoverability of the assets of a subsidiary acquired by Otter Tail Energy Services in 1998. As a result of the evaluation it was determined that $800,000 of goodwill was impaired and was charged to amortization expense during 2000. As a result of the writedown, the remaining goodwill related to the acquisition is $1.0 million as of December 31, 2001. Total intangibles as of December 31 are as follows:
2001 2000 ------ ----- (in thousands) Goodwill on telecommunications operations $ 7,749 $ 7,749 Other intangible assets, primarily goodwill 56,761 47,288 ------ ------- Total 64,510 55,037 Less accumulated amortization 14,705 11,505 ------ ------- Intangibles-net $49,805 $43,532 ======= =======
Adoption of new accounting pronouncements--The Company adopted Statement of Financial Accounting Standards (SFAS) 133, Accounting for Derivative Instruments and Hedging Activities, as amended, on January 1, 2001, which requires all derivative instruments be reported on the consolidated balance sheet at fair value. The adoption of SFAS No. 133 did not have a material effect on the Company's consolidated financial statements. The application of SFAS 133 to electric utilities continued to evolve throughout 2001. On December 19, 2001, the Financial Accounting Standards Board revised SFAS 133 Implementation Issue No. C15 to be effective April 1, 2002 with early adoption allowed. As of December 31, 2001, the Company early adopted the revised SFAS 133 Implementation Issue No. C15. The Company has determined that certain electric energy contracts meet the criteria of a derivative under SFAS 133 but qualify for the normal purchase and normal sales exception and are not subject to mark-to-market accounting treatment. SFAS 133 did not have a material effect on the Company's 2001 consolidated financial statements. In July 2001 the FASB issued SFAS 141, Business Combinations, which requires the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS 141 also specifies that intangible assets acquired in a business combination, that meet certain criteria, be recognized and reported apart from goodwill. The Company has adopted this statement as of July 1, 2001 and applied it to the acquisitions that occurred after July 1, 2001: Interim Solutions and Sales, Inc., Midwest Medical Diagnostics, Inc., Nuclear Imaging, Ltd., and Titan Steel Corporation. Adoption of this statement did not have a material effect on the Company's consolidated financial statements. In July 2001 the FASB issued SFAS 142, Goodwill and Other Intangible Assets, which requires goodwill and intangible assets with indefinite useful lives no longer be amortized. Rather they will be tested for impairment, at least annually, in accordance with the provisions of SFAS 142. Intangible assets with finite useful lives will be amortized over their respective estimated useful lives and will be reviewed for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 142 is effective January 1, 2002, except for any goodwill arising in a purchase business combination completed on or after July 1, 2001 which would be subject immediately to the provisions of SFAS 142. As of December 31, 2001, the Company had net goodwill of $48.2 million. Included on the Company's consolidated statement of income for the year ended December 31, 2001 is $3.2 million in goodwill amortization expense. SFAS 142 requires the Company perform an assessment of goodwill impairment as of the date of adoption. Any impairment loss resulting from this transition to SFAS 142 would be recognized as a cumulative effect of a change in accounting principle in the Company's consolidated income statement at the time of adoption. The Company is continuing to evaluate the statement for its impact on the Company's consolidated financial statements. Based on the work completed to date, the Company does not expect the implementation of this statement to have a material impact on its consolidated results of operations and financial position. In July 2001 the FASB issued SFAS 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for retirement obligations associated with tangible long-lived assets. This statement is effective for fiscal years beginning after June 15, 2002. The Company is assessing this statement but has not yet determined the impact of SFAS 143 on its consolidated financial position or results of operations. The FASB issued SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets in October 2001. SFAS 144 replaces SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. This statement develops one accounting model for long-lived assets to be disposed of by sale and also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity in a disposal transaction. The statement is effective for fiscal years beginning after December 15, 2001. The Company adopted the accounting model for impairment or disposal of long-lived assets starting January 1, 2002. Adoption of this statement did not have a material effect on the Company's consolidated financial statements. 2. Business combinations, dispositions and segment information On February 28, 2001 the Company acquired all of the outstanding common stock of T.O. Plastics, Inc. in exchange for 451,066 newly issued shares of the Company's common stock. T.O. Plastics, Inc. custom manufactures returnable pallets, material and handling trays and horticultural containers. It has three facilities in Minnesota and one facility in South Carolina. On September 28, 2001 the Company acquired all of the outstanding common stock of St. George Steel Fabrication, Inc. in exchange for 270,370 newly issued shares of the Company's common stock. St. George Steel is a fabricator of steel products engaged in custom and proprietary operations located in Utah. These acquisitions were accounted for as a pooling-of-interests. Since the St. George Steel acquisition was initiated prior to June 30, 2001, pooling-of-interest accounting was allowed under the transition provision of Statement of Financial Accounting Standards No. 141. The Company's consolidated financial statements for 2000 and 1999 have been restated to reflect the effects of the poolings. The results of operations of the separate companies and the combined amounts included in the consolidated financial statement are presented in the table below.
Otter Tail Pooled Corporation Entities Combined ------------------------------------------------------------------------------------------------------------------ (in thousands, except per share amounts) FOR THE YEAR ENDED DECEMBER 31, 1999: Changes in common equity: Common shares, par value $ 119,250 $ 3,607 $ 122,857 Premium on common shares -- -- -- Unearned compensation (301) -- (301) Retained earnings 126,744 (534) 126,210 Accumulated other comprehensive income -- -- -- --------- --------- --------- Total common equity $ 245,693 $ 3,073 $ 248,766 ========= ========= ========= Operating revenues $ 464,577 $ 24,667 $ 489,244 Net Income 44,977 318 45,295 Earnings available for common shares 42,749 318 43,067 Average common shares outstanding-diluted 23,853 722 24,575 Diluted earnings per share $ 1.79 $1.75 FOR THE YEAR ENDED DECEMBER 31, 2000: Changes in common equity: Common shares, par value $ 119,264 $ 3,607 $ 122,871 Premium on common shares 50 -- 50 Unearned compensation (226) -- (226) Retained earnings 140,511 285 140,796 Accumulated other comprehensive income (220) -- (220) --------- --------- --------- Total common equity $ 259,379 $ 3,892 $ 263,271 ========= ========= ========= Operating revenues $ 559,445 $ 27,486 $ 586,931 Net Income 40,224 818 41,042 Earnings available for common shares 38,346 817 39,163 Average common shares outstanding-diluted 23,928 721 24,649 Diluted earnings per share $ 1.61 $ 1.59 FOR THE THREE MONTHS ENDED MARCH 31, 2001 (1): Operating revenues $ 155,509 $ 4,145 $ 159,654 Net Income 11,471 529 12,000 Earnings available for common shares 11,002 528 11,530 Average common shares outstanding-diluted 24,506 270 24,776 Diluted earnings per share $ 0.45 $ 0.47 FOR THE THREE MONTHS ENDED JUNE 30, 2001 (1): Operating revenues $ 152,896 $ 4,436 $ 157,332 Net Income 8,775 382 9,157 Earnings available for common shares 8,305 383 8,688 Average common shares outstanding-diluted 24,529 270 24,799 Diluted earnings per share` $ 0.34 $ 0.35
FOR THE SIX MONTHS ENDED JUNE 30, 2001 (1): Operating revenues $ 308,405 $ 8,581 $ 316,986 Net Income 20,246 911 21,157 Earnings available for common shares 19,307 911 20,218 Average common shares outstanding-diluted 24,515 270 24,785 Diluted earnings per share` $ 0.79 $ 0.82
(1) St. George Steel Fabrication, Inc. only. On September 4, 2001 the Company acquired the assets and operations of Interim Solutions and Sales, Inc. and Midwest Medical Diagnostics, Inc. of Minneapolis, Minnesota. These companies operate as a division of DMS Imaging, Inc. and provide mobile diagnostic imaging services on an interim basis for computed tomography and magnetic resonance imaging, fee-per-exam options and sales of previously owned imaging equipment. Revenues for 2000 were approximately $3.1 million. The acquisition was accounted for using the purchase method and the excess of the purchase price over the net assets acquired was $2.2 million. On September 10, 2001 the Company acquired the assets and operations of Nuclear Imaging, Ltd., of Sioux Falls, South Dakota. Nuclear Imaging provides mobile nuclear medicine, positron emission tomography and bone densitometry services to more than 120 healthcare facilities in the Midwest. Nuclear Imaging is a subsidiary of DMS Imaging, Inc. Revenues for 2000 were approximately $6.9 million. The acquisition was accounted for using the purchase method and the excess of the purchase price over the net assets acquired was $4.8 million On November 1, 2001 the Company acquired the assets and operations of Titan Steel Corporation of Salt Lake City, Utah. Titan is a fabricator of steel products engaged in custom operations. Titan is an operating division of St. George Steel Fabrication, Inc. Revenues for 2000 were approximately $9 million. The acquisition was accounted for using the purchase method and the excess of the purchase price over the net assets acquired was immaterial. The acquisitions of Interim Solutions and Sales, Inc., Midwest Medical Diagnostics, Inc., Nuclear Imaging, Ltd and Titan Steel Corporation were accounted for using the purchase method of accounting under SFAS 141. Under the transition provision of SFAS 142 no goodwill was amortized for these acquisitions during 2001. The pro forma effect of these acquisitions on 2000 and 1999 revenues, net income, or earnings per share was not significant. On January 1, 2000 the Company acquired the assets and operations of Vinyltech Corporation (Vinyltech) located in Phoenix, Arizona. Vinyltech is a manufacturer of polyvinyl chloride (PVC) pipe and produces approximately 90 million pounds of pipe annually. Annual revenues for 1999 were approximately $41 million. On June 1, 2000 the Company acquired the assets and operations of Portable X-Ray & EKG, Inc. (PXE) located in Minneapolis, Minnesota. PXE is a provider of mobile x-ray, EKG, ultrasound and echocardiogram services primarily to patients in long-term care facilities in the Minneapolis/St. Paul market. Its 1999 annual revenues were approximately $2.8 million. These acquisitions were accounted for using the purchase method of accounting. The excess of the purchase price over the net assets acquired of approximately $24 million is being amortized over 15 years. The pro forma effect of these acquisitions on 1999 revenues, net income, or earnings per share was not significant. On September 1, 1999 the Company acquired the flatbed trucking operations of E. W. Wylie Corporation (Wylie). The acquisition was accounted for using the purchase method of accounting. The excess of the purchase price over net assets acquired of approximately $8 million is being amortized over 15 years. Wylie is located in Fargo, North Dakota, and operates in 48 states and 6 Canadian provinces. The pro forma effect of the Wylie acquisition on 1999 revenues, net income, or earnings per share was not significant. On October 1, 1999 the Company completed the sale of certain assets of the radio stations and video production company owned by KFGO, Inc. and the radio stations owned by Western Minnesota Broadcasting Company for $24.1 million. The gain after income tax was $8.1 million or $0.34 cents per share. Segment information--The accounting policies of the segments are described under note 1 - Summary of significant accounting policies. The Company's business operations consist of five segments based on products and services. Electric includes the electric utility only and is based in Minnesota, North Dakota, and South Dakota. Plastics consists of businesses involved in the production of PVC pipe in the Upper Midwest and Southwest regions of the United States. Health services include businesses involved in the sale of diagnostic medical equipment, supplies and accessories. In addition these businesses also provide service maintenance, mobile diagnostic imaging, mobile PET and nuclear medicine imaging, portable x-ray imaging and rental of diagnostic medical imaging equipment to various medical institutions located in 32 states. Manufacturing operations consist of businesses involved in the production of wind towers, frame-straightening equipment and accessories for the auto body shop industry, custom plastic pallets, material and handling trays, and horticultural containers, fabrication of steel products, contract machining, and metal parts stamping and fabrication located in the Upper Midwest and Utah. Other business operations consist of businesses operating in electrical and telephone construction contracting, transportation, telecommunications, entertainment, and energy services and natural gas marketing as well as the portion of corporate administrative and general expenses that are not allocated to other segments. The electrical and telephone construction contracting companies and energy services and natural gas marketing business operate primarily in the Upper Midwest. The telecommunications companies operate in central and northeast Minnesota and the transportation company operates in 48 states and 6 Canadian provinces. The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for 2001, 2000 and 1999 is presented in the following table.
2001 2000 1999 ------ ------ ------ (in thousands) Operating revenue Electric $307,684 $262,280 $233,527 Plastics 63,216 82,667 31,504 Manufacturing 123,436 97,506 87,086 Health services 79,129 66,319 68,805 Other business operations 80,667 78,159 68,322 -------- -------- -------- Total $654,132 $586,931 $489,244 ======== ======== ======== Operating income Electric $ 57,150 $ 49,268 $ 47,234 Plastics (1,391) 8,745 3,382 Manufacturing 12,175 6,945 5,297 Health services 6,862 5,729 4,936 Other business operations 2,688 3,561 7,364 ------ -------- -------- Total $ 77,484 $ 74,248 $ 68,213 ======== ======== ======== Depreciation and amortization Electric $ 24,272 $ 23,778 $ 23,366 Plastics 3,229 3,301 1,168 Manufacturing 5,139 3,930 3,627 Health services 3,517 2,981 4,244 Other business operations 5,943 6,572 4,454 -------- -------- -------- Total $ 42,100 $ 40,562 $ 36,859 ======== ======== ======== Capital expenditures Electric $ 34,992 $ 24,659 $ 21,095 Plastics 1,572 3,361 4,491 Manufacturing 10,516 8,688 4,019 Health services 3,282 2,871 993 Other business operations 3,234 6,694 4,647 -------- -------- -------- Total $ 53,596 $ 46,273 $ 35,245 ======== ======== ======== Identifiable assets Electric $523,948 $531,778 $524,012 Plastics 45,649 49,831 16,477 Manufacturing 67,033 59,130 43,908 Health services 50,560 32,909 29,542 Other business operations 95,351 64,060 80,402 -------- -------- -------- Total $782,541 $737,708 $694,341 ======== ======== ========
No single external customer accounts for 10 percent or more of the Company's revenues. Substantially all sales and long-lived assets of the Company are within the United States. 3. Rate matters and arbitration settlement. In 2001 the Minnesota Legislature exempted certain generation machinery and attached equipment from the new state personal property tax levy. The law also required that any windfall tax savings resulting from this exemption be refunded to electric utility customers. As a result of this law, $238,000 in 2001 property tax savings will be refunded to retail electric customers in 2002. On December 29, 2000, the NDPSC approved a performance-based ratemaking plan that links allowed earnings in North Dakota to seven defined performance standards in the areas of price, electric service reliability, customer satisfaction, and employee safety. The plan is in place for 2001 through 2005, unless suspended or terminated by the NDPSC or the Company. In 2001, the electric utility recorded an estimated $334,000 refund to North Dakota customers based on 2001 earnings and the performance relative to the defined standards of the performance-based ratemaking plan. During the second quarter of 2000, the Minnesota, South Dakota and North Dakota utility regulatory agencies approved the accounting treatment of settlement proceeds related to the Knife River coal contract arbitration. The settlement proceeds of $3.2 million (including interest) had been recorded as a liability on the balance sheet since 1999 pending regulatory approval. The approval allowed the Company to recover arbitration costs of $1.0 million that had been previously expensed and to recognize as income $308,000 of fuel cost savings applicable to wholesale power pool sales. The remaining $1.9 million represents a reduction of fuel costs that were returned to the Company's electric retail customers through the cost of energy adjustment clause during 2000. On October 6, 1999, the NDPSC approved a settlement agreement following an audit of the Company's electric operations in North Dakota. The effect of this settlement decreased 1999 earnings by approximately $441,000 after taxes or $0.02 per share. As part of the settlement agreement, the Company was required to refund to North Dakota customers during 2000 any 1999 regulated electric operations earnings from North Dakota over a 12.5 percent return on equity. The amount of the refund was insignificant. 4. Common shares New issuances--Common stock issuances during 2001 included 721,436 unregistered shares to effect the pooling acquisitions, 74,480 shares issued as a result of stock options exercised, 3,041 shares issued as director compensations and 1,681 shares of restricted stock. Stock split--On March 15, 2000 the Company effected a two-for-one Common Stock split in the form of a 100 percent stock dividend by issuance of one additional $5.00 par value Common Share for each $5.00 par value Common Share outstanding on February 15, 2000. All common share and per share amounts have been adjusted for 2000 and 1999 to reflect the stock split. Stock incentive plan--Under the 1999 Stock Incentive Plan (Incentive Plan) a total of 2,600,000 common shares were authorized for granting of stock awards. The Incentive Plan provides for the grant of options, performance awards, restricted stock, stock appreciation rights and other types of stock grants or stock-based awards. The exercise price of the stock options is equal to the fair market value per share at the date of the grant. Options granted to outside directors are exercisable immediately, and all other options granted as of December 31, 2001 vest ratably over a four-year period. The options expire ten years after the date of the grant. The Company accounts for the Incentive Plan under APB 25. Unearned compensation relating to the options granted in 1999 was $151,000 at December 31, 2001, and is included as a reduction of common equity. Had compensation costs for the stock options issued under the Incentive Plan been determined based on estimated fair value at the award dates, as prescribed by SFAS 123, the Company's net income for 1999 through 2001 would have decreased as presented in the table below. This may not be representative of the pro forma effects for future years if additional options are granted. Using the Black-Scholes option-pricing model, the Company's pro forma net income with related assumptions are as follows:
2001 2000 1999 ---------------------------------------------------------------------------------------------------------- Net income As reported $43,603 $41,042 $45,295 Pro forma $42,770 $40,697 $45,132 Diluted earnings per share As reported $1.68 $1.59 $1.75 Pro forma $1.64 $1.58 $1.75 Risk free interest rate 5.5% 5.2% 5.2% Expected lives 7 years 7 years 7 years Expected volatility 24.9% 23.7% 19.3% Dividend yield 4.0% 4.5% 5.0%
Presented below is a summary of the stock options activity for 2001, 2000, and 1999.
Stock Option Activity 2001 2000 1999 -------------------------------------------------------------------------------------------------------------------- Average Average Average exercise exercise exercise Options price Options price Options price ------- ---- ------- ----- ------- ---- Outstanding, beginning of year 787,316 $19.55 442,900 $19.25 -- $ -- Granted 582,000 26.33 360,000 19.75 450,700 19.25 Exercised 74,936 19.44 750 19.19 -- -- Forfeited 29,338 22.17 14,834 19.30 7,800 19.19 --------- ------- ------- Outstanding, year end 1,265,042 22.39 787,316 19.55 442,900 19.25 ========= ======= ======= Exercisable, year end 257,269 $19.83 127,542 $19.25 -- $ -- Fair value of options granted during year $ 5.88 $ 3.79 $ 2.79
The following table summarizes information about options outstanding as of December 31, 2001:
Options outstanding Options exercisable ------------------------------------------------------------------------------ Weighted- average weighted- Weighted- Outstanding remaining average Exercisable average Range of as of contractual exercise as of exercise exercise prices 12/31/01 life price 12/31/01 price --------------------------------------------------------------------------------------------------------- $17.84-$20.82 687,542 7.6 $19.46 238,769 $19.38 $20.83-$23.79 7,500 7.6 $21.75 2,500 $21.75 $23.80-$26.77 554,000 9.3 $26.25 16,000 $26.25 $26.78-$29.74 16,000 9.9 $29.34 -- --
In addition to the stock options granted, 1,681, 12,415 and 2,298 shares of restricted stock were granted during 2001, 2000 and 1999, respectively. Employee stock purchase plan--The 1999 Employee Stock Purchase Plan (Purchase Plan) allows eligible employees to purchase the Company's common shares at 85 percent of the lower market price at either the beginning or the end of each six-month purchase period. A total of 400,000 common shares are available for purchase by employees under the Purchase Plan. During 2001 56,612 common shares and in 2000, 53,630 common shares were purchased from the open market. Dividend reinvestment and share purchase plan--On August 30, 1996, the Company filed a shelf registration statement with the Securities and Exchange Commission for the issuance of up to 2,000,000 common shares pursuant to the Company's Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by shareholders or customers who participate in the Plan to be either new issue common shares or common shares purchased on the open market. Since June 1999, common shares needed for this Plan have been purchased from the open market instead of issuing new shares. Prior to this the Company had been issuing newly issued common shares: 89,238 shares were issued in 1999. Shareholder rights plan--On January 27, 1997, the Company's Board of Directors declared a dividend of one preferred share purchase right (Right) for each outstanding common share held of record as of February 10, 1997. One Right was also issued with respect to each common share issued after February 10, 1997. Each Right entitles the holder to purchase from the Company one one-hundredth of a share of newly created Series A Junior Participating Preferred Stock at a price of $70, subject to certain adjustment. The Rights are exercisable when, and are not transferable apart from the Company's common shares until, a person or group has acquired 15 percent or more, or commenced a tender or exchange offer for 15 percent or more, of the Company's common shares. If the specified percentage of the Company's common shares is acquired, each Right will entitle the holder (other than the acquiring person or group) to receive, on exercise, common shares of either the Company or the acquiring company having value equal to two times the exercise price of the Right. The Rights are redeemable by the Company's Board of Directors in certain circumstances and expire on January 27, 2007. 5. Retained earnings restriction The Company's Indenture of Mortgage and Articles of Incorporation, as amended, contain provisions that limit the amount of dividends that may be paid to common shareholders. Under the most restrictive of these provisions, retained earnings at December 31, 2001 were restricted by $9,238,000. 6. Commitments and contingencies At December 31, 2001, the electric utility had commitments under contracts in connection with construction programs aggregating approximately $16,234,000. For capacity and energy requirements the electric utility has agreements extending through 2006, at annual costs of approximately $14,168,000 in 2002, $12,241,000 in 2003, $12,261,000 in 2004, $10,762,000 in 2005, and $10,028,000 in 2006. The electric utility has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. These contracts expire between 2002 and 2016. In total, the electric utility is committed to the minimum purchase of approximately $105,927,000 or to make payments in lieu thereof, under these contracts. The cost of energy adjustment process in the rate-making provision lessens the risk of loss from market price changes because it provides for recovery of most fuel costs. The amounts of future operating lease payments are as follows:
Electric Diversified utility companies Total -------- ---------- --------- (in thousands) 2002 $ 1,445 $14,978 $16,423 2003 1,440 11,091 12,531 2004 1,151 7,958 9,109 2005 944 6,213 7,157 2006 944 1,542 2,486 Later years 4,537 584 5,121 ------- ------- ------- Total $10,461 $42,366 $52,827 ======= ======= =======
Rent expense was $20,242,000, $16,595,000, and $14,233,000, for 2001, 2000, and 1999, respectively. The Company is occasionally a party to litigation arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company believes the effect on its consolidated results of operations and financial position, if any, for the disposition of all currently pending matters will not be material. 7. Long-term obligations Long-term debt--All utility property, with certain minor exceptions, is subject to the lien of the Indenture of Mortgage of the Company securing its First Mortgage Bonds. The Company is required by the Indenture to make annual payments (exclusive of redemption premiums) for sinking fund purposes, except that the requirement with respect to certain series may be satisfied by the delivery of bonds of such series of equal principal amount. The Company issued First Mortgage Bonds of its pollution control series to secure payment of a like principal amount of revenue bonds that were issued by local governmental units to finance facilities leased or purchased and that the Company has capitalized. As a requirement of the issuance of the 6.63% Senior Notes, each of the subsidiaries of the Company has completed a guaranty agreement. Varistar's term notes and credit line borrowings are secured by a pledge of all of the common stock of the companies owned by Varistar. The aggregate amounts of maturities and sinking fund requirements on bonds outstanding and other long-term obligations at December 31, 2001, for each of the next five years are $28,946,000 for 2002, $7,378,000 for 2003, $6,851,000 for 2004, $6,122,000 for 2005, and $4,222,000 for 2006. 8. Pension plan and other postretirement benefits Pension plan--The Company's noncontributory funded pension plan covers substantially all electric utility and corporate employees. The plan provides 100 percent vesting after 5 vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. The Company reserves the right to discontinue the plan, but no change or discontinuance may affect the pensions theretofore vested. The Company's policy is to fund pension costs accrued. All past service costs have been provided for. The pension plan has a trustee who is responsible for pension payments to retirees. Five investment managers are responsible for managing the plan's assets. In addition, an independent actuary performs the necessary actuarial valuations for the plan. Net periodic pension cost/(income) for 2001, 2000, and 1999 includes the following components:
2001 2000 1999 ------ ------ ------- (in thousands) Service cost--benefit earned during the period $ 2,544 $ 2,458 $ 3,080 Interest cost on projected benefit obligation 8,766 8,439 8,150 Expected return on assets (14,610) (13,662) (12,159) Amortization of transition asset (235) (235) (235) Amortization of prior-service cost 1,107 1,107 1,287 Amortization of net gain (1,900) (1,869) (149) ------- ------- ------- Net periodic pension cost/(income) $(4,328) $(3,762) $ (26) ======= ======= =======
The plan assets consist of common stock and bonds of public companies, U.S. Government Securities, cash, and cash equivalents. The following tables provide a reconciliation of the changes in the plan's benefit obligations and fair value of assets over the two-year period ending December 31, 2001, and a statement of the funded status as of December 31 of both years:
2001 2000 ------ ------ (in thousands) Reconciliation of benefit obligation: Obligation at January 1 $116,444 $114,445 Service cost 2,544 2,458 Interest cost 8,766 8,439 Actuarial loss (gain) 4,332 (1,502) Benefit payments (7,563) (7,396) --------- --------- Obligation at December 31 $124,523 $116,444 ========= ========= Reconciliation of fair value of plan assets: Fair value of plan assets at January 1 $153,649 $159,555 Actual return on plan assets (7,292) 1,490 Benefit payments (7,563) (7,396) --------- ---------- Fair value of plan assets at December 31 $138,794 $153,649 ========= ========= Funded status: Over funded status at December 31 $ 14,271 $ 37,205 Unrecognized transition asset (73) (309) Unrecognized prior-service cost 6,710 7,816 Unrecognized net actuarial gain (13,831) (41,964) --------- -------- Net prepaid benefit cost recognized $ 7,077 $ 2,748 ========= =========
The following table provides the amounts recognized in the Consolidated Balance Sheets as of December 31:
2001 2000 ------ ------ (in thousands) Prepaid benefit cost $ 7,077 $ 2,748
The assumptions used for actuarial valuations were:
2001 2000 ------ ------ Discount rate 7.75% 7.75% Rate of increase in future compensation level 4.25% 4.25% Long-term rate of return on assets 9.50% 9.50%
Executive survivor and supplemental retirement plan--The Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees. This plan provides defined benefit payments to these employees on their retirements for life or to their beneficiaries on their death for a 15-year postretirement period. Life insurance carried on the plan participants is payable to the Company on the employee's death. There are no plan assets in this nonqualified benefit plan due to the nature of the plan. Net periodic pension cost for 2001, 2000, and 1999 includes the following components:
2001 2000 1999 ------ ------ ------ (in thousands) Service cost--benefit earned during the period $ (76) $ (136) $ (99) Interest cost on projected benefit obligation 956 798 569 Amortization of transition obligation - 17 17 Amortization of prior service cost 191 191 106 Recognized net actuarial loss 117 1 47 ------- ------- ------ Net periodic pension cost $ 1,188 $ 871 $ 640 Early retirement and curtailment -- 711 -- ------- ------- ------- Total $ 1,188 $ 1,582 $ 640 ======= ======= =======
The following tables provide a reconciliation of the changes in the plan's benefit obligations over the two-year period ending December 31, 2001 and a statement of the funded status as of December 31:
2001 2000 -------- -------- (in thousands) Reconciliation of benefit obligation: Obligation at January 1 $ 12,713 $ 10,412 Service cost (76) (136) Interest cost 956 798 Plan amendments (939) (359) Actuarial loss 2,451 1,732 Early retirement -- 711 Benefit payments (740) (445) --------- ---------- Obligation at December 31 $ 14,365 $ 12,713 ========= ========== Funded status: Funded status at December 31 $(14,365) $ (12,713) Unrecognized transition obligation -- -- Unrecognized prior-service cost 1,104 2,234 Unrecognized net actuarial loss 5,124 2,789 --------- ---------- Net amount recognized $ (8,137) $ (7,690) ========= ==========
The following table provides the amounts recognized in the Consolidated Balance Sheet as of December 31:
2001 2000 -------- -------- (in thousands) Accrued benefit liability $ (11,216) $ (10,144) Intangible asset 1,104 2,234 Accumulated other comprehensive expense 1,975 220 ---------- ---------- Net amount recognized $ (8,137) $ (7,690) ========== ==========
The assumptions used for actuarial valuations were:
2001 2000 -------- -------- Discount rate 7.75% 7.75% Rate of increase in future compensation level 4.50% 4.50%
Postretirement benefits--The Company provides a portion of health insurance and life insurance benefits for retired electric utility and corporate employees. Substantially all of the Company's electric utility and corporate employees may become eligible for health insurance benefits if they reach age 55 and have 10 years of service. On adoption of SFAS 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, in January 1993, the Company elected to recognize its transition obligation related to postretirement benefits earned of approximately $14,964,000 over a period of 20 years. There are no plan assets. The net periodic postretirement benefit cost for 2001, 2000, and 1999 includes the following components:
2001 2000 1999 ------ ------ ------ (in thousands) Service cost - benefit earned during the period $ 681 $ 688 $ 753 Interest cost on accumulated postretirement benefit obligation 1,768 1,701 1,432 Amortization of transition obligation 748 748 748 Amortization of prior service cost 111 111 111 Life insurance benefits -- 865 -- Amortization of net gain (51) -- -- ------- ------ ------ Net periodic postretirement benefit cost $3,257 $4,113 $3,044
The following tables provide a reconciliation of the changes in the plan's benefit obligations over the two-year period ending December 31, 2001 and a statement of the funded status as of December 31:
2001 2000 ------- ------- (in thousands) Reconciliation of benefit obligation: Obligation at January 1 $ 24,606 $ 20,251 Service cost 681 688 Interest cost 1,768 1,701 Actuarial loss 3,077 2,396 Benefit payments (2,264) (1,937) Life insurance benefits -- 865 Participant premium payments 682 642 --------- --------- Obligation at December 31 $ 28,550 $ 24,606 ========= ========= Funded status: Funded status at December 31 $(28,550) $(24,606) Unrecognized transition obligation 8,230 8,978 Unrecognized prior service cost 375 486 Unrecognized loss (gain) 1,304 (1,825) --------- --------- Net amount recognized $(18,641) $(16,967) ========== =========
The amounts recognized in the Consolidated Balance Sheets as of December 31:
2001 2000 ------- ------- (in thousands) Accrued benefit liability $(18,641) $ (16,967)
The assumed health-care cost-trend rate used in measuring the accumulated postretirement benefit obligation as of December 31, 2001 was 10.0 percent for 2002, decreasing linearly each successive year until it reaches 5.0 percent in 2007, after which it remains constant. The assumed discount rate used in determining the accumulated postretirement benefit obligation as of December 31, 2001 and 2000, was 7.75 for both years. Assumed health-care cost-trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health-care cost-trend rates for 2001 would have the following effects:
1 percent 1 percent increase decrease -------- -------- (in thousands) Effect on total of service and interest cost components $ 402 $ (324) Effect on the postretirement benefit obligation $3,615 $(3,011)
Leveraged employee stock ownership plan--The Company has a leveraged employee stock ownership plan for the benefit of all its electric utility and corporate employees. Contributions made by the Company were $1,100,000 for 2001, $1,130,000 for 2000, and $1,110,000 for 1999. 9. Compensating balances and short-term borrowings The Company maintains formal bank lines of credit for its electric utility operations separate from lines of credit maintained by the diversified companies. The lines of credit make available to the Company bank loans for short-term financing and provide backup financing for commercial paper notes. At December 31, 2001, the Company maintained no compensating balances to support formal bank lines of credit. The Company's bank lines of credit totaled $42,000,000, none of which was used at December 31, 2001. 10.Fair value of financial instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash and short-term investments--The carrying amount approximates fair value because of the short-term maturity of those instruments. Other investments--The carrying amount approximates fair value. A portion of other investments is in financial instruments that have variable interest rates that reflect fair value. The remainder of other investments is accounted for by the equity method which, in the case of operating losses, results in a reduction of the carrying amount. Redeemable preferred stock--The fair value is estimated based on the current rates available to the Company for the issuance of redeemable preferred stock. Long-term debt--The fair value of the Company's long-term debt is estimated based on the current rates available to the Company for the issuance of debt. About $17 million of the Company's long-term debt, which is subject to variable interest rates, approximates fair value.
2001 2000 ------------------ ------------------ (in thousands) Carrying Fair Carrying Fair amount value amount value --------- --------- --------- --------- Cash and short-term investments $ 11,378 $ 11,378 $ 1,259 $ 1,259 Other investments 18,009 18,009 17,966 17,966 Redeemable preferred stock -- -- (18,000) (18,000) Long-term debt (227,360) (255,785) (195,128) (202,942)
11. Property, plant, and equipment
2001 2000 ------- ------ (December 31, in thousands) Electric plant: Production $ 313,013 $ 310,956 Transmission 158,639 155,611 Distribution 258,774 251,753 General 80,044 77,037 --------- --------- Electric plant 810,470 795,357 Less accumulated depreciation and amortization 376,241 358,301 --------- --------- Electric plant net of accumulated depreciation 434,229 437,056 Construction work in progress 25,094 10,539 --------- --------- Net electric plant $ 459,323 $ 447,595 --------- --------- Diversified operations plant $ 145,712 $ 129,716 Less accumulated depreciation and amortization 65,622 58,118 --------- --------- Diversified plant net of accumulated depreciation 80,090 71,598 --------- --------- Construction work in progress 3,564 2,578 --------- --------- Net diversified operations plant $ 83,654 $ 74,176 --------- --------- Net plant $ 542,977 $ 521,771 ========= =========
12. Income taxes The total income tax expense differs from the amount computed by applying the federal income tax rate (35 percent in 2001, 2000 and 1999) to net income before total income tax expense for the following reasons:
2001 2000 1999 ------ ------ ------ (in thousands) Tax computed at federal statutory rate $22,290 $20,789 $24,424 Increases (decreases) in tax from: State income taxes net of federal income tax benefit 2,564 2,279 2,652 Investment tax credit amortization (1,176) (1,183) (1,185) Differences reversing in excess of federal rates (503) (774) (384) Dividend received/paid deduction (674) (670) (667) Affordable housing tax credits (1,418) (1,414) (1,393) Permanent and other differences (1,000) (672) 1,042 -------- --------- ---------- Total income tax expense $20,083 $18,355 $24,489 ======== ========= ========== Overall effective federal and state income tax rate 31.5% 30.9% 35.1% Income tax expense includes the following: Current federal income taxes $21,110 $21,835 $25,875 Current state income taxes 3,107 4,162 5,099 Deferred federal income taxes (2,247) (4,717) (3,431) Deferred state income taxes 707 (328) (476) Affordable housing tax credits (1,418) (1,414) (1,393) Investment tax credit amortization (1,176) (1,183) (1,185) -------- -------- ------- Total $20,083 $18,355 $24,489 ======== ======== ========
The Company's deferred tax assets and liabilities were composed of the following on December 31, 2001 and 2000:
2001 2000 ------ ------ (in thousands) Deferred tax assets Amortization of tax credits $ 9,098 $ 9,849 Vacation accrual 1,892 1,623 Unearned revenue 1,850 1,715 Operating reserves 13,552 12,537 Differences related to property 4,394 3,067 Transfer to regulatory liability 577 539 Other 2,025 1,642 ---------- ---------- Total deferred tax assets $ 33,388 $ 30,972 ---------- ---------- Deferred tax liabilities Differences related to property (104,764) (105,539) Excess tax over book pension (2,812) (1,113) Transfer to regulatory asset (5,053) (5,510) Other (2,330) (1,523) ---------- ---------- Total deferred tax liabilities $(114,959) $(113,685) ---------- ---------- Deferred income taxes $ (81,571) $ (82,713) ========== ==========
13. Quarterly information (unaudited) Because of changes in the number of common shares outstanding and the impact of diluted shares, the sum of the quarterly earnings per common share may not equal total earnings per common share.
Three Months Ended March 31 June 30 September 30 December 31 ----------------- ----------------- ----------------- ----------------- 2001 2000 2001 2000 2001 2000 2001 2000 ------ ------ ------ ------ ------ ------ ------ ------ (in thousands except per share data) Operating revenues $159,654 $140,227 $157,332 $141,436 $177,674 $149,999 $159,472 $155,269 Operating income $ 22,438 $ 20,789 $ 15,720 $ 17,932 $ 20,310 $ 19,796 $ 19,016 $ 15,731 Net income $ 12,000 $ 11,004 $ 9,157 $ 9,303 $ 11,077 $ 10,915 $ 11,369 $ 9,820 Earnings available for common shares $ 11,530 $ 10,534 $ 8,688 $ 8,833 $ 10,607 $ 10,446 $ 10,785 $ 9,350 Basic earnings per share $ .47 $ .43 $ .35 $ .36 $ .43 $ .43 $ .44 $ .38 Diluted earnings per share $ .47 $ .43 $ .35 $ .36 $ .43 $ .42 $ .43 $ .38 Dividends paid per common share $ .26 $ .255 $ .26 $ .255 $ .26 $ .255 $ .26 $ .255 Price range: High $ 31.00 $ 21.31 $ 30.10 $ 27.50 $ 30.00 $ 23.88 $ 29.45 $ 29.00 Low $ 23.00 $ 17.75 $ 24.12 $ 19.00 $ 26.75 $ 20.75 $ 27.50 $ 21.19 Average number of common shares outstanding--basic 24,577 24,571 24,586 24,571 24,606 24,571 24,633 24,573 Average number of common shares outstanding--diluted 24,776 24,575 24,799 24,642 24,881 24,645 24,912 24,725 -------------------------------------------------------------------------------------------------------------------------
Stock Listing Otter Tail Corporation common stock trades on The Nasdaq Stock Market.