Dailystocks.com - Ticker-based level links to all the information for the Stocks you own. Portal for Daytrading and Finance and Investing Web Sites
DailyStocks.com
What's New
Site Map
Help
FAQ
Log In
Home Quotes/Data/Chart Warren Buffett Fund Letters Ticker-based Links Education/Tips Insider Buying Index Quotes Forums Finance Site Directory
OTCBB Investors Daily Glossary News/Edtrl Company Overviews PowerRatings China Stocks Buy/Sell Indicators Company Profiles About Us
Nanotech List Videos Magic Formula Value Investing Daytrading/TA Analysis Activist Stocks Wi-fi List FOREX Quote ETF Quotes Commodities
Make DailyStocks Your Home Page AAII Ranked this System #1 Since 1998 Bookmark and Share


Welcome!
Welcome to the investing community at DailyStocks where we believe we have some of the most intelligent investors around. While we have had an online presence since 1997 as a portal, we are just beginning the forums section now. Our moderators are serious investors with MBA and CFAs with practical experience wwell-versed in fundamental, value, or technical investing. We look forward to your contribution to this community.

Recent Topics
Article by DailyStocks_admin    (02-09-09 06:16 AM)

Filed with the SEC from Jan 22 to Jan 28:

Otter Tail (OTTR)
Microsoft (MSFT) co-founder Bill Gates' investment firm boostd its stake to about 3.4 million shares (9.6%) from the 2.56 million (7.38%) it held on Sept. 30. Gates' Cascade Investment said that it expects to engage in discussions with Otter Tail's management about business and strategic direction.

BUSINESS OVERVIEW

(a) General Development of Business
Otter Tail Corporation (the Company) was incorporated in 1907 under the laws of the State of Minnesota. The Company’s executive offices are located at 215 South Cascade Street, P.O. Box 496, Fergus Falls, Minnesota 56538-0496 and 4334 18 th Avenue SW, Suite 200, P.O. Box 9156, Fargo, North Dakota 58106-9156. Its telephone number is (866) 410-8780.
The Company makes available free of charge at its internet website (www.ottertail.com) its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors and executive officers and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. Information on the Company’s website is not deemed to be incorporated by reference into this Annual Report on Form 10-K.
In the late 1980s, the Company determined its core electric business was located in a region of the country where there was little growth in the demand for electricity. In order to maintain growth for shareholders, Otter Tail Power Company (as the Company was then known) began to explore opportunities for the acquisition and long-term ownership of nonelectric businesses. This strategy has resulted in steady revenue growth over the years. In 2001, the name of the Company was changed to “Otter Tail Corporation” to more accurately represent the broader scope of electric and nonelectric operations and the name “Otter Tail Power Company” was retained for use by the electric utility. In 2007, approximately 26% of the Company’s consolidated operating revenues and approximately 45% of the Company’s consolidated income came from electric operations.
The Company’s strategy is straightforward: Reliable utility performance combined with growth opportunities at all its businesses provides long-term value. This includes growing the core electric utility business which provides a strong base of revenues, earnings and cash flows. In addition, the Company looks to its nonelectric operating companies to provide organic growth as well. Organic, internal growth comes from new products and services, market expansion and increased efficiencies. The Company expects much of the growth in the next few years will come from major capital investment at existing companies. The Company also expects to grow through acquisition and adheres to strict guidelines when reviewing acquisition candidates. The Company’s aim is to add companies that will produce an immediate positive impact on earnings and provide long-term growth potential. The Company believes owning well-run, profitable companies across different industries will bring more growth opportunities and more balance to results. In doing this, the Company also avoids concentrating business risk within a single industry. All of the operating companies operate under a decentralized business model with disciplined corporate oversight.
The Company assesses the performance of its operating companies over time, using the following criteria:
• ability to provide returns on invested capital that exceed the Company’s weighted average cost of capital over the long term; and

• assessment of an operating company’s business and potential for future earnings growth.
The Company is a committed long-term owner, and therefore does not acquire companies in pursuit of short-term gains. However, the Company will divest operating companies that do not meet these criteria over the long term.

Otter Tail Corporation and its subsidiaries conduct business in all 50 states and in international markets. The Company had approximately 4,099 full-time employees at December 31, 2007. The businesses of the Company have been classified into six segments: Electric, Plastics, Manufacturing, Health Services, Food Ingredient Processing and Other Business Operations.
• Electric (the Utility) includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota under the name Otter Tail Power Company. In addition, the Utility is an active wholesale participant in the Midwest Independent Transmission System Operator (MISO) markets. Electric utility operations have been the Company’s primary business since incorporation.
• Plastics consists of businesses producing polyvinyl chloride (PVC) and polyethylene (PE) pipe in the Upper Midwest and Southwest regions of the United States.

• Manufacturing consists of businesses in the following manufacturing activities: production of waterfront equipment, wind towers, material and handling trays and horticultural containers, contract machining, and metal parts stamping and fabrication. These businesses have manufacturing facilities in Minnesota, North Dakota, South Carolina, Missouri, California, Florida, Oklahoma and Ontario, Canada and sell products primarily in the United States.

• Health Services consists of businesses involved in the sale of diagnostic medical equipment, patient monitoring equipment and related supplies and accessories. These businesses also provide equipment maintenance, diagnostic imaging services and rental of diagnostic medical imaging equipment to various medical institutions located throughout the United States.

• Food Ingredient Processing consists of Idaho Pacific Holdings, Inc. (IPH), which owns and operates potato dehydration plants in Ririe, Idaho; Center, Colorado and Souris, Prince Edward Island, Canada. IPH produces dehydrated potato products that are sold in the United States, Canada and other countries. Approximately 31% of IPH’s sales are to customers outside of the United States.

• Other Business Operations consists of businesses in residential, commercial and industrial electric contracting industries, fiber optic and electric distribution systems, wastewater and HVAC systems construction, transportation and energy services. These businesses operate primarily in the Central United States, except for the transportation company which operates in 48 states and six Canadian provinces.
The Company’s corporate operating costs, which include corporate staff and overhead costs, the results of the Company’s captive insurance company and other items are excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets.
The Company’s electric operations, including wholesale power sales, are operated as a division of Otter Tail Corporation, and the Company’s energy services operation is operated as a subsidiary of Otter Tail Corporation. Substantially all of the other businesses are owned by the Company’s wholly-owned subsidiary, Varistar Corporation (Varistar).

The Company continues to look for strategic acquisitions of additional businesses with emphasis on adding to existing operating companies and expects continued growth in this area.
On February 19, 2007 the Company’s wholly-owned subsidiary, ShoreMaster, Inc. (ShoreMaster), acquired the assets of the Aviva Sports product line for $2.0 million in cash. The Aviva Sports product line operates under Aviva Sports, Inc. (Aviva), a newly-formed wholly-owned subsidiary of ShoreMaster. The Aviva Sports product line is sold internationally and consists of products for consumer use in the pool, lake and yard, as well as commercial use at summer camps, resorts and large public swimming pools. The acquisitions of the Aviva Sports product line fits well with the other product lines of ShoreMaster, a leading manufacturer and supplier of waterfront equipment.
On May 15, 2007 the Company’s wholly-owned subsidiary, BTD Manufacturing, Inc. (BTD), acquired the assets of Pro Engineering, LLC (Pro Engineering) for $4.8 million in cash. Pro Engineering specializes in providing metal parts stampings to customers in the Midwest. The acquisition of Pro Engineering by BTD provides expanded growth opportunities for both companies.
The Company made significant investments in its existing operating companies in 2007 in order to drive organic growth in the coming years. Capital expenditures exclusive of acquisitions totaled $162 million, including expenditures for the Utility’s portion of the Langdon Wind Project and DMI Industries, Inc.’s (DMI) wind tower manufacturing facility near Tulsa, Oklahoma.
For a discussion of the Company’s results of operations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which is incorporated by reference to pages 19 through 35 of the Company’s 2007 Annual Report to Shareholders, filed as an Exhibit hereto.
(b) Financial Information About Industry Segments
The Company is engaged in businesses that have been classified into six segments: Electric, Plastics, Manufacturing, Health Services, Food Ingredient Processing and Other Business Operations. Financial information about the Company’s segments and geographic areas is incorporated by reference to note 2 of “Notes to Consolidated Financial Statements” on pages 47 and 48 of the Company’s 2007 Annual Report to Shareholders, filed as an Exhibit hereto.

Wholesale electric energy kilowatt-hours (kWh) sales were 28.6% of total kWh sales for 2007 and 41.0% for 2006. Wholesale electric energy kWh sales decreased by 40.7% between the years while revenue per kWh increased by 11.4%. 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 in the future.
With the inception of the MISO Day 2 markets in April 2005, MISO introduced two new types of contracts, virtual transactions and Financial Transmission Rights (FTR). Virtual transactions are of two types: Virtual Demand Bid, which is a bid to purchase energy in MISO’s Day-Ahead Market that is not backed by physical load, and Virtual Supply Offer which is an offer submitted by a market participant in the Day-Ahead Market to sell energy not supported by a physical injection or reduction in withdrawals in commitment by a resource. An FTR is a financial contract that entitles its holder to a stream of payments, or charges, based on transmission congestion charges calculated in MISO’s Day-Ahead Market. A market participant can acquire an FTR from several sources: the annual or monthly FTR allocation based on existing entitlements, the annual or monthly FTR auction, the FTR secondary market or a grant of an FTR in conjunction with a transmission service request. An FTR is structured to hedge a market participant’s exposure to uncertain cash flows resulting from congestion of the transmission system. In 2007, net revenues from virtual and FTR transactions represented 0.1% of total electric energy revenues compared with 1.4% in 2006. As the MISO markets have evolved and become more efficient, profits from virtual transactions have declined.

The aggregate population of the Utility’s retail electric service area is approximately 230,000. In this service area of 423 communities and adjacent rural areas and farms, approximately 130,900 people live in communities having a population of more than 1,000, according to the 2000 census. The only communities served which have a population in excess of 10,000 are Jamestown, North Dakota (15,527); Fergus Falls, Minnesota (13,471); and Bemidji, Minnesota (11,917). As of December 31, 2007 the Utility served 129,342 customers. This is an increase of 272 customers over December 31, 2006.

The base load net plant capability for Big Stone Plant and Coyote Station constitutes the Utility’s ownership percentages of 53.9% and 35%, respectively. The Utility owns 100% of the Hoot Lake Plant.
In addition to its base load capability, the Utility has combustion turbine and small diesel units owned or under contract, used chiefly for peaking and standby purposes, with a total capability of 145,098 kilowatt (kW), hydroelectric capability of 4,338 kW and 40,500 kW of wind generation under construction as part of the Langdon Wind Project. During 2007, the Utility generated about 72% of its retail kWh sales and purchased the balance.
On March 29, 2007 the Utility and Minnkota Power Cooperative entered into an agreement with FPL Energy to develop the Langdon Wind Project, a 159 megawatt (MW) wind farm south of Langdon, North Dakota which was completed in early 2008. The Utility’s participation in the project includes the ownership of 27 wind turbines nameplate rated at 1.5 MW each and a 25-year power purchase agreement with Langdon Wind, LLC to purchase the electricity generated from 13 other wind turbines at the site. Construction of the 27 wind turbines owned by the Utility was completed in January 2008 adding approximately 12,000 kW of capacity to its net winter season generating capability and 9,000 kW of capacity to its net summer season generating capability, once all transmission arrangements are completed.
The Utility has arrangements to help meet its future base load requirements and continues to investigate other means for meeting such requirements. The Utility has an agreement to purchase 50,000 kW of year-round capacity through April 30, 2010. The Utility has agreements to purchase the output from wind generating facilities of approximately 40,500 kW (nameplate rating). The Utility has a direct control load management system which provides some flexibility to the Utility to effect reductions of peak load. The Utility, in addition, offers rates to customers which encourage off-peak usage.
The Utility traditionally experiences its peak system demand during the winter season. For the year ended December 31, 2007 the Utility experienced a system peak demand of 704,940 kW on February 2, 2007, which was also the highest all-time system peak demand (as reported to Mid-Continent Area Power Pool). Taking into account additional capacity available to it on February 2, 2007 under purchase power contracts (including short-term arrangements), as well as its own generating capacity, the Utility’s capability of then meeting system demand, excluding reserve requirements computed in accordance with accepted industry practice, amounted to 846,275 kW (804,320 kW if reserve requirements are included). The Utility’s additional capacity available under power purchase contracts (as described above), combined with generating capability and load management control capabilities, is expected to meet 2008 system demand, including industry reserve requirements.

Big Stone II
On June 30, 2005 the Utility and a coalition of six other electric providers entered into several agreements for the development of a second electric generating unit, named Big Stone II, at the site of the existing Big Stone Plant near Milbank, South Dakota. The three primary agreements are the Participation Agreement, the Operation and Maintenance Agreement and the Joint Facilities Agreement. Central Minnesota Municipal Power Agency, Great River Energy, Heartland Consumers Power District, Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc., Southern Minnesota Municipal Power Agency and Western Minnesota Municipal Power Agency are parties to all three agreements. In September 2007, Great River Energy and Southern Minnesota Municipal Power Agency withdrew from the project. The five remaining project participants decided to downsize the proposed plant’s nominal generating capacity from 630 MW to between 500 and 580 MW. New procedural schedules have been established in the various project-related proceedings, which will take into consideration the optimal plant configuration decided on by the remaining participants. NorthWestern Corporation, one of the co-owners of the existing Big Stone Plant, is an additional party to the Joint Facilities Agreement.
The Participation Agreement is an agreement to jointly develop, finance, construct, own (as tenants in common) and manage the Big Stone II Plant. The Participation Agreement includes provisions which obligate the parties to the agreement to obtain financing and pay their share of development, construction, operating and maintenance costs for the Big Stone II Plant. It also provides for the sharing of the plant output. Estimated construction costs for the plant including transmission are expected to be between $1.5 billion and $1.7 billion depending upon the size of unit constructed. The Participation Agreement provides that the Utility shall pay for and own approximately 120 MW share of the Big Stone II Plant and be entitled to a corresponding interest in the plant’s electrical output. The project participants included in the Participation Agreement a section covering withdrawal rights due to higher than anticipated project costs. Each participant has certain withdrawal rights exercisable at an agreed upon time. Under amendments to the Participation Agreement entered into in 2007, the agreed upon time is not later than 60 days after the later of receipt of i) the Minnesota Public Utilities Commission (MPUC) order regarding the Transmission Certificate of Need and ii) the Prevention of Significant Deterioration (PSD) air permit from the South Dakota Board of Minerals and Environment. The Participation Agreement establishes a Coordinating Committee and an Engineering and Operating Committee to manage the development, design, construction, operation and maintenance of the Big Stone II Plant.
The Operation and Maintenance Agreement designates the Utility as the operator of the Big Stone II Plant. As operator, the Utility is required to provide staff and resources for the development, design, financing, construction and operation of the Big Stone II Plant. The other project participants are each required to reimburse the Utility for their respective share of the costs relating to those activities. The Coordinating Committee and the Engineering and Operating Committee, which are made up of representatives of all project participants, are authorized to supervise the Utility in its role as operator.
The Joint Facilities Agreement provides for the transfer of certain real property and easements from the Big Stone I Plant owners to the Big Stone II Plant participants and for the shared use of certain equipment and facilities between the two plants. The Joint Facilities Agreement also allocates between the two plants the costs of operation and maintenance of the shared equipment and facilities.
The proposed project is intended to serve the participants’ native customer loads and is expected to be part of the Utility’s regulated rate base. The project will be nominally rated between 500 and 580 MW, and it will be coal fired. The proposed project is expected to meet air emission requirements as prescribed by the Environmental Protection Agency and the South Dakota Department of Environment and Natural Resources. Black & Veatch Corporation, a Kansas City based engineering firm, has been selected to do the plant design work and provide construction management services.

The participants have secured or are in the process of securing the permits required for construction and operation of the project, including the plant site permit, air emission permits and certificate of need and route permits for transmission. In addition, a federal environmental impact statement (EIS) is expected to yield a Record of Decision (ROD) in third quarter 2008. Applicants for all major permits have been filed and those that have not yet been acted on are scheduled for final agency action in 2008. For more information regarding the status of the permitting process, see “General Regulation” and “Environmental Regulation.” Financial close, which requires the participants to provide binding financial commitments to support their share of costs, is to occur 90 days after the EIS ROD. The financial close is not currently expected until third quarter of 2008. No one can predict the exact outcome of any of these proceedings and there have been interveners in the permitting process. If the necessary approvals are received and plans progress, groundbreaking is expected to take place in 2009 with the plant in service by 2013.
As of December 31, 2007 the Utility capitalized $8.2 million in costs related to the planned construction of Big Stone II. Should approvals of permits not be received on a timely basis, the project could be at risk. If the project is abandoned for permitting or other reasons, these capitalized costs and others incurred in future periods may be subject to expense and may not be recoverable.

CEO BACKGROUND

Name Principal Occupation Age Director Since
Nominees for election for three-year terms expiring in April 2011:



John D. Erickson
President & CEO
Otter Tail Corporation
Fergus Falls, Minnesota

Mr. Erickson serves on no Committees. 49 2007


Nathan I. Partain
President and Chief Investment Officer
Duff and Phelps Investment Management Co.
Chicago, Illinois

President, Chief Executive Officer and
Chief Investment Officer
DNP Select Income Fund, Inc.
(closed-end utility income fund)

Director, DNP Select Income Fund Inc.
Director, DTF Tax-Free Income Inc.
Director, Duff & Phelps Utility and Corporate Bond Trust Inc.

Mr. Partain serves on the Audit, Compensation,
and Executive Committees. 51 1993


James B. Stake
Retired Executive Vice President
Enterprise Services
3M Company
(diversified manufacturing)
St. Paul, Minnesota 55


Directors with terms expiring in April 2010:



Arvid R. Liebe
Retired President
Liebe Drug, Inc.
(retail business)

Owner
Liebe Farms, Inc.
Milbank, South Dakota

Mr. Liebe serves on the Compensation,
Corporate Governance, and Executive Committees. 66 1995


John C. MacFarlane
Chairman of the Board
Retired Chief Executive Officer and President
Otter Tail Corporation
Fergus Falls, Minnesota

Mr. MacFarlane serves on the Executive Committee. 68 1983


Gary J. Spies
Chairman
Service Food, Inc.
(retail business)
Fergus Falls, Minnesota

Vice President
Fergus Falls Development Company,
Midwest Regional Development Company, LLC
(land and housing development)
Fergus Falls, Minnesota

Mr. Spies serves on the Audit and
Corporate Governance Committees. 66 2001



MANAGEMENT DISCUSSION FROM LATEST 10K

The information required by this Item is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on Pages 19 through 35 of the Company’s 2007 Annual Report to Shareholders, filed as an Exhibit hereto.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

RESULTS OF OPERATIONS
Following is an analysis of our operating results by business segment for the three and nine months ended September 30, 2008 and 2007, followed by our outlook for the remainder of 2008 and a discussion of changes in our consolidated financial position during the nine months ended September 30, 2008.
Comparison of the Three Months Ended September 30, 2008 and 2007
Consolidated operating revenues were $352.9 million for the three months ended September 30, 2008 compared with $302.2 million for the three months ended September 30, 2007. Operating income was $19.7 million for the three months ended September 30, 2008 compared with $25.5 million for the three months ended September 30, 2007. The Company recorded diluted earnings per share of $0.31 for the three months ended September 30, 2008 compared to $0.44 for the three months ended September 30, 2007.
Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the three-month periods ended September 30, 2008 and 2007 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions.

The increase in retail revenues reflects $4.0 million in Minnesota and North Dakota Renewable Resource Cost Recovery Rider revenue recorded in the third quarter of 2008. The electric utility billed and accrued $3.1 million in Minnesota Renewable Resource Cost Recovery Rider revenue for recovery of the Minnesota portion of the electric utility’s renewable energy expenses and investment costs going back to January 1, 2008 as a result of the Minnesota Public Utilities Commission’s (MPUC) August 2008 approval of the electric utility’s request for a Renewable Resource Cost Recovery Rider. North Dakota Renewable Resource Cost Recovery Rider revenues billed and accrued in the third quarter of 2008 totaled $0.9 million. The North Dakota Public Service Commission (NDPSC) approved the electric utility’s request for a Renewable Resource Cost Recovery Rider in May 2008. The increase in retail revenues also includes $0.9 million attributable to an increase in Minnesota retail electric rates of approximately 2.9%, which was approved by the MPUC. These increases in retail revenues were partially offset by a decrease in revenues related to a 3.2% decrease in retail kilowatt-hour (kwh) sales resulting from a 17.3% reduction in cooling degree days between the quarters as the region experienced a milder summer in 2008 compared with summer 2007.
Wholesale electric revenues from company-owned generation were $9.1 million for the quarter ended September 30, 2008 compared with $5.7 million for the quarter ended September 30, 2007 as a result of a 37.7% increase in wholesale kwh sales combined with a 16.2% increase in the price per kwh sold. A decrease in kwhs generated to serve retail customers resulted in more generation being available to meet wholesale market demands. Plant availability, demand, load distribution and economic dispatch across the entire Midwest Independent Transmission System Operator (MISO) region are all factors that drive wholesale prices of electricity. Net gains from energy trading contracts settled decreased by $1.0 million in the third quarter of 2008 compared with the third quarter of 2007. Trading volumes were down only 1.8% but profit margins on trades decreased 59% between the quarters. Net revenue from the purchase and sale of Financial Transmission Rights increased $0.7 million between the quarters.
The $0.8 million reduction in net marked-to-market losses on forward energy contracts reflects third quarter 2007 reductions of marked-to-market gains recognized on open forward energy contracts in the first half of 2007.
Construction work completed for other entities on regional wind power projects contributed $2.6 million to the increase in other electric revenues in the third quarter of 2008 compared with the third quarter of 2007. Revenues from the sale of steam to an ethanol plant near Big Stone Plant decreased $0.4 million between the quarters as a result of the ethanol plant being shut down for maintenance in September 2008.
Production fuel costs increased 10.2% despite a 6.5% decrease in kwhs generated as a result of a 17.8% increase in the cost of fuel per kwh generated. Generation for retail sales decreased 9.4% while generation used for wholesale electric sales increased 37.7% between the quarters. The increase in fuel costs per kwh is related to higher prices for natural gas and fuel oil used to generate electricity and higher diesel fuel prices which result in increased costs to operate coal mines and to transport coal by rail. Approximately 90% of the fuel cost increases associated with generation to serve retail electric customers is subject to recovery through the Fuel Clause Adjustment (FCA) component of retail rates. The electric utility’s 27 wind turbines at the Langdon Wind Energy Center provided 3.0% of total kwh generation in the third quarter of 2008.
The increase in purchased power — system use is due to a 39.2% increase in kwhs purchased combined with a 15.6% increase in the cost per kwh purchased. The increase in the cost per kwh of purchased power reflects a general increase in fuel and purchased power costs across the Mid-Continent Area Power Pool region as a result of higher fuel prices in the third quarter of 2008 compared with the third quarter of 2007.
The increase in other operating and maintenance expenses between the quarters includes: (1) a $2.3 million increase in costs related to contracted construction work completed for other entities on regional wind projects, (2) the recognition of $1.5 million in expenses recoverable through the Minnesota Resource Cost Recovery Rider that had been deferred in the first six months of 2008 pending approval of the rider in the third quarter of 2008, (3) $1.4 million in increased wage and benefit expenses, and (4) a $0.3 million increase in software licensing expenses.
Depreciation expenses increased as a result of recent capital additions, including 27 new wind turbines at the Langdon Wind Energy Center.

Operating revenues for the plastics segment decreased as result of a 10.9% decrease in pounds of pipe sold, mostly offset by an 11.4% increase in the price per pound of pipe sold. The increase in cost of goods sold reflects a 15.6% increase in resin prices per pound of pipe sold. The decrease in operating expenses reflects a decrease in bonus incentives directly related to decreased sales and profits in the nine months ended September 30, 2008 compared with the nine months ended September 30, 2007.

Revenues from scanning and other related services were down $0.1 million as the imaging side of the business continued to be affected by less than optimal utilization of certain imaging assets. Revenues from equipment sales and servicing were also down $0.1 million between the quarters. The increase in cost of goods sold is mainly due to increases in repair and maintenance and other equipment operating costs on the imaging side of the business. The decrease in operating expenses includes a $0.6 million gain on the sale of a portable imaging business in Wisconsin in the third quarter of 2008 and a $0.4 million decrease in sales and marketing expenses between the quarters.

The decrease in revenues in the food ingredient processing segment is due to a 4.8% decrease in pounds of product sold, partially offset by a 2.5% increase in the price per pound of product sold. Lower production caused by potato supply shortages at the end of the 2007 crop and a late harvest of the 2008 crop increased overhead costs per unit of sales. These supply constraints, combined with energy costs rising at rates faster than could be passed through to customers, increased costs and lowered profits on products sold in the third quarter of 2008. The decrease in operating expenses reflects a decrease in bonus incentives directly related to decreased sales and gross margins in 2008 compared with 2007. The increase in depreciation and amortization expense between the quarters is due to recent capital additions.

The change in corporate operating expenses includes increases in stock-based compensation, benefit expenses, software licensing and maintenance expenses and increases in outside professional service costs related to the formation of a holding company.
Interest Charges
Interest charges increased $2.3 million in the third quarter of 2008 compared with the third quarter of 2007 as a result of increases in average long-term and short-term debt outstanding between the quarters along with higher borrowing rates on short-term debt.
Other Income
The $0.5 million increase in other income was mainly due to an increase in the allowance for equity funds used in construction at the electric utility in the third quarter of 2008 compared with the third quarter of 2007. The electric utility recorded no allowance for equity funds used in construction in the third quarter of 2007 because its average balance of construction work in progress was less than average short-term borrowings during the quarter.
Income Taxes
The $3.9 million (49.4%) decrease in income taxes between the quarters is primarily due to a $7.6 million (35.8%) decrease in income before income taxes for the three months ended September 30, 2008 compared with the three months ended September 30, 2007. Federal production tax credits of $0.6 million and North Dakota wind tax credits of $0.1 million recorded in the third quarter of 2008 related to the electric utility’s new wind turbines also contributed to the reduction in taxes between the quarters. Also, the allowance for equity funds used during construction at the electric utility is not subject to income tax expense.

Comparison of the Nine Months Ended September 30, 2008 and 2007
Consolidated operating revenues were $976.8 million for the nine months ended September 30, 2008 compared with $909.2 million for the nine months ended September 30, 2007. Operating income was $47.1 million for the nine months ended September 30, 2008 compared with $76.6 million for the nine months ended September 30, 2007. The Company recorded diluted earnings per share of $0.69 for the nine months ended September 30, 2008 compared to $1.31 for the nine months ended September 30, 2007.
Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the nine-month periods ended September 30, 2008 and 2007 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions.

The increase in retail revenues reflects $5.5 million in Minnesota and North Dakota Renewable Resource Cost Recovery Rider revenue. In the third quarter of 2008, the electric utility billed and accrued $3.1 million in Minnesota Renewable Resource Cost Recovery Rider revenue for recovery of the Minnesota portion of the electric utility’s renewable energy expenses and investment costs going back to January 1, 2008 as a result of the MPUC’s August 2008 approval of the electric utility’s request for a Renewable Resource Cost Recovery Rider. The increase in retail revenues also includes $2.6 million attributable to an increase in Minnesota retail electric rates of approximately 2.9%, which was approved by the MPUC. The remaining $4.6 million increase in retail revenues was due to a 2.8% increase in retail kwh sales resulting from colder weather in the first six months of 2008, when heating degree days were 11.4% higher than in the first six months of 2007.

Wholesale electric revenues from company-owned generation were $18.2 million for the nine months ended September 30, 2008 compared with $15.2 million for the nine months ended September 30, 2007. The increase reflects a 25.9% increase in wholesale kwh sales, partially offset by a 5.1% reduction in the price per kwh sold. A 5.3% increase in kwhs generated from company-owned resources resulted in more generation being available to meet wholesale market demands. Plant availability, demand, load distribution and economic dispatch across the entire MISO region are all factors that drive wholesale prices of electricity. Net gains from energy trading contracts settled in the first nine months of 2008 were $1.5 million compared with $2.5 million in the first nine months of 2007. Trading volumes were higher but profit margins on trades were significantly lower between the periods. Trading volumes were up 42.8% but profit margins on trades decreased 88% between the periods. Net revenue from the purchase and sale of Financial Transmission Rights increased $1.9 million between the quarters.
The $0.4 million decrease in net marked-to-market gains on forward energy contracts reflects lower margins on trades in the first nine months of 2008 compared with the first nine months of 2007.
Construction work performed for other entities on regional wind power projects contributed $1.7 million to the increase in other electric revenues. MISO tariff revenues increased $0.4 million between the periods.
The increase in fuel costs reflects a 10.4% increase in the cost of fuel per kwh generated combined with a 1.9% increase in kwhs generated at fuel-burning plants. The increase in fuel costs per kwh is directly related to higher diesel fuel prices which result in increased costs to operate coal mines and to transport coal by rail. Approximately 90% of the fuel cost increases associated with generation to serve retail electric customers is subject to recovery through the FCA component of retail rates. The electric utility’s 27 new wind turbines at the Langdon Wind Energy Center provided 3.2% of total kwh generation in the first nine months of 2008.
The decrease in purchased power – system use is due to a 12.8% reduction in kwhs purchased partially offset by a 4.3% increase in the cost per kwh purchased. The decrease in kwh purchases for system use was directly related to the increase in kwhs generated at company-owned plants. The increase in the cost per kwh of purchased power reflects a general increase in fuel and purchased power costs across the Mid-Continent Area Power Pool region as a result of higher demand due to colder weather in the first six months of 2008 compared with the first six months of 2007 and increased generation costs mainly due to higher fuel prices.
The increase in other operating and maintenance expenses between the periods includes: (1) $2.0 million for Hoot Lake unit 2 turbine repairs and boiler maintenance in 2008, (2) a $1.6 million increase in costs related to contracted construction work completed for other entities on regional wind projects, (3) $0.8 million in increased wage and benefit expenses, (4) $0.8 million for boiler washes at Big Stone Plant and Coyote Station in 2008, (5) $0.4 million in expenses associated with the Langdon Wind Center operating and maintenance agreement, (6) a $0.4 million increase in storm repair and tree-trimming expenses, (7) a $0.3 million increase in software licensing expenses, (8) a $0.2 million increase in bad debt expenses, and (9) a $0.2 million increase in Big Stone Plant legal costs.
Depreciation expenses increased as a result of recent capital additions, including 27 new wind turbines at the Langdon Wind Energy Center.

Operating revenues for the plastics segment decreased mainly as result of a 17.8% decrease in pounds of pipe sold, partially offset by a 6.2% increase in the price per pound of pipe sold between the periods. The decrease in pounds of pipe sold was due to softening in the construction markets served by this segment, which was expected. The decrease in cost of goods sold was directly related to the decrease in pounds of pipe sold. However, the cost per pound of pipe sold increased 14.2% due to higher resin prices, resulting in a 30.2% decline in gross margins per pound of pipe sold. The decrease in operating expenses reflects a decrease in bonus incentives directly related to decreased sales and profits in the nine months ended September 30, 2008 compared with the nine months ended September 30, 2007.

The decrease in revenues in the food ingredient processing segment is due to an 18.1% decrease in pounds of product sold, partially offset by a 7.4% increase in the price per pound of product sold. Cost of goods sold decreased as a result of the decrease in sales, partially offset by a 14.1% increase in the cost per pound of product sold. The decrease in product sales was due to a reduction in sales to European customers and major snack customers and due to lower production caused by potato supply shortages at the end of the 2007 crop and a late harvest of the 2008 crop. European sales were higher than normal in 2007 due to reduced crop yields in Europe in 2006. The increase in the cost per pound of product sold between the periods is mainly due to higher fuel oil and natural gas prices and production decreases related to potato supply shortages which resulted in higher overhead absorption costs in the third quarter of 2008. The decrease in operating expenses reflects a decrease in bonus incentives directly related to decreased sales and gross margins in 2008 compared with 2007. The increase in depreciation and amortization expense between the periods is due to recent capital additions.

The change in corporate operating expenses includes increases in stock-based compensation, increases in outside professional services mainly related to the formation of a holding company, increases in claim loss provisions at our captive insurance company and increases in software licensing and maintenance expenses. Corporate expenses in 2007 included a $0.6 million gain on disposal of assets.
Interest Charges
Interest charges increased $6.2 million in the first nine months of 2008 compared with the first nine months of 2007 as a result of increases in both average long-term debt outstanding and average short-term debt outstanding between the periods along with higher borrowing rates on short-term debt.
Other Income
The $1.5 million increase in other income was mainly due to an increase in the allowance for equity funds used in construction at the electric utility in the first nine months of 2008 compared with the first nine months of 2007. The electric utility recorded no allowance for equity funds used in construction in the first nine months of 2007 because its average balance of construction work in progress was less than average short-term borrowings during the same period.
Income Taxes
The $15.7 million (67.7%) decrease in income taxes between the periods is primarily the result of a $34.1 million (54.2%) decrease in income before income taxes for the nine months ended September 30, 2008 compared with the nine months ended September 30, 2007. Federal production tax credits of $1.9 million and North Dakota wind tax credits of $0.2 million recorded in the first nine months of 2008 related to the electric utility’s new wind turbines also contributed to the reduction in taxes between the periods. Also, the allowance for equity funds used during construction at the electric utility is not subject to income tax expense.

2008 EXPECTATIONS
The statements in this section are based on our current outlook for 2008 and are subject to risks and uncertainties given current global economic conditions and the other risk factors outlined under “Forward Looking Information – Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995.”
We have revised our 2008 earnings guidance to be in a range of $1.05 to $1.30 per diluted share from our previously announced range of $1.25 to $1.50. Contributing to the revised earnings guidance for 2008 are the following items:
• We continue to expect increased levels of net income from our electric segment in 2008, but to a lesser degree due to milder weather conditions in the third quarter and early fourth quarter, an unscheduled outage at Hoot Lake Plant Unit 2 late in the third quarter and the impact of lower forward energy prices on asset-based wholesale margins. The increase is attributable to the 2.9% rate increase granted in Minnesota and rate riders for wind energy in North Dakota and Minnesota. The increase also results from having lower-cost generation available for the year, as there have been no major shutdowns of Big Stone Plant or Coyote Station in 2008.
• We expect our plastics segment’s 2008 performance to be below normal levels as this segment continues to be impacted by the sluggish housing and construction markets. Also, announced reductions in polyvinyl chloride (PVC) resin prices in October 2008 are expected to negatively impact PVC pipe prices, profit margins on PVC pipe sales and the value of PVC pipe held in inventory. Announced capacity expansions are not expected to have a material impact on 2008 results.
• We expect a further decrease in net income in our manufacturing segment in 2008. Increased capacity related to recent expansions and acquisitions as well as the start-up of DMI’s wind tower manufacturing plant in Oklahoma in 2008 are expected to result in increased levels of revenue. DMI is investing in new facilities and incurring costs related to starting up and expanding facilities as well as integrating new customers in order to prepare for the anticipated growth in the wind industry subsequent to 2008. This is expected to result in a decrease in net income in 2008 compared with 2007. Also, for ShoreMaster the continuing impact of a softening economy on its residential business and limited access to credit markets for customers to finance construction of commercial projects is expected to cause a further decrease in net income for our manufacturing segment in 2008. Backlog in place on September 30, 2008 in our manufacturing segment to support revenues for the remainder of 2008 is approximately $131 million. This compares with $95 million in revenue earned in the fourth quarter of 2007. DMI accounts for a substantial portion of the 2008 backlog.
• We expect a further decline in net income from our health services segment in 2008 due to lower utilization levels of certain imaging assets and cancellation of equipment orders by hospitals that were expected to occur in 2008 but have been either completely cancelled or delayed into 2009 due to concerns over the weakening economy and limited access to credit markets to finance equipment purchases.
• We expect a significant reduction in net income from our food ingredient processing business in 2008 as a result of higher natural gas and fuel oil prices during the first three quarters and reductions in raw potato supplies which are expected to lower sales volumes for the rest of 2008.
• We expect our other business operations segment to have higher net income in 2008 compared with 2007. Backlog for the construction businesses at the end of the third quarter of 2008 was approximately $48 million for the remainder of 2008 compared with $51 million in revenue in the fourth quarter of 2007.
• We expect corporate general and administrative costs to increase in 2008.

FINANCIAL POSITION
For the period 2008 through 2012, we estimate funds internally generated net of forecasted dividend payments will be sufficient to repay a portion of currently outstanding short-term debt or to finance a portion of current capital expenditures. Reduced demand for electricity, reductions in wholesale sales of electricity or margins on wholesale sales, or declines in the number of products manufactured and sold by our companies could have an effect on funds internally generated. Additional equity or debt financing will be required in the period 2008 through 2012 to finance the expansion plans of our electric segment, to reduce borrowings under our lines of credit, including borrowings used to finance DMI’s plant addition in Oklahoma and BTD’s acquisition of Miller Welding, to refund or retire early any of our presently outstanding debt or cumulative preferred shares, to complete acquisitions or for other corporate purposes. There can be no assurance, especially given the current disruptions in global financial markets, 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 us. If adequate funds are not available on acceptable terms, our businesses, results of operations and financial condition could be adversely affected.
On April 30, 2008 Otter Tail Power Company announced plans to invest $121 million related to the construction of 48 megawatts of wind energy generation at the Ashtabula Wind Center site in Barnes County, North Dakota, with an expected completion date in late 2008. Otter Tail Power Company’s participation in the proposed project includes the ownership of 32 wind turbines rated at 1.5 megawatts each. Contracts related to construction of the 32 wind towers and turbines to be owned by Otter Tail Power Company increased our 2008 purchase obligations by $121 million.
In September 2008, we completed a public offering of 5,175,000 common shares under our universal shelf registration statement filed with the Securities and Exchange Commission, including 675,000 common shares issued pursuant to the full exercise of the underwriters’ overallotment option. The public offering price was $30 per share. Net proceeds from the sale of the common shares after deducting underwriting discounts and commissions and offering expenses were $149.1 million. The net proceeds will be used to finance the construction of Otter Tail Power Company’s 32 wind turbines and collector system at the Ashtabula Wind Center in Barnes County, North Dakota and the expansion of DMI’s wind tower manufacturing facilities in Tulsa, Oklahoma and West Fargo, North Dakota.
Our wholly owned subsidiary, Varistar Corporation (Varistar), has a $200 million credit agreement (the Varistar Credit Agreement) with the following banks: U.S. Bank National Association, as agent for the Banks and as Lead Arranger, Bank of America, N.A., Keybank National Association, and Wells Fargo Bank, National Association, as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., Bank of the West and Union Bank of California, N.A. The Varistar Credit Agreement is an unsecured revolving credit facility that Varistar can draw on to support its operations. The Varistar Credit Agreement expires on October 2, 2010. Borrowings under the line of credit bear interest at LIBOR plus 1.75%, subject to adjustment based on Varistar’s adjusted cash flow leverage ratio (as defined in the Varistar Credit Agreement). The Varistar Credit Agreement contains a number of restrictions on the businesses of Varistar and its material subsidiaries, including restrictions on their ability to merge, sell assets, incur indebtedness, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Varistar Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Varistar’s obligations under the Varistar Credit Agreement are guaranteed by each of its material subsidiaries. Outstanding letters of credit issued by Varistar can reduce the amount available for borrowing under the line by up to $30 million. As of September 30, 2008, $112.0 million of the $200 million line of credit was in use and $15.0 million was restricted from use to cover outstanding letters of credit.
On July 30, 2008 Otter Tail Corporation, dba Otter Tail Power Company replaced its credit agreement with U.S. Bank National Association, which provided for a $75 million line of credit, with a new credit agreement providing for a $170 million line of credit with an accordion feature whereby the line can be increased to $250 million as described in the new credit agreement. The prior credit agreement was subject to renewal on September 1, 2008. The new credit agreement (the Electric Utility Credit Agreement) is between Otter Tail Corporation, dba Otter Tail Power Company and JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association and Merrill Lynch Bank USA, as Banks, U.S Bank National Association, as a Bank and as agent for the Banks, and Bank of America, N.A., as a Bank and as Syndication Agent. The Electric Utility Credit Agreement is an unsecured revolving credit facility that the electric utility can draw on to support the working capital needs and other capital requirements of its operations. Borrowings under this line of credit bear interest at LIBOR plus 0.5%, subject to adjustment based on the ratings of the Company’s senior unsecured debt. The Electric Utility Credit Agreement contains a number of restrictions on the business of the electric utility, including restrictions on its ability to merge, sell assets, incur indebtedness, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The Electric Utility Credit Agreement is subject to renewal on July 30, 2011. As of September 30, 2008, no amounts were borrowed under this line of credit.
Each of our Cascade Note Purchase Agreement, our 2007 Note Purchase Agreement and our 2001 Note Purchase Agreement states we may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. Each of the Cascade Note Purchase Agreement and the 2001 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require us to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the respective note purchase agreements. The 2007 Note Purchase Agreement states we must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of the Company.
The 2001 Note Purchase Agreement, the 2007 Note Purchase Agreement and the Cascade Note Purchase Agreement contain a number of restrictions on us and our subsidiaries. In each case these include restrictions on our ability and the ability of our subsidiaries to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties.
The Electric Utility Credit Agreement, the 2001 Note Purchase Agreement, the Cascade Note Purchase Agreement, the 2007 Note Purchase Agreement, the Lombard US Equipment Finance note and the financial guaranty insurance policy with Ambac Assurance Corporation relating to our pollution control refunding bonds contain covenants by us not to permit our debt-to-total capitalization ratio to exceed 60% or permit our interest and dividend coverage ratio (or in the case of the Cascade Note Purchase Agreement, our interest coverage ratio) to be less than 1.5 to 1. The note purchase agreements further restrict us from allowing our priority debt to exceed 20% of total capitalization. Financial covenants in the Varistar Credit Agreement require Varistar to maintain a fixed charge coverage ratio of not less than 1.25 to 1 and to not permit its cash flow leverage ratio to exceed 3.0 to 1. We were in compliance with all of the covenants under our financing agreements as of September 30, 2008.
Our obligations under the 2001 Note Purchase Agreement and the Cascade Note Purchase Agreement are guaranteed by certain of our subsidiaries. Varistar’s obligations under the Varistar Credit Agreement are guaranteed by each of its material subsidiaries.

On September 26, 2008 Standard and Poor’s Ratings Services lowered its corporate credit rating and senior unsecured debt rating on the Company from BBB+ to BBB- and changed its outlook from negative to stable, citing a growing appetite for non-utility businesses in combination with expected credit measures that are more consistent with the BBB- rating and expected cash flow constraints given current economic indicators. Our disclosure of these securities ratings is not a recommendation to buy, sell or hold our securities. This and any future downgrade in our securities ratings could increase our borrowing costs resulting in possible reductions to net income in future periods and increase the risk of default on our debt obligations.
In March 2008, DMI entered into a three-year $40 million receivable purchase agreement whereby designated customer accounts receivable may be sold to General Electric Capital Corporation on a revolving basis. Accounts receivable totaling $90.9 million have been sold in 2008. Discounts of $0.5 million for the nine months ended September 30, 2008 were charged to operating expenses in the consolidated statements of income. The balance of receivables sold that were still outstanding to the buyer as of September 30, 2008 was $22.7 million. In compliance with Statement of Financial Accounting Standards (SFAS) No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities , sales of accounts receivable are reflected as a reduction of accounts receivable in the consolidated balance sheets and the proceeds are included in the cash flows from operating activities in the consolidated statements of cash flows.
In December 2007, ShoreMaster entered into an agreement with GE Commercial Distribution Finance Corporation (CDF) to provide floor plan financing for certain dealer purchases of ShoreMaster products. Financings under this agreement began in 2008. This agreement improves our liquidity by financing dealer purchases of ShoreMaster’s products without requiring substantial use of working capital. ShoreMaster is paid by CDF shortly after product shipment for purchases financed under this agreement. The floor plan financing agreement requires ShoreMaster to repurchase new and unused inventory repossessed by CDF to satisfy the dealer’s obligations to CDF under this agreement. ShoreMaster has agreed to unconditionally guarantee to CDF all current and future liabilities which any dealer owes to CDF under this agreement. Any amounts due under this guaranty will be payable despite impairment or unenforceability of CDF’s security interest with respect to inventory that may prevent CDF from repossessing the inventory. The aggregate total of amounts owed by dealers to CDF under this agreement was $3.5 million on September 30, 2008. ShoreMaster has incurred no losses under this agreement. We believe current available cash and cash generated from operations provide sufficient funding in the event there is a requirement to perform under this agreement.
As part of its marketing programs ShoreMaster pays floor plan financing costs of its dealers for CDF financed purchases of ShoreMaster products for certain set time periods based on the timing and size of a dealer’s order.
Cash provided by operating activities was $40.2 million for the nine months ended September 30, 2008 compared with cash provided by operating activities of $57.3 million for the nine months ended September 30, 2007. The $17.1 million decrease in cash from operating activities includes an $18.5 million decrease in net income, and a $9.4 million increase in cash used for working capital items from $26.3 million in the first nine months of 2007 to $35.7 million in the first nine months of 2008, offset by an $8.2 million increase in noncash depreciation expense and a $2.0 million reduction in discretionary cash contributions to our pension fund.
Major uses of funds for working capital items in the first nine months of 2008 were an increase in receivables of $24.3 million, an increase in inventories of $9.1 million and an increase in other current assets of $8.2 million, partially offset by an increase in payables and other current liabilities of $5.0 million. The $24.3 million increase in receivables includes: (1) $14.4 million at the electric utility as a result of increases in wholesale sales and energy trading volumes in 2008, higher energy bills related to recently approved resource recovery riders and billings for increased levels of contracted construction work for other entities, and (2) $9.4 million at Foley Company related to an increase in the number and size of jobs in progress in 2008. The $9.1 million increase in inventories is mainly related to a buildup of inventory at our plastic pipe companies as a result of recent declines in sales combined with the effect of higher PVC resin prices on raw material and finished goods inventory. The $8.2 million increase in other current assets includes: (1) an $18.4 million increase in costs in excess of billings, mainly at DMI, as a result of increased production activity, (2) a $4.3 million increase in prepaid expenses across all companies related to the timing of 2008 annual insurance premiums and other payments, and (3) a $3.9 million increase in income taxes receivable, offset by (4) an $18.3 million decrease in accrued utility revenues related to a decrease in unbilled revenue due to milder weather in September 2008 compared to December 2007. The $5.0 million increase in payables and other current liabilities is mainly due to a $4.5 million increase in accounts payable and billings in excess of costs at Foley Company related to increased levels of jobs in progress.
Net cash used in investing activities was $206.9 million for the nine months ended September 30, 2008 compared with $103.7 million for the nine months ended September 30, 2007. Cash used for capital expenditures increased by $72.8 million between the periods. Cash used for capital expenditures at the electric utility increased by $67.6 million, mainly due to payments for assets at the Langdon Wind Energy Center and the Ashtabula Wind Center. Cash used for capital expenditures at Northern Pipe Products, Inc. increased $3.0 million related to the installation of a new PVC pipe extrusion line at their Hampton, Iowa plant. Cash used for capital expenditures increased by $2.3 million in our food ingredient processing segment related to the expansion of a warehouse at the Center, Colorado plant. We paid $41.7 million in cash to acquire Miller Welding in May 2008. We completed two acquisitions during the first nine months of 2007 for a combined purchase price of $6.8 million.
Net cash provided by financing activities was $144.2 million for the nine months ended September 30, 2008 compared with $43.0 million for the nine months ended September 30, 2007. Proceeds from the issuance of common stock, net of issuance expenses, were $156.8 million in the first nine months of 2008 compared with $7.6 million in the first nine months of 2007. We issued 5,175,000 common shares in a public offering in September 2008. During the first nine months of 2008, 276,535 common shares were issued for stock options exercised compared with 293,382 common shares issued for stock options exercised in the first nine months of 2007. Proceeds from the issuance of long-term debt were $1.1 million in the first nine months of 2008 compared with $25.1 million in the first nine months of 2007. Proceeds from short-term borrowings were $17.0 million in the first nine months of 2008 compared with proceeds from short-term borrowings of $39.9 million in the first nine months of 2007. Dividends paid on common and preferred shares in the first nine months of 2008 were $27.4 million compared with $26.6 million in the first nine months of 2007. The increase in dividend payments is due to a 1.5 cent per share increase in common dividends paid and an increase in common shares outstanding between the periods.


SHARE THIS PAGE:  Add to Delicious Delicious  Share    Bookmark and Share



 
Icon Legend Permissions Topic Options
You can comment on this topic
Print Topic

Email Topic

832 Views