Black Hills Power Files for Interim Electric Rate Increase for South Dakota Customers Effective April 1, 2010(03/01/2010)  Back to Table of Contents

RAPID CITY, SD, Mar. 1, 2010 - Black Hills Corp. (NYSE:BKH) subsidiary Black Hills Power made a filing today with the South Dakota Public Utilities Commission requesting interim rates be implemented for electricity service on and after April 1, 2010. The Black Hills Power filing proposes an interim rate increase of $24 million, or approximately 20 percent, for South Dakota electric utility customers. A typical Black Hills Power South Dakota residential customer using 600 kilowatt-hours of power each month will see an interim increase of $12.18 per month, or about 40¢ per day. The interim rate increase will be included in customer bills beginning in April 2010, subject to adjustment once a final order pertaining to Black Hills Power's South Dakota rate request is received from the South Dakota Public Utilities Commission.

"Although we continue to work towards resolution of our rate request filed on September 30, 2009, we do not anticipate receiving a final order from the South Dakota Public Utilities Commission by April 1, 2010. In the event the Commission does not complete its review and issue a final order within six months, South Dakota law allows investor owned utilities to change customer rates on an interim basis, subject to adjustment once a final order is received," said Chuck Loomis, vice president, operations for Black Hills Power. "The implementation of interim rates on April 1, 2010 coincides with the expected commercial operation of the Wygen III generation facility, constructed to serve the growing electricity demand of our Black Hills customers," continued Loomis.

On Sept. 30, 2009, Black Hills Power filed a request for an electric revenue increase with the South Dakota Public Utilities Commission to recover costs associated with the Wygen III power plant located near Gillette, Wyo., and other generation, transmission and distribution assets and increased operating expenses. In its original application, Black Hills Power requested a $32 million increase in annual utility revenues, or approximately 26.6 percent, to be effective on April 1, 2010.

"We understand that any rate increase is difficult for our customers and we want to ensure the interim rates implemented use the best information possible," said Loomis. "As is typical in a regulatory process that extends over a 6 month period or more - following a filing the utility continues operating and there are known and measurable costs that change, and in this case have reduced, the amount requested in Black Hills Power's original application," concluded Loomis.

Black Hills Power's last base rate increase was based on 2005 costs and became effective in January 2007. For more detailed information, you can view Black Hills Power's complete September 30, 2009 rate request at the South Dakota Public Utilities Commission's Web site puc.sd.gov/Dockets/Electric/2009/default.aspx.

MDU Resources pipeline subsidiary announces enhancement plans for storage and pipeline(02/16/2010)  Back to Table of Contents

BISMARCK, N.D. - February 16, 2010 - Williston Basin Interstate Pipeline Company, the wholly owned natural gas transmission pipeline subsidiary of MDU Resources, announced plans to increase firm deliverability from its existing Baker storage facility in southeastern Montana. In conjunction with the storage enhancement, Williston Basin also announced plans to expand its existing natural gas pipeline system from the Baker storage facility to western North Dakota, where it connects with the Northern Border Pipeline.

The proposed storage enhancement would add up to 125 million cubic feet per day (MMcf/d) to existing firm storage deliverability volumes from the Baker storage facility. The storage project will be accomplished by drilling new storage wells, adding compression and replacing and looping existing storage gathering pipelines. The associated pipeline expansion will require new compression as well as looping of existing pipelines between Baker and Northern Border Pipeline. The project cost is expected to be in the range of $100 - $130 million, and the targeted in-service date is April 2012.

The Baker storage facility has a current firm withdrawal capacity of 115 MMcf/d. The proposed enhancement project will more than double firm deliverability from the Baker field, bringing the total to 240 MMcf/d. The ultimate size of the storage and pipeline expansion projects will depend on shipper interest.

A binding open season for the Baker storage enhancement and associated pipeline expansion will begin on February 16, 2010, and will run through March 18, 2010. Open season documents will be available on Williston Basin's Web site at www.wbip.com.

"Usage of our storage facilities reached record levels in 2009 and we are currently sold out of firm storage capacity so this is an excellent time to move forward with an enhancement of our Baker storage field," said Steven L. Bietz, president and chief executive officer of Williston Basin Interstate Pipeline Company. "We feel confident that increasing the firm storage deliverability at our Baker facility, along with associated firm pipeline capacity to Northern Border, will be well received by both existing and potential new customers."

Williston Basin's Baker storage field is the largest natural gas storage field in North America. It is one of three storage fields owned and operated by Williston Basin. The total working gas capacity of the three fields is 193 Bcf.

NorthWestern Corporation Financial Results - December 31, 2009(02/12/2010)  Back to Table of Contents

NorthWestern Corporation d/b/a NorthWestern Energy (NYSE: NWE) reported financial results for the year ended Dec. 31, 2009.

Click here - Financial Results - to view as a PDF file.

MDU Resources Declares Quarterly Dividends on Common and Preferred Stock(02/11/2010)  Back to Table of Contents

BISMARCK, N.D. - Feb. 11, 2010 - The MDU Resources Group, Inc. (NYSE: MDU) Board of Directors today declared quarterly dividends on the company's common and preferred stock.

The dividend for common stock is 15.75 cents per share, unchanged from the previous quarter. Dividends for preferred stock are:

The dividends are payable April 1, 2010, to stockholders of record March 11, 2010.

Otter Tail Corporation Reports 2009 Financial Results and Issues 2010 Earnings Guidance; Board Declares Quarterly Dividend(02/09/2010)  Back to Table of Contents

FERGUS FALLS, Minn., Feb. 8, 2010 (GLOBE NEWSWIRE) -- Otter Tail Corporation (Nasdaq:OTTR) today announced financial results for the fourth quarter and year ended December 31, 2009.

2009 Summary:

• Diluted earnings per share were $0.71 compared with $1.09 in 2008.
• Consolidated revenues decreased to $1.0 billion from a record $1.3 billion in 2008.
• Consolidated net income was $26.0 million compared with $35.1 million in 2008.
• Operating cash flow increased 46.2% to a record $162.7 million compared with $111.3 million in 2008.
• Electric segment net income increased 2.5% to $34.1 million.
• Food Ingredient Processing segment net income reached a record $7.4 million.
• The corporation maintains a strong balance sheet, capital structure and liquidity position.

CEO Overview

"2009 proved to be a difficult year and our financial results reflect that reality," said John Erickson, president and chief executive officer of Otter Tail Corporation. "We are pleased, however, with how our company adapted to the realities of the economy. We preserved our core strengths and continued to be disciplined in investing for the opportunities that lie ahead. While the impact of the recession was widespread, affecting nearly all of our operating companies, we are encouraged that our food ingredient processing segment posted record net income in 2009 and that net income from Otter Tail Power Company, our core electric business, also increased in 2009. In addition, Otter Tail Power Company invested $100 million in another major wind energy project with the construction of 49.5 megawatts of generating capacity at the Luverne Wind Farm in eastern North Dakota."

Erickson continued, "Signs of economic recovery are mixed and we expect 2010 will be another challenging year, requiring continued discipline on managing costs and capital expenditures. Despite this economic uncertainty, our current estimate of 2010 earnings is in the range of $1.00 to $1.40 per diluted share, considerably better than our 2009 results. We emerge from a difficult year as a more efficient organization with a healthy balance sheet and a strong capital structure and liquidity position."

Liquidity and Cash Flow from Operations

In 2009, the corporation's cash flow from operations increased 46.2% to a record $162.7 million compared with $111.3 million in 2008. The $51.4 million increase in cash from operating activities reflects a $45.2 million increase in cash from working capital items between the years.

As of December 31, 2009, Otter Tail Corporation and Otter Tail Power Company (OTP) had $347.5 million available under existing credit facilities to provide for working capital requirements and help fuel future growth initiatives. In December 2009, the corporation issued $100 million of its 9.000% Notes due 2016 and used the net proceeds to repay borrowings under the Otter Tail Corporation credit facility. In January 2010, OTP paid off the remaining $58 million balance outstanding on its two-year, $75 million term loan, originally due on May 20, 2011, using lower cost funds available under the OTP credit facility.

2010 Dividend Declared

On February 8, 2010 the Board of Directors declared a quarterly common stock dividend of $0.2975 per share. This dividend is payable March 10, 2010 to shareholders of record on February 15, 2010. The Board's dividend decision reflects the corporation's financial strength, commitment to the dividend and confidence in the future, while exhibiting prudence given the difficult economic times. Our expectation, based on our strategic plan, is that our ratio of dividends to earnings will decline over time as our operating results improve. The corporation has paid dividends without interruption since 1938.

The Board also declared quarterly dividends on the corporation's four series of preferred stock, payable March 1, 2010 to shareholders of record on February 15, 2010.

Segment Performance Summary

Electric

Electric segment revenues and net income were $314.6 million and $34.1 million, respectively, in 2009 compared with $340.0 million and $33.2 million in 2008. The decrease in electric revenues was due to decreases in wholesale electricity sales and prices, less contract work performed for other entities in 2009 and lower fuel and purchased power prices resulting in a reduction in revenues related to the recovery of fuel and purchased power costs.

Wholesale electric revenues from company-owned generation were $12.6 million in 2009 compared with $23.7 million in 2008. The decrease in wholesale electric revenues resulted from a 14.8% decrease in wholesale kilowatt-hour (kwh) sales due to lower wholesale demand and reduced plant availability, combined with a 37.7% decrease in revenue per kwh sold due to lower wholesale prices. Other electric operating revenues decreased $8.4 million, mainly as a result of a decrease in revenues from construction and permitting work completed for other entities on regional energy projects. Net gains from energy trading activities, including net mark-to-market gains on forward energy contracts, were $3.2 million in 2009 compared with $3.5 million in 2008.

While retail kwh sales grew by 0.1%, retail electric revenues decreased $5.5 million due to:

• a $15.5 million decrease in revenues related to a reduction in costs of fuel and purchased power to serve retail customers,
• a $1.5 million increase in 2008 revenue related to the cost of replacement power purchased in November and December 2007 when Big Stone Plant was down for maintenance, and
• a $0.5 million increase in a refund paid to Minnesota customers for amounts collected under interim rates, partially offset by
• a $6.6 million increase in Minnesota and North Dakota renewable resource recovery rider revenues,
• $3.8 million from a 3.0% general rate increase in North Dakota, approved in November 2009, and
• $1.5 million from an 11.7% general rate increase in South Dakota, approved in June 2009.

Fuel costs related to retail use were down $8.9 million due to a 9.4% reduction in kwh generation for retail use combined with a 5.8% reduction in fuel cost per kwh generated. A major factor contributing to the decrease in fuel costs was a 32.6% decrease in kwhs generated from OTP's fuel-oil and natural gas-fired combustion turbines, in combination with lower fuel and natural gas prices. A contributing factor to the reduction in fuel cost per kwh of generation was a 238% increase in generation from OTP's zero-fuel-cost wind turbines, which provided 12.0% of the electricity generated by OTP to serve retail customers in 2009. Despite a 35.8% increase in kwh purchases to serve retail customers, purchased power costs decreased by $3.4 million as a result of a 30.8% decrease in the cost per kwh purchased. Decreases in natural gas prices, increased output from regional hydroelectric plants, increased efficiency in wholesale electric markets and a decline in industrial demand for electricity are factors that contributed to a significant decline in wholesale electric prices in 2009.

A $9.5 million decrease in electric operating and maintenance expenses includes:

• a $7.5 million decrease in costs associated with construction work completed for other entities on regional energy projects, commensurate with an $8.0 million decrease in related revenue,
• a $1.1 million reduction in external services expenses, for tree trimming and power-plant maintenance, and
• a $0.9 million reduction in vehicle and travel expenses related to a 37% reduction in fuel prices and an increase in vehicle costs capitalized for transportation equipment used on construction projects in 2009.

Depreciation expense increased $5.2 million, mainly due to the additions of 32 wind turbines at the Ashtabula Wind Energy Center in 2008 and 33 wind turbines at the Luverne Wind Farm placed in service in September 2009. OTP's interest costs increased by $6.5 million as a result of debt incurred to finance a portion of OTP's recent investments in wind-powered generation. OTP received a U.S. Treasury grant of $30.2 million in October under the American Recovery and Reinvestment Act of 2009 related to its Luverne Wind Farm assets. The proceeds offset a portion of the $100.6 million in costs incurred by OTP to construct the 33 wind turbines at the Luverne Wind Farm. OTP chose to receive the grant instead of receiving Production Tax Credits on its future federal income tax filings.

Plastics

Plastics revenues and net loss were $80.2 million and $0.1 million, respectively, in 2009 compared with revenues of $116.5 million and net income of $1.9 million in 2008. The decrease in revenues and net income was due to a 9.5% decrease in pounds of pipe sold combined with a 24.0% decrease in the price per pound of pipe sold. Costs per pound of pipe sold decreased 23.8% between the years. Beginning in 2008, significant reductions in new home construction in markets served by the plastic pipe companies have resulted in reduced demand and lower prices for PVC pipe products.

Manufacturing

Manufacturing revenues and net loss were $323.9 million and $2.0 million, respectively, in 2009 compared with revenues of $470.5 million and net income of $5.3 million in 2008.

• At DMI, revenues decreased $88.3 million mainly as a result of lower volumes of wind towers being sold in 2009, but DMI's net income increased by $0.4 million as a result of improved productivity and cost control measures implemented in 2009. Also, in 2008, DMI's costs of goods sold included $4.3 million related to the start-up of its Oklahoma plant and $3.5 million in additional labor and material costs on a production contract in Ft. Erie.
• At BTD, revenues decreased $30.4 million, which led to a decrease of $7.4 million from net income in 2008 to a net loss in 2009. These decreases were the result of a significant decline in sales volume and margins on sales, reductions in capacity utilization and decreased revenues from the sale of scrap metal due to less scrap and lower steel prices in 2009. BTD's depreciation expenses increased $1.2 million in 2009, mainly related to the acquisition of Miller Welding & Iron Works, Inc. in May 2008.
• At T.O. Plastics, revenues decreased $7.0 million and net income was down $0.5 million as a result of lower sales volume related to the economic recession.
• At ShoreMaster, revenues decreased $20.8 million while net losses decreased by $0.2 million. The decrease in revenues reflects a lower volume of commercial construction projects and lower sales of residential products between the years. ShoreMaster's 2009 results were also impacted by $1.6 million in product recall and testing costs. ShoreMaster's results in 2008 included $2.3 million in expenses from the operation and closure of a production facility in California.

Health Services

Health services revenues and net loss were $110.0 million and $2.1 million, respectively, in 2009 compared with revenues of $122.5 million and net income of $0.1 million in 2008. Decreases in revenues of $9.5 million from scanning and other related services and $3.0 million from equipment sales and servicing were partially offset by decreases in costs of goods sold of $7.0 million between the years. Also, results in 2008 included after-tax gains from the sale of certain imaging assets of $0.7 million. The imaging side of the business continues to be affected by less-than-optimal utilization of certain imaging assets.

Food Ingredient Processing

Food ingredient processing revenues and net income were $79.1 million and $7.4 million, respectively, in 2009 compared with revenues of $65.4 million and $1.7 million in 2008. The $13.7 million increase in revenues is due to a 6.6% increase in pounds of product sold, combined with a 13.5% increase in the price per pound of product sold. A $3.3 million increase in cost of goods sold was due to increased product sales, slightly mitigated by a 0.6% decrease in the cost per pound of product sold.

Other Business Operations

Other business operations revenues and net loss were $136.1 million and $1.9 million, respectively, in 2009 compared with revenues of $199.5 million and net income of $5.3 million in 2008. At the construction companies, revenues and net income decreased $53.2 million and $4.3 million, respectively, as a result of a reduction in work volume due to the economic recession and increased competition for available work. In the corporation's trucking operations, revenues decreased $10.2 million due to a reduction in miles driven directly related to the economic recession, which led to a $2.9 million reduction from net income in 2008 to a net loss in 2009. Lower asset utilization rates and an increase in equipment maintenance costs also contributed to the net loss from trucking operations in 2009.

Corporate

Corporate expenses, net-of-tax, were $9.4 million in 2009 compared with $12.3 million in 2008, mainly due to net-of-tax reductions in insurance and employee benefit costs of $1.6 million, a $0.6 million net-of-tax increase in the cash surrender value of corporate-held life insurance and a $0.4 million net-of-tax decrease in interest costs related to a reduction in corporate-held debt.

Income Taxes

The corporation's effective income tax rate for 2009 is significantly lower than its effective income tax rate for 2008. The reduction from the federal statutory rate mainly reflects the benefit of production tax credits and North Dakota wind energy credits--approximately $7.4 million in 2009 compared with $3.6 million in 2008--related to the ownership and operation of OTP's wind turbines.

Fourth Quarter 2009 Results

Diluted earnings per share were $0.23 compared with $0.38 for the fourth quarter of 2008. Revenues were $258.0 million compared with $334.4 million for the same quarter a year ago. Operating income was $13.1 million compared with $25.8 million for the fourth quarter of 2008. Net income was $8.3 million compared with $13.7 million in the fourth quarter of 2008. Net income increases in the electric, plastics and food ingredient processing segments were more than offset by decreases in net income in the corporation's manufacturing, health services and other business operations segments and a $0.5 million increase in unallocated corporate expenses.

2010 Business Outlook

The corporation anticipates 2010 diluted earnings per share to be in the range of $1.00 to $1.40. This guidance considers the cyclical nature of some of the corporation's businesses and reflects challenges presented by current economic conditions and the corporation's plans and strategies for improving operating results as the economy recovers. The corporation's current consolidated capital expenditures expectation for 2010 is in the range of $75-85 million. This compares with $177 million of capital expenditures in 2009. The corporation continues to explore investments in generation and transmission projects for the electric segment that could have positive impacts on the corporation's earnings and returns on capital.

Contributing to the earnings guidance for 2010 are the following items:

• The corporation expects lower levels of net income from its electric segment in 2010. This decrease is due to continued soft wholesale power markets, lower AFUDC earnings as there are no large construction projects expected in 2010, and increased operating and maintenance expense in 2010 due primarily to increased employee benefit costs. Expectations in 2010 also reflect an interim rate increase of approximately $1.5 million in the Minnesota jurisdiction.
• The corporation expects its plastics segment's 2010 performance to improve and be more in line with 2008 results.
• The corporation expects earnings from its manufacturing segment to improve in 2010 as a result of the following:

• Improved earnings are expected at BTD in 2010 due to productivity improvements and cost reductions made in 2009.

• Results at ShoreMaster are expected to be near breakeven in 2010 given the restructuring of costs that occurred in 2009. ShoreMaster continues to be affected by current depressed economic conditions and does not expect any improvement to overall business conditions until the economy starts to recover.

• Improved earnings are expected at DMI in 2010 due to a better backlog of business going into 2010 and continued improvements in productivity from cost controls implemented in 2009.

• Slightly better earnings are expected at T. O. Plastics in 2010 compared with 2009.

• Backlog in place in the manufacturing segment to support 2010 revenues is approximately $239 million compared with $241 million one year ago.

• The corporation expects increased net income from its health services segment in 2010. In an effort to right-size its fleet of imaging assets, health services will not renew leases on a large number of imaging assets that come off lease in 2010. This will result in a lower level of rental costs in 2010.
• The corporation expects a similar level of net income from its food ingredient processing business in 2010 compared with 2009.
• The other business operations segment is expected to have improved earnings in 2010 compared with 2009. Backlog in place for the construction businesses is $84 million for 2010 compared with $71 million one year ago.
• Corporate general and administrative costs are expected to return to more normal levels in 2010.

Risk Factors and Forward-Looking Statements that Could Affect Future Results

The information in this release includes certain forward-looking information, including 2010 expectations, made under the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Although the corporation believes its expectations are based on reasonable assumptions, actual results may differ materially from those expectations. The following factors, among others, could cause actual results for the corporation to differ materially from those discussed in the forward-looking statements:

• The corporation is subject to federal and state legislation, regulations and actions that may have a negative impact on its business and results of operations.
• Federal and state environmental regulation could require the corporation to incur substantial capital expenditures and increased operating costs.
• Volatile financial markets and changes in the corporation's debt ratings could restrict its ability to access capital and could increase borrowing costs and pension plan and postretirement health care expenses.
• The corporation relies on access to the capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If the corporation is not able to access capital at competitive rates, its ability to implement its business plans may be adversely affected.
• Disruptions, uncertainty or volatility in the financial markets can also adversely impact the corporation's results of operations, the ability of its customers to finance purchases of goods and services, and its financial condition, as well as exert downward pressure on stock prices and/or limit its ability to sustain its current common stock dividend level.
• The value of the corporation's defined benefit pension plan assets declined significantly in 2008 due to volatile equity markets. Asset values increased in 2009 and the corporation made a $4 million discretionary contribution to the pension plan in 2009. If the market value of pension plan assets declines again as in 2008 or does not increase as projected and relief under the Pension Protection Act is no longer granted, the corporation could be required to contribute additional capital to the pension plan in future years.
• Any significant impairment of the corporation's goodwill would cause a decrease in its asset values and a reduction in its net operating performance.
• A sustained decline in the corporation's common stock price below book value or declines in projected operating cash flows at any of its operating companies may result in goodwill impairments that could adversely affect its results of operations and financial position, as well as credit facility covenants.
• Economic conditions could negatively impact the corporation's businesses.
• If the corporation is unable to achieve the organic growth it expects, its financial performance may be adversely affected.
• The corporation's plans to grow and diversify through acquisitions and capital projects may not be successful, which could result in poor financial performance.
• The corporation's plans to acquire additional businesses and grow and operate its nonelectric businesses could be limited by state law.
• The terms of some of the corporation's contracts could expose it to unforeseen costs and costs not within its control, which may not be recoverable and could adversely affect its results of operations and financial condition.
• The corporation is subject to risks associated with energy markets.
• Certain of the corporation's operating companies sell products to consumers that could be subject to recall.
• Competition is a factor in all of the corporation's businesses.
• The corporation may experience fluctuations in revenues and expenses related to its electric operations, which may cause its financial results to fluctuate and could impair its ability to make distributions to its shareholders or scheduled payments on its debt obligations.
• In September 2009, OTP announced its withdrawal as a participating utility and the lead developer for the planned construction of a second electric generating unit at its Big Stone Plant site. As of December 31, 2009 OTP had incurred $13.0 million in costs related to the project. OTP has deferred recognition of these costs as operating expenses pending determination of recoverability by the state and federal regulatory commissions that approve its rates. If OTP is denied recovery of all or any portion of these deferred costs, such costs would be subject to expense in the period they are deemed to be unrecoverable.
• Actions by the regulators of the electric segment could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.
• OTP could be required to absorb a disproportionate share of costs for investments in transmission infrastructure required to provide independent power producers access to the transmission grid. These costs may not be recoverable through a transmission tariff and could result in reduced returns on invested capital and/or increased rates to OTP's retail electric customers.
• OTP's electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.
• Fluctuations in wholesale electric sales and prices could result in earnings volatility.
• Wholesale sales of electricity from excess generation could be affected by reductions in coal shipments to the Big Stone and Hoot Lake plants due to supply constraints or rail transportation problems beyond the corporation's control.
• Changes to regulation of generating plant emissions, including but not limited to carbon dioxide ("CO2") emissions, could affect our operating costs and the costs of supplying electricity to our customers.
• The corporation's plastics segment is highly dependent on a limited number of vendors for PVC resin, many of which are located in the Gulf Coast regions, and a limited supply of resin. The loss of a key vendor, or an interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for this business.
• The corporation's plastic pipe companies compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish the pipe companies' products from those of its competitors.
• Reductions in PVC resin prices can negatively impact PVC pipe prices, profit margins on PVC pipe sales and the value of PVC pipe held in inventory.
• Competition from foreign and domestic manufacturers, the price and availability of raw materials, fluctuations in foreign currency exchange rates and general economic conditions could affect the revenues and earnings of the corporation's manufacturing businesses.
• Changes in the rates or method of third-party reimbursements for diagnostic imaging services could result in reduced demand for those services or create downward pricing pressure, which would decrease revenues and earnings for the corporation's health services segment.
• The corporation's health services businesses may be unable to continue to maintain agreements with Philips Medical from which the businesses derive significant revenues from the sale and service of Philips Medical diagnostic imaging equipment.
• Technological change in the diagnostic imaging industry could reduce the demand for diagnostic imaging services and require the corporation's health services operations to incur significant costs to upgrade its equipment.
• Actions by regulators of the corporation's health services operations could result in monetary penalties or restrictions in the corporation's health services operations.
• The corporation's food ingredient processing segment operates in a highly competitive market and is dependent on adequate sources of potatoes for processing. Should the supply of potatoes be affected by poor growing conditions, this could negatively impact the results of operations for this segment.
• The corporation's food ingredient processing business could be adversely affected by changes in foreign currency exchange rates.
• A significant failure or an inability to properly bid or perform on projects by the corporation's construction or manufacturing businesses could lead to adverse financial results.

For a further discussion of other risk factors and cautionary statements, refer to reports the corporation files with the Securities and Exchange Commission.

NorthWestern Corporation Conference Call Announcement - Year-End 2009 Financial Results(02/03/2010)  Back to Table of Contents

YEAR-END 2009 FINANCIAL RESULTS

NorthWestern’s Year-End 2009 Financial Results will be e-mailed to you. You may also find NorthWestern’s news release on PR Newswire.

YEAR-END 2009 FINANCIAL RESULTS CONFERENCE CALL

A conference call to discuss financial results for the year-end 2009 will be held:

If you are unable to participate in the conference call as scheduled above, a replay will be available beginning at 4:30 p.m. ET on February 12 through March 13, 2010. To access the replay, dial 800 475-6701, access code 144451.

The call also will be simultaneously broadcast on our Web site at www.northwesternenergy.com, and a replay will be available for 30 days following the conference call.

MDU Resources Reports 2009 Earnings and Initiates 2010 Earnings Guidance(02/01/2010)  Back to Table of Contents

• Consolidated earnings of $260.4 million, excluding the after-tax noncash charge.
• Including the noncash charge, the company reported a consolidated loss of $124.0 million.
• Record operating cash flows of approximately $845 million.
• Strong balance sheet with equity of 63% of total capital.
• Initial earnings guidance for 2010 of $1.10 to $1.35 per common share.

BISMARCK, N.D. - Feb. 1, 2010 - MDU Resources Group, Inc. (NYSE:MDU) announced 2009 consolidated earnings of $260.4 million, or $1.40 per common share, compared to $377.2 million, or $2.05 per share for 2008, with the decline in earnings related primarily to lower natural gas and oil prices. These results exclude the after-tax noncash charge of $384.4 million and $84.2 million, respectively, related to low natural gas and oil prices. Including the respective noncash charges, the company reported a consolidated loss for 2009 of $124.0 million, or 67 cents per common share compared to earnings of $293.0 million, or $1.59 per share for 2008.

In the fourth quarter of 2009 the company had consolidated earnings of $72.5 million, or 38 cents per share compared to $72.8 million or 40 cents per share in the same period of 2008. 2008 earnings exclude a noncash charge of $84.2 million. Including the noncash charge, the company reported a loss of $11.4 million, or 6 cents per share in the fourth quarter of 2008.

"Our businesses generated record operating cash flow of approximately $845 million with strong day to day operating performance," said Terry D. Hildestad, president and chief executive officer of MDU Resources. "This performance allowed us to increase our dividend for the 19th consecutive year this past November. The results once again demonstrate the value of our diversified business strategy."

The company's utility business posted record earnings. Results reflect a full year of Intermountain Gas Company earnings which was acquired in late 2008. The utility group continues to focus on integrating the operations of its four utilities to produce efficiencies that reduce costs and improve service to 950,000 customers in an 8-state region. Montana-Dakota Utilities set a safety record for the third consecutive year and was one of two companies recognized by the American Gas Association in 2009 as the industry's safest medium-sized combination utilities.

The challenged construction market, including the traditionally strong Las Vegas gaming market, impacted the company's construction services business and resulted in lower earnings. Equipment sales and rentals remained strong, as customers prepare for an anticipated effort to strengthen and expand the country's electricity transmission infrastructure.

Significantly lower prices for natural gas and oil affected earnings of the company's natural gas and oil production business. Although prices rebounded somewhat late in the year, average realized prices in 2009 declined 30 percent for natural gas and 42 percent for oil. In response to this low-price environment and the desire to preserve capital, the business reduced its drilling program in 2009, like many in the industry, which resulted in a natural gas production decline of 13 percent. Oil production increased 11 percent as the company focused much of its drilling in North Dakota's Bakken region.

MDU Resources' pipeline and energy services group increased earnings by 44 percent to record levels, in large part the result of record revenue generating natural gas storage levels. The business had record total throughput, principally because of an increase in volumes transported to storage. Last August, Williston Basin Interstate Pipeline completed an expansion of its Grasslands Pipeline, which provides Rocky Mountain natural gas producers access to Mid Continent markets. Grasslands now has a firm capacity of 213 MMcf per day. Also contributing to earnings was the August acquisition of Total Corrosion Solutions.

The construction materials and contracting business increased earnings by 56 percent, despite the continuing weakness of the national construction market. Sales volumes and margins of asphalt and asphalt oil increased, while aggregate and ready-mix products sales volumes decreased. In addition, the business continued to focus on aggressive cost management.

"Our financial condition is very healthy because of our aggressive efforts to lower operating costs and preserve capital," said Hildestad. "We have a strong balance sheet, liquidity and good access to capital. This puts us in an excellent position to take advantage of growth opportunities that may result from this prolonged recession, including organic growth and acquisitions of businesses and reserves of natural gas, oil and aggregates because of lower values. We are providing initial guidance for 2010 in the range of $1.10 to $1.35 per common share."

The company recently announced the upcoming retirement of Vernon A. Raile, executive vice president, treasurer and chief financial officer effective Feb. 16 at the age of 65, the company's mandatory retirement age for officers. Doran N. Schwartz will succeed him as vice president and chief financial officer.

The company will host a webcast at 1 p.m. EST today to discuss earnings results and guidance. The event can be accessed at www.mdu.com. A webcast replay and audio replay will be available. The dial in number for audio replay is (800) 642 1687 or for international callers, (706) 645 9291, conference ID 45709171.

Northwestern To Host Year-End 2009 Financial Results Conference Call(01/28/2010)  Back to Table of Contents

SIOUX FALLS, S.D. – January 28, 2010 – NorthWestern Corporation d/b/a NorthWestern Energy (NYSE: NWE) today announced that it will host an investor conference call on Friday, February 12, 2010 at 3:30 p.m. Eastern Time (2:30 p.m. Central Time) to review its financial results for the year ended December 31, 2009.

The conference call will be webcast live on the Internet at northwesternenergy.com under the “Investor Information” heading. To listen, please go to the site at least 10 minutes in advance of the call to register. An archived webcast will be available shortly after the call.

A telephonic replay of the call will be available beginning at 5:30 p.m. ET on February 12, 2010, through March 12, 2010, at 800-475-6701, access code 144451.

Black Hills Corp. Reports 2009 Results, Announces 40th Consecutive Dividen Increase, And Reaffirms 2010 Earnings Guidance(01/28/2010)  Back to Table of Contents

STRATEGY ON TRACK, KEY FINANCINGS COMPLETE, AND STRONG PERFORMANCE FROM THE GAS UTILITIES

RAPID CITY, SD - January 28, 2010 - Black Hills Corp. (NYSE: BKH) today announced 2009 financial results and the 40th consecutive increase in its quarterly dividend to shareholders. Income from continuing operations for fourth quarter 2009 was $32.4 million or $0.84 per share compared to loss from continuing operations for fourth quarter 2008 of $96.6 million or $2.52 per share. Net income for the three months ending Dec. 31, 2009, was $32.8 million or $0.85 per share compared to a net loss of $98.8 million or $2.58 per share for the same period in 2008. The 2009 fourth quarter results include an $11.6 million or $0.30 per share non-cash mark-to-market gain for certain interest rate swaps.

Click to view entire news release: 1/28/2010 News Release

Click to view 2009 Financial Results: 2009 Financials

Black Hills Corp. Schedules 2009 Fourth Quarter and Full Year Financial Results, Conference Call and Webcast(01/21/2010)  Back to Table of Contents

RAPID CITY, SD - January 21, 2010 - Black Hills Corporation (NYSE: BKH) announced today that it will issue a news release regarding 2009 fourth quarter and full year results on Thursday, Jan. 28, 2010, and host a live conference call and webcast at 11 a.m. ET on Friday, Jan. 29 to discuss the company's financial and operating performance.

Those interested in listening to the live broadcast can call 800-230-1092. To access the live webcast and download a copy of the investor presentation, go to the Black Hills Web site at www.blackhillscorp.com and click "Webcast" in the "Investor Relations" section. The presentation will be posted on the Web site prior to the webcast. Listeners should allow at least five minutes for registering and accessing the presentation. For those unable to listen to the live broadcast, a replay will be available by telephone through Feb. 5, 2010, at 800-475-6701 in the United States and at 320-365-3844 for international callers. Callers need to enter the access code 139497# when prompted.

NorthWestern Corporation News Release(01/15/2010)  Back to Table of Contents

Butte, Mont. – January 15, 2010 – NorthWestern Energy (NYSE:NWE) announced today that it has submitted a supplemental filing regarding allocated cost of service and rate design to the Montana Public Service Commission (MPSC) in response to the determination made last October that the company’s general rate case filing on October 16, 2009, did not meet the MPSC’s applicable minimum filing requirements.

The MPSC has until February 2, 2010, to determine whether the supplemental filing meets the MPSC’s minimum filing requirements. If the supplemental filing is found to meet minimal filing requirements, NorthWestern agreed to extend the timeframe by which the MPSC must issue a final order concerning the general rate filing by 90 days to October 11, 2010.

In its rate case filing, NorthWestern proposed a revenue requirement increase of approximately $1.96 million for its natural gas utility and approximately $15.5 million for its electric utility.

MDU Resources Announces Webcast of Analyst Conference Call(01/13/2010)  Back to Table of Contents

BISMARCK, N.D. - Jan. 13, 2010 - MDU Resources Group, Inc. (NYSE:MDU) will webcast its year-end 2009 earnings and 2010 guidance conference call February 1 following the release of its results.

The webcast will begin at 1 p.m. EST and can be accessed at www.mdu.com. A webcast replay and audio replay will be available. The dial-in number for audio replay is (800) 642-1687, or (706) 645-9291 for international callers, conference ID 45709171.

MDU Resources Names Chief Financial Officer, Chief Accounting Officer, Treasurer(01/07/2010)  Back to Table of Contents

BISMARCK, N.D. - Jan. 7, 2010 - MDU Resources Group, Inc. (NYSE: MDU) today announced that Doran N. Schwartz has been named vice president and chief financial officer for the corporation, Nicole A. Kivisto has been named vice president, controller and chief accounting officer, and Douglass A. Mahowald has been named treasurer and assistant secretary. All positions are effective Feb. 17.

"We are pleased to have this experienced and talented team to help lead our corporation through continued growth," said Terry D. Hildestad, MDU Resources president and chief executive officer. "They have demonstrated great leadership, and their business knowledge and expertise will be beneficial in leading the finance group as we continue to create value for our stakeholders."

Schwartz previously was MDU Resources' vice president and chief accounting officer. Prior to joining MDU Resources in 2005, he was a director in the finance area for American Express and was an audit manager for Deloitte & Touche. Schwartz is a native of Bismarck, N.D., and holds a bachelor's degree in business administration from the University of Minnesota-Moorhead, a bachelor's degree in accounting from the University of Northern Iowa and a master's degree in business administration from the University of Wisconsin-Whitewater. He is a certified public accountant. Schwartz replaces retiring CFO Vernon A. Raile.

Kivisto has been MDU Resources' controller since 2005. She joined the corporation in 1995 and has held a number of positions of increasing responsibility. Kivisto grew up in Beulah, N.D., has a bachelor's degree in accounting from the University of Minnesota-Moorhead and is a graduate of the Carlson School of Management Minnesota Executive Program. She is a certified public accountant.

Mahowald joined MDU Resources in 1982, holding positions of increasing responsibility and becoming assistant treasurer and assistant secretary in 1992. Mahowald is a native of Garrison, N.D., and has a bachelor's degree in finance from the University of St. Thomas in St. Paul, Minn.

MDU Resources Chief Financial Officer Vernon A. Raile to Retire(01/06/2010)  Back to Table of Contents

BISMARCK, N.D. - Jan. 6, 2010 - MDU Resources Group, Inc. (NYSE:MDU) announced that Vernon A. Raile, executive vice president, treasurer and chief financial officer, will retire on Feb. 16.

During his 30-year career with MDU Resources, the company has grown from a small utility with revenues of about $182 million into a Fortune 500 diversified natural resources company with revenues of more than $5 billion.

"Vern has done an outstanding job of ensuring that our accounting and financial expertise have kept pace with the increasingly complex needs that result from this growth," said Terry D. Hildestad, MDU Resources president and chief executive officer. "He also was instrumental in putting the financing in place to support the two largest acquisitions in our company's history. Vern and his wife, Jane, have our best wishes in this well-deserved retirement."

The company has a long-standing policy mandating that officers retire at age 65.

Raile joined the company in 1980 as tax manager, and subsequently was promoted to positions as assistant treasurer, controller and chief accounting officer. He was named to his present position in 2006. Prior to joining MDU Resources, Raile was a supervisor and director in the Iowa Department of Revenue's Income Tax Division, and a tax auditor for the North Dakota Tax Department.

Raile is a certified public accountant and a member of the American Institute of Certified Public Accountants. He has an associate degree from Bismarck State College, a bachelor's degree from Drake University and a Master of Business Administration degree from the University of North Dakota. He is a graduate of the financial management program at Stanford University's Graduate School of Business. He and Jane live in Bismarck.

MDU Resources Group, Inc., a Fortune 500 company and a member of the S&P MidCap 400 index, provides value-added natural resource products and related services that are essential to energy and transportation infrastructure, operating in three core lines of business: energy, utility resources and construction materials. MDU Resources includes natural gas and oil production, natural gas pipelines and energy services, electric and natural gas utilities, construction services, and construction materials and contracting. For more information about MDU Resources, see the company's Web site at www.mdu.com.

Black Hills Energy Requests Electric Rate Increase in Colorado to be Effective in 2010(01/06/2010)  Back to Table of Contents

PUEBLO, Colo., January 6, 2010 - Black Hills Corp. (NYSE:BKH) utility subsidiary Black Hills Energy - Colorado Electric announced today that the utility has filed a request for an electric revenue increase with the Colorado Public Utilities Commission. The request is necessary to cover the utility's increased expenses, which are not fully offset by cost savings and efficiency measures the utility has implemented and are primarily associated with electricity supply contracts, and investments in equipment and electricity distribution facilities necessary to maintain and strengthen the reliability of Black Hills' electric delivery system in Colorado. The last base rate increase for Black Hills Energy customers in Colorado became effective in September 2004.

In its current request, Black Hills Energy is seeking a $22.9 million, or approximately 12.8 percent, increase in annual revenues, with an anticipated effective date of mid-2010. If the proposed rate request is approved by the Colorado Public Utilities Commission, a typical Black Hills Energy residential customer using an average of 600 kilowatt-hours each month can expect an estimated increase of $10.79 per month. A typical small-commercial customer using an average of 2,300 kWh each month can expect to see an estimated increase of $36 per month. The increase experienced by Black Hills Energy's commercial, industrial and governmental customers will vary depending on rate class, load factor and the level of their electricity demand and usage. Black Hills Energy currently serves approximately 93,300 residential, commercial, industrial and governmental electric customers in southeastern Colorado.

"We've worked hard to operate efficiently and serve the growing electricity needs of our customers during the six years since the last rate increase. However, inflation and other cost increases we incur to ensure the continued growth and reliability of our electric systems necessitate a rate increase at this time," said Stuart Wevik, Black Hills Corp. vice president of electric utilities.

"Our utility companies have been serving communities for more than 125 years, and we are committed to providing safe, reliable electric service at a reasonable price. In fact, most of our residential customers pay only $2 to $3 a day for the electricity needed to provide their lighting, heating, air-conditioning, refrigeration, cooking, entertainment and communications."

For more detailed information, you can view Black Hills Energy's complete rate request at the Colorado Public Utilities Commission Web site in the near future at www.dora.state.co.us/puc or go to www.blackhillsenergy.com.

Public Utilities Commission approves Xcel Energy rate increase(01/05/2010)  Back to Table of Contents

PIERRE, S.D. – The South Dakota Public Utilities Commission conditionally approved an approximate 5.5 percent increase over current rates for Xcel Energy this week. In recent years Xcel Energy had received some interim rate recovery from the PUC, but this is the first base rate increase for the company in 17 years.

The application filed by Xcel Energy with the PUC in June 2009 requested a 10.7 percent rate increase to current rates, which would have generated approximately $15.7 million in additional annual revenue. The commission decision increases bills by $8 million, a 5.5 percent increase over current rates. PUC staff and Xcel Energy had previously reached a settlement stipulation for a slightly higher increase, but commissioners unanimously voted to remove costs related to a development fund mandated by the Minnesota Legislature that had been a part of the recommended rate increase.

PUC Chairman Dusty Johnson commended the PUC staff and company representatives for agreeing to a rate increase substantially lower than the company’s original request. “These are difficult economic times and I’m glad we’ve been able to cut this request in half,” he said. “It’s been 17 years since the last general rate increase and that kind of stability is good for ratepayers.”

In presenting its case to the PUC, Xcel Energy noted much of the requested increase stemmed from more than $6 billion of infrastructure investment made by the company in recent years. Additionally, representatives stated their customer base in South Dakota has grown by 44 percent and overall electric use has expanded by 78 percent since 1992. The company’s operating costs have risen and infrastructure improvements have been made during the same 17-year period. The company serves about 81,000 customers in southeastern South Dakota.

PUC Vice Chairman Steve Kolbeck pointed out the number of expenses that were reduced during negotiations, resulting in a lower rate increase. “Not only are specific costs related to operating expenses and rate design carefully reviewed, staff looked at accounting methods and management principles when negotiating with the company on the rate increase,” he said.

Commissioner Gary Hanson noted the intricate process of reviewing and negotiating the rate case. “The PUC staff clearly identified the potential for reducing costs as they plowed through the hundreds of details of Xcel Energy’s application. This due diligence and successful negotiation avoided a lengthy formal hearing thereby saving the ratepayer between $300,000 and $400,000 in costs the company could have incurred as part of that extended process,” he said.

A PUC staff team comprised of five analysts and one attorney were supported by a three-member consultant group in analyzing the rate request. The PUC staff engaged in negotiations with Xcel Energy representatives, making formal requests for additional information, holding meetings and discussions before reaching a settlement agreement that was presented to the commission on Dec. 22, 2009, and discussed at the commission Jan. 5, 2010, meeting.

No individuals or organizations formally intervened in the case. The PUC received eight written comments from consumers and organizations about the rate case.

Black Hills Corp. Completes $120 Million Project Financing(12/09/2009)  Back to Table of Contents

RAPID CITY, SD - December 9, 2009 - Black Hills Corp. (NYSE: BKH) announced today that its subsidiary, Black Hills Wyoming, LLC, completed $120 million in project financing, secured by the company's Wygen I and Gillette CT generation facilities. The loan amortizes over a seven year term with a maturity date of December 9, 2016 and has an interest rate of LIBOR plus 3.25 percent per annum. Black Hills Corp. plans to use the net proceeds to pay down a portion of short term borrowings on its corporate revolving credit facility.

"We continue to make progress replacing short-term debt with cost effective long-term financings. By completing our corporate bond issuance in May, the Black Hills Power first mortgage bond offering in October and now closing on this project financing, we have attained more favorable terms than were possible in late 2008 or earlier this year," said David R. Emery, chairman, president and chief executive officer of Black Hills Corp. "We are well positioned to move forward with our substantial capital investment plans over the next several years and look forward to the associated earnings growth."

The Bank of Nova Scotia was book-runner for the offering and Bayerische Landesbank, CoBank, and Union Bank were participating banks.

Otter Tail Corporation Announces Closing of Public Offering of Senior Unsecured Notes(12/04/2009)  Back to Table of Contents

FARGO, N.D., Dec. 4, 2009 (GLOBE NEWSWIRE) -- Otter Tail Corporation (Nasdaq:OTTR) announced today the closing of an offering of $100 million of its 9.000% Notes due 2016. The Notes will be senior unsecured obligations of Otter Tail Corporation. Otter Tail Corporation intends to use the net proceeds of the offering to reduce borrowings under its revolving credit facility.

Bank of America Securities LLC and J.P. Morgan Securities Inc. acted as joint book-running managers, U.S. Bancorp Investments, Inc. acted as lead manager and BNP Paribas Securities Corp., KeyBanc Capital Markets Inc. and Wells Fargo Securities, LLC acted as co-managers for the offering.

This press release is for informational purposes only and is not an offer to buy or the solicitation of an offer to sell with respect to any securities. The offering was made only by means of the prospectus supplement and the prospectus relating to the Notes. The offering was not made in any jurisdiction in which the making or acceptance thereof would not be in compliance with the securities, blue sky or other laws of such jurisdiction.

About The Corporation: Otter Tail Corporation has interests in diversified operations that include an electric utility, manufacturing, health services, food ingredient processing and infrastructure businesses which include plastics, construction and transportation. Otter Tail Corporation stock trades on the NASDAQ Global Select Market under the symbol OTTR. The latest investor and corporate information is available at www.ottertail.com. Corporate offices are located in Fergus Falls, Minnesota, and Fargo, North Dakota.

Black Hills Energy Requests Natural Gas Rate Increase In Nebraska Effective In 2010(12/02/2009)  Back to Table of Contents

$28.8 million in improvements to natural gas distribution systems and operating cost increases since 2006 primary reasons for the request

LINCOLN, Neb., Dec. 2, 2009 - Black Hills Energy's Nebraska natural gas utility, a subsidiary of Black Hills Corp. (NYSE:BKH), today announced it has filed a request for a natural gas revenue increase with the Nebraska Public Service Commission to recover the cost of capital investments the company made in its Nebraska natural gas distribution systems since July 1, 2006, and increased operating expenses incurred during the same period. The company last filed for a rate increase in November 2006.

Black Hills Energy is seeking a $12.1 million or 6.5 percent increase in annual revenue. Interim rates take effect March 1, 2010. If final rates approved by the NPSC are lower than interim rates, customers will receive a refund with interest.

"We provide natural gas to customers in 110 Nebraska communities. Since 2006, we have spent nearly $30 million in Nebraska to replace obsolete pipes and other equipment, make system upgrades and implement new technology so that our gas distribution systems are safe, reliable and efficient," said Dan Mechtenberg, Black Hills Energy vice president of Nebraska natural gas operations.

"While these improvements are necessary to serve our customers, the associated costs are not reflected in our current rates. We proactively work to keep our operating costs low and delay rate increases as long as we can. The process to recover investment costs and increases in operating costs requires a filing with the Nebraska Public Service Commission. This rate filing includes only those costs and capital investments made since our last request in 2006 and are critical to continue providing the safe and reliable natural gas service our customers deserve," said Mechtenberg.

The average monthly bill would increase by approximately $5.48 for residential customers if the proposed rates are approved, and $2.65 for commercial customers. The actual change in a customer's bill will vary based on how much natural gas is used and the price of natural gas, which is not part of this rate case.

"Black Hills Energy natural gas service remains a good value and comparable to other natural gas providers in our area," said Mechtenberg. "If approved, our average residential customer in Nebraska will pay 18 cents more per day to keep their house warm, cook meals, dry clothing and heat water. The rate request will not take effect for 90 days and before permanent rates are implemented, our filing undergoes rigorous review by the commission."

Black Hills Energy is also proposing to change the way its rates are structured, moving from a single delivery charge to a two-tier declining block delivery charge. The declining block rate design is fairly common and in line with other natural gas utilities in Nebraska. Declining block rates levelize the utility's revenue collection, minimizing the impact of extreme weather.

Black Hills Energy's last rate increase of 4.36 percent was based on costs through June 30, 2006, and went into effect Feb. 15, 2007. Black Hills Energy's complete rate request will be available on the NPSC Web site, www.psc.state.ne.us.

Otter Tail Corporation Announces Public Offering of Senior Unsecured Notes(11/30/2009)  Back to Table of Contents

FARGO, N.D., Nov. 30, 2009 (GLOBE NEWSWIRE) -- Otter Tail Corporation (Nasdaq:OTTR) announced today that it intends to offer a new series of notes in an underwritten registered public offering. The notes will be senior unsecured obligations of Otter Tail Corporation. The aggregate principal amount, maturity and interest rate of the notes will be determined at the time the notes are sold to investors. The offering will be made pursuant to an effective shelf registration statement that was previously filed with the Securities and Exchange Commission.

Otter Tail Corporation intends to use the net proceeds of the offering to reduce borrowings under its revolving credit facility and for general corporate purposes.

A copy of the prospectus supplement and accompanying prospectus for this offering may be obtained, when available, by contacting Banc of America Securities LLC, 100 West 33rd Street, 3rd Floor, New York, NY 10001, Toll-Free: 1-800-294-1322, Attention: Prospectus Department or J.P. Morgan Securities Inc., 270 Park Avenue, High Grade Syndicate Desk, 8th Floor, New York, NY 10017, Telephone: 212-834-4533.

This press release is for informational purposes only and is not an offer to buy or the solicitation of an offer to sell with respect to any securities. The offering is being made only by means of the prospectus supplement and the prospectus relating to the notes. The offering is not being made in any jurisdiction in which the making or acceptance thereof would not be in compliance with the securities, blue sky or other laws of such jurisdiction.

The offering is subject to market conditions and there can be no assurance as to whether or when the offering may be completed, or as to the actual size or terms of the offering.

MPSC Accepts Motion for Reconsideration Regarding Company's Recent General Rate Filing(11/24/2009)  Back to Table of Contents

Butte, Mont. – Nov. 24, 2009 – NorthWestern Energy (NYSE:NWE) announced today that the Montana Public Service Commission (MPSC) has accepted its motion for reconsideration regarding the MPSC’s Nov. 12, 2009, decision that the company’s general rate filing did not meet the MPSC’s applicable minimum filing requirements, primarily related to allocated cost of service and rate design.

As a result of today’s hearing, NorthWestern does not need to re-file its general rate case and will work with MPSC staff to determine what additional information is necessary to meet the MPSC’s minimum filing requirements and submit a supplemental filing by January 15, 2010. The MPSC indicated that it will decide by the end of January whether the supplemental filing meets the MPSC’s minimum filing requirements.

Assuming the supplemental filing is found to meet minimal filing requirements, NorthWestern agreed to extend the timeframe by which the MPSC must issue a final order concerning the general rate filing by 90 days to October 11, 2010.

NorthWestern is pleased with the MPSC’s decision and the opportunity to work directly with MPSC staff to address the submittal of supplemental information.

In its Oct. 16, 2009 rate case filing, NorthWestern proposed a revenue requirement increase of approximately $1.96 million for its natural gas utility and approximately $15.5 million for its electric utility.

MPSC Rules NorthWestern Energy May Re-file General Rate Filing to Comply With State Minimum Filing Requirements(11/19/2009)  Back to Table of Contents

Butte, Mont. – Nov. 19, 2009 – NorthWestern Energy (NYSE:NWE) announced today that the Montana Public Service Commission (MPSC) recently determined that the Company's general rate case filing on Oct. 16, 2009, did not meet the MPSC's applicable minimum filing requirements, primarily related to allocated cost of service and rate design.

In its rate case filing, NorthWestern proposed a revenue requirement increase of approximately $1.96 million for its natural gas utility and approximately $15.5 million for its electric utility.

NorthWestern's proposed filing also included new cost allocation between rate classes and rate designs. The proposals introduced an inclining block residential rate structure that would assign more costs to residential customers that use more energy within each rate class. Under this methodology, some customers would see higher increases than the average residential customer while other residential customers may experience lower than average rates.

In response to the MPSC's action, NorthWestern submitted a motion for reconsideration or in the alternative, if it is denied, a motion to bifurcate the general rate case into a revenue requirement proceeding and an allocated cost of service and rate design proceeding. The Company believes the motion to reconsider bears merit because the filing does, in fact, comply with the MPSC's filing requirements. In addition, should the MPSC deny the motion for reconsideration, the motion to bifurcate would allow a separation of the overall revenue requirement from the allocated cost of service and rate design rules, allowing a proceeding on the revenue requirement to continue.

NorthWestern expects the MPSC to rule as early as next week on the motions. If the MPSC's initial determination stands, the Company expects to correct the deficiencies and re-file the rate case. If a re-filing is required, the rate case decision likely would be delayed from the third quarter of 2010, as previously anticipated, to the fourth quarter of 2010.

MDU Resources Increases Common Stock Dividend for 19th Straight Year(11/12/2009)  Back to Table of Contents

BISMARCK, N.D. - Nov. 12, 2009 - The MDU Resources Group (NYSE: MDU) board of directors today increased the company's quarterly common stock dividend to 15.75 cents per share, for an annualized dividend of 63 cents per share. The previous quarterly dividend was 15.5 cents per share.

"We are very proud of our company's record of returning value to shareholders," said Harry J. Pearce, chairman of the board. "This is the 19th consecutive year that we have increased the common stock dividend, and we have a 72-year unbroken record of consecutive dividend payments that stretches back to 1937.

"Our diversified business strategy and aggressive cost management are providing strong cash flow and a healthy balance sheet, despite current economic conditions," Pearce said.

The board of directors also declared dividends on preferred stock as follows:

The dividends are payable Jan. 1, 2010 to stockholders of record Dec. 10, 2009.

PUC to hear public comments about Black Hills Power proposed rate increase Nov. 24(11/05/2009)  Back to Table of Contents

PIERRE, S.D. – The South Dakota Public Utilities Commission will hold a public input meeting on Tuesday, Nov. 24, 2009, at the Journey Museum in Rapid City to hear comments about the electric rate increase proposed by Black Hills Power. The meeting will begin at 7 p.m. (MST) in the Wells Fargo Theater at the Journey Museum, 222 New York St. The meeting will adjourn at the conclusion of comments from all persons who have arrived before 9 p.m.

Black Hills Power has applied to the PUC for approval to increase rates by approximately $32 million annually or approximately 26.6 percent based on the company's test year ending June 30, 2009. Black Hills Power has indicated a typical residential electric customer using 600 kWh per month would see a net increase of $17.99 per month. The proposed rates may potentially affect approximately 64,100 customers in Black Hills Power's service territory.

The public input meeting will begin with a short presentation by Black Hills Power following which PUC Commissioners Dusty Johnson, Steve Kolbeck and Gary Hanson will hear comments from the public. Representatives of Black Hills Power will be available to address specific questions.

The PUC also accepts written comments from the public to be considered by commissioners and entered into the public record online at www.puc.sd.gov. Such comments may be e-mailed to the commission at puc@state.sd.us or sent or hand-delivered to the PUC office at 500 E. Capitol Ave., Pierre, SD 57501. Submissions should include the commenter's full name, mailing address and telephone number.

Visit the PUC Web site for more information on the Black Hills Power rate increase request and related filings submitted to the commission. Select "Commission Actions," "Electric Dockets" and "2009 Electric Dockets." Click on the docket titled EL09-018 to access the documents. The company also has information about its rate request on its Web site at www.BlackHillsPower.com.

Participating Utilities Announce Wind-Down of Big Stone II Project(11/02/2009)  Back to Table of Contents

BISMARCK, N.D. - Nov. 2, 2009 - MDU Resources Group, Inc. (NYSE:MDU) announced today that the Big Stone II Project, a planned 500-to-600-megawatt coal-fired power plant to be located near Milbank, South Dakota, and its associated transmission, will not be built. The project's four participants include Montana-Dakota Utilities Co., a division of MDU Resources.

The project required additional participants to move forward; however none have committed.

Montana-Dakota President and Chief Executive Officer Dave Goodin said that, while it's disappointing that Big Stone II will not be built, the utility has an adequate electric supply for the near-term.

"We have a purchased power agreement through 2015 that was to bridge us to Big Stone II going online; we still have that agreement in place," Goodin said. "We will now look at other supply options that are reliable and cost-beneficial for our customers. We have plans to expand our wind production by 30 megawatts in 2010 and will review other generation options."

The other Big Stone II Project participants were Central Minnesota Municipal Power Agency, Heartland Consumers Power District and Missouri River Energy Services.

MDU Resources Reports Third Quarter Earnings and Increases Earnings Guidance(10/30/2009)  Back to Table of Contents

BISMARCK, N.D. - Oct. 30, 2009 - MDU Resources Group, Inc. (NYSE:MDU) today reported third quarter financial results, with consolidated earnings of $92.4 million, or 50 cents per common share, compared to $118.2 million, or 64 cents per common share for the third quarter of 2008.

"We had a very good third quarter, particularly when you consider the fact that natural gas and oil prices were substantially lower than a year ago," said Terry D. Hildestad, president and chief executive officer of MDU Resources.

Consolidated earnings for the nine months ended Sept. 30, excluding a first quarter noncash charge related to low natural gas and oil prices, were $188.0 million or $1.02 per share, compared to $304.4 million or $1.66 per share for the first nine months of 2008. Results for the nine months ended Sept. 30, 2009 including the noncash charge were a loss of $196.4 million or $1.07 per share.

"Based on our first three quarters, we are increasing our 2009 earnings guidance," Hildestad said. "Our businesses are providing us with record levels of operating cash flow and a healthy balance sheet. Like most businesses, we see the effects of a weak economy. However, with our diversified business strategy and aggressive cost management, we are well positioned for growth as the economy recovers."

• Consolidated earnings of 50 cents per common share.
• Record cash flows from operations of $629 million year-to-date.
• Solid balance sheet with equity of 63% of total capital.
• Increases earnings guidance for 2009 to $1.25 to $1.40 per common share, excluding a first quarter noncash charge of $384.4 million after-tax. (Including the noncash charge, guidance for 2009 is a loss of 67 cents to 82 cents per common share.)

Otter Tail Corporation Announces Third Quarter Earnings; Board of Directors Declares Dividend(10/29/2009)  Back to Table of Contents

 * Consolidated net income improved 10.0% as net income in our
   electric and food ingredient processing segments increased $3.0
   million and $2.8 million, respectively, compared with the third
   quarter of 2008.

 * Consolidated revenues decreased 27.1% compared with last year's
   third quarter.

 * Diluted earnings per share totaled $0.29 compared with $0.31 in
   the third quarter of 2008.

 * Operating cash flow increased by $100.3 million for the nine
   months ended September 30, 2009 compared with the same period
   last year.

 * On October 29, 2009 the Board of Directors declared a quarterly
   common stock dividend of 29.75 cents per share payable December
   10, 2009 to shareholders of record on November 13, 2009.

 * The Board also declared quarterly dividends on the corporation's
   four series of preferred stock, payable December 1, 2009, to
   shareholders of record on November 13, 2009.

 * The corporation expects its 2009 diluted earnings per share to
   be near the low end of its previously announced range of $0.70
   to $1.10.

 * On September 11, 2009 Otter Tail Power Company announced its
   withdrawal from participation in the planned construction of a
   500- to 600-megawatt generating unit at its Big Stone Plant site.

 * On July 1, 2009 the corporation completed its transition to a
   holding company structure.

 * a $0.8 million increase in North Dakota interim rates,

 * a $0.7 million increase in South Dakota rates, and

 * $0.4 million in accrued revenues related to transmission asset
   investments subject to recovery in Minnesota under a rate rider,
   partially offset by a decrease in revenues related to a 3.7%
   reduction in retail kilowatt-hour (kwh) sales.

 * a $4.5 million decrease in costs associated with construction
   work completed for other entities on regional energy projects,
   commensurate with a $5.3 million decrease in related revenue,

 * recognition, in the third quarter of 2008, of $1.5 million in
   costs eligible for recovery through the Minnesota Resource
   Recovery Rider that had been deferred pending approval of the rider,

 * a $1.2 million reduction in external services expenses for
   power-plant maintenance and tree trimming,

 * a $1.0 million reduction in employee incentive expenses,

 * a $0.5 million reduction in travel expenses related to
   decreased fuel costs, an increase in travel expenses capitalized
   and reductions in employee training expenses, and

 * a $0.5 million decrease in material and operating supply expenses
   mainly related to boiler maintenance expenses incurred in the
   third quarter of 2008.

 * At DMI, revenues decreased $28.6 million mainly as a result of
   lower volumes of wind towers being sold related to the 2009
   slowdown of installed megawatts of wind energy, but net income
   increased by $0.9 million as a result of improved productivity
   and cost control measures implemented in 2009. Also, in the third
   quarter of 2008, DMI's costs of goods sold included $1.5 million
   related to start-up inefficiencies at its Oklahoma plant.

 * At BTD, revenues decreased $14.5 million and net income was
   down $2.4 million as a result of a decline in sales volume.

 * At T.O. Plastics, revenues decreased $2.1 million and net income
   was down $0.3 million as a result of lower sales volume.

 * At ShoreMaster, revenues decreased $6.6 million while net losses
   decreased $1.5 million. The decrease in revenues mainly reflects
   revenues recognized on a commercial construction project in the
   third quarter of 2008. Revenues also decreased as a result of a
   reduction in sales of residential products between the quarters.
   ShoreMaster's net loss in the third quarter of 2008 included a
   $0.8 million after-tax loss from the operation and closure of a
   production facility in California. Additional cuts in operating
   and sales expenses of $1.5 million also contributed to the
   reduction in net losses at ShoreMaster.

 * The corporation now expects 2009 earnings from its electric
   segment to be lower than 2008 electric segment earnings. The
   corporation's expectations for earnings from its electric
   segment have been revised downward due to the negative impact
   of milder weather conditions in the third quarter, softness in
   demand from commercial and industrial customers and lower
   volumes and margins from wholesale energy sales. Declining
   demand along with the lowest natural gas prices in years are
   having a dramatic impact on the volume and price that can be
   realized from sales of excess generation into the marketplace.
   While 2009 earnings are expected to be impacted by lower than
   requested electric revenue increases in North Dakota and South
   Dakota and lower volumes and margins from wholesale energy sales,
   OTP has benefited from continued cost reduction efforts and higher
   than expected earnings from the allowance for funds used during
   construction related to construction of its Luverne Wind Farm.

 * The corporation expects its plastics segment's 2009 performance
   to be below 2008 earnings, given continued poor economic
   conditions.

 * The corporation now expects its manufacturing segment to post a
   net loss in 2009 as a result of the following:
    -- BTD continued to experience unexpected declines in customer
       demand in the third quarter of 2009 and expects soft demand
       to continue for the rest of the year resulting in lower
       earnings compared with 2008.
    -- While spending on waterfront products is expected to decline
       in the current economy, a reduction in net loss compared
       with 2008 is expected at ShoreMaster given the restructuring
       that has occurred in its business. ShoreMaster has implemented
       significant cost reductions across the organization, reduced
       capital spending and reorganized its business units for more
       efficient operations. ShoreMaster continues to experience
       performance issues on a marina construction project which is
       having a negative effect on its results of operations.
    -- DMI's earnings in 2009 are now expected to be in line with
       its 2008 earnings, despite the sluggish economy, as a result
       of expense reductions and productivity improvements.
    -- T.O. Plastics' expects slightly lower earnings in 2009
       compared with 2008. While T.O. Plastics expects economic
       challenges to continue, it has implemented cost reductions
       and efficiency projects to maintain profitability.
    -- Backlog in place in the manufacturing segment to support
       revenues for the remainder of 2009 is approximately $61
       million compared with $131 million one year ago.

 * The corporation now expects its health services segment to record
   a net loss in 2009. Cost reductions implemented in 2009 have not
   been enough to offset the impact of low utilization of the
   current fleet of imaging assets.  The health services segment
   leases its imaging assets.  These leases expire at various dates
   from 2010 through 2014.

 * The corporation expects increased net income from its food
   ingredient processing business in 2009 based on expectations
   of higher sales volumes, lower energy costs and higher
   production levels in 2009 compared with 2008.

 * The corporation expects its other business operations segment to
   have lower earnings in 2009 compared with 2008. The decline in
   construction projects in 2009 due to poor economic conditions
   has negatively affected the corporation's construction companies.
   The corporation's trucking operations continue to be impacted by
   lower selling prices and volumes in its heavy haul business.
   Backlog in place for the corporation's construction businesses
   is $25 million for the remainder of 2009 compared with $48 million
   one year ago.

 * The corporation expects corporate general and administrative
   costs to decrease in 2009.

 * The corporation is subject to federal and state legislation,
   regulations and actions that may have a negative impact on its
   business and results of operations.

 * Federal and state environmental regulation could cause the
   corporation to incur substantial capital expenditures and
   increased operating costs.

 * Volatile financial markets and changes in the corporation's debt
   rating could restrict its ability to access capital and could
   increase borrowing costs and pension plan expenses. Disruptions,
   uncertainty or volatility in the financial markets can also
   adversely impact the corporation's results of operations, the
   ability of its customers to finance purchases of goods and
   services, and its financial condition as well as exert downward
   pressure on stock prices and/or limit its ability to sustain its
   current common stock dividend level.

 * The value of the corporation's defined benefit pension plan
   assets declined significantly during 2008 due to volatile
   equity markets. The corporation made a $4 million discretionary
   contribution to the pension plan in 2009. If the market value
   of pension plan assets declines or does not increase as projected
   and relief under the Pension Protection Act is no longer granted,
   the corporation could be required to contribute additional capital
   to the pension plan in future years.

 * A sustained decline in the corporation's common stock price
   below book value or declines in projected operating cash flows
   at any of its operating companies may result in goodwill
   impairments that could adversely affect its results of
   operations and financial position, as well as credit facility
   covenants.

 * Any significant impairment of the corporation's goodwill would
   cause a decrease in its asset values and a reduction in its net
   operating performance.

 * Economic conditions could negatively impact the corporation's
   businesses.

 * If the corporation is unable to achieve the organic growth it
   expects, its financial performance may be adversely affected.

 * The corporation's plans to grow and diversify through
   acquisitions and capital projects may not be successful and
   could result in poor financial performance.

 * The corporation's plans to acquire additional businesses and grow
   and operate its nonelectric businesses could be limited by state
   law.

 * The terms of some of the corporation's contracts could expose it
   to unforeseen costs and costs not within its control, which may
   not be recoverable and could adversely affect its results of
   operations and financial condition.

 * The corporation is subject to risks associated with energy
   markets.

 * Certain of the corporation's operating companies sell products
   to consumers that could be subject to recall.

 * Competition is a factor in all of the corporation's businesses.

 * The corporation may experience fluctuations in revenues and
   expenses related to its electric operations, which may cause
   its financial results to fluctuate and could impair its ability
   to make distributions to its shareholders or scheduled payments
   on its debt obligations.

 * On September 11, 2009 OTP announced its withdrawal -- both as a
   participating utility and as the project's lead developer -- from
   Big Stone II, due to many factors, including economic risks and
   uncertainty associated with proposed federal climate legislation
   and existing federal environmental regulations, that made
   proceeding with Big Stone II and committing to $400 million in
   capital expenditures untenable for OTP customers and our
   shareholders. As of September 30, 2009, OTP had incurred $13.6
   million in costs related to this project. OTP believes these
   incurred costs are probable of recovery in future rates and has
   deferred recognition of these costs as operating expenses pending
   determination of recoverability by the state and federal
   regulatory commissions that approve OTP's rates. However, if OTP
   is denied recovery of all or any portion of these deferred costs,
   such costs would be subject to expense in the period they are
   deemed to be unrecoverable.

 * Actions by the regulators of the electric segment could result
   in rate reductions, lower revenues and earnings or delays in
   recovering capital expenditures.

 * Future operating results of the electric segment will be impacted
   by the outcome of rate rider filings in Minnesota for transmission
   investments.

 * OTP could be required to absorb a disproportionate share of
   costs for investments in transmission infrastructure required
   to provide independent power producers access to the transmission
   grid. These costs may not be recoverable through a transmission
   tariff and could result in reduced returns on invested capital
   and/or increased rates to OTP's retail electric customers.

 * OTP's electric generating facilities are subject to operational
   risks that could result in unscheduled plant outages,
   unanticipated operation and maintenance expenses and increased
   power purchase costs.

 * Wholesale sales of electricity from excess generation could be
   affected by reductions in coal shipments to the Big Stone and
   Hoot Lake plants due to supply constraints or rail
   transportation problems beyond the corporation's control.

 * Existing or new laws or regulations addressing climate change
   or reductions of greenhouse gas emissions by federal or state
   authorities, such as mandated levels of renewable generation
   or mandatory reductions in carbon dioxide (CO2) emission levels,
   taxes on CO2 emissions or cap and trade regimes, that result
   in increases in electric service costs could negatively impact
   the corporation's net income, financial position and operating
   cash flows if such costs cannot be recovered through rates granted
   by ratemaking authorities in the states where OTP provides service
   or through increased market prices for electricity.

 * The corporation's plastics segment is highly dependent on a
   limited number of vendors for PVC resin, many of which are
   located in the Gulf Coast regions, and a limited supply of resin.
   The loss of a key vendor or an interruption or delay in the
   supply of PVC resin could result in reduced sales or increased
   costs for this business. Reductions in PVC resin prices could
   negatively impact PVC pipe prices, profit margins on PVC pipe
   sales and the value of PVC pipe held in inventory.

 * The corporation's plastic pipe companies compete against a
   large number of other manufacturers of PVC pipe and manufacturers
   of alternative products. Customers may not distinguish the pipe
   companies' products from those of its competitors.

 * Competition from foreign and domestic manufacturers, the price
   and availability of raw materials, fluctuations in foreign
   currency exchange rates and general economic conditions could
   affect the revenues and earnings of the corporation's
   manufacturing businesses.

 * Changes in the rates or method of third-party reimbursements
   for diagnostic imaging services could result in reduced demand
   for those services or create downward pricing pressure, which
   would decrease revenues and earnings for the corporation's health
   services segment.

 * The corporation's health services businesses may be unable to
   continue to maintain agreements with Philips Medical from which
   the businesses derive significant revenues from the sale and
   service of Philips Medical diagnostic imaging equipment.

 * Technological change in the diagnostic imaging industry could
   reduce the demand for diagnostic imaging services and require
   the corporation's health services operations to incur significant
   costs to upgrade their equipment.

 * Actions by regulators of the corporation's health services
   operations could result in monetary penalties or restrictions in
   the corporation's health services operations.

 * The corporation's food ingredient processing segment operates in
   a highly competitive market and is dependent on adequate sources
   of raw materials for processing. Should the supply of these raw
   materials be affected by poor growing conditions, this could
   negatively impact the results of operations for this segment.

 * The corporation's food ingredient processing business could be
   adversely affected by changes in foreign currency exchange
   rates.

 * A significant failure or an inability to properly bid or perform
   on projects by the corporation's construction or manufacturing
   businesses could lead to adverse financial results.

                        Otter Tail Corporation
                  Consolidated Statements of Income
   For the Three and Nine Months Ended September 30, 2009 and 2008
           In thousands, except share and per share amounts
                            (not audited)

                            Quarter Ended            Year-to-Date
                             September 30,           September 30,
                           2009        2008        2009        2008
 Operating Revenues by
  Segment:
  Electric              $   73,553  $   82,883  $  232,757  $  249,139
  Plastics                  27,353      36,690      63,066      99,685
  Manufacturing             75,928     127,778     248,790     345,715
  Health Services           27,053      31,139      83,412      91,144
  Food Ingredient
   Processing               18,691      15,333      59,358      47,144
  Other Business
   Operations               36,123      59,650      97,615     145,840
  Corporate Revenue and
   Intersegment
   Eliminations             (1,261)       (554)     (3,462)     (1,911)
                        ----------  ----------  ----------  ----------
   Total Operating
    Revenues               257,440     352,919     781,536     976,756
 
 Operating Expenses:
  Fuel and Purchased
   Power                    24,284      29,188      83,947      93,042
  Nonelectric Cost of
   Goods Sold
   (depreciation
   included below)         141,318     213,999     429,598     583,457
  Electric Operating
   and Maintenance
   Expense                  25,521      35,318      86,155      95,005
  Nonelectric Operating
   and Maintenance
   Expense                  30,476      37,222      93,520     108,211
  Product Recall and
   Testing Costs                --          --       1,766          --
  Plant Closure Costs           --         883          --       2,295
  Depreciation and
   Amortization             18,345      16,563      54,265      47,600
                        ----------  ----------  ----------  ----------
   Total Operating
    Expenses               239,944     333,173     749,251     929,610
 
 Operating Income (Loss)
  by Segment:
  Electric                  14,733      10,513      35,654      37,714
  Plastics                   2,372       3,096        (890)      5,685
  Manufacturing              1,740       3,059       1,959       8,198
  Health Services           (1,020)        614      (1,151)       (254)
  Food Ingredient
   Processing                3,061      (1,644)      9,258       1,346
  Other Business
   Operations                 (223)      7,626      (2,880)      6,570
  Corporate                 (3,167)     (3,518)     (9,665)    (12,113)
                        ----------  ----------  ----------  ----------
   Total Operating
    Income                  17,496      19,746      32,285      47,146
 
 Interest Charges            7,358       7,269      20,280      21,023
 Other Income                1,609       1,157       3,627       2,745
 Income Taxes                1,155       4,003      (2,079)      7,490
 
 Net Income (Loss) by
  Segment
  Electric                   9,527       6,519      22,448      22,545
  Plastics                   1,298       1,641        (869)      2,913
  Manufacturing                100         380      (1,157)      1,160
  Health Services             (649)        254        (875)       (525)
  Food Ingredient
   Processing                1,772      (1,074)      5,544         734
  Other Business
   Operations                 (205)      4,341      (1,986)      3,370
  Corporate                 (1,251)     (2,430)     (5,394)     (8,819)
                        ----------  ----------  ----------  ----------
 Total Net Income           10,592       9,631      17,711      21,378
 Preferred Stock
  Dividend                     184         184         552         552
                        ----------  ----------  ----------  ----------
 Balance for Common:    $   10,408  $    9,447  $   17,159  $   20,826
                        ==========  ==========  ==========  ==========
 Average Number of
  Common Shares
  Outstanding:
  Basic                 35,528,190  30,513,578  35,413,893  30,108,381
  Diluted               35,788,293  30,817,013  35,670,244  30,398,235
 
 Earnings Per Common
  Share:
  Basic                 $     0.29  $     0.31  $     0.48  $     0.69
  Diluted               $     0.29  $     0.31  $     0.48  $     0.69


                        Otter Tail Corporation
                     Consolidated Balance Sheets
                                Assets
                             In thousands
                            (not audited)

                                            September 30, December 31,
                                                2009          2008

 Current Assets
 Cash and Cash Equivalents                  $      6,066  $      7,565
 Accounts Receivable:
  Trade--Net                                     111,737       136,609
  Other                                            8,731        13,587
 Inventories                                      84,000       101,955
 Deferred Income Taxes                             8,411         8,386
 Accrued Utility and Cost-of-Energy Revenues      10,572        24,030
 Costs and Estimated Earnings in Excess of
  Billings                                        44,141        65,606
 Income Taxes Receivable                           9,200        26,754
 Other                                            20,086         8,519
                                            ------------  ------------
  Total Current Assets                           302,944       393,011
                                            ------------  ------------
 
 Investments                                       9,019         7,542
 Other Assets                                     42,979        22,615
 Goodwill                                        106,778       106,778
 Other Intangibles--Net                           34,279        35,441

 Deferred Debits
 Unamortized Debt Expense and Reacquisition
  Premiums                                         9,488         7,247
 Regulatory Assets and Other Deferred Debits      98,813        82,384
                                            ------------  ------------
  Total Deferred Debits                          108,301        89,631
                                            ------------  ------------

 Plant
 Electric Plant in Service                     1,322,059     1,205,647
 Nonelectric Operations                          350,147       321,032
                                            ------------  ------------
  Total                                        1,672,206     1,526,679
 Less Accumulated Depreciation and
  Amortization                                   588,527       548,070
                                            ------------  ------------
 Plant--Net of Accumulated Depreciation and
  Amortization                                 1,083,679       978,609
 Construction Work in Progress                    50,024        58,960
                                            ------------  ------------
  Net Plant                                    1,133,703     1,037,569
                                            ------------  ------------

   Total                                    $  1,738,003  $  1,692,587
                                            ============  ============


                        Otter Tail Corporation
                     Consolidated Balance Sheets
                        Liabilities and Equity
                             In thousands
                            (not audited)

                                            September 30, December 31,
                                                2009          2008

 Current Liabilities
 Short-Term Debt                            $    122,500  $    134,914
 Current Maturities of Long-Term Debt              1,275         3,747
 Accounts Payable                                100,142       113,422
 Accrued Salaries and Wages                       21,476        29,688
 Accrued Taxes                                    10,092        10,939
 Other Accrued Liabilities                        16,130        12,034
                                            ------------  ------------
  Total Current Liabilities                      271,615       304,744
                                            ------------  ------------

 Pensions Benefit Liability                       79,781        80,912
 Other Postretirement Benefits Liability          34,076        32,621
 Other Noncurrent Liabilities                     21,641        19,391

 Deferred Credits
 Deferred Income Taxes                           116,705       123,086
 Deferred Tax Credits                             48,297        34,288
 Regulatory Liabilities                           66,855        64,684
 Other                                               829           397
                                            ------------  ------------
  Total Deferred Credits                         232,686       222,455
                                            ------------  ------------

 Capitalization
 Long-Term Debt, Net of Current Maturities       411,309       339,726
 Class B Stock Options of Subsidiary               1,220         1,220

 Cumulative Preferred Shares                      15,500        15,500

 Cumulative Preference Shares                         --            --

 Common Shares, Par Value $5 Per Share           178,417       176,923
 Premium on Common Shares                        246,948       241,731
 Retained Earnings                               245,836       260,364
 Accumulated Other Comprehensive Loss             (1,026)       (3,000)
                                            ------------  ------------
  Total Common Equity                            670,175       676,018
                                            ------------  ------------

   Total Capitalization                        1,098,204     1,032,464
                                            ------------  ------------

    Total                                   $  1,738,003  $  1,692,587
                                            ============  ============


                        Otter Tail Corporation
                Consolidated Statements of Cash Flows
                             In thousands
                            (not audited)

                                                   Nine Months Ended
                                                     September 30,
                                                   2009        2008
                                                ----------  ----------

 Cash Flows from Operating Activities
  Net Income                                    $   17,711  $   21,378
  Adjustments to Reconcile Net Income to Net
   Cash Provided by Operating Activities:
   Depreciation and Amortization                    54,265      47,600
   Deferred Tax Credits                             (1,666)     (1,180)
   Deferred Income Taxes                             8,243       9,123
   Change in Deferred Debits and Other Assets       (2,909)     (2,162)
   Discretionary Contribution to Pension Plan       (4,000)     (2,000)
   Change in Noncurrent Liabilities and
    Deferred Credits                                 7,497       1,795
   Allowance for Equity (Other) Funds Used
    During Construction                             (2,940)     (1,712)
   Change in Derivatives Net of Regulatory
    Deferral                                        (1,512)       (337)
   Stock Compensation Expense                        2,664       2,885
   Other--Net                                          736         580
  Cash Provided by (Used for) Current Assets
   and Current Liabilities:                             --          --
   Change in Receivables                            29,993     (24,314)
   Change in Inventories                            18,721      (9,054)
   Change in Other Current Assets                   29,329      (8,165)
   Change in Payables and Other Current
    Liabilities                                    (32,506)      4,997
   Change in Interest and Income Taxes
    Payable/Receivable                              16,953         810
                                                ----------  ----------
    Net Cash Provided by Operating Activities      140,579      40,244

 Cash Flows from Investing Activities
  Capital Expenditures                            (150,138)   (172,237)
  Proceeds from Disposal of Noncurrent Assets        4,730       7,446
  Acquisitions--Net of Cash Acquired                    --     (41,674)
  Net Increase in Other Investments and
   Long-Term Assets                                (20,805)       (393)
                                                ----------  ----------
   Net Cash Used in Investing Activities          (166,213)   (206,858)

 Cash Flows from Financing Activities
  Net Short-Term Borrowings                        (12,414)     16,955
  Proceeds from Issuance of Common Stock             4,637     162,961
  Common Stock Issuance Expenses                       (23)     (6,136)
  Payments for Retirement of Common Stock             (229)        (91)
  Proceeds from Issuance of Long-Term Debt          75,005       1,140
  Short-Term and Long-Term Debt Issuance
   Expenses                                         (3,693)       (527)
  Payments for Retirement of Long-Term Debt         (5,983)     (2,691)
  Dividends Paid                                   (32,239)    (27,382)
                                                ----------  ----------
   Net Cash Provided by Financing Activities        25,061     144,229

 Effect of Foreign Exchange Rate Fluctuations
  on Cash                                             (926)        423
                                                ----------  ----------
 Net Change in Cash and Cash Equivalents            (1,499)    (21,962)
 Cash and Cash Equivalents at Beginning of
  Period                                             7,565      39,824
                                                ----------  ----------
 Cash and Cash Equivalents at End of Period     $    6,066  $   17,862
                                                ==========  ==========

CONTACT:  Otter Tail Corporation
          Media contact:
          Michael J. Olsen, VP of Corporate Communications
            (701) 451-3580
            (866) 410-8780
          Investor contact:
          Loren Hanson, Director of Shareholder Services 
            (218) 739-8481 
            (800) 664-1259

Black Hills Corp. Reports Third Quarter 2009 Results, Announces Quarterly Dividend and Provides Earnings Guidance(10/29/2009)  Back to Table of Contents

GROWTH PROJECTS ON TARGET AND SHORT TERM DEBT REFINANCED

RAPID CITY, SD - October 29, 2009 - Black Hills Corp. (NYSE: BKH) today announced third quarter 2009 financial results. Loss from continuing operations for the third quarter 2009 was $3.9 million, or $0.10 per share, compared to income from continuing operations for the third quarter 2008 of $19.5 million, or $0.51 per share. Net loss for the three months ended Sept. 30, 2009, was $2.2 million, or $0.06 per share compared to net income of $164.9 million or $4.29 per share for the same period in 2008. The 2009 quarterly results include a $5.7 million, or $0.15 per share non-cash mark-to-market loss for certain interest rate swaps.

For the nine months ended Sept. 30, 2009, income from continuing operations was $46.4 million, or $1.20 per share, compared to $44.5 million, or $1.16 per share for the same period ended Sept. 30, 2008. Net income for the nine months ended Sept. 30, 2009, was $48.8 million, or $1.26 per share, compared to $203.9 million, or $5.31 per share, reported for the same period in 2008. The 2009 results include a $24.6 million or $0.64 per share non-cash mark-to-market gain for certain interest rate swaps; a $16.9 million, or $0.44 per share, gain on the sale of a 23.5 percent ownership interest in the Wygen I power generation facility; and a $27.8 million, or $0.72 per share, non-cash ceiling test impairment charge.

"We made substantial progress during the third quarter on key strategic growth initiatives. However, continued low natural gas prices reduced income from our oil and gas and energy marketing businesses and lower off-system sales margins for our electric utilities. We are not satisfied with our bottom-line results in 2009, but as our guidance for 2010 indicates, we are confident that planned capital expenditures will lead to strong earnings growth in the coming years," said David R. Emery, chairman, president and CEO of Black Hills Corp. "Our employees continue to make great progress on our strategic and integration projects that strengthen our balance sheet, increase our asset base and improve operating efficiencies for the long-term benefit of our customers and shareholders. We recently completed a $180 million first mortgage bond offering at very favorable rates, reducing short-term debt. With the completion of a 20-year power purchase agreement with Black Hills Energy - Colorado Electric, we now have plans to invest approximately $1 billion in growth capital through 2011."

• Black Hills Power filed two independent requests for electric revenue increases with the South Dakota Public Utility Commission and the Wyoming Public Service Commission to recover costs associated with the Wygen III power plant under construction near Gillette, Wyo., other generation, transmission and distribution assets and increased operating expenses.
• In the South Dakota request, Black Hills Power seeks a $32 million increase in annual utility revenues and anticipates new rates will be effective for South Dakota customers on April 1, 2010.
• In the Wyoming request, Black Hills Power seeks a $3.8 million
• increase in annual utility revenues and anticipates new rates will be effective for Wyoming customers in 2010.
• Construction of the Wygen III generation facility project is under
• budget and scheduled to begin commercial operation as early as April 1, 2010, three months earlier than originally expected. A 25 percent ownership interest in this generation facility was sold in April 2009.
• Plans to construct utility-owned gas-fired generation facilities to
• serve Black Hills Energy - Colorado Electric customers are moving forward. Equipment has been ordered, and construction is expected to begin in third quarter 2010 with an in-service date of January 2012. Hearings regarding the certificate of public convenience and necessity, filed in June 2009, are expected to occur in December 2009.
• Black Hills Colorado IPP, a non-regulated subsidiary of the company,
• was selected to provide power to Black Hills Energy - Colorado Electric through a competitive bid process. BHCI will build 200 megawatts of natural gas-fired electric generation in Colorado to sell to Black Hills Energy - Colorado Electric through a 20-year power purchase agreement. The BHCI facility is expected to cost $240 million to $265 million and be ready to deliver power by Jan. 1, 2012.
• Black Hills Wyoming, a subsidiary of the company, extended its 60 megawatts power purchase agreement with Cheyenne Light from the original termination date of March 31, 2013, until Dec. 31, 2022. Black Hills Wyoming will continue to provide the capacity and associated energy from the Wygen I generation facility.
• Black Hills Energy - Colorado Electric, Black Hills Power and Cheyenne Light were selected by the Department of Energy for smart grid investment grant funding totaling $16.7 million. The DOE funds are made available under the American Recovery and Reinvestment Act of 2009 and are subject to negotiation of final terms with the DOE. The funds would enable the installation of about 149,000 smart meters in the company's Colorado, South Dakota and Wyoming electric utility service territories.
• Cheyenne Light began receiving wind power from the recently
• commissioned Silver Sage wind generation facility on Oct. 1. Combined with the wind energy received under a previously completed renewable energy sales agreement with the Happy Jack wind generation facility, up to 60 megawatts of wind energy is being purchased by the utility. Under separate power purchase agreements, Black Hills Power purchases 35 megawatts of the wind energy from Cheyenne Light.

Compared to the third quarter of 2008, income from continuing operations in the third quarter of 2009 reflects the following:

Utilities
$0.2 million decrease in electric utility earnings
$1.6 million decrease in gas utility earnings

Non-regulated Energy
$1.2 million increase in coal mining earnings
$1.7 million decrease in oil and gas earnings
$2.6 million decrease in power generation earnings
$11.3 million decrease in energy marketing earnings

$7.0 million decrease in corporate earnings

"We expect a significant improvement in our financial performance next year. Continued execution of our strategy combined with an improving business climate and strengthening natural gas prices will lead to the strong earnings growth our shareholders expect from Black Hills," Emery said.

EARNINGS GUIDANCE

• $16.9 million, or $0.44 per share, gain on the sale of a 23.5 percent ownership interest in the Wygen I power generation facility;
• $24.6 million, or $0.64 per share, non-cash mark-to-market gain for certain interest rate swaps that remain in place with no additional mark-to-market earnings impacts estimated in the fourth quarter;
• $27.8 million, or $0.72 per share, oil and gas non-cash ceiling test impairment charge; no further ceiling test impairment charge anticipated;
• Normal operations and weather conditions in utility service
• territories impacting customer usage, off-system sales, construction, maintenance and/or capital investment projects;
• No significant unplanned outages at the company's power generation facilities for remainder of 2009;
• Slight earnings improvement from energy marketing during fourth
• quarter compared to first nine months of 2009;
• Total oil and natural gas production of 12.3 to 12.6 Bcf equivalent. Forecasted production includes the impacts of approximately 0.4 Bcfe shut-in due to low commodity prices;
• Oil and gas average NYMEX prices for October 2009 through December
• 2009 of $4.78 per Mcf for natural gas and $78.16 per Bbl for oil; production-weighted average well-head prices of $3.86 per Mcf and $70.08 per Bbl, all based on forward strips, and average hedged prices of $5.21 per Mcf and $70.36 per Bbl; and
• No significant acquisitions or divestitures. In 2010, Black Hills expects earnings from continuing operations to be in the range of $1.80 to $2.05 per share. This estimate is predicated on a number of considerations, including the following:
• Planned capital expenditures in 2010 estimated at $425 million to $475 million; including oil and gas capital expenditures of $30 million to $40 million assuming slight recovery in natural gas prices;
• Planned debt and equity financings to maintain a capital structure in
• the range of 50 percent to 55 percent debt to total capitalization;
• Previously disclosed undesignated long-term debt hedges remain in
• place with no additional mark-to-market impacts from Sept. 30, 2009;
• Normal operations and weather conditions within utility service territories impacting customer usage, off-system sales, construction, maintenance and/or capital investment projects;
• Commercial operation of the Wygen III power plant as planned on April 1, 2010;
• Increased earnings at our electric and gas utilities with successful completion of pending and potential rate requests;
• No significant unplanned outages at any of company's power generation facilities;
• Strong earnings recovery from energy marketing due to improved natural
• gas prices and market conditions;
• Total oil and natural gas production in range of 11.3 to 11.9 Bcfe;
• Oil and gas annual average NYMEX prices of $5.93 per Mcf for natural
• gas and $82.60 per Bbl for oil; production-weighted average well-head prices of $4.70 per Mcf and $73.85 per Bbl, all based on forward strips, and average hedged prices of $5.24 per Mcf and $77.70 per Bbl; and
• No additional significant acquisitions or divestitures.

On Oct. 29, 2009, the board of directors declared a quarterly dividend on the common stock. Common shareholders will receive $0.355 per share. Dividends will be payable Dec. 1, 2009, to all shareholders of record at the close of business on Nov. 17, 2009.

The company will host a conference call and webcast at 11 a.m. EDT on Friday, Oct. 30, to discuss financial and operating performance. To listen to the live broadcast, call 888-423-3268. To access the live webcast and download a copy of the investor presentation, go to the Black Hills site at www.blackhillscorp.com and click "Webcast" in the "Investor Relations" section. The presentation will be posted on the site prior to the webcast. Listeners should allow at least five minutes for registering and accessing the presentation. For those unable to listen to the live broadcast, a replay will be available by telephone through Nov. 6, 2009, at 800-475-6701 in the United States and at 320-365-3844 for international callers. Callers need to enter the access code 119392# when prompted.

NorthWestern Reports 3rd Quarter 2009 Financial Results(10/29/2009)  Back to Table of Contents

Department of Energy Selects Three Black Hills Electric Utilities for Smart Grid Project Funding(10/28/2009)  Back to Table of Contents

Black Hills electric utility customers in Colorado, South Dakota and Wyoming can benefit from new technology

RAPID CITY, S.D., Oct. 28, 2009 - Black Hills Corp. (NYSE: BKH) announced today that the Department of Energy has selected each of its electric utility subsidiaries, Black Hills Energy - Colorado Electric, Black Hills Power and Cheyenne Light, Fuel & Power, for smart grid investment grant funding totaling $16.7 million. The DOE funds are made available under the American Recovery and Reinvestment Act of 2009 and subject to negotiation of final terms and conditions between the company and the DOE. If negotiations are successful, the funds will enable the installation of about 149,000 smart meters and related infrastructure associated with specific projects in the company's Colorado, South Dakota and Wyoming electric service territories.

Specifically, Black Hills Energy - Colorado Electric received preliminary approval for $6.1 million in matching funds for the installation of an additional 42,000 smart meters and communications infrastructure that will help facilitate automated meter reading and provide a pilot for a dynamic pricing program in their southeastern Colorado service area. Black Hills Power received preliminary approval for $5.6 million in funds toward the installation of 69,000 smart meters, along with the communications infrastructure, IT software and equipment necessary to initiate a smart grid system in their service area in western South Dakota and Wyoming. Cheyenne Light received preliminary approval for $5 million in matching funds toward the installation of 38,000 smart meters and communications infrastructure that will provide the foundation for consumers to better monitor their energy consumption in and around Cheyenne, Wyo.

"We are pleased that our three electric utility applications were among the 100 selected by the DOE for funding and were chosen from the more-than 400 that were submitted for review," said David R. Emery, chairman, president and chief executive officer of Black Hills Corp. "We will evaluate the Department of Energy's proposal and hope to move forward with projects that will benefit our customers, communities and shareholders."

A total of $3.4 billion was awarded by the DOE as part of the American Reinvestment and Recovery Act of 2009. These funds will be matched by additional industry funding for a total public-private investment worth more than $8 billion. The DOE expects to hold briefings with those who received funding notices during the week of Nov. 16, and then, one-on-one negotiations will begin. Grant recipients can expect questions and comments about their project applications that will help determine the final award amounts and other details. In Colorado, South Dakota and Wyoming, the Black Hills Corp. subsidiaries were the only investor-owned electric utilities selected to receive the DOE funding.

PUC Chairman Johnson to testify before U.S. Senate committee(10/26/2009)  Back to Table of Contents

PIERRE, S.D. – Dusty Johnson, chairman of the South Dakota Public Utilities Commission, will testify before the U.S. Senate Committee on Environment and Public Works in Washington, D.C., on Wednesday, Oct. 28 about the effect proposed federal carbon legislation will have on South Dakotans.

The committee will hold a three-day hearing on the Clean Energy Jobs and American Power Act, also known as the Kerry-Boxer bill. Johnson joins a host of leaders scheduled to testify that includes presidential cabinet secretaries Steven Chu, Dept. of Energy; Ray LaHood, Dept. of Transportation; and Ken Salazar, Dept. of Interior; as well industry experts such as Dan Richer, director of Google's climate and energy initiatives and Bill Klesse, chairman and CEO of Valero Energy Corp.

Johnson's testimony focuses on the consumer impact proposed carbon legislation will have on residents of South Dakota and other Midwestern states. The PUC estimates the legislation would increase the bills of many South Dakotans by 25 percent as soon as 2012. An impact of that size would pull more than a quarter billion dollars a year out of South Dakota. "I understand the desire to reduce our carbon footprint, and I think we should. But the climate change legislation pending is not the right approach," Johnson said.

Substantially burdensome costs, negative impact on domestic energy production and unfair distribution of allowances are among the main points Johnson will stress in his presentation to the senate. "This climate change legislation is complex and complicated," Johnson said. "But the effect it would have on South Dakotans and others in the heartland is simple and severe: higher energy costs, restrictive controls on our energy producers and a redistribution of wealth from our states to the coastal states," he said.

Testifying before the Committee on Environment and Public Works gives Johnson the opportunity to speak directly to one of the bill's authors, Sen. Barbara Boxer of California who chairs the committee. "This bill is blatantly unfair to the Midwest, and is more about politics than the environment. Rather than deal with our carbon problems by investing in energy efficiency and new technologies, this bill focuses on transferring wealth. The bill would give California 12 million more carbon allowances than it needs for compliance while South Dakota would face a 3 million-allowance shortfall. California would be able to turn around and sell their excess credits to South Dakota, realizing tens of millions of dollars in windfall profits," Johnson said. "Utility companies don't pay these bills, consumers do."

To view a live Web cast of this hearing at 9:30 a.m. EDT (8:30 a.m. CDT/7:30 a.m. MDT) on Wednesday, Oct. 28, go to http://epw.senate.gov/public/ click on the "Live Hearing" link. Chairman Johnson is expected to testify sometime around 1 p.m. EDT (Noon CDT/11 a.m. MDT).

MDU Resources to Present at Edison Electric Institute Financial Conference(10/23/2009)  Back to Table of Contents

BISMARCK, N.D. - Oct. 23, 2009 - MDU Resources Group, Inc. (NYSE:MDU) will present at the EEI Financial Conference on Tuesday, Nov. 3 at 10:30 a.m. EST. The live audio webcast can be accessed at www.mdu.com. A webcast replay will be available.

MDU Resources Group, Inc., a Fortune 500 company and a member of the S&P MidCap 400 index, provides value added natural resource products and related services that are essential to energy and transportation infrastructure, operating in three core lines of business: utility resources, energy and construction materials. MDU Resources includes electric and natural gas utilities, construction services, natural gas and oil production, natural gas pipelines and energy services, and construction materials and contracting. For more information about MDU Resources, see the company's Web site at www.mdu.com or contact the Investor Relations Department at investor@mduresources.com.

Energy Smart helps make state among "most improved"(10/23/2009)  Back to Table of Contents

PIERRE, S.D. – South Dakota's energy efficiency ranking took a giant leap upward, landing it in the most improved category in a newly released American Council for an Energy Efficient Economy survey. Other states in this category are Delaware, Colorado and Tennessee.

South Dakota moved to 36th from its 47th rank of a year ago, according to the efficiency advocacy organization. This ranking follows several energy efficiency efforts undertaken by the South Dakota Public Utilities Commission and utilities in the state. The study takes into account items such as utility efficiency programs, building codes, and appliance and transportation standards.

"The Public Utilities Commission and the state's energy providers launched South Dakota Energy Smart in 2007 with the goal of recognizing and promoting energy efficiency," PUC Chairman Dusty Johnson stated. "This initiative was the start of a comprehensive plan to enhance energy efficiency, to the benefit of South Dakotans. This new ranking is evidence that the program is already paying off and gaining support. Although this news is encouraging, we expect the Energy Smart partnership to pay even bigger dividends in the future."

"The Energy Smart partnership has encouraged valuable projects that save both energy and money," according to PUC Vice Chairman Steve Kolbeck. "Our partners are following through with their pledges of two years ago to provide worthwhile energy efficiency programs. Just this week, the commission approved an expanded energy efficiency program offered by one of the state's utilities, providing new options for consumers to save energy."

PUC Commissioner Gary Hanson said, "Energy Smart is a resource for consumers to help them make wise, worthwhile energy choices. We all know fossil fuels are limited, and we must move forward to find other energy sources and efficiencies before these sources are depleted. Smart energy use benefits all of us and our environment. ACEEE's scorecard acknowledges our partnership's efforts, moving us past 11 states in one year."

Partnering organizations included in South Dakota Energy Smart are Black Hills Power, MidAmerican Energy Co., Montana-Dakota Utilities Co., NorthWestern Energy, Otter Tail Power Co., Xcel Energy, Heartland Consumers Power District, Missouri River Energy Services, the South Dakota Municipal Electric Association, the South Dakota Rural Electric Association and the PUC. More than 30 additional South Dakota organizations are supporters of the program. For a complete list of these organizations, go to www.SDEnergySmart.com.

Black Hills Corp. Schedules Third Quarter 2009 Financial Results Conference Call and Webcast(10/22/2009)  Back to Table of Contents

RAPID CITY, SD - October 22, 2009 - Black Hills Corporation (NYSE: BKH) announced today that it will issue a news release regarding 2009 third quarter results on Thursday, Oct. 29, 2009, and host a live conference call and webcast at 11 a.m. ET on Friday, Oct. 30 to discuss financial and operating performance.

To listen to the live broadcast, call 888-423-3268. To access the live webcast and download a copy of the investor presentation, go to the Black Hills web site at www.blackhillscorp.com and click "Webcast" in the "Investor Relations" section. The presentation will be posted on the web site prior to the webcast. Listeners should allow at least five minutes for registering and accessing the presentation. For those unable to listen to the live broadcast, a replay will be available by telephone through Nov. 6, 2009, at 800-475-6701 in the United States and at 320-365-3844 for international callers. Callers need to enter the access code 119392# when prompted.

Black Hills Power Prices $180 Million of First Mortgage Bonds(10/22/2009)  Back to Table of Contents

RAPID CITY, SD - October 22, 2009 - Black Hills Corp. (NYSE: BKH) announced today that Black Hills Power, an electric utility subsidiary of Black Hills Corp., priced a $180 million bond offering (in aggregate principal amount) of 6.125 percent series AF first mortgage bonds due 2039. The bonds were priced at 99.931 percent of par and a reoffer yield of 6.13 percent. Black Hills expects the issuance and delivery to occur on October 27, 2009, subject to customary closing conditions. Net proceeds will be used to repay approximately $103.3 million of principal and interest on indebtedness borrowed from Black Hills Corporation primarily to fund the construction of Wygen III, a 110 MW coal-fired base load electric generation facility located near Gillette, Wyoming, which is expected to become operational in mid 2010. In addition, Black Hills Power expects to use approximately $27 million of net proceeds to pay the utility's remaining share of costs to complete the construction of Wygen III, and $30 million to repay the utility's Series AC, 8.06% first mortgage bonds at their maturity in February 2010. The remainder of net proceeds will be used for general purposes including other planned capital projects.

"The completion of this bond offering provides low cost, long-term financing and allows us to reduce our short-term debt as planned," said David R. Emery, chairman, president and chief executive officer of Black Hills Corp.

"We are pleased to secure such attractive financing terms for our Black Hills Power utility customers for the next thirty years. Utility investments in infrastructure such as Wygen III are essential to ensure safe, reliable and reasonably priced energy for our communities and provide future earnings growth for our shareholders."

The Black Hills Power bonds will mature on November 1, 2039. Interest on the bonds will accrue and be payable semi-annually at the rate of 6.125 percent per annum. The bonds will rank equally with all of Black Hills Power's other first mortgage bonds, are secured by a lien on substantially all of Black Hills Power's utility properties, and are subject to certain exceptions and permitted liens.

RBC Capital Markets, RBS, and Scotia Capital served as joint book-running managers for the offering. Senior co-managers were BMO Capital Markets and Mitsubishi UFJ Securities, with The Williams Capital Group, L.P. and US Bancorp Investments, Inc. serving as co-managers.

Copies of the prospectus supplement relating to the offering may be obtained by calling RBC Capital Markets Corporation toll free at 1-866-375-6829, RBS Securities Inc. toll free at 1-866-884-2071 or Scotia Capital (USA) Inc. toll free at 1-800-372-3930. An electronic copy of the prospectus supplement is available on the website of the Securities and Exchange Commission at www.sec.gov.

This joint news release by Black Hills Power and Black Hills Corp. shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of these securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of such jurisdiction.

Keystone XL Pipeline Public Input Hearing Scheduled for Nov. 3(10/22/2009)  Back to Table of Contents

PIERRE, S.D. – The South Dakota Public Utilities Commission will hold a public input hearing on Tuesday, Nov. 3 to hear comments about the siting permit application for the South Dakota portion of a crude oil pipeline known as the Keystone XL Project proposed by TransCanada Keystone Pipeline LP. The hearing begins at 6 p.m. CST in Room 414 of the State Capitol in Pierre and will adjourn at the conclusion of comments from all persons who have arrived before 8 p.m.

The proposed pipeline route in South Dakota has an estimated length of 314 miles that will cross portions of Harding, Butte, Perkins, Meade, Pennington, Haakon, Jones, Lyman and Tripp counties. The project also includes seven pump stations to be located in Harding, Meade, Haakon, Jones and Tripp counties. The plans specify two pump stations each in Harding and Tripp counties.

If constructed, the project will transport crude oil starting in Hardisty, Alberta, Canada and ending in the Port Arthur and East Houston areas of Texas.

The public input session is a component of the PUC hearing on the Keystone XL Pipeline permit application which is scheduled for Nov. 2-6, 2009, in Pierre.

The Nov. 3 session will be the fourth public input hearing before the PUC as part of the Keystone XL proceeding. Earlier public input hearings were held in April in Winner, Philip and Buffalo.

To listen to a live Web cast of the November hearing, go to the PUC Web site, www.puc.sd.gov, and click on the "Listen LIVE" link near the top of the home page.

Visit the PUC Web site for more information on the Keystone XL Pipeline application and related filings submitted to the commission. Select "Commission Actions," "Hydrocarbon Pipeline Dockets" and "2009 Hydrocarbon Pipeline Dockets." Click on the docket titled HP09-001 to access the documents.

Black Hills Power Requests Electric Rate Increase in Wyoming, First in 15 Years(10/19/2009)  Back to Table of Contents

RAPID CITY, SD, Oct. 19, 2009 - Black Hills Corp. (NYSE:BKH) subsidiary Black Hills Power announced today that the utility has filed a request for an electric revenue increase with the Wyoming Public Service Commission to recover costs associated with its new generation facility, Wygen III, located near Gillette, Wyo., and other generation, transmission and distribution investments and increased operating expenses during the past fifteen years.

"We have worked hard to keep our rates stable for 15 years, but as our integrated resource plan and analysis indicated in 2007, the investment we made to construct Wygen III and implement other system upgrades are necessary to serve the growing electricity needs in our service area," said Chuck Loomis, vice president, operations for Black Hills Power. "The planning and construction process for the new Wygen III generation plant occurred over the past several years with oversight from the Wyoming Public Service Commission. These requests are a normal part of our utility business and must be in line with established regulatory policies set by the Commission. And while Black Hills Corp., the parent company of Black Hills Power, has experienced significant growth through recent acquisitions, this Black Hills Power rate request is unrelated and is focused on recovering only the utility investments made by Black Hills Power that are necessary in order to provide the safe and reliable electric service our Wyoming customers expect and deserve."

In its request, Black Hills Power is seeking a $3.8 million increase in annual revenues and that new rates become effective for its Wyoming customers on the in-service date of Wygen III, which is expected to be April 1, 2010. If the proposed rates are approved, a typical Wyoming residential customer using an average of 600 kilowatt-hours (kWh) of power each month will see an increase of $19.44 per month, or about $0.64 per day, but the actual change in each customer's monthly utility bill will vary based on their electric service rates and electricity use. The increase experienced by Black Hills Power's commercial and industrial customers in Wyoming will vary depending on rate class, load factor, and the amount and nature of their electricity use. Black Hills Power currently serves approximately 2,700 residential, commercial and industrial electric customers in northeastern Wyoming.

The last base rate increase of 8.97 percent for Black Hills Power customers in Wyoming was based on 1994 costs and became effective in August 1995. During the past 15 years, Black Hills Power residential energy consumption in Wyoming has increased 33 percent and commercial energy consumption has increased 28 percent. When adjusted for inflation, the proposed Black Hills Power rates for Wyoming customers in 2010 would be approximately equal to rates paid by customers in 1995. In addition, Black Hills Power has voluntarily incorporated 35 megawatts of wind generation into its supply portfolio as the demand for renewable energy has continued to grow in the region.

NorthWestern Energy Submits Delivery Services General Rate Case Filing to the Montana Public Service Commission(10/19/2009)  Back to Table of Contents

Butte, Mont. – October 19, 2009 – NorthWestern Energy (NYSE:NWE) today submitted its general rate filing to the Montana Public Service Commission seeking approval to change several components of its delivery services charges for Montana electricity and natural gas customers. This filing was required pursuant to a stipulation approved by the Montana PSC in 2008.

If approved, the proposed changes would result in an increase of $0.08, or less than one-tenth of one percent, for a typical natural gas customer using 10 dekatherms/per month. A typical residential electric customer's total monthly bill would increase by $2.41 or about 3.35%. The company has asked for an interim rate adjustment pending the full review by the Commission.

"This filing addresses the foundational aspects associated with the day-to-day operations and maintenance of our electric and natural gas infrastructure," said Bob Rowe, President and CEO. "Despite the economic downturn and other challenges, this is an exciting time to work at NorthWestern. We're making the appropriate investments in our system to provide safe and reliable service. We're engaging our stakeholders at all levels to prepare our system to meet the expectations our customers have for utility service now and in the future."

The proposed changes include new cost allocation between rate classes and rate designs. The proposals introduce an inclining block residential rate structure that would assign more costs to residential customers that use more energy within each rate class. Under this methodology, some customers would see higher increases than the typical residential customer while other residential customers may experience lower rates than average. The intent of the inclining structure is to provide additional incentive to larger volume residential users to reduce their consumption through adoption of energy efficiency measures.

The amount of the proposed rate increases, based on a requested authorized return on equity of 10.9% and a weighted cost of capital of 8.3%, has been reduced as a result of a reduction to income tax expense due to recent changes made to the tax accounting method related to capital expenditures and repair expenses. As a result of this change, NorthWestern's proposed revenue requirement for its natural gas utility was reduced from approximately $4.8 million to $1.96 million and for its electric utility from $24.1 million to $15.5 million. The general rate filing does not address energy supply issues, which are addressed in other proceedings. The transmisison and distribution components of a typical total bill represent less than 50% for residential electric and natural gas customers with energy supply costs making up the balance of the bill amounts.

Charts are available that show the relationship between the regulated delivery service costs and rates and "pass through" electric and natural gas supply costs. Delivery rates have been stable in recent years with relatively few and relatively modest adjustments. Volatility in customer bills has been primarily due to adjustments in market-based natural gas and electric supply costs, which commonly comprise more than one-half of a customer's total bill. To see the charts, visit www.northwesternenergy.com/ourcompany/ratefilingimages.asp.

NorthWestern's Third Quarter 2009 Financial Results(10/15/2009)  Back to Table of Contents

NorthWestern's Third Quarter 2009 Financial Results will be e-mailed to you. You may also find NorthWestern's news release on PR Newswire.

THIRD QUARTER 2009 FINANCIAL RESULTS CONFERENCE CALL

A conference call to discuss financial results for the third quarter 2009 will be held:

• Thursday, October 29, 2009
• 11:00 a.m. (Eastern time)
• 10:00 a.m. (Central time)
• 8:00 a.m. (Pacific time)
• Dial 800-230-1096
• NorthWestern Corporation
• Third Quarter 2009 Financial Results
• Host: Dan Rausch

If you are unable to participate in the conference call as scheduled above, a replay will be available beginning at 1:00 p.m. ET on October 29 through November 29, 2009. To access the replay, dial 800-475-6701, access code 118865.

The call also will be simultaneously broadcast on our Web site at www.northwesternenergy.com, and a replay will be available for 30 days following the conference call.

Northwestern Energy Taps Private Placement Market For $55 Million 30-Year First Mortgage Bonds(10/02/2009)  Back to Table of Contents

SIOUX FALLS, S.D. – October 2, 2009 – NorthWestern Corporation d/b/a NorthWestern Energy (NYSE: NWE) today announced that on September 30, 2009, NorthWestern Corporation (the "Company") entered into a purchase agreement to sell $55,000,000 aggregate principal amount of 5.71% First Mortgage Bonds due October 15, 2039, with Country Life Insurance Company, Canada Life Insurance Company of America, and John Hancock Life Insurance Company.

The Company will use the entire net proceeds from this offering to pay a portion of the costs of the proposed Mill Creek generation project and/or fund future capital expenditures.

"This offering demonstrates NorthWestern's ability to access the debt markets at favorable terms as we look forward to financing our growth initiatives," said Brian Bird, Vice President, Chief Financial Officer and Treasurer.

For more information on NorthWestern Energy, please visit our Website at www.northwesternenergy.com.

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