Commitments and Contingencies

ENVIRONMENTAL LIABILITIES AND REGULATION

The operation of electric generating, transmission and distribution facilities, and gas gathering, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are promulgated, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs become fixed and reliably determinable.

Our liability for environmental remediation obligations is estimated to range between $29.3 to $38.9 million, primarily for manufactured gas plants discussed below. As of September 30, 2011, we have a reserve of approximately $32.2 million. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. Over time, as specific laws are implemented and we gain experience in operating under them, a portion of the costs related to such laws will become determinable, and we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material adverse effect on our consolidated financial position or ongoing operations.

Manufactured Gas Plants - Approximately $27.1 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. Our current reserve for remediation costs at this site is approximately $13.4 million, and we estimate that approximately $8.9 million of this amount will be incurred during the next five years.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. During 2006, the NDEQ released to us the Phase II Limited Subsurface Assessments performed by the NDEQ's environmental consulting firm for Kearney and Grand Island. In February 2011, NDEQ completed an Abbreviated Preliminary Assessment and Site Investigation Report for Grand Island, which recommended additional ground water testing. Our reserve estimate includes assumptions for additional ground water testing. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to excess regulated pollutants in the groundwater. Voluntary soil and coal tar removals were conducted in the past at the Butte and Helena locations in accordance with MDEQ requirements. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the conditions at these sites; however, additional groundwater monitoring will be necessary. Monitoring of groundwater at the Helena site is ongoing and will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site or if any additional actions beyond monitored natural attenuation will be required.

Global Climate Change - There are national and international efforts to adopt measures related to global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide. These efforts include legislative proposals and U.S. Environmental Protection Agency (EPA) regulations at the federal level, actions at the state level, as well as litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their GHG emissions. We have joint ownership interests in four electric generating plants, all of which are coal fired and operated by other companies. We have undivided interests in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

While numerous bills have been introduced in Congress that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA is regulating GHG emissions under its existing authority pursuant to the Clean Air Act. For example, the EPA promulgated regulations requiring major sources in the United States to begin collecting and reporting information regarding their GHG emissions. Certain of our facilities began collecting such data on January 1, 2010 and submitted their first annual reports to the EPA by its September 30, 2011 deadline. For petroleum and natural gas facilities, data collection began on January 1, 2011, with the first annual report due on March 31, 2012.

In June 2010, the EPA also adopted rules that make certain “stationary sources,” such as power plants, subject to permitting requirements for their GHG emissions. Sources that emit more than 100,000 tons of greenhouse gases per year are now required to obtain permits for those emissions even if they are not otherwise required to obtain a new or modified permit. Such permits may require the installation and operation of “best available control technology” to control GHG emissions.

Also, in December 2010, the EPA entered into an agreement to settle litigation brought by states and environmental groups whereby the EPA agreed to issue New Source Performance Standards for GHG emissions from certain new and modified electric generating units and “emissions guidelines” for existing units over the next two years. Pursuant to this settlement agreement, the EPA agreed to issue proposed rules by September 2011 and final rules by May 2012. The EPA, however, did not meet the September deadline for issuing a proposed rule. It is uncertain whether the EPA still expects to meet the May 2012 deadline for issuing a final rule.

On June 20, 2011, the U.S. Supreme Court issued a decision that bars state and private parties from bringing federal common law nuisance actions against electrical utility companies based on their alleged contribution to climate change. The Supreme Court's decision did not, however, address state law claims. This decision is expected to affect other pending federal climate change litigation, including a case brought by individuals alleging public nuisance claims against a variety of companies that emit GHGs and seeking compensation for damages suffered in the wake of Hurricane Katrina. The plaintiffs in that case, which was previously dismissed, re-filed their lawsuit in May 2011. Although we are not a defendant in any of these proceedings, additional litigation in federal and state courts over these issues is continuing.

Physical impacts of climate change present potential risks for severe weather, such as floods and tornadoes, in the locations where we operate or have interests. Furthermore, requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance, increase our costs of procuring electricity in the marketplace or curtail the demand for fossil fuels such as oil and gas. In addition, we believe future legislation and regulations that affect GHG emissions from power plants are likely, although technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. We cannot predict with any certainty whether these risks will have a material impact on our operations.

Coal Combustion Residuals (CCRs) - In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and scrubber wastes. Under one approach, the EPA would regulate CCRs as a hazardous waste under Subtitle C of RCRA. This approach would have significant impacts on coal-fired plants, and would require plants to retrofit their operations to comply with hazardous waste requirements from the generation of CCRs and associated waste waters through transportation and disposal. This could also have a negative impact on the beneficial use of CCRs and the current markets associated with such use. The second approach would regulate CCRs as a solid waste under Subtitle D of RCRA. This approach would only affect disposal, most significantly any wet disposal, of CCRs. We cannot predict at this time the final requirements of the EPA's CCR regulations and what impact, if any, they would have on us, but the costs could be significant.

Water Intakes - Section 316(b) of the Federal Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. Permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA takes action to address several court decisions that rejected portions of previous rules and confirmed that EPA has discretion to consider costs relative to benefits in developing cooling water intake structure regulations. In March 2011, EPA proposed rules to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. When final rules are issued and implemented, additional capital and/or increased operating costs may be incurred. The costs of complying with any such final water intake standards are not currently determinable, but could be significant.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures

EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants where we have joint ownership.

The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule requires the use of Best Available Retrofit Technology (BART) for certain electric generating units to achieve emissions reductions from designated sources that are deemed to contribute to visibility impairment in Class I air quality areas.

In May 2011, the EPA issued a proposed rule setting forth Maximum Achievable Control Technology (MACT) standards for hazardous air pollutant emissions from electric generating units that among other things, seek to set stringent emission limits for acid gases, mercury, and other hazardous air pollutants. EPA is under a consent decree deadline to issue the final MACT standards by mid-November 2011. Given the potential for legal challenges and regulatory uncertainties associated with EPA's final rule, it is not possible to fully assess the impact of this rulemaking.

On July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under the CSAPR, the first phase of the nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions reductions would commence in 2012 with further reductions effective in 2014. On October 7, 2011, EPA announced that it was proposing technical corrections to CSAPR that increase the allowances allocated to certain facilities and have the effect of allowing unlimited interstate trading of allowances between 2012 and 2014. Numerous challenges to CSAPR have been filed with the EPA and in Federal court and we cannot predict the outcome of such challenges. Regardless of the outcome, CSAPR only applies to power plants within the eastern half of the United States, and, thus is only applicable to one plant in which we have an ownership interest, the Neal 4 plant located in Iowa. We do not expect CSAPR to affect any of the other plants in which we have an ownership interest.

We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are subject to the Clean Air Visibility Rule and would be subject to the EPA's proposed rules, as discussed below.

South Dakota. The South Dakota Department of Environment and Natural Resources (DENR) determined that the Big Stone Plant, of which we have a 23.4% ownership, is subject to the Clean Air Visibility Rule. South Dakota DENR submitted its revised State Implementation Plan (SIP) and associated implementation rules to the EPA on September 19, 2011. Under the SIP, the Big Stone Plant must install and operate a new BART compliant air quality control system (AQCS) to reduce emissions as expeditiously as practicable, but no later than five years after the EPA's approval of South Dakota's SIP. We expect EPA approval of the SIP in the first half of 2012, however such approval cannot be guaranteed and we cannot predict the timing of any such approval with certainty. We will not incur any significant costs unless the EPA approves the SIP or issues a federal implementation plan in its place. Although studies and evaluations are continuing, the current project cost for the AQCS is estimated to be approximately $490 million (our share is 23.4%).

Our incremental capital expenditure projections include amounts related to our share of the BART technologies at Big Stone based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process. The SDPUC has historically allowed timely recovery of the costs of environmental improvements; however, there is no precedent on a project of this size.

Based on the proposed MACT rule, it appears that Big Stone would meet the proposed requirements by installing the AQCS system and using mercury control technology such as activated carbon injection. Mercury emissions monitoring equipment installation is already installed at Big Stone, but its operation has been put on hold pending additional regulatory direction.

North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, of which we have 10% ownership, to reduce its NOx emissions. On February 23, 2010, the North Dakota Department of Health (NDDOH) issued a construction permit to Coyote Station requiring installation of control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 12-month rolling average basis. The control equipment must be installed by July 1, 2018 and compliance with the limit must be beginning on July 1, 2019. Subsequent to issuance of the construction permit, the NDDOH entered into further negotiations with the EPA on regional haze plan implementation. As part of those negotiations, Coyote agreed to accept a NOx emission limit of 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown, beginning on July 1, 2018. The current estimate of the total cost of the project is approximately $6.0 million (our share is 10%).

Iowa. The Neal 4 generating facility, of which we have an 8.7% ownership, is installing a scrubber, a baghouse and a selective non-catalytic reduction system to comply with the CSAPR and the MACT standards. These improvements are expected to result in compliance with the regional haze provisions of the Clean Air Act. The Neal 4 owners are currently evaluating the plant's ability to meet the CSAPR standards on the timeframe required by EPA. Capital expenditures for such equipment are currently estimated to be approximately $270 million (our share is 8.7%). The plant began incurring such costs in 2011 and the costs will be spread over the next three years. Our incremental capital expenditure projections include amounts related to our share of the emission control equipment at Neal 4 based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process.

Montana. The Colstrip facility is currently controlling emissions of mercury under regulations issued by the State of Montana and has been since January 2010. The owners do not believe additional equipment will be necessary to meet the MACT standards for mercury. Additionally, the Colstrip facility anticipates meeting the expected standards for acid gases without additional costs. However, Colstrip may have to install additional controls to further reduce particulate matter to meet MACT standards. The Colstrip owners are continuing to determine what may be required and while it is not possible to predict costs at this time, the costs of additional controls could be significant. In November 2010, Colstrip Unit 4 received a request from the EPA to provide further analysis regarding why Colstrip Unit 4 is not a BART eligible unit under the regional haze rule. The plant operator completed a high level analysis of various control options to reduce emissions of SO2 and particulate matter and submitted that analysis to EPA in January 2011. The analysis shows that these units are well controlled, any incremental reductions would not be cost effective and further analysis is not warranted. The plant operator also concluded that further analysis for NOx was not justified as controls at Colstrip Unit 4 were installed and the EPA previously agreed that such controls would satisfy BART for NOx control. The plant operator informed us that the EPA verbally indicated that it does not agree with all of the plant operator's conclusions and will be requesting additional information. The EPA is under a consent decree to take final action on Montana's regional haze implementation plan no later than June 29, 2012. The costs of complying with any final regional haze standards in Montana are not currently determinable, but could be significant.

Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:


•	We may not know all sites for which we are alleged or will be found to be responsible for remediation; and


•	Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.

LEGAL PROCEEDINGS

Colstrip Energy Limited Partnership

In December 2006 and June 2007, the MPSC issued orders relating to certain QF long-term rates for the period July 1, 2003, through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a QF with which we have a power purchase agreement through June 2024. Under the terms of the power purchase agreement with CELP, energy and capacity rates were fixed through June 30, 2004 (with a small portion to be set by the MPSC's determination of rates in the annual avoided cost filing), and beginning July 1, 2004 through the end of the contract, energy and capacity rates are to be determined each year pursuant to a formula, with the rates to be used in that formula derived from the annual MPSC QF rate review.

CELP initially appealed the MPSC's orders and then, in July 2007, filed a complaint against NorthWestern and the MPSC in Montana district court, which contested the MPSC's orders. CELP disputed inputs into the underlying rates used in the formula, which initially are calculated by us and reviewed by the MPSC on an annual basis, to calculate energy and capacity payments for the contract years 2004-2005 and 2005-2006. CELP claimed that NorthWestern breached the power purchase agreement causing damages, which CELP asserted to be approximately $23 million for contract years 2004-2005 and 2005-2006. The parties stipulated that NorthWestern would not implement the final derived rates resulting from the MPSC orders, pending an ultimate decision on CELP's complaint.

On June 30, 2008, the Montana district court granted both a motion by the MPSC to bifurcate, having the effect of separating the issues between contract/tort claims against us and the administrative appeal of the MPSC's orders and a motion by us to refer the claims against us to arbitration. The order also stayed the appellate decision pending a decision in the arbitration proceedings. Arbitration was held in June 2009 and the arbitration panel entered its interim award in August 2009, holding that although NorthWestern failed to use certain data inputs required by the power purchase agreement, CELP was entitled to neither damages for contract years 2004-2005 or 2005-2006, nor to recalculation of the underlying MPSC filings for those years, effectively finalizing CELP's contract rates for those years. We requested clarification from the arbitration panel as to its intent regarding the applicable rates.

On November 2, 2009, we received the final award from the arbitration panel which confirmed that the filed rates for 2004-2005 and 2005-2006 are not required to be recalculated. In affirming its interim award, the arbitration panel also denied CELP's request for attorney fees, holding that each party would be responsible for its own fees.

On June 15, 2010, the Montana district court confirmed the final arbitration panel award and denied CELP's motion to vacate, modify or correct the award. CELP appealed the decision to the Montana Supreme Court (MSC). In May 2011, the MSC affirmed the Montana district court's order and the arbitration award.

Meanwhile, on October 31, 2010, NorthWestern filed with the MPSC, consistent with the direction of the arbitration panel, for a determination of the inputs that will be used to calculate contract rates for periods subsequent to June 30, 2006. The MPSC has not yet ruled on our filing. On June 30, 2011, CELP submitted another demand for arbitration, seeking clarification from the same panel regarding the panel's intent as to the implementation of its award in Contract Years 17 (July 2005 - June 2006) and 18 (July 2006 - June 2007). Based on our current assumptions (including current discount rates), if CELP prevailed entirely, we could be required to increase our QF liability by approximately $24 million. If we prevailed entirely, we could reduce our QF liability by up to $25 million. Due to the uncertainty around resolution of this matter, we currently are unable to predict its outcome. In addition, settlement discussions concerning these claims are ongoing.

Gonzales

We are a defendant - along with the Montana Power Company (MPC) and pre-bankruptcy NorthWestern Corporation (NOR) - in an action (Gonzales Action) pending in the Montana Second Judicial District Court, Butte-Silver Bow County (Montana State Court), alleging fraud, constructive fraud and violations of the Unfair Claim Settlement Practices Act all arising out of the adjustment of workers' compensation claims. Putnam and Associates, the third party administrator of such workers' compensation claims, also is a defendant.

The Gonzales Action was first filed on December 18, 1999, against MPC (NOR acquired MPC in 2002) and was stayed due to the chapter 11 bankruptcy filing of NOR. On August 10, 2005, the Bankruptcy Court approved a Bankruptcy Settlement Stipulation which permitted the Gonzales Action to proceed, assigned to plaintiffs NOR's interest in MPC's insurance policies (to the extent applicable to the allegations made by plaintiffs), released NOR from any and all obligations to the plaintiffs concerning such claims, and preserved plaintiffs' right to pursue claims arising after November 1, 2004, relating to the adjustment of workers' compensation claims. To date, no insurance carrier has indicated that coverage is available for any of the claims.

We and Putnam and Associates have agreed to settle the Gonzales Action and have executed a settlement agreement which remains subject to the approval of the Montana State Court. We paid the settlement agreement amount of $2.5 million to the Clerk of the Montana State Court in full satisfaction of all Gonzales Action claims. The Clerk of the Montana State Court will hold these funds pending final Montana State Court approval of the settlement, which could happen in early 2012.

Bozeman Explosion

On March 5, 2009, a natural gas explosion occurred in downtown Bozeman, Montana, resulting in one fatality, the destruction of or damage to six buildings and the businesses in them, and lesser damage to other nearby properties and businesses. Thirty-three lawsuits have been filed against NorthWestern in the District Court of Gallatin County, Montana, and a number of additional claims not currently in litigation also have been made against us. We have approximately $150 million of insurance coverage available for known and potential claims arising from the explosion. We tendered our self-insured retention under those policies to our insurance carriers, who accepted the tender and assumed the defense and handling of the existing and potential additional lawsuits and claims arising from the incident.

Settlements have been reached in 24 of the 33 cases filed to date, including the sole wrongful death case, and we have settled most of the additional claims that were not in litigation. There are nine remaining property damage and business loss cases pending, none of which is likely to be tried before the fall of 2012. While we cannot predict an outcome in those cases, we are continuing to vigorously defend them. A small number of additional pending claims not in litigation are being handled by our primary insurance carrier. We believe the possibility of any loss in excess of our self-insured retention on the remaining lawsuits and claims is remote.

We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.