The following discussion and analysis should be read in conjunction with "Item 6 Selected Financial Data" and our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our industry segments, see Note 21 - Segment and Related Information to the Consolidated Financial Statements, which is included in Item 8 herein. For information regarding our revenues, net income and assets; see our Consolidated Financial Statements included in Item 8.

OVERVIEW

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 673,200 customers in Montana, South Dakota and Nebraska. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2012, 2011 and 2010. Following is a brief overview of highlights for 2012, and a discussion of our strategy and outlook.

SIGNIFICANT ITEMS

Significant items for the year ended December 31, 2012 include:

•      Improvement in net income of approximately $5.9 million as compared with
       2011, due primarily to:


?            Higher gross margin of $52.2 million, largely due to a $47.9 million
             gain associated with a favorable arbitration decision discussed in
             more detail below;

? Partially offset by

?                  a charge of approximately $24.0 million in the third quarter
                   of 2012 for the impairment of substantially all of the
                   capitalized preliminary survey and investigative costs
                   associated with the MSTI project;


?                  higher other operating expenses of $16.5 million, primarily
                   property taxes and depreciation; and

? higher income tax expense of $8.1 million.

• Purchased and placed into service the 40 MW Spion Kop wind project in Judith Basin County in Montana for approximately $84 million.

• Purchased natural gas production interests in northern Montana's Bear Paw Basin for approximately $19 million.

• Received approval from the MPSC to include our Battle Creek production assets in natural gas rate base.

• Successfully accessed the capital markets to fund growth projects and extend maturities by:

?            Entering into an Equity Distribution Agreement with UBS Securities
             LLC. Under this agreement we have received net proceeds of
             approximately $28.5 million from the sales of 815,416 common shares,
             after commissions and other fees; and


?            Issuing $90 million of First Mortgage Bonds at 4.15% and $60 million
             of First Mortgage Bonds at 4.30%, maturing in 2042 and 2052,
             respectively.

Colstrip Energy Limited Partnership (CELP) favorable arbitration decision

CELP is a QF with which we have a power purchase agreement (PPA) for approximately 306,600 MWH's annually through June 2024. Under the terms of the PPA with CELP, energy and capacity rates were fixed for the first fifteen years 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, subject to annual review and approval by the MPSC. The MPSC's last final order covered rates through June 30, 2006. We have been in litigation with CELP since 2007 over how to determine energy and capacity rates under the PPA. Based on our calculations, the annual all-in rate has ranged between $63.38 per MWH and $83.57 per MWH between July 1, 2007 and June 30, 2012. Based on CELP's calculations, the annual all-in rate would have ranged between approximately $11.00 per MWH and $16.00 per MWH higher than our calculated rate between July 1, 2007 and June 30, 2012. If CELP had prevailed we would have owed them approximately $25.4 million more for that time period and our annual payments through June 2024 would be approximately $4.0 million to $5.0 million higher than under our calculation.

On November 1, 2012, an arbitration panel issued a final award in our favor. The final award confirmed that the rate methodology used by us for calculating the rates for the July 1, 2006 to June 30, 2011 period was consistent with the PPA and a previous final award issued by the same arbitration panel on October 30, 2009. Based on the clarity provided by the final award regarding the rate calculation for 2006 through the remainder of the PPA, we have updated the calculation of our QF liability and recorded a pre-tax gain of $47.9 million during the fourth quarter of 2012.

The deadline to challenge the arbitration panel's final award was January 30, 2013, and CELP did not challenge the final award. During 2013, we expect the MPSC to review our filings and issue final orders consistent with the arbitration panel's final award for the years July 1, 2006 through June 30, 2011.

MSTI Impairment

The MSTI line is a proposed 500 kV transmission project from southwestern Montana to southeastern Idaho with a potential capacity of 1,500 MW. We previously disclosed that there was significant market uncertainty related to the project, and that we would consider writing down or writing off the costs of the MSTI project depending on the likelihood of reaching an agreement with the Bonneville Power Administration (BPA) to serve its southern Idaho loads. On October 2, 2012, BPA notified us that it had ranked other options ahead of MSTI to serve BPA's southern Idaho loads. This notification was in conjunction with the January 2012 Memorandum of Understanding between NorthWestern and BPA agreeing to explore the potential for MSTI to accommodate BPA's needs. Based on BPA's decision, continued market uncertainty, and permitting issues causing timeline delays, we determined that we will not further pursue development of MSTI at this time. As a result, during the third quarter of 2012 we recorded an impairment charge of substantially all of the capitalized preliminary survey and investigative costs related to MSTI, totaling approximately $24.0 million.

We also proposed a Collector Project that would consist of up to five new transmission lines in Montana to connect new generation, primarily wind farms, with our existing transmission system and to the proposed MSTI line. The timing of the Collector Project would coincide with the construction of MSTI. Due to the status of MSTI, we have also suspended efforts on the Collector Project. We have not capitalized any costs associated with the Collector Project.

Dave Gates Generating Station at Mill Creek (DGGS) On January 1, 2011, we began commercial operations of DGGS, a 150 MW natural gas fired facility that provides regulating resources (in place of previously contracted ancillary services). DGGS was constructed for a total cost of $183 million, as compared to an original estimate of $202 million. Our regulatory filings seeking approval of rates related to DGGS are based on an allocation of approximately 80% of revenues related to the facility from retail customers being subject to the jurisdiction of the MPSC and approximately 20% of revenues allocated to wholesale customers subject to the jurisdiction of the FERC.

In March 2012, the MPSC issued a final order in review of our previously submitted required compliance filing. The MPSC found that the total project costs incurred were prudent and established final rates. As a result of the lower than estimated construction costs and impact of the flow-through of accelerated state tax depreciation, the final rates are lower than our 2011 interim rates. We are refunding the amount we over collected of approximately $6.2 million to customers over a one-year period that began in May 2012. The MPSC's final order approves using our proposed cost allocation methodology on a temporary basis, and requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers.

In our DGGS FERC proceedings, total project costs were not challenged and the parties to the case stipulated to the revenue requirement; however, intervenors challenged the allocation of costs. We proposed allocating 20% of the DGGS revenue requirement to FERC jurisdictional customers, based on our past practice of allocating 20% of the contracted costs for these services to FERC jurisdictional customers. A hearing was held in June 2012 before a FERC Administrative Law Judge (ALJ) to consider this proposed allocation methodology. In September 2012, we received an initial decision from the ALJ concluding that we should only recover approximately 4.4% of the revenue requirement from FERC jurisdictional customers. The ALJ's initial decision is nonbinding.

During the fourth quarter of 2012, we filed a brief in opposition to the initial decision. Various intervening parties also filed briefs in opposition or support of the initial decision. The FERC is expected to consider the matter and issue a binding decision during the second quarter of 2013. The FERC is not obliged to follow any of the findings from the ALJ's initial decision and can accept or reject the initial decision in whole or in part. If the FERC upholds the ALJ decision and a portion of the costs are effectively disallowed, we would be required to assess DGGS for impairment. If we disagree with a decision issued by the FERC, we may pursue full appellate rights through rehearing and appeal to a United States Circuit Court of Appeals, which could extend into 2015.

We continue to bill customers interim rates that have been in effect since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC. As a result of the ALJ initial decision, we deferred additional
revenue of approximately $11.4 million during the third quarter of 2012. Of this charge, approximately $6.4 million relates to

revenues collected during 2011. As of December 31, 2012, our cumulative deferred revenue related to DGGS FERC jurisdictional revenues is approximately $16.5 million. We expect to defer revenues of approximately $0.7 million per month during 2013 pending final resolution at FERC.

DGGS was shut down on January 31, 2012 after problems were discovered in the power turbines of two of the generation units. Similar problems were subsequently found in the third unit. There are two power turbines per unit, and by May 3, 2012, five of the six turbines had been returned to service through using a combination of the original turbines after servicing by their supplier Pratt & Whitney Power Systems (PWPS) and turbines on loan from PWPS. By late 2012 all six turbines had been returned to service. PWPS has been investigating the root cause of the problem and we expect modifications of the turbines will take place during 2013 to address issues identified in the root cause analysis. We anticipate that the work will be performed in a manner that will not require DGGS to be taken completely off-line. Turbine repair costs are covered under the manufacturer's warranty. We have entered into an agreement with PWPS that will extend the warranty for all of the turbines for two years beyond the point at which the last of the six turbines have been fitted with the modifications discussed above.

STRATEGY

We are focused on providing our customers with safe and reliable service at reasonable rates. In response to our aging infrastructure, we continue to make significant maintenance capital investments in our generation, distribution and transmission assets in excess of our depreciation, which is the amount of these costs we recover through rates. These investments reflect our focus on maintaining our system reliability, and allow us to pursue the deployment of newer technology that promotes the efficient use of electricity, including smart grid. See the "Capital Requirements" discussion below for further detail on planned maintenance capital expenditures.

We are considering additional opportunities for the ownership and/or development of electric generation facilities and proven gas reserves, which are intended to help stabilize our customers' energy costs.

Investing in our system and making prudent acquisitions provide us the opportunity to grow our rate base and earn a reasonable return on invested capital.

Regulatory Matters

General rate cases are necessary to cover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. In September 2012, we filed a request with the MPSC for a natural gas delivery revenue increase of approximately $15.7 million. This request was based on a return on equity of 10.5%, a capital structure consisting of 52% debt and 48% equity and rate base of $309.5 million. A hearing is scheduled for the second quarter of 2013.

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We expect to file a general electric rate case in South Dakota during the second quarter of 2013 based on a 2012 test year due to the supply investments discussed below. As part of this rate case, we plan to include a known and measurable adjustment to incorporate the cost of the Aberdeen Generating Station. We also expect to request a tariff mechanism (environmental rider) to recover future environmental related expenses and capital costs associated with Big Stone and Neal #4 electric generation units.

Distribution Investment

Montana Distribution System Infrastructure Project (DSIP)

As part of our commitment to maintain high level reliability and system performance we continue to evaluate the condition of our distribution assets to address aging infrastructure through our asset management process. The primary goals of our infrastructure investment are to reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. We are working on various solutions taking a proactive and pragmatic approach to replace these assets while also evaluating the implementation of additional technologies to prepare the overall system for smart grid applications.

We requested and received MPSC approval of an accounting order to defer certain incremental operating and maintenance expenses incurred during 2011 and 2012 and amortize these expenses associated with the phase-in portion of the DSIP. The amortization of these expenses will be approximately $3.1 million annually over five years beginning in 2013.

In addition, we are projecting approximately $72.0 million of incremental DSIP expenses, including $10.9 million for 2013, and approximately $253.3 million of DSIP capital expenditures over a five-year time span beginning in 2013. Based on

our current forecast, along with the MPSC's approval of the accounting order, we believe DSIP-related expenses and capital expenditures will be recovered in base rates through annual or biennial general rate cases.

Supply Investments

Wind Generation
During the fourth quarter of 2012, we purchased and placed into service the 40 MW Spion Kop wind project in Judith Basin County in Montana for approximately $84 million. The terms of pre-approval by the MPSC include an authorized rate of return of 7.4%, which was computed using a 10% return on equity, a 5% estimated cost of debt and a capital structure consisting of 52% debt and 48% equity. The pre-approval also includes a performance condition that would reduce our revenue requirement if the average production failed to meet a minimum threshold for the first three years. We do not believe this performance condition will have a significant impact on our revenue requirement. During the fourth quarter of 2012, we made a compliance filing to reflect actual project costs, including an adjustment to reduce the cost of debt to 4.23% and the authorized rate of return to 7.0%.

Both the energy and associated renewable energy credits are included in our electric supply portfolio to meet future customer loads and RPS obligations. Beginning in December 2012, the cost of service of the electricity generated, including a return on our investment, has been included in electric supply rates.

We expect the acquisition of Spion Kop to contribute net income of approximately $4.0 million based on estimated revenues of approximately $6.2 million during 2013. We expect a state tax bonus depreciation deduction of approximately $2.5 million will be flowed through to customers during 2013. The revenue estimate is also based on our expectation that we will flow through annual Production Tax Credits (PTCs) of approximately $3.0 million. PTCs are federal income tax credits on qualifying renewable electric generation property. As the state bonus depreciation deduction and the PTCs are flowed through to customers, the lower revenue is offset by corresponding reductions to our income tax expense.

South Dakota Electric

During 2012, we began construction on the Aberdeen Generating Station, a 60 MW natural gas peaking facility located in Aberdeen, South Dakota, which we expect to achieve commercial operation before the 2013 summer season. This facility is intended to provide peaking reserve margin necessary to comply with capacity reserve requirements. As of December 31, 2012, we have capitalized approximately $50.7 million associated with this project. We do not expect additional capital expenditures during 2013 to be significant.

The Big Stone and Neal #4 electric generation facilities are subject to additional emission reduction requirements. We expect Big Stone to begin incurring costs in 2013 with costs spread over three years. Neal #4 began incurring such costs in 2011 and work is expected to be completed in 2013. Our current estimate of capital expenditures related to these projects is approximately $119 million, including approximately $46.9 million in 2013. As discussed above, we expect to request an environmental rider related to these costs.

Montana Natural Gas

In March 2012, we submitted an application with the MPSC to place our majority interest in the Battle Creek Field natural gas production fields and gathering system (Battle Creek) acquired in 2010 in regulated natural gas rate base. The application reflected a joint stipulation between us and the MCC of a 10% return on equity and a capital structure consisting of 52% debt and 48% equity. Since November 2010, the cost of service for the natural gas produced, including a return on our investment had been included in our natural gas supply tracker on an interim basis. We received a final order approving our request during the fourth quarter of 2012 and recognized approximately $2.2 million of revenue that we had deferred pending MPSC approval of our application. The deferred revenue represented the difference between our cost of service and natural gas market prices.

During the third quarter of 2012, we completed the purchase of natural gas production interests in northern Montana's Bear Paw Basin, including 75% interests in two gas gathering systems. Together with our existing Battle Creek natural gas production assets, we expect annual production to be approximately 10% of our natural gas load in Montana. The purchase price for the Bear Paw Basin assets including the interests in the two gathering systems (Bear Paw) was $19.5 million (subject to customary post closing adjustments). Beginning in November 2012, the cost of service for Bear Paw natural gas produced, including a return on our investment is included in our natural gas supply tracker on an interim basis. We are recognizing Bear Paw related revenue based on the precedent established by the MPSC's approval of Battle Creek. We expect to file an application with the MPSC to place our Bear Paw assets in natural gas rate base during 2013 and this revenue is subject to

refund until we receive MPSC approval of our application. We expect the Bear Paw acquisition to provide additional margin of approximately $1.9 million in 2013.

Transmission Investment

Colstrip 500 kV Upgrade

All of the current joint owners of the existing Colstrip 500 kV transmission line from Colstrip, Montana to mid-Columbia, as well as BPA, are working to develop an upgrade to the system, which involves an additional substation and related electrical equipment to increase westbound capacity out of Montana by more than 500 MWs. The project, including construction timing, is dependent on other investments BPA has planned further west in its system. As of December 31, 2012, we have capitalized approximately $1.2 million of preliminary survey and investigative costs associated with this upgrade.

RESULTS OF OPERATIONS

Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment.

NON-GAAP FINANCIAL MEASURE

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Gross Margin, that is considered a "non-GAAP financial measure." Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of Gross Margin is intended to supplement investors' understanding of our operating performance. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Our Gross Margin measure may not be comparable to other companies' Gross Margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is primarily affected by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

OVERALL CONSOLIDATED RESULTS

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011

                               Year Ended December 31,
                      2012         2011       Change     % Change
                                    (in millions)
Operating Revenues
Electric           $   805.6    $   797.5    $   8.1        1.0  %
Natural Gas            263.4        318.3      (54.9 )    (17.2 )
Other                    1.3          1.5       (0.2 )    (13.3 )
                   $ 1,070.3    $ 1,117.3    $ (47.0 )     (4.2 )%

Year Ended December 31,

                2012       2011      Change     % Change
                             (in millions)
Cost of Sales
Electric      $ 277.8    $ 327.1    $ (49.3 )    (15.1 )%
Natural Gas     117.6      167.4      (49.8 )    (29.7 )
              $ 395.4    $ 494.5    $ (99.1 )    (20.0 )%

Year Ended December 31,

               2012       2011      Change    % Change
                           (in millions)
Gross Margin
Electric     $ 527.8    $ 470.4    $ 57.4       12.2  %
Natural Gas    145.8      150.9      (5.1 )     (3.4 )
Other            1.3        1.4      (0.1 )     (7.1 )
             $ 674.9    $ 622.7    $ 52.2        8.4  %

Consolidated gross margin in 2012 was $674.9 million, an increase of $52.2 million, or 8.4%, from gross margin in 2011. Primary components of this change include the following:

                                           Gross Margin 2012 vs. 2011
                                                 (in millions)
Gain on CELP arbitration decision        $                   47.9
DSM lost revenues                                             5.9
Montana property tax tracker                                  4.0
Gas production                                                3.3
Transmission capacity                                         2.3
South Dakota natural gas rate increase                        1.7
Natural gas and electric retail volumes                      (7.0 )
DGGS revenues                                                (3.8 )
Operating expenses recovered in trackers                     (1.3 )
Other                                                        (0.8 )
Increase in Consolidated Gross Margin    $                   52.2

This $52.2 million increase in gross margin includes the following:

• A $47.9 million gain associated with a favorable arbitration decision related to a dispute over energy and capacity rates with CELP, as discussed above;

• An increase in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers. See additional discussion below;

• An increase in Montana property taxes included in a tracker as compared to 2011;

• An increase in gas production margin due to the inclusion of Battle Creek in rates, including approximately $1.1 million that we had deferred in prior periods based on the difference between our cost of service and current natural gas market prices. The acquisition of the Bear Paw Basin assets in the third quarter of 2012 also contributed to the higher gas production margin;

• An increase in transmission capacity revenues due to higher demand to transmit energy for others across our lines; and

• An increase in South Dakota natural gas rates implemented in December 2011.

These increases were partly offset by the following:

• A decrease in natural gas retail volumes, and to a lesser extent electric residential retail volumes, due primarily to warmer winter and spring weather;

• Lower DGGS related revenues primarily due to the deferral of an additional . . .