Regulatory Matters	9 Months Ended
Sep. 30, 2012
Regulated Operations [Abstract]
Public Utilities Disclosure [Text Block]	Regulatory Matters 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 Montana Public Service Commission (MPSC) and approximately 20% of revenues allocated to wholesale customers subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). In our DGGS FERC proceedings total project costs were not challenged and the parties to the case have stipulated to the revenue requirement; however, intervenors have challenged the allocation of costs. Our allocation methodology of 20% of the DGGS revenue requirement to FERC jurisdictional customers is based on our past practice of allocating the contracted costs for these services. 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. In response to the initial decision, we and the intervening parties will have the opportunity to respond with briefs in support or opposition to be filed during the fourth quarter of 2012. We intend to vigorously appeal the initial decision to the full FERC. 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 which have been effective 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 September 30, 2012, our cumulative deferred revenue related to DGGS FERC jurisdictional revenues is approximately $14.3 million. 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 beginning 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. 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. We are coordinating with PWPS to investigate the root cause of the problem. Testing of the conclusions of the root cause analysis is expected to occur during the fourth quarter of 2012. We expect that any required modifications or further servicing of the turbines to implement the root cause analysis will take place during the first quarter of 2013. We anticipate that the work will be performed in a manner that will not require DGGS to be taken completely off-line. We expect the turbine repair costs will be covered under the manufacturer's warranty. Montana Electric and Natural Gas Tracker Filings Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas supply procurement activities were prudent. In May 2012, we filed our 2012 annual electric and natural gas supply tracker filings. During June, we received an order from the MPSC approving the requested natural gas tracker rates on an interim basis. During July, the MPSC approved the electric tracker filing on an interim basis; however, the order specifically excludes DGGS contract costs from interim recovery and provides that they are to be reviewed at a future date. Demand-side management (DSM) lost revenues - Base rates, including impacts of past DSM activities, are reset in general rate case filings. As time passes between rate cases, more energy saving measures (primarily more efficient residential and commercial lighting) are implemented, causing an increase in DSM lost revenues. This increase in DSM lost revenues is included in our annual tracker filings until the next general rate case. Historically, the MPSC has authorized us to include a calculation of lost revenues based on actual DSM program activity, but prohibited the inclusion of forecasted or estimated future lost revenue in the electric tracker. In April 2012, we received a final order for our 2011 annual electric tracker filing, which authorized us to include forecasted lost revenues in future filings. Based on this order, we have recognized $3.3 million of the requested $5.7 million of lost revenues for the 2011/2012 tracker period. We have not recognized the entire amount as we are required to provide the MPSC with a detailed independent study supporting our requested DSM lost revenues during the fourth quarter of 2012. The study will also be subject to review and potential challenge by intervenors, such as the Montana Consumer Counsel (MCC). The MPSC could ultimately determine our requested amounts are too high and we may have to refund a portion of DSM lost revenues that we have recognized. We do not expect the MPSC to issue a final order related to the DSM lost revenues until at least the first quarter of 2013. Wind Generation In February 2012, the MPSC approved our application for pre-approval to purchase a wind project in Judith Basin County in Montana to be developed and constructed by Spion Kop Wind, LLC, a wholly-owned subsidiary of Compass Wind, LLC (Compass) that would provide 40 MW of name plate capacity, with an estimated cost for the total project of approximately $86 million. The approval includes 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 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. We expect to take ownership of the project and pay Compass approximately $81 million during the fourth quarter of 2012. Both the energy and associated renewable energy credits will be placed into our electric supply portfolio to meet future customer loads and renewable portfolio standards obligations. Through September 30, 2012 we have completed construction of the required transmission infrastructure and capitalized approximately $5.3 million of costs associated with this project. Battle Creek Filing 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 acquired in 2010 in regulated natural gas rate base. The application reflects 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 has been included in our natural gas supply tracker on an interim basis. A hearing was held in September 2012 and we expect to receive a final order during the fourth quarter of 2012. Pending MPSC approval, the corresponding amounts included in the natural gas supply tracker are subject to refund and through September 30, 2012, we have deferred revenue of approximately $2.2 million based on the difference between our cost of service and current natural gas market prices. Montana Natural Gas Rate Filing In September 2012, we filed a request with the MPSC for a natural gas distribution 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. We are currently awaiting the establishment of a procedural schedule.

Regulatory Matters

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 Montana Public Service Commission (MPSC) and approximately 20% of revenues allocated to wholesale customers subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).

In our DGGS FERC proceedings total project costs were not challenged and the parties to the case have stipulated to the revenue requirement; however, intervenors have challenged the allocation of costs. Our allocation methodology of 20% of the DGGS revenue requirement to FERC jurisdictional customers is based on our past practice of allocating the contracted costs for these services. 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.

In response to the initial decision, we and the intervening parties will have the opportunity to respond with briefs in support or opposition to be filed during the fourth quarter of 2012. We intend to vigorously appeal the initial decision to the full FERC. 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 which have been effective 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 September 30, 2012, our cumulative deferred revenue related to DGGS FERC jurisdictional revenues is approximately $14.3 million.

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 beginning 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.

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. We are coordinating with PWPS to investigate the root cause of the problem. Testing of the conclusions of the root cause analysis is expected to occur during the fourth quarter of 2012. We expect that any required modifications or further servicing of the turbines to implement the root cause analysis will take place during the first quarter of 2013. We anticipate that the work will be performed in a manner that will not require DGGS to be taken completely off-line. We expect the turbine repair costs will be covered under the manufacturer's warranty.

Montana Electric and Natural Gas Tracker Filings

Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas supply procurement activities were prudent.

In May 2012, we filed our 2012 annual electric and natural gas supply tracker filings. During June, we received an order from the MPSC approving the requested natural gas tracker rates on an interim basis. During July, the MPSC approved the electric tracker filing on an interim basis; however, the order specifically excludes DGGS contract costs from interim recovery and provides that they are to be reviewed at a future date.

Demand-side management (DSM) lost revenues - Base rates, including impacts of past DSM activities, are reset in general rate case filings. As time passes between rate cases, more energy saving measures (primarily more efficient residential and commercial lighting) are implemented, causing an increase in DSM lost revenues. This increase in DSM lost revenues is included in our annual tracker filings until the next general rate case. Historically, the MPSC has authorized us to include a calculation of lost revenues based on actual DSM program activity, but prohibited the inclusion of forecasted or estimated future lost revenue in the electric tracker. In April 2012, we received a final order for our 2011 annual electric tracker filing, which authorized us to include forecasted lost revenues in future filings. Based on this order, we have recognized $3.3 million of the requested $5.7 million of lost revenues for the 2011/2012 tracker period. We have not recognized the entire amount as we are required to provide the MPSC with a detailed independent study supporting our requested DSM lost revenues during the fourth quarter of 2012. The study will also be subject to review and potential challenge by intervenors, such as the Montana Consumer Counsel (MCC). The MPSC could ultimately determine our requested amounts are too high and we may have to refund a portion of DSM lost revenues that we have recognized. We do not expect the MPSC to issue a final order related to the DSM lost revenues until at least the first quarter of 2013.

Wind Generation

In February 2012, the MPSC approved our application for pre-approval to purchase a wind project in Judith Basin County in Montana to be developed and constructed by Spion Kop Wind, LLC, a wholly-owned subsidiary of Compass Wind, LLC (Compass) that would provide 40 MW of name plate capacity, with an estimated cost for the total project of approximately $86 million. The approval includes 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 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.

We expect to take ownership of the project and pay Compass approximately $81 million during the fourth quarter of 2012. Both the energy and associated renewable energy credits will be placed into our electric supply portfolio to meet future customer loads and renewable portfolio standards obligations. Through September 30, 2012 we have completed construction of the required transmission infrastructure and capitalized approximately $5.3 million of costs associated with this project.

Battle Creek Filing

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 acquired in 2010 in regulated natural gas rate base. The application reflects 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 has been included in our natural gas supply tracker on an interim basis. A hearing was held in September 2012 and we expect to receive a final order during the fourth quarter of 2012. Pending MPSC approval, the corresponding amounts included in the natural gas supply tracker are subject to refund and through September 30, 2012, we have deferred revenue of approximately $2.2 million based on the difference between our cost of service and current natural gas market prices.

Montana Natural Gas Rate Filing

In September 2012, we filed a request with the MPSC for a natural gas distribution 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. We are currently awaiting the establishment of a procedural schedule.