Rate Matters	12 Months Ended
Dec. 31, 2011
Rate Matters [Abstract]
Rate Matters	12. Rate Matters NSP-Minnesota Pending Regulatory Proceedings - MPUC Base Rate NSP-Minnesota - Minnesota Electric Rate Case - In November 2010, NSP-Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million, or 1.81 percent in 2012. The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent. The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011. In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments. The DOER revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent. The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation were associated with ROE and compensation related issues. In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million. The revisions were due to delays in the Monticello nuclear plant extended power uprate. In November 2011, NSP-Minnesota reached a settlement agreement with the Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group and Verso Paper Corp., which settled all financial issues and several rate design issues between the signing parties. The settlement includes a rate increase of approximately $58.0 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent. The settlement agreement reflects a reduction to depreciation expense and NSP-Minnesota's rate request by $30 million with an additional adjustment of $7.5 million related to employee compensation. The settlement also provides NSP-Minnesota the ability to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012, which is currently projected to increase by approximately $28 million. NSP-Minnesota also agreed to not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement and the property tax filing are approved by the MPUC. NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $67.4 million for 2011 and has reduced depreciation expense by $30 million. In February 2012, the ALJ recommended MPUC approval of the settlement agreement. In addition, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement. A decision is expected by the MPUC in the first half of 2012. Pending Regulatory Proceedings - NDPSC NSP-Minnesota – North Dakota Electric Rate Case - In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent in 2011 and a step increase of $4.2 million, or 2.6 percent in 2012. The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent. The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011. NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $2.4 million for 2011. The interim rates will remain in effect until the NDPSC makes its final decision on the case. In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012, due to the termination of the Merricourt wind project. In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff. If approved by the NDPSC, the settlement would result in a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues. To address 2011 sales coming in below test year projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase. An NDPSC decision is expected in March 2012. Pending Regulatory Proceedings - SDPUC NSP-Minnesota – South Dakota Electric Rate Case - In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012. The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms. The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent. NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year. As a result of delays in the rate case process, interim rates of $12.7 million were implemented Jan. 2, 2012. A final decision is expected in the first half of 2012. Electric, Purchased Gas and Resource Adjustment Incentive Clauses NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates. At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows: CIP Rider - CIP expenses are recovered through base rates and a rider that is adjusted annually. Under the 2010 electric CIP rider request approved by the MPUC in October 2010, NSP-Minnesota recovered $84.4 million through the rider during November 2010 to December 2011. This is in addition to $60.9 million recovered through base rates. During December 2010 to December 2011, NSP-Minnesota recovered $27.4 million through the natural gas CIP rider approved in November 2010. This is in addition to $4.4 million recovered in base rates. In January 2012, the MPUC approved NSP-Minnesota's annual electric rider petition requesting recovery of $74.7 million of electric CIP expenses and financial incentives to be recovered during February 2012 through December 2012. In December 2011, the MPUC approved NSP-Minnesota's annual gas rider petition requesting $10.6 million of natural gas CIP expenses and financial incentives to be recovered during January 2012 through December 2012. This proposed recovery through the riders is in addition to an estimated $48.3 million and $3.8 million through electric and gas base rates, respectively. NSP-Wisconsin Recently Concluded Regulatory Proceedings - PSCW Base Rate NSP-Wisconsin 2011 Electric and Gas Rate Case - In June 2011, NSP-Wisconsin filed a request with the PSCW to increase electric rates approximately $29.2 million, or 5.1 percent and natural gas rates approximately $8.0 million, or 6.6 percent effective Jan. 1, 2012. The rate filing is based on a 2012 forecast test year and includes a requested ROE of 10.75 percent, an equity ratio of 52.54 percent, an electric rate base of approximately $718 million and a natural gas rate base of $84 million. In December 2011, the PSCW approved an electric rate increase of approximately $12.2 million or 2.1 percent, and a natural gas rate increase of $2.9 million or 2.4 percent, with new rates effective Jan. 1, 2012. The primary reason for the natural gas rate reduction from the original request was the PSCW decision to deny NSP-Wisconsin's proposal to pre-collect certain manufactured gas plant remediation costs. The primary reasons for the electric rate reduction were updated 2012 electric fuel costs and the delays in the Monticello nuclear plant extended life cycle management and power uprate project. The rate increases were based on a 10.4 percent ROE and an equity ratio of 52.59 percent. PSCo Pending and Recently Concluded Regulatory Proceedings - CPUC Base Rate PSCo 2010 Gas Rate Case - In December 2010, PSCo filed a request with the CPUC to increase Colorado retail gas rates by $27.5 million on an annual basis. In March 2011, PSCo revised its requested rate increase to $25.6 million. The revised request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.1 percent. PSCo proposed recovering $23.2 million of test year capital and O&M expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006. PSCo also proposed removing the earnings on gas in underground storage from base rates. In August 2011, the CPUC approved a comprehensive settlement that PSCo reached with the CPUC Staff and the OCC to increase rates by $12.8 million, to institute the PSIA rider, and to remove gas in underground storage from base rates and recover those costs in the GCA. The GCA is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs. Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent. New base rates and the GCA recovery went into effect in September 2011. The PSIA rider and new rate designs went into effect on Jan. 1, 2012. PSCo 2011 Electric Rate Case - In November 2011, PSCo filed a request with the CPUC to increase Colorado retail electric rates by $141.9 million. The request was based on a 2012 forecast test year, a 10.75 percent ROE, a rate base of $5.4 billion and an equity ratio of 56 percent. Final rates are expected to be effective in the summer of 2012. The CPUC is expected to rule on the electric rate case in July 2012. In November 2011, PSCo filed a petition to implement interim rates, subject to refund, of $100 million to be effective in January 2012. On Jan. 11, 2012, the CPUC denied PSCo's request to implement an interim electric rate increase of $100 million on the basis that it had not demonstrated adverse financial impacts. On Jan. 12, 2012, PSCo filed for reconsideration of the CPUC's decision to deny interim rates, and requested that the CPUC authorize interim rates of approximately $42 million, specifically related to the impacts resulting from the expiration of the Black Hills contract. On Jan. 17, 2012, the CPUC denied the request for reconsideration. However, on Jan. 27, 2012, the CPUC approved PSCo's request for deferred accounting of the $42 million annual revenue requirement associated with the Black Hills contract. Pending Regulatory Proceedings - FERC Base Rate PSCo Wholesale Electric Rate Case - In February 2011, PSCo filed with the FERC to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent. The formula rate would be estimated each year for the following year and then trued-up to actual costs after the conclusion of the calendar year. A decision is expected in the first quarter of 2012. Electric, Purchased Gas and Resource Incentive Adjustment Clauses PSCo has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates. At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows: DSM and the DSMCA - The CPUC approved higher savings goals and a slightly higher financial incentive mechanism for PSCo's electric DSM energy efficiency programs starting in 2012. Savings goals will increase to 130 percent of the current goals and incentives will be awarded as one installment in the year following plan achievements. PSCo will also be able to earn an incentive on 11 percent of net economic benefits at an achievement level of 130 percent and a maximum annual incentive of $30 million. The CPUC approved the PSCo electric DSM budget of $77.3 million and gas DSM budget of $12.2 million effective Jan. 1, 2012. This is in addition to $29.4 million for electricity demand response programs recovered through the DSMCA. Energy efficiency and demand response related DSM costs are recovered through a combination of the DSMCA riders and base rates. The DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. REC Sharing - In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers' share of the margins to be netted against the RESA regulatory asset balance. In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance. In June 2011, PSCo filed an application with the CPUC for permanent treatment of RECs that are bundled with energy into California. The application is seeking margin sharing of 30 percent to PSCo and 70 percent to customers for deliveries outside of California and 40 percent to PSCo and 60 percent to customers for deliveries inside of California. PSCo also proposed that sales of RECs bundled with on-system energy be aggregated with other trading margins and shared 20 percent to PSCo and 80 percent to customers. In September 2011, the CPUC Staff, the OCC, and the Colorado Energy Consumers filed answer testimony requesting the CPUC approve margin sharing of 8 percent to 25 percent to PSCo for deliveries outside of California and 8 percent to 35 percent for deliveries inside of California. In January 2012, the CPUC approved the margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. All customer margin sharing and unspent carbon offset funds will be credited to the RESA regulatory asset balance. Because the sharing percentage was less than recommended by the CPUC Staff, OCC, and the Colorado Energy Consumers, PSCo plans to file an Application for Rehearing, Rearguement and Reconsideration during the first quarter of 2012. SPS Recently Concluded Regulatory Proceedings - NMPRC and PUCT Base Rate SPS – New Mexico Retail Rate Case - In February 2011, SPS filed a request with the NMPRC seeking to increase New Mexico electric rates approximately $19.9 million. The rate filing was based on a 2011 test year adjusted for known and measurable changes for 2012, a requested ROE of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent. In December 2011, the NMPRC approved a black box settlement with new rates effective Jan. 1, 2012. The settlement increased base rates by $13.5 million. SPS agreed not to file another base rate case until Dec. 3, 2012 with new final rates from the result of such case not going into effect until Jan. 1, 2014 (Settlement Period). However, SPS can request to implement interim rates if the NMPRC standard for interim rates is met. During the Settlement Period, rates are to remain fixed aside from the continued operation of the fuel adjustment clause and certain exceptions for energy efficiency, a rider for an approved renewable portfolio standard regulatory asset, and actual costs incurred for environmental regulations with an effective date after Dec. 31, 2010. SPS – Texas Retail Rate Case - In May 2010, SPS filed a request with the PUCT seeking to increase Texas electric rates by approximately $71.5 million inclusive of franchise fees. The rate filing was based on a 2009 test year adjusted for known and measurable changes, a requested ROE of 11.35 percent, an electric rate base of $1.031 billion and an equity ratio of 51.0 percent. In November 2010, SPS filed an update to the cost of service to reflect the sale of Lubbock facilities which reduced the total request to approximately $63.7 million. Effective Feb. 16, 2011, the parties reached an unopposed settlement to resolve all issues in the case and increase base rates by $39.4 million, of which $16.9 million is associated with the transfer of two riders, the TCRF and the PCRF, into base rates. Effective Jan. 1, 2012, base rates increased by an additional $13.1 million. SPS agreed not to file another rate case until Sept. 15, 2012. In addition, SPS cannot file a TCRF application until 2013, and if SPS files a TCRF application before the effective date of rates in its next rate case, it must reduce the calculated TCRF revenue requirement by $12.2 million.

12. Rate Matters

NSP-Minnesota

Pending Regulatory Proceedings - MPUC

Base Rate

NSP-Minnesota - Minnesota Electric Rate Case - In November 2010, NSP-Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million, or 1.81 percent in 2012. The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent. The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011.

In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments. The DOER revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent. The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation were associated with ROE and compensation related issues.

In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million. The revisions were due to delays in the Monticello nuclear plant extended power uprate.

In November 2011, NSP-Minnesota reached a settlement agreement with the Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group and Verso Paper Corp., which settled all financial issues and several rate design issues between the signing parties. The settlement includes a rate increase of approximately $58.0 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent. The settlement agreement reflects a reduction to depreciation expense and NSP-Minnesota's rate request by $30 million with an additional adjustment of $7.5 million related to employee compensation. The settlement also provides NSP-Minnesota the ability to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012, which is currently projected to increase by approximately $28 million. NSP-Minnesota also agreed to not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement and the property tax filing are approved by the MPUC. NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $67.4 million for 2011 and has reduced depreciation expense by $30 million.

In February 2012, the ALJ recommended MPUC approval of the settlement agreement. In addition, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement. A decision is expected by the MPUC in the first half of 2012.

Pending Regulatory Proceedings - NDPSC

NSP-Minnesota – North Dakota Electric Rate Case - In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent in 2011 and a step increase of $4.2 million, or 2.6 percent in 2012. The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.

The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011. NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $2.4 million for 2011. The interim rates will remain in effect until the NDPSC makes its final decision on the case.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012, due to the termination of the Merricourt wind project.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff. If approved by the NDPSC, the settlement would result in a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues. To address 2011 sales coming in below test year projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.

An NDPSC decision is expected in March 2012.

Pending Regulatory Proceedings - SDPUC

NSP-Minnesota – South Dakota Electric Rate Case - In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012. The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms. The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent. NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year.

As a result of delays in the rate case process, interim rates of $12.7 million were implemented Jan. 2, 2012. A final decision is expected in the first half of 2012.

Electric, Purchased Gas and Resource Adjustment Incentive Clauses

NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates. At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows:

CIP Rider - CIP expenses are recovered through base rates and a rider that is adjusted annually. Under the 2010 electric CIP rider request approved by the MPUC in October 2010, NSP-Minnesota recovered $84.4 million through the rider during November 2010 to December 2011. This is in addition to $60.9 million recovered through base rates. During December 2010 to December 2011, NSP-Minnesota recovered $27.4 million through the natural gas CIP rider approved in November 2010. This is in addition to $4.4 million recovered in base rates.

In January 2012, the MPUC approved NSP-Minnesota's annual electric rider petition requesting recovery of $74.7 million of electric CIP expenses and financial incentives to be recovered during February 2012 through December 2012. In December 2011, the MPUC approved NSP-Minnesota's annual gas rider petition requesting $10.6 million of natural gas CIP expenses and financial incentives to be recovered during January 2012 through December 2012. This proposed recovery through the riders is in addition to an estimated $48.3 million and $3.8 million through electric and gas base rates, respectively.

NSP-Wisconsin

Recently Concluded Regulatory Proceedings - PSCW

Base Rate

NSP-Wisconsin 2011 Electric and Gas Rate Case - In June 2011, NSP-Wisconsin filed a request with the PSCW to increase electric rates approximately $29.2 million, or 5.1 percent and natural gas rates approximately $8.0 million, or 6.6 percent effective Jan. 1, 2012. The rate filing is based on a 2012 forecast test year and includes a requested ROE of 10.75 percent, an equity ratio of 52.54 percent, an electric rate base of approximately $718 million and a natural gas rate base of $84 million.

In December 2011, the PSCW approved an electric rate increase of approximately $12.2 million or 2.1 percent, and a natural gas rate increase of $2.9 million or 2.4 percent, with new rates effective Jan. 1, 2012. The primary reason for the natural gas rate reduction from the original request was the PSCW decision to deny NSP-Wisconsin's proposal to pre-collect certain manufactured gas plant remediation costs. The primary reasons for the electric rate reduction were updated 2012 electric fuel costs and the delays in the Monticello nuclear plant extended life cycle management and power uprate project. The rate increases were based on a 10.4 percent ROE and an equity ratio of 52.59 percent.

PSCo

Pending and Recently Concluded Regulatory Proceedings - CPUC

Base Rate

PSCo 2010 Gas Rate Case - In December 2010, PSCo filed a request with the CPUC to increase Colorado retail gas rates by $27.5 million on an annual basis. In March 2011, PSCo revised its requested rate increase to $25.6 million. The revised request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.1 percent. PSCo proposed recovering $23.2 million of test year capital and O&M expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006. PSCo also proposed removing the earnings on gas in underground storage from base rates.

In August 2011, the CPUC approved a comprehensive settlement that PSCo reached with the CPUC Staff and the OCC to increase rates by $12.8 million, to institute the PSIA rider, and to remove gas in underground storage from base rates and recover those costs in the GCA. The GCA is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs. Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent.

New base rates and the GCA recovery went into effect in September 2011. The PSIA rider and new rate designs went into effect on Jan. 1, 2012.

PSCo 2011 Electric Rate Case - In November 2011, PSCo filed a request with the CPUC to increase Colorado retail electric rates by $141.9 million. The request was based on a 2012 forecast test year, a 10.75 percent ROE, a rate base of $5.4 billion and an equity ratio of 56 percent. Final rates are expected to be effective in the summer of 2012. The CPUC is expected to rule on the electric rate case in July 2012.

In November 2011, PSCo filed a petition to implement interim rates, subject to refund, of $100 million to be effective in January 2012. On Jan. 11, 2012, the CPUC denied PSCo's request to implement an interim electric rate increase of $100 million on the basis that it had not demonstrated adverse financial impacts. On Jan. 12, 2012, PSCo filed for reconsideration of the CPUC's decision to deny interim rates, and requested that the CPUC authorize interim rates of approximately $42 million, specifically related to the impacts resulting from the expiration of the Black Hills contract. On Jan. 17, 2012, the CPUC denied the request for reconsideration. However, on Jan. 27, 2012, the CPUC approved PSCo's request for deferred accounting of the $42 million annual revenue requirement associated with the Black Hills contract.

Pending Regulatory Proceedings - FERC

Base Rate

PSCo Wholesale Electric Rate Case - In February 2011, PSCo filed with the FERC to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent. The formula rate would be estimated each year for the following year and then trued-up to actual costs after the conclusion of the calendar year. A decision is expected in the first quarter of 2012.

Electric, Purchased Gas and Resource Incentive Adjustment Clauses

PSCo has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates. At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows:

DSM and the DSMCA - The CPUC approved higher savings goals and a slightly higher financial incentive mechanism for PSCo's electric DSM energy efficiency programs starting in 2012. Savings goals will increase to 130 percent of the current goals and incentives will be awarded as one installment in the year following plan achievements. PSCo will also be able to earn an incentive on 11 percent of net economic benefits at an achievement level of 130 percent and a maximum annual incentive of $30 million.

The CPUC approved the PSCo electric DSM budget of $77.3 million and gas DSM budget of $12.2 million effective Jan. 1, 2012. This is in addition to $29.4 million for electricity demand response programs recovered through the DSMCA. Energy efficiency and demand response related DSM costs are recovered through a combination of the DSMCA riders and base rates. The DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year.

REC Sharing - In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers' share of the margins to be netted against the RESA regulatory asset balance. In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

In June 2011, PSCo filed an application with the CPUC for permanent treatment of RECs that are bundled with energy into California. The application is seeking margin sharing of 30 percent to PSCo and 70 percent to customers for deliveries outside of California and 40 percent to PSCo and 60 percent to customers for deliveries inside of California. PSCo also proposed that sales of RECs bundled with on-system energy be aggregated with other trading margins and shared 20 percent to PSCo and 80 percent to customers. In September 2011, the CPUC Staff, the OCC, and the Colorado Energy Consumers filed answer testimony requesting the CPUC approve margin sharing of 8 percent to 25 percent to PSCo for deliveries outside of California and 8 percent to 35 percent for deliveries inside of California.

In January 2012, the CPUC approved the margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. All customer margin sharing and unspent carbon offset funds will be credited to the RESA regulatory asset balance. Because the sharing percentage was less than recommended by the CPUC Staff, OCC, and the Colorado Energy Consumers, PSCo plans to file an Application for Rehearing, Rearguement and Reconsideration during the first quarter of 2012.

SPS

Recently Concluded Regulatory Proceedings - NMPRC and PUCT

Base Rate

SPS – New Mexico Retail Rate Case - In February 2011, SPS filed a request with the NMPRC seeking to increase New Mexico electric rates approximately $19.9 million. The rate filing was based on a 2011 test year adjusted for known and measurable changes for 2012, a requested ROE of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent.

In December 2011, the NMPRC approved a black box settlement with new rates effective Jan. 1, 2012. The settlement increased base rates by $13.5 million. SPS agreed not to file another base rate case until Dec. 3, 2012 with new final rates from the result of such case not going into effect until Jan. 1, 2014 (Settlement Period). However, SPS can request to implement interim rates if the NMPRC standard for interim rates is met. During the Settlement Period, rates are to remain fixed aside from the continued operation of the fuel adjustment clause and certain exceptions for energy efficiency, a rider for an approved renewable portfolio standard regulatory asset, and actual costs incurred for environmental regulations with an effective date after Dec. 31, 2010.

SPS – Texas Retail Rate Case - In May 2010, SPS filed a request with the PUCT seeking to increase Texas electric rates by approximately $71.5 million inclusive of franchise fees. The rate filing was based on a 2009 test year adjusted for known and measurable changes, a requested ROE of 11.35 percent, an electric rate base of $1.031 billion and an equity ratio of 51.0 percent. In November 2010, SPS filed an update to the cost of service to reflect the sale of Lubbock facilities which reduced the total request to approximately $63.7 million.

Effective Feb. 16, 2011, the parties reached an unopposed settlement to resolve all issues in the case and increase base rates by $39.4 million, of which $16.9 million is associated with the transfer of two riders, the TCRF and the PCRF, into base rates. Effective Jan. 1, 2012, base rates increased by an additional $13.1 million.

SPS agreed not to file another rate case until Sept. 15, 2012. In addition, SPS cannot file a TCRF application until 2013, and if SPS files a TCRF application before the effective date of rates in its next rate case, it must reduce the calculated TCRF revenue requirement by $12.2 million.