5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.'s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings - Minnesota Public Utilities Commission (MPUC)

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, a requested return on equity (ROE) of 11.25 percent, an electric rate base of $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 August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and an additional increase of approximately $29 million in 2012.

In November 2011, NSP-Minnesota reached a settlement agreement with various parties, which resolved all financial issues and several rate design issues. The settlement agreement includes:

·	A rate increase of approximately $58 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent and an equity ratio of 52.56 percent.

·	A reduction to depreciation expense and NSP-Minnesota's rate request by $30 million.

·	The ability for NSP-Minnesota to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012.

·	The stipulation that NSP-Minnesota will not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement agreement and the property tax filing are approved by the MPUC.

In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement. On March 29, 2012, the MPUC approved the settlement and a written order is pending. As of March 31, 2012 and Dec. 31, 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $78 million and $67 million, repectively, to align with the settlement agreement.

NSP-Minnesota - Minnesota Property Tax Deferral Request - As part of the settlement agreement in the Minnesota electric rate case, the settling parties acknowledged that NSP-Minnesota would be filing a petition seeking deferred accounting for 2012 property tax expense in excess of the level approved in the rate case. The settling parties waived any right to object to the petition, but reserved the right to review and comment on the petition. In December 2011, NSP-Minnesota filed the petition to request deferral of approximately $28 million of incremental 2012 property taxes that will not be recovered in base rates. The estimate of 2012 incremental property taxes has been subsequently revised to approximately $24 million.

In April 2012, the Minnesota Department of Commerce (DOC) filed comments on the petition. The DOC concluded that NSP-Minnesota had not made a reasonable case for deferred accounting and recommended that the MPUC deny NSP-Minnesota's request to defer incremental 2012 property taxes and also opposed the proposed rider mechanism. The Xcel Large Industrials and the Minnesota Chamber of Commerce filed comments in support of the deferred accounting treatment as preferable to a rider mechanism, with the understanding that all costs will be reviewed in NSP-Minnesota's next rate case. Until the MPUC rules on the issue, NSP-Minnesota will continue to expense the incremental property taxes. An MPUC decision is expected in the second quarter of 2012.

Recently Concluded Regulatory Proceedings - North Dakota Public Service Commission (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, and a step increase of $4.2 million, or 2.6 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 $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.

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.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff, which provided for 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 2012 sales coming in below forecast revenue projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase. In February 2012, the NDPSC approved the settlement agreement.

Pending Regulatory Proceedings - South Dakota Public Utilities Commission (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. On Jan. 2, 2012, interim rates of $12.7 million were implemented.

In April 2012, the SDPUC Staff filed their direct testimony, which recommended an ROE of approximately 9 percent (ranging from 8.5 percent to 9.5 percent) and a lower cost of debt than the request (6.02 percent compared to the original request of 6.13 percent). The Staff also recommended disallowance of the Nobles wind project costs unless the SDPUC determines there is energy value in which case the Staff's recommendation would be to disallow a portion of the costs. NSP-Minnesota's rebuttal testimony is due by April 27, 2012 and a final SDPUC decision is expected in the summer of 2012.

PSCo

Recently Concluded Regulatory Proceedings - CPUC

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, an electric rate base of $5.4 billion and an equity ratio of 56 percent.

On April 26, 2012, the CPUC approved a comprehensive multi-year settlement agreement, which covers 2012 through 2014. Key terms of the agreement include the following:

PSCo will implement an annual electric rate increase of $73 million in 2012. The rate increase will be effective on May 1, 2012, subject to refund. In addition, PSCo will implement incremental electric rate increases of $16 million on Jan. 1, 2013 and $25 million on Jan. 1, 2014. These rate increases are net of the shift of the costs from the purchased capacity cost adjustment and the transmission cost adjustment clauses to base rates.

·	The settlement reflects an authorized ROE of 10 percent and an equity ratio of 56 percent.

·	PSCo will forego the opportunity allowed under the CACJA to seek additional rate mechanisms to recover approved CACJA plan costs through 2014. PSCo will instead recover the carrying costs of CACJA related expenditures through the recording of allowance for funds used during construction.

For 2012 through 2014, incremental property taxes in excess of $76.7 million (2010-2011 historic test year property taxes) will be deferred over a three-year period with the amortization effective the first year after the deferral. To the extent that PSCo is successful in gaining the manufacturer's sales tax refund as a result of the sales tax lawsuit currently pending in the Colorado Supreme Court, PSCo shall credit such refunds first against legal fees incurred to obtain the refund and then against the deferred property tax balances outstanding at the end of the 2014.

The rates that take effect include no incremental recovery of deferred costs associated with the expiration of the Black Hills contract. However, the jurisdictional allocator used to determine the increase in base rates and for all rider calculations will reflect the expiration of the Black Hills contract as of Dec. 31, 2011. The rates that would take effect also include no change in depreciation rates.

·	The signing parties agree to implement an earnings test, in which customers and shareholders will share earnings above an ROE of 10 percent. The sharing mechanism is as follows:

ROE	Shareholders		Customers
> 10.0% ≤ 10.2%	40	%	60	%
> 10.2% ≤ 10.5%	50		50
> 10.5%	-		100

PSCo agrees that it will not file for an electric rate increase that would take effect prior to Jan. 1, 2015, provided that net revenue requirements increases or decreases in excess of $10 million caused by changes in tax law, government mandates, or natural disasters may be deferred or recovered through a modified rate adjustment. In the event normalized base revenues in either 2012 or 2013 are 2.0 percent below 2011 actual levels adjusted to reflect the rate increases allowed for 2012 and 2013, PSCo has the right to an additional rate adjustment in the next year for 50 percent of the shortfall. The parties acknowledge that PSCo may file an electric rate increase as early as May 1, 2014, so long as no rate increase takes effect on either an interim or permanent basis prior to Jan. 1, 2015.

Pending and Recently Concluded Regulatory Proceedings - Federal Energy Regulatory Commission (FERC)

PSCo 2011 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. In September 2011, PSCo implemented an interim rate increase of $7.8 million, subject to refund.

In April 2012, PSCo filed an unopposed settlement agreement with wholesale customers for an annual rate increase of $7.8 million. The primary reasons for the decrease from the original request were a reduction to depreciation expense of $5.8 million and a lower ROE (ranging from 10.1 percent to 10.4 percent). The reduction of depreciation expense is associated with the early retirement of plants related to PSCo's compliance with the CACJA. The depreciation expense will be deferred and amortized over the original life of the plants.

PSCo Transmission Formula Rate Case - In April 2012, PSCo filed with the FERC to revise the wholesale transmission rates formula from a historic test year formula rate to a forecast transmission formula. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo's transmission revenue by approximately $2.0 million over rates expected to be effective in June 2012. A FERC decision is expected in the second half of 2012.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (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 renewable energy standard adjustment (RESA) regulatory asset balance. In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

In the first quarter of 2012, the CPUC approved an annual 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. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. In March 2012, PSCo credited approximately $28.7 million against the RESA regulatory asset balance.

This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and to review evidence regarding actual deliveries in relatively more complex markets such as California.