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, 2012 and in Note 5 to Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarter period ended March 31, 2013, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

Base Rate

NSP-Minnesota – Minnesota 2012 Electric Rate Case — In November 2012, NSP-Minnesota filed a request with the MPUC for an increase in annual revenues of approximately $285 million, or 10.7 percent. The rate filing is based on a 2013 forecast test year, a requested return on equity (ROE) of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. In January 2013, interim rates of approximately $251 million became effective, subject to refund.

In March 2013, NSP-Minnesota filed rebuttal testimony and revised the requested annual revenue increase to approximately $219.7 million, or 8.23 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. The updated request reflects alternate proposals in several key areas including:


•	Deferral of depreciation expenses and property taxes related to Sherco Unit 3 for 2012 and 2013 and removal of avoided 2013 operating and maintenance (O&M) expense due to the extended outage at Sherco Unit 3.


•	Removal of Monticello 2013 license costs from plant in service and deferral of 2013 depreciation expense for the primary Monticello life cycle management (LCM) / extended power uprate (EPU) project until after an MPUC order finding the costs prudent.


•	Removal of Prairie Island EPU project costs, reflecting the MPUC decision to cancel the project in December 2012.


•	Adjustments to compensation and benefits recovery including Annual Incentive Plan (AIP) to reflect prior MPUC decisions establishing a limitation at 15 percent of base pay using a four-year average AIP target, pension expense and active healthcare costs.


•	Adjustment of pension recoveries to reflect amortized recovery of 2008 market losses.


•	Recovery of coal pile and ash pond remediation costs at the Black Dog plant through a 15 year amortization.


•	Updated forecast for property taxes.


•	Updated forecast with 6 months of actual sales, customer and weather data through December 2012, and updated economic assumptions based on a December 2012 economic forecast, proposing a refund if sales are higher than forecast on a weather-normalized basis.


•	Correction to the original filing and other adjustments.

In April 2013, intervenors filed surrebuttal testimony, including the Minnesota Department of Commerce (DOC), Office of Attorney General (OAG), Minnesota Chamber (MCC), Xcel Large Industrials (XLI), Commercial Group, Industrial, Commercial and Institutional Customers, and Energy Cents Coalition. The DOC recommended a revenue increase of $89.6 million, based on a 9.83 percent ROE, an average electric rate base of approximately $6.1 billion and an equity ratio of 52.56 percent. Subsequently, the DOC’s recommendation was revised to approximately $98.6 million, largely to reflect updated information.

In its surrebuttal testimony, the OAG recommended no recovery for the Prairie Island EPU project, stating it should have been written off in 2012 when cancellation of the project was approved by the MPUC. The DOC is also not supportive of recovery of the Prairie Island EPU cancelled EPU costs. The OAG suggests pension recovery in rates exceeds benefit payout because of changes made to benefit plans and recommends correction for an alleged over-collection of funds to pay for future benefits which may never be paid out. The OAG supports the DOC in adjustments to recovery of annual incentive compensation and does not find NSP-Minnesota’s Sherco Unit 3 proposal warranted. XLI and MCC also opposed recovery of Sherco Unit 3 costs and Monticello EPU costs.

Through the hearing and briefing process, NSP-Minnesota revised its rate request to approximately $209 million to reflect updated property tax information, resolution of concerns regarding Wisconsin wholesale customers and other adjustments. The $209 million revenue requirement reflects a requested deficiency of $259 million combined with $50 million of rate mitigation through deferral mechanisms.

ALJ Recommendation

On July 3, 2013, the Minnesota Administrative Law Judge (ALJ) issued her report and recommended a rate increase of approximately $127 million, based on a ROE of 9.83 percent, an equity ratio of 52.56 percent and an electric rate base of $6.233 billion. In addition, the ALJ recommendation included approximately $51 million in deferrals of which NSP-Minnesota estimates $34 million will affect net income. The deferrals are related to Sherco Unit 3 and pension.

The ALJ indicated that Sherco Unit 3 should be considered “used and useful” for rate making purposes, but that a portion of the Monticello LCM/EPU would not be considered “used and useful” until NSP-Minnesota obtains the uprate license from the Nuclear Regulatory Commission (NRC). The ALJ also found that the prudency of the cost increases for the Monticello LCM/EPU project and cost recovery for the cancelled Prairie Island EPU project should be determined in the next Minnesota rate case. In addition, the ALJ recommended accepting NSP-Minnesota’s position on the inclusion of the pension market loss and incentive compensation and the DOC’s position on the sales forecast.

The table below reconciles the final position of NSP-Minnesota, the DOC and the ALJ.



(Millions of Dollars)	NSP-Minnesota Request			DOC Recommendation			ALJ Recommendation
NSP-Minnesota original request	$	285		$	285		$	285
ROE	—			(43		)	(43		)
Sherco Unit 3	(35		)	(40		)	(38		)
Reduced recovery for the nuclear plants	(11		)	(9		)	(14		)
Incentive compensation	(3		)	(20		)	(4		)
Sales forecast	(1		)	(26		)	(26		)
Pension	(10		)	(25		)	(13		)
Employee benefits	(4		)	(6		)	(6		)
Black Dog remediation	(5		)	(5		)	(5		)
NSP-Wisconsin wholesale allocation	(7		)	(7		)	(7		)
Other, net	—			(5		)	(2		)
Recommended rate increase	209			99			127
Preliminary estimated impact of cost deferrals	50			5			34
Estimated impact on 2013 pre-tax income	$	259		$	104		$	161

The MPUC has scheduled deliberations for Aug. 6 and 8, 2013. The MPUC is expected to reach a decision on the issues at the deliberations and issue an order in September 2013.

NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with the interim rates of approximately $16 million and $47 million, as of March 31 and June 30, 2013, respectively.

Pending Regulatory Proceedings — North Dakota Public Service Commission (NDPSC)

Base Rate

NSP-Minnesota – North Dakota 2012 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC to increase annual retail electric rates approximately $16.9 million, or 9.25 percent. The rate filing is based on a 2013 forecast test year, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent. In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund. In June 2013, NSP-Minnesota revised its rate increase to $16 million, reflecting updated information. There were no intervenors in this proceeding.

On July 17, 2013, NDPSC Advocacy Staff filed direct testimony prepared by their rate case consultants. Staff’s testimony recommended a 9.0 percent ROE and other revenue requirement adjustments, which resulted in an overall rate reduction of approximately $2.1 million. Primary revenue requirement adjustments include:



(Millions of Dollars)	Revenue requirement adjustments as filed by the Staff
NSP-Minnesota revised request	$	16.0
Use of a one month coincident peak demand allocator for certain rate base and operation expenses	(20.0		)
ROE	(5.2		)
Incentive compensation	(0.8		)
Adjustment for various O&M expenses	(0.7		)
Calculation of federal income taxes	6.3
Modified cost of capital and increased capital structure to 53.42 percent	1.4
Other, net	0.9
Recommended rate decrease	$	(2.1	)

Additionally, NDPSC Staff recommends customers in NSP-Minnesota’s North Dakota jurisdiction be excluded from paying for costs of certain purchased power agreements.

Next steps in the procedural schedule are expected to be as follows:


•	Rebuttal Testimony – Aug. 12, 2013


•	Technical Hearings – Aug. 27-28, 2013


•	Initial Briefs – Sept. 20, 2013


•	Reply Briefs/Proposed Findings – October 2013

A final NDPSC decision on the case is expected in the fourth quarter of 2013.

NSP-Wisconsin

Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW)

Base Rate

NSP-Wisconsin – Wisconsin 2014 Electric and Gas Rate Case — On May 31, 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent.

The rate filing is based on a 2014 forecast test year, a ROE of 10.4 percent, an equity ratio of 52.5 percent, and a forecasted average net investment rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility.

Next steps in the procedural schedule are expected to be as follows:


•	Staff and Intervenor Direct Testimony – Oct. 4, 2013


•	Rebuttal Testimony – Oct. 18, 2013


•	Surrebuttal testimony – Oct. 28, 2013


•	Hearing – Oct. 30, 2013


•	Initial Brief – Nov. 13, 2013


•	Reply Brief – Nov. 20, 2013

A PSCW decision is anticipated in December 2013, with final rates going into effect in January 2014.

PSCo

Pending and Recently Concluded Regulatory Proceedings — CPUC

Base Rate

PSCo – Colorado 2013 Gas Rate Case — In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015. The request is based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $1.3 billion and an equity ratio of 56 percent. PSCo is requesting an extension of its Pipeline System Integrity Adjustment (PSIA) rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects. PSCo estimates that the PSIA will increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue. In conjunction with the multi-year base rate step increases, PSCo is proposing a stay-out provision and an earnings test through the end of 2015 with a commitment to file a rate case to implement revised rates on Jan. 1, 2016.

In order to accommodate the procedural schedule, rates will go into effect as filed on Aug. 10, 2013, subject to refund.

On April 3, 2013, four parties filed answer testimony in the natural gas case. The CPUC Staff and Office of Consumer Counsel (OCC) recommended changes to the level of integrity management costs moved from the PSIA rider to base rates. PSCo’s 2013 deficiency based on a Forecasted Test Year (FTY) net of PSIA changes was $45 million for 2013 and the revenue deficiency was $28.3 million based on a Historic Test Year (HTY).

The CPUC Staff recommended a rate reduction of $14.4 million, based on a HTY, an ROE of 9 percent and an equity ratio of 52 percent and other adjustments. The OCC recommended a rate increase of $0.5 million based on a HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments. While the OCC did not recommend that the CPUC set rates using a FTY, they did calculate a revenue deficiency of $12.4 million for 2013. No other intervenor made ROE recommendations or specific recommendations regarding the revenue deficiency. The major adjustments to the test year proposed by the CPUC Staff and OCC are presented below.



(Millions of Dollars)	CPUC Staff			OCC
PSCo deficiency based on a HTY	$	28.3		$	28.3
ROE and capital structure adjustments	(20.8		)	(20.0		)
Move to a 13 month average from year end rate base	(5.7		)	(3.2		)
Remove pension asset	(5.9		)	—
Remove incentive compensation	(3.5		)	(0.2		)
Challenge known and measurable	—			(9.0		)
Eliminate depreciation annualization	—			(1.8		)
Revenue adjustments	(4.1		)	(1.4		)
Resulting tax impacts	1.5			4.7
Other adjustments	(4.2		)	3.1
Recommendation	$	(14.4	)	$	0.5

On April 26, 2013, the CPUC Staff filed supplemental testimony recommending an additional net disallowance of $1.6 million for adjustments and corrections.

On April 29, 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, with subsequent step increases of $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. PSCo agreed to recover approximately $3.5 million of revenue requirement in the PSIA, rather than through base rates and accepted the CPUC Staff’s recommendation to use deferred accounting to accommodate property tax increases.

Hearings were held in May 2013. An ALJ recommendation is anticipated in August 2013 and a decision is expected in the third quarter of 2013.

PSCo – Colorado 2013 Steam Rate Case — In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015. The request is based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent. Final rates are expected to be effective in the fourth quarter of 2013.

On July 23, 2013, PSCo, CPUC Staff, the OCC and Colorado Energy Consumers representing the Building Owners Management Association filed an unopposed joint motion for the CPUC to vacate the current procedural schedule and to set a date of Aug. 12, 2013, by which the parties shall file either: (i) a comprehensive settlement agreement resolving all issues presented in this matter; or (ii) a consensus revised procedural schedule.

PSCo – 2011 Electric Rate Case Earnings Test — On April 1, 2013, PSCo filed a tariff implementing the earnings sharing mechanism consistent with the settlement and CPUC decision for PSCo’s 2011 electric rate case. The earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year over PSCo’s authorized ROE threshold of 10 percent. In the April 2013 filing for 2012, PSCo indicated that its earnings did not exceed the established threshold. CPUC Staff, the OCC and Colorado Energy Consumers each filed notices with the CPUC disputing PSCo’s assertion that earnings did not exceed the threshold. In June 2013, PSCo entered into a comprehensive settlement of issues with all parties, which was approved by the CPUC and resulted in a refund of approximately $8.2 million to customers over the next year. As of June 30, 2013, PSCo recognized a liability for the settlement amount as well as an estimated accrual representing its best estimate of any refund obligation for the 2013 test year.

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 March 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. For the three months ended June 30, 2013 and 2012, PSCo credited the RESA regulatory asset balance $6.5 million and $6.3 million, respectively. The cumulative credit to the RESA regulatory asset balance was $93.3 million and $82.8 million at June 30, 2013 and Dec. 31, 2012, respectively. The credits include the customers’ share of REC trading margins and the customers’ share of carbon offset funds.

This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and evidence regarding actual deliveries.

2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report. The OCC and CPUC Staff requested the CPUC set the matter for hearing to review in detail the information provided, including a review of the prudence of expenditures in 2012, and to develop standards for future filings. The CPUC approved the request on July 10, 2013 and assigned the matter to an ALJ. A procedural schedule has not been set.

SPS

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Base Rate

SPS – Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the PUCT for an increase in annual revenue of approximately $90.2 million. The rate filing is based on a historic twelve month test year ended June 30, 2012 (adjusted for known and measurable changes), a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent.

In April 2013, the parties filed a settlement agreement in which SPS’ base rate will increase by $37 million, effective May 1, 2013, on an interim basis pending the PUCT’s approval of the settlement, and by an additional $13.8 million on Sept. 1, 2013. In addition, the settlement allows SPS to file a transmission cost recovery adjustment rider in the fourth quarter of 2013 and for those rates to become effective on an interim basis in January 2014. Under the settlement, SPS cannot file another base rate case in 2013, but there are no restrictions on SPS filing a base rate case in 2014. On June 6, 2013, the PUCT approved the settlement without modification.

Pending Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

Base Rate

SPS – New Mexico 2012 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million. The rate filing is based on a 2014 forecast test year, a requested ROE of 10.65 percent, a jurisdictional electric rate base of $479.8 million and an equity ratio of 53.89 percent.

In March 2013, the NMPRC ruled that SPS’ case, as originally filed, was incomplete due to confidential exhibits to testimony and schedules being included in SPS’ direct case, and directed the hearing examiner to review SPS’ claims of confidentiality and to determine the date the filing is complete. After SPS made filings to address the NMPRC’s concern about the confidential documents, the hearing examiner determined that SPS’ application was completed on April 12, 2013. The NMPRC has suspended the tariffs for an initial nine month period beyond that date, or until Jan. 11, 2014. The NMPRC has authority to suspend the rates for an additional three months beyond the initial nine month period, or until April 11, 2014. On June 19, 2013, SPS revised its requested rate increase to $43.3 million.

Next steps in the procedural schedule are expected to be as follows:


•	Staff/Intervenor Direct Testimony – Aug. 22, 2013


•	Rebuttal Testimony – Sept. 9, 2013


•	Evidentiary Hearings – Sept. 16-27, 2013

Purchase and Sale Agreement for Certain Texas Transmission Assets — On March 29, 2013, SPS entered into a purchase and sale agreement with Sharyland Distribution and Transmission Services, LLC for the sale of certain segments of SPS’ transmission lines and two related substations for a base purchase price of $37 million, subject to adjustments for unplanned capital expenditures. The transaction is subject to various regulatory approvals including that of the Federal Energy Regulatory Commission (FERC).

On April 29, 2013, SPS made filings regarding the planned transaction with the PUCT, the NMPRC and the FERC. If approved, the sale is expected to close by the end of 2013.

Next steps in the procedural schedules are expected to be as follows:


•	PUCT Intervenor Direct Testimony – Aug. 2, 2013


•	PUCT Staff Direct Testimony – Aug. 9, 2013


•	PUCT SPS Rebuttal Testimony – Aug. 16, 2013


•	PUCT Evidentiary Hearing – Sept. 3, 2013


•	NMPRC Staff/Intervenor Direct Testimony – Sept. 12, 2013


•	NMPRC SPS Rebuttal Testimony – Sept. 27, 2013


•	NMPRC Evidentiary Hearing – Oct. 8 - 9, 2013