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, 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)

NSP Minnesota – Minnesota 2014 Multi-Year Electric Rate Case — In November 2013, NSP-Minnesota filed a two-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015.

The NSP-Minnesota electric rate case reflects an increase in revenues of approximately $193 million or 6.9 percent in 2014 and an additional $98 million or 3.5 percent in 2015. The request includes a proposed rate moderation plan for 2014 and 2015. After reflecting interim rate adjustments, NSP-Minnesota requested a rate increase of $127 million or 4.6 percent in 2014 and an incremental rate increase of $164 million or 5.6 percent in 2015.

NSP-Minnesota’s moderation plan includes the acceleration of the eight-year amortization of the excess depreciation reserve and the use of expected funds from the U.S. Department of Energy (DOE) for settlement of certain claims. These DOE refunds would be in excess of amounts needed to fund NSP-Minnesota’s decommissioning expense. The interim rate adjustments are primarily associated with ROE, Monticello life cycle management (LCM)/extended power uprate (EPU) project costs and NSP-Minnesota’s request to amortize amounts associated with the canceled Prairie Island (PI) EPU project.

In December 2013, the MPUC approved interim rates of $127 million effective Jan. 3, 2014, subject to refund. The MPUC determined that the costs of Sherco Unit 3 would be allowed in interim rates, and that NSP-Minnesota’s request to accelerate the depreciation reserve amortization was a permissible adjustment to its interim rate request.

In June 2014, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) recommended an increase of approximately $61.6 million in 2014 and a step increase of $54.9 million for 2015, based on a recommended ROE of 9.8 percent and an equity ratio of 52.5 percent. The DOC also recommended adoption of a full decoupling pilot for the residential and small commercial and industrial (C&I) class, based on actual results (not weather-normalized) for three years and made rate design and cost allocation recommendations.

Several other intervenors also filed testimony and included the following recommendations:


•	One or more of these parties made recommendations seeking modifications to rate design, supporting, modifying or opposing decoupling, and proposing inclining block rates and advocating for modification and application of the excess nuclear depreciation reserve.


•	One or more of these parties also made revenue requirement adjustments, including some of the same adjustments recommended by the DOC, such as the exclusion of the Monticello EPU, sales forecast and modifying or eliminating PI EPU amortization.


•	Other key revenue adjustments include:


◦	Amortization of excess depreciation reserve for nuclear plant;


◦	Seeking to exclude two owned wind projects from the step rate increase;


◦	Denial of the Multi-Year Plan step rate increase;


◦	An ROE recommendation of 9 percent;


◦	Modification to the capital structure; and


◦	Exclusion of construction work in progress and allowance for funds used during construction (AFUDC) from rates and adjustments to AFUDC rates and application.

In July 2014, NSP-Minnesota filed rebuttal testimony and reduced its request to an increase in revenues of approximately $169.5 million or 6.2 percent in 2014 and an additional $95 million or 3.5 percent in 2015. The revision reflects an update to NSP-Minnesota’s 2014 sales forecast and narrowed the number of disputed issues in the case by agreeing to or partially agreeing to an outcome on several smaller issues. NSP-Minnesota continues to support its initial filed position, including cost recovery of the Monticello LCM/EPU project, an ROE of 10.25 percent and property taxes. For the 2015 increase, NSP-Minnesota reduced its request by $3.5 million in order to focus the request on specific capital projects.

The following table summarizes the DOC’s recommendations from NSP-Minnesota’s filed request:



(Millions of Dollars)	DOC Direct Testimony 2014			NSP-Minnesota Rebuttal Testimony 2014
Filed rate request	$	192.7		$	192.7
Monticello EPU cost recovery	(31.3		)	—
Sales forecast	(29.5		)	(15.8		)
ROE	(26.9		)	—
Health care, pension and other benefits	(21.9		)	(0.8		)
Property taxes	(13.5		)	—
PI EPU	(5.8		)	(3.8		)
Other, net	(2.2		)	(2.8		)
Total recommendation 2014	$	61.6		$	169.5



(Millions of Dollars)	DOC Direct Testimony 2015 Step			NSP-Minnesota Rebuttal Testimony 2015 Step
Filed rate request	$	98.5		$	98.5
Depreciation	(17.5		)	—
Property taxes	(14.5		)	(3.3		)
Production tax credits to be included in base rates	(11.1		)	(11.1		)
DOE settlement proceeds	(10.8		)	10.1
Capital changes and disallowances	(5.6		)	—
Nuclear outage amortization	(5.5		)	—
Emission chemicals	(3.0		)	(0.2		)
Excess depreciation reserve adjustment	22.7			—
Other, net	1.7			1.0
Total recommendation 2015 step increase	54.9			95.0
Cumulative total for 2014 and 2015 step increase	$	116.5		$	264.5

NSP-Minnesota’s rebuttal rate request, moderation plan, interim rate adjustments and certain impacts on expenses are detailed in the table below:



(Millions of Dollars)	2014			Percentage Increase	2015			Percentage Increase
Rebuttal pre-moderation deficiency	$	250			$	68
Moderation change compared to prior year:
Depreciation reserve	(81		)		53
DOE settlement proceeds	—				(26		)
Rebuttal rate request	169			6.2%	95			3.5%
Interim rate adjustments	(66		)		66
PI EPU	4				(4		)
Revenue impact^(a)	107				157
Depreciation expense - decrease/(increase)	81				(46		)
Recognition of DOE settlement proceeds	—				26
Rebuttal pre-tax impact on operating income	$	188			$	137


^(a)	NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request.

NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with interim rates of approximately $12.5 million as of June 30, 2014.

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


•	Surrebuttal Testimony — Aug. 4, 2014;


•	Evidentiary Hearing — Aug. 11-18, 2014;


•	Initial Brief — Sept. 23, 2014;


•	Reply Brief — Oct. 14, 2014; and


•	Administrative Law Judge (ALJ) Report — Dec. 22, 2014.

A final MPUC decision is anticipated in March 2015.

NSP-Minnesota – Nuclear Project Prudence Investigation — In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes AFUDC. Project expenditures were initially estimated at approximately $320 million, excluding AFUDC, in 2008 in NSP-Minnesota’s EPU certificate of need (CON) and plant life extension filings.

In October 2013, NSP-Minnesota filed a report to further support the change and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and (3) additional Nuclear Regulatory Commission (NRC) licensing related requests over the five-plus year application process. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken by other utilities and the project remains economically beneficial to customers. NSP-Minnesota has received all necessary licenses from the NRC for the Monticello EPU, and has begun the process to comply with the license requirements for higher power levels, subject to NRC oversight and review.

On July 2, 2014, the DOC filed testimony and recommended a disallowance of recovery of approximately $71.5 million of project costs, including expenditures and associated AFUDC, on a Minnesota jurisdictional basis. This equates to a total NSP System amount of approximately $94 million.

The DOC’s recommendation indicated that although the combined LCM/EPU project is cost effective, NSP-Minnesota should have done a better job of estimating initial project costs of the investments required to achieve 71 megawatts (MW) of additional capacity (i.e., EPU costs) as opposed to investments required to extend the life of the plant. They asserted that approximately 85 percent of the total $665 million in costs were associated with project components required solely to achieve the EPU.

The DOC’s recommendation, NSP-Minnesota’s response and comments of other parties are expected to be considered by an ALJ later this year, who in turn will make a report of recommendations to the MPUC. The results and any recommendations from the conclusion of this prudence proceeding are expected to be considered by the MPUC in NSP-Minnesota’s pending Minnesota 2014 Multi-Year electric rate case.

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


•	Rebuttal Testimony — Aug. 26, 2014;


•	Surrebuttal Testimony — Sept. 19, 2014;


•	Hearing — Sept. 25 - Sept. 30, 2014;


•	Reply Brief — Nov. 21, 2014; and


•	ALJ Report — Dec. 31, 2014.

A final MPUC decision is anticipated in the first quarter of 2015.

Electric, Purchased Gas and Resource Adjustment Clauses

NSP-Minnesota - Gas Utility Infrastructure Cost (GUIC) Rider — In August 2014, NSP-Minnesota plans to file a GUIC rider with the MPUC for approval to recover the cost of natural gas infrastructure investments in Minnesota to improve safety and reliability. Costs include funding for pipeline assessment and system upgrades in 2015 and beyond, as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. Sewer separation costs stem from the inspection of sewer lines and the redirection of gas pipes in the event their paths are in conflict. NSP-Minnesota is requesting recovery of approximately $14.9 million from Minnesota gas utility customers beginning Jan.1, 2015, including $4.8 million of deferred sewer separation and integrity management costs. An MPUC decision is anticipated by the end of 2014.

Pending Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)

South Dakota 2015 Electric Rate Case — In June 2014, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $15.6 million annually, or 8.0 percent, effective Jan. 1, 2015. The request is based on a 2013 historic test year (HTY) adjusted for certain known and measurable changes for 2014 and 2015, a requested ROE of 10.25 percent, an average rate base of $433.2 million and an equity ratio of 53.86 percent. This request reflects NSP-Minnesota’s proposal to move recovery of approximately $9.0 million for certain Transmission Cost Recovery (TCR) rider and Infrastructure rider projects to base rates.

The major components of the request are as follows:



(Millions of Dollars)	Request
Nuclear investments and operating costs	$	13.4
Other production, transmission and distribution	5.0
Technology improvements	2.1
Pension and operating and maintenance (O&M) expenses	1.6
Wind generation facilities	1.4
Capital structure	1.1
Incremental increase to base rates	$	24.6

Infrastructure rider to be included in base rates	$	(8.4	)
TCR rider to be included in base rates	(0.6		)
Net request	$	15.6

A procedural schedule is anticipated to be established in the second half of 2014. Final rates are expected to be effective in the first quarter of 2015.

NSP-Wisconsin

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

NSP-Wisconsin 2015 Electric Rate Case — In May 2014, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $20.6 million, or 3.2 percent, effective Jan. 1, 2015. The request is for the limited purpose of updating 2015 electric rates to reflect anticipated increases in the production and transmission fixed charges and the fuel and purchased power components of the interchange agreement with NSP-Minnesota. No changes are being requested to the capital structure or the 10.2 percent ROE authorized by the PSCW in the 2014 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap for 2015 only, in which 100 percent of the earnings above the authorized ROE would be refunded to customers.

The major cost components of the requested increase are summarized below:



(Millions of Dollars)	Request
Production and transmission fixed charges	$	28.1
Fuel and purchased power	13.9
Sub-Total	$	42.0

NSP-Minnesota transmission depreciation reserve	$	(16.2	)
Monticello EPU deferral	(5.2		)
Total	$	20.6

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


•	Direct Testimony (PSCW staff and intervenors) — Oct. 3, 2014;


•	Rebuttal Testimony — Oct. 17, 2014;


•	Surrebuttal Testimony — Oct. 24, 2014; and


•	Evidentiary Hearing — Oct. 28, 2014.

A final PSCW decision is anticipated by the end of the year with final rates implemented in January 2015.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013.

In January 2014, Xcel Energy filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO transmission owners separately answered the complaint, arguing the complainants do not have standing to challenge the MISO Tariff provisions, have not met their burden of proof to demonstrate that the current FERC-approved ROE, capital structure and other incentives are unjust and unreasonable, and the complaint should be dismissed. Other parties filed comments supporting a reduction in the MISO regional ROE, the equity capital structure limitations, and limits on ROE incentives, and supported the proposed effective date. In January 2014, the complainants filed an answer to the MISO transmission owners’ motion to dismiss. The complaint is pending FERC action.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth. The FERC set the issue of the appropriate long-term growth rate for further hearing procedures. The FERC could order settlement judge procedures, and if necessary a hearing, to apply the new methodology to MISO transmission owners. The new FERC ROE methodology is expected to reduce transmission revenue, net of expense, between $5 million and $7 million annually for NSP-Minnesota and NSP-Wisconsin.

PSCo

Pending and Recently Concluded Regulatory Proceedings — CPUC

PSCo – Colorado 2014 Electric Rate Case — In June 2014, PSCo filed an electric rate case in Colorado with the CPUC requesting an increase in annual revenue of approximately $137.7 million, or 4.89 percent. The request includes the initiation of a CACJA rider as part of the overall 2015 rate case request of approximately $95 million, as well as additional amounts for calendar years 2016 and 2017. The CACJA rider is anticipated to increase revenue recovery by approximately $40 million in 2016 and then decline to approximately $36 million in 2017. PSCo’s objective is to establish a multi-year regulatory plan that provides certainty for PSCo and its customers.

The rate filing is based on a 2015 test year, a requested ROE of 10.35 percent, an electric rate base of $6.39 billion and an equity ratio of 56 percent. As part of the filing, PSCo will transfer approximately $19.9 million from the transmission rider to base rates. This transfer will not impact customer bills. The CACJA rider is projected to recover incremental investment and expenses, based on a comprehensive plan to retire certain coal plants, add pollution control equipment to other existing coal units and add natural gas generation. The CACJA project investment is expected to be completed by 2017.

In July 2014, the CPUC set hearings for early December 2014. A decision as well as implementation of final rates are anticipated in the first quarter of 2015.

PSCo – Manufacturer’s Sales Tax Refund — Pursuant to the multi-year settlement agreement with the CPUC, PSCo defers 2012-2014 annual property taxes in excess of $76.7 million. To the extent that PSCo was successful in the manufacturer’s sales tax refund lawsuit against the Colorado Department of Revenue, PSCo was to credit such refunds first against certain legal fees, and then against the unamortized deferred property tax balance at the end of 2014.

After PSCo’s initial successes in the District Court and Court of Appeals, the Colorado Supreme Court on June 30, 2014 ruled against PSCo’s claim that it was due refunds for the payment of sales taxes on purchases of certain equipment from December 1998 to December 2001. Under the multi-year settlement agreement, as a result of the adverse ruling, PSCo is required to reduce its 2014 property tax deferral by $10 million, as this amount will not be recovered in electric rates. This impact is reflected in PSCo’s pending electric rate case before the CPUC.

PSCo – Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012-2014. In April 2014, PSCo filed its 2013 earnings test with the CPUC proposing a refund obligation of $45.7 million to electric customers to be returned between August 2014 and July 2015. This tariff was approved by the CPUC in July 2014 to be effective Aug. 1, 2014. As of June 30, 2014, PSCo has also recognized management’s best estimate of an accrual for the 2014 earnings test.

2012 Pipeline System Integrity Adjustment (PSIA) Report — In April 2013, PSCo filed its 2012 PSIA report, requesting $43.5 million for recovery of expenditures. In February 2014, PSCo, the CPUC Staff and the Office of Consumer Counsel (OCC) agreed to a settlement amount of $43.4 million for recovery of 2012 expenditures, subject to final approval. This includes a one-time disallowance of approximately $0.1 million of O&M expenditures and an agreement not to disallow capital expenditures related to a pipeline replacement project. In July 2014, the ALJ issued a final decision approving the settlement agreement.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent to customers for 2014. In 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 renewable energy standard adjustment (RESA) regulatory asset balance. PSCo’s credit to the RESA regulatory asset balance was not material for the three months ended June 30, 2014. For the three months ended June 30, 2013, PSCo credited the RESA regulatory asset balance $6.5 million. The cumulative credit to the RESA regulatory asset balance was $104.6 million and $104.5 million at June 30, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds.

The current sharing mechanism will be effective through 2014. In May 2014, PSCo filed with the CPUC to continue this sharing mechanism for 2015 and beyond, but remove the step increase in the sharing allocation of hybrid REC trades on margins in excess of $20 million. In July 2014, the CPUC sent the proceeding to an ALJ. A decision is anticipated later in 2014.

Pending Regulatory Proceedings — FERC

PSCo – Production Formula Rate ROE Complaint — In August 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates effective Sept. 1, 2013. In June 2014, PSCo and its wholesale customers reached a confidential settlement in principle to resolve the complaint. The settlement is expected to be filed with the FERC in September 2014. As of June 30, 2014, PSCo has recorded a refund accrual based on the settlement terms.

PSCo Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from an HTY formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. 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 wholesale transmission and ancillary services revenue by approximately $2.0 million annually. Various transmission customers protested the filing. In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures.

In June 2012, several wholesale customers filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. In October 2012, the FERC consolidated this complaint with the April 2012 formula rate change filing.

In December 2013, the FERC approved a partial settlement resolving all issues related to the April 2012 transmission rate filing and June 2012 complaint other than ROE. The settlement is not expected to materially increase 2014 transmission revenues.

In March 2014, the FERC Staff filed testimony supporting an ROE of 8.91 percent for July 2012 to November 2012, and an ROE of 8.70 percent thereafter. In June 2014, PSCo and its transmission customers reached a confidential settlement in principle to resolve the ROE issue in the transmission rate filing and complaint. The settlement is expected to be filed with the FERC in September 2014. As of June 30, 2014, PSCo has recorded a refund accrual based on the settlement terms.

SPS

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

SPS – Texas 2014 Electric Rate Case — In January 2014, SPS filed a retail electric rate case in Texas with each of its Texas municipalities and the PUCT for a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflected a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the Transmission Cost Recovery Factor (TCRF) to zero when the final base rates become effective. In April 2014, SPS revised its request to a net increase of $48.1 million, based on updated information.

The rate filing is based on a HTY ending June 2013, a requested ROE of 10.40 percent, an electric rate base of approximately $1.27 billion and an equity ratio of 53.89 percent. The requested rate increase reflected an increase in depreciation expense of approximately $16 million.

SPS, intervenors, and other parties have commenced settlement negotiations. A final settlement is anticipated to be filed with the PUCT in the third quarter of 2014. A final decision is anticipated later this year and final rates are expected to be effective retroactive to June 1, 2014.

Electric, Purchased Gas and Resource Adjustment Clauses

TCRF Rider — In November 2013, SPS filed with the PUCT to implement the TCRF for Texas retail customers. The requested increase in revenues was $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. In July 2014, the PUCT approved a settlement agreement between the parties allowing SPS to recover $4 million annually through the TCRF. As of June 30, 2014, SPS had recorded an accrual for estimated refunds.

Recently Concluded Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

SPS – New Mexico 2014 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 effective in 2014. The rate filing was based on a 2014 forecast test year, a requested ROE of 10.65 percent, an electric rate base of $479.8 million and an equity ratio of 53.89 percent.

In September 2013, SPS filed rebuttal testimony, revising its requested rate increase to $32.5 million, based on updated information and an ROE of 10.25 percent. The request reflected a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million.

In March 2014, the NMPRC approved an overall increase of approximately $33.1 million. The increase reflects a base rate increase of $12.7 million and rider recovery of $18.1 million for renewable energy costs, both based on an ROE of 9.96 percent and an equity ratio of 53.89 percent. Final rates were effective April 5, 2014. In April 2014, the New Mexico Attorney General (NMAG) filed a request for rehearing. The rehearing request was denied by the NMPRC. In June 2014, the NMAG filed an appeal of the NMPRC’s denial to the New Mexico Supreme Court. A decision is expected in 2015.

The following table summarizes the NMPRC’s approval from SPS’ revised request:



(Millions of Dollars)	NMPRC Approval
SPS revised request, September 2013	$	32.5
Fuel clause adjustment credit — non-renewable energy costs	2.3
SPS revised request, fuel adjusted	34.8
ROE (9.96 percent)	(1.2		)
Rate rider adjustment — renewable energy costs	6.0
Base rate reduction for rate rider — renewable energy costs	(6.0		)
Other, net	(0.5		)
Approved increase, March 2014	$	33.1

Means of recovery:
Base revenue	$	12.7
Rider revenue	18.1
Fuel clause	2.3
	$	33.1

Pending Regulatory Proceedings — FERC

SPS Wholesale Rate Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a rate complaint alleging that the base ROE included in the SPS production formula rate of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth. The FERC also issued orders consolidating the Golden Spread complaints and setting them for settlement judge procedures and hearings and indicated the parties should apply the new ROE methodology to this proceeding. The effective dates of the refunds are April 20, 2012 and July 19, 2013. The first settlement conference was held in July 2014 and further settlement conferences are anticipated. SPS continues to evaluate the impact of the new FERC ROE methodology. In July 2014, SPS requested rehearing of the June 2014 orders.