Rate Matters

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — 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 was based on a 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 initially reflected a requested 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 included a proposed rate moderation plan. In December 2013, the MPUC approved interim rates of $127 million, effective Jan. 3, 2014, subject to refund. In 2014, NSP-Minnesota revised its requested rate increase to $115.3 million for 2014 and to $106.0 million for 2015, for a total combined unadjusted increase of $221.3 million.

In May 2015, the MPUC ordered a total increase of $166.1 million, or 5.9 percent, consisting of $58.9 million and $125.2 million in 2014 and 2015, respectively, and an $18.0 million adjustment related to disallowance of certain Monticello LCM/EPU costs. The MPUC also approved a three-year, decoupling pilot with a 3 percent cap on base revenue for the residential and small commercial and industrial classes, based on actual sales, effective Jan. 1, 2016. The decoupling mechanism would eliminate the impact of changes in electric sales due to conservation and weather variability for these classes.

In July 2015, the MPUC deliberated on requests for reconsideration and determined the Monticello EPU project was not yet used-and-useful, as final approval related to the full EPU uprate condition had not been received from the NRC as of June 30, 2015. As a result, $13.8 million was excluded from final rates. Monticello subsequently received final NRC compliance approval in July 2015. The MPUC also approved 2015 interim rates effective March 3, 2015 and stated that the 2014 interim rate refund obligation be netted against the 2015 interim rate revenue under-collections.

The MPUC’s decisions resulted in a total estimated 2014 and 2015 annual rate increase of $149.4 million, or 5.3 percent.

The following table outlines the impact of the MPUC’s July decision:



(Millions of Dollars)	MPUC July Decision
2014 and 2015 step increase - based on MPUC May order	$	166.1
Reconsideration/clarification adjustments:
2015 Monticello EPU used-and-useful adjustment	(13.8		)
2014 property tax final true-up	(3.1		)
Other, net	0.2
Total 2014 and 2015 step increase	$	149.4
Impact of interim rate effective March 3, 2015	(3.6		)
Estimated revenue impact	$	145.8

NSP-Minnesota – Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested ROE of 10.0 percent and a 52.50 percent equity ratio. The request is detailed in the table below.



Request (Millions of Dollars)	2016			2017			2018
Rate request	$	194.6		$	52.1		$	50.4
Increase percentage	6.4		%	1.7		%	1.7		%
Interim request	$	163.7		$	44.9		N/A
Rate base	$	7,800		$	7,700		$	7,700

NSP-Minnesota also proposed a five-year alternative plan that would extend the rate plan two additional years.

In addition, NSP-Minnesota has requested the MPUC encourage parties to engage in a formal mediation type procedure as outlined by Minnesota’s rate case statute which may streamline the settlement process.

In December 2015, the MPUC approved interim rates for 2016. The MPUC deferred making a decision on incremental interim rates for 2017 and indicated that NSP-Minnesota could bring back its request in the fourth quarter of 2016. The MPUC also required NSP-Minnesota to file supplemental direct testimony addressing costs associated with the LCM at the PI nuclear plant. NSP-Minnesota filed supplemental testimony in January 2016 demonstrating that the capital work at PI, including the LCM, is required during the rate case period, higher costs associated with the LCM are necessary to operate the plant through the end of its licensed life and recovery of these costs will result in reasonably priced energy for customers.

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



(Millions of Dollars)	2016			2017			2018			Total
2014 multi-year rate case items:
Excess depreciation reserve	$	26.0		$	51.0		$	—		$	77.0
DOE settlement	25.7			—			—			25.7
Monticello LCM/EPU	11.2			(1.6		)	(1.5		)	8.1
	62.9			49.4			(1.5		)	110.8
Additional items:
Capital investments	128.7			12.8			44.6			186.1
Property taxes	30.2			7.6			5.2			43.0
NOL carryforwards	(6.3		)	(24.5		)	(6.5		)	(37.3		)
Other costs	(20.9		)	6.8			8.6			(5.5		)
	131.7			2.7			51.9			186.3

Total rate request	$	194.6		$	52.1		$	50.4		$	297.1

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


•	Intervenors’ direct testimony — June 14, 2016;


•	Rebuttal testimony — Aug. 9, 2016;


•	Surrebuttal testimony — Sept. 16, 2016;


•	Settlement conference — Sept. 26, 2016;


•	Evidentiary hearing — Oct. 4-7, 2016;


•	ALJ report — Feb. 21, 2017; and


•	MPUC order — June 1, 2017.

NSP-Minnesota – Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 MW. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes AFUDC. In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows.

NSP-Minnesota – 2016 TCR Filing — In October 2015, NSP-Minnesota submitted its 2016 TCR filing with the MPUC, requesting recovery of $19.2 million of 2016 transmission investment costs not included in electric base rates. This filing included an option to keep approximately $59.1 million of revenue requirements associated with two CapX2020 projects completed in 2015 within the TCR rider or to include these revenue requirements in electric base rates during the interim rate implementation of the next electric rate case. In November 2015, NSP-Minnesota submitted an update to its TCR filing in which it confirmed that it was requesting the MPUC approve keeping the two CapX2020 projects in the TCR rider, increasing the revenue requirements to $78.3 million, until the conclusion of the 2016 Minnesota electric rate case.

Recently Concluded Regulatory Proceedings — SDPUC

NSP-Minnesota – South Dakota Infrastructure Rider —In December 2015, the SDPUC approved recovery of $10.2 million through the infrastructure rider effective beginning Jan. 1, 2016. As part of the South Dakota 2015 electric rate case, the infrastructure rider was refreshed with new projects and was also expanded as a mechanism to allow for possible recovery of other investments related to generation, transmission, and distribution.

Electric, Purchased Gas and Resource Adjustment Clauses

CIP and CIP Rider — In December 2012, the MPUC approved reductions to the CIP financial incentive mechanisms effective for the 2013 through 2015 program years and in 2015 extended the mechanisms to the 2016 program year. The estimated average annual electric and natural gas incentives are $30.6 million and $3.6 million, respectively, based on the approved savings goals.

CIP expenses are recovered through base rates and a rider that is adjusted annually.


•	In July 2015, the MPUC approved NSP-Minnesota’s 2014 CIP electric and natural gas financial incentives totaling $40.1 million and $5.8 million, respectively.


•	In addition, the MPUC approved NSP-Minnesota’s proposed 2015 to 2016 electric and natural gas CIP riders. NSP-Minnesota estimates 2016 recovery of $21.5 million of electric CIP expenses and $9.2 million of natural gas CIP expenses.


•	This proposed recovery through the riders is in addition to an estimated $86.9 million and $3.7 million through electric and gas base rates, respectively.

NSP-Minnesota – Gas Utility Infrastructure Cost (GUIC) Rider — In October 2015, NSP-Minnesota filed the 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 assessments 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 requested recovery of approximately $15.5 million from Minnesota gas utility customers beginning April 1, 2016. This request includes $1.9 million in over-recovery from 2015 and $4.5 million of deferred sewer separation and integrity management costs which is the 2016 portion of a five year amortization.

An MPUC decision is expected in the second half of 2016.

NSP-Wisconsin

Recently Concluded Regulatory Proceedings — PSCW

NSP-Wisconsin – Wisconsin 2016 Electric and Gas Rate Case — In May 2015, NSP-Wisconsin filed a request with the PSCW seeking an increase in annual electric rates of $27.4 million, or 3.9 percent, and an increase in natural gas rates of $5.9 million, or 5.0 percent, effective Jan. 1 2016. The rate filing was based on a 2016 forecast test year, a ROE of 10.2 percent, an equity ratio of 52.5 percent and a forecasted average rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility.

In December 2015, the PSCW approved an electric rate increase of approximately $7.6 million, or 1.1 percent, and a natural gas rate increase of $4.2 million, or 3.6 percent, based on a 10.0 percent ROE and an equity ratio of 52.5 percent. New rates went into effect in January 2016. As shown below, NSP-Wisconsin received approximately 65 percent of the non-fuel and purchased power portion of its requested electric rate increase and 71 percent of its requested natural gas rate increase.

The major components of the requested rate increases and the PSCW’s approval are summarized as follows:



Electric Rate Request (Millions of Dollars)	NSP-Wisconsin Request			PSCW Approval
Capital investments	$	23.0		$	13.9
ROE & other capital structure adjustments	—			(3.8		)
Generation and transmission expenses (excluding fuel and purchased power)	37.2			42.7
O&M expenses	11.1			3.2
Sales forecast	(27.0		)	(27.0		)
Rate increase - non-fuel and purchased power	44.3			29.0
Rate reduction - fuel and purchased power	(16.9		)	(21.4		)
Total electric rate increase	$	27.4		$	7.6



Natural Gas Rate Request (Millions of Dollars)	NSP-Wisconsin Request			PSCW Approval
Capital investments	$	3.7		$	3.7
ROE & other capital structure adjustments	—			(0.4		)
O&M expenses	3.2			1.9
Environmental remediation expenses	2.9			2.9
Sales forecast	(3.9		)	(3.9		)
Total natural gas rate increase	$	5.9		$	4.2

PSCo

Pending and Recently Concluded Regulatory Proceedings — CPUC

PSCo – Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $66.2 million over three years. The request was based on a HTY ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the periods in the MYP and an equity ratio of 56 percent. In addition, PSCo requested an extension of its PSIA rider through 2020 to recover costs associated with its pipeline integrity efforts. The rider would recover incremental revenue of $42.8 million over three years.

In July 2015, PSCo filed rebuttal testimony with adjustments and modified recovery between base rates and the PSIA rider. The revised request is summarized below:



(Millions of Dollars)	2015			2016 Step			2017 Step
PSCo’s filed base rate request	$	40.5		$	7.6		$	18.1
Shift O&M expenses between PSIA and base rates	—			7.0			6.4
Rebuttal corrections and adjustments	—			—			(7.7		)
Total base rate increase	$	40.5		$	14.6		$	16.8
Incremental PSIA rider revenues	(0.1		)	14.7			21.7
Total revenue impact from rebuttal	$	40.4		$	29.3		$	38.5
Requested ROE	10.1		%	10.1		%	10.3		%
Rate base	$	1,260		$	1,310		$	1,360

In November 2015, the ALJ issued his recommended decision, which reflected a 2014 HTY with a 13-month average rate base, the Cherokee pipeline investment adjusted to year-end rate base, a ROE of 9.5 percent and an equity ratio of 56.51 percent. In addition, the ALJ’s recommendation included a three-year extension (2016 through 2018) of the PSIA rider with all O&M expenses transferred to base rates as well as certain other projects shifting between the PSIA rider and base rates, beginning January 2016. The ALJ also recommended that certain expenses, including property taxes and damage prevention costs that exceed the 2014 HTY level, be deferred. He further recommended a pension cost tracker and certain other deferral related items.

In February 2016, the CPUC issued their written order. Key matters are as follows:


•	2014 HTY, with a 13-month average rate base, with the exception of the Cherokee pipeline which is included at a year-end level;


•	Extension of the PSIA rider through 2018 with all O&M expenses transferred to base rates;


•	A ROE of 9.5 percent; and


•	An equity ratio of 56.51 percent.

The following table reflects the ALJ’s position and the CPUC’s written order (estimated):



(Millions of Dollars)	ALJ			CPUC’s Written Order
PSCo’s filed 2015 base rate request^(a)	$	40.5		$	40.5
ROE	(7.8		)	(7.8		)
Capital structure and cost of debt	(0.5		)	(0.5		)
Cherokee pipeline adjustment	4.1			4.1
Move to 2014 HTY	(14.1		)	(14.1		)
O&M expenses	(3.0		)	(2.4		)
Other, net	(1.1		)	(1.1		)
Overall recommended rate increase	$	18.1		$	18.7


^(a)	The ALJ’s recommendation and the CPUC’s written order also includes approximately $20.0 million of PSIA costs be transferred to base rates, effective Jan. 1, 2016.

The ALJ’s recommendation, as well as the CPUC’s written order for the PSIA rider, are as follows (estimated):



	ALJ						CPUC’s Written Order
(Millions of Dollars)	2016			2017			2016			2017
PSCo’s filed incremental PSIA request	$	21.7		$	21.2		$	21.7		$	21.2
Transfer PSIA costs to base rates	(20.5		)	—			(20.5		)	—
PSIA cost recovery remaining in base	(4.3		)	—			(4.3		)	—
Projects not recovered through the PSIA	(3.6		)	(2.0		)	(3.3		)	(0.8		)
ROE and capital structure	(0.3		)	(1.6		)	(0.3		)	(1.6		)
Total	$	(7.0	)	$	17.6		$	(6.7	)	$	18.8

The following table summarizes the estimated annual pre-tax impact of the CPUC’s written order:



(Millions of Dollars)	2015			2016			2017
Base rate increase	$	18.7		$	19.7		$	—
Incremental PSIA rider revenues	(0.2		)	(6.7		)	18.8
Expense deferrals, net amortization ^(a)	(3.6		)	1.5			5.2
Estimated pre-tax impact	$	14.9		$	14.5		$	24.0


^(a)	Deferral and amortization impacts relate primarily to recognition of accelerated amortization of prepaid pension assets and deferrals of pension expense in excess of the amount approved in the prior general gas rate case.

Interim rates, subject to refund, went into effect Oct. 1, 2015. PSCo has recognized management’s best estimate of the potential customer refund obligation.

PSCo – Colorado 2015 Steam Rate Case — In November 2015, PSCo filed a request to increase Colorado retail steam rates by $3.5 million in 2016. In December 2015, the CPUC approved the filed request which recovers costs related to upgrades for the state steam plant as well as the Zuni Station and permits use of the Zuni Station exclusively for steam business. Final rates are implemented in two steps with $2.8 million, which began on Jan. 1, 2016, and the remaining $0.7 million which will be effective Nov. 1, 2016.

PSCo – Annual Electric Earnings Test — In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test in which PSCo shares with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of Dec. 31, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test of $15 million. PSCo will file its 2015 earnings test with the CPUC in April 2016. The final sharing obligation will be based on the CPUC approved tariff and could vary from the current estimate.

Electric, Purchased Gas and Resource Adjustment Clauses

DSM and the DSMCA — Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Savings goals were 384 GWh in 2014 and 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million. For the years 2016 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual spending limit of $84.3 million.

In July 2015, the CPUC approved PSCo’s 2015-2016 DSM plan:


•	A 2015 DSM electric budget of $81.6 million and a natural gas budget of $13.1 million; and


•	A 2016 DSM electric budget of $78.7 million and a natural gas budget of $13.6 million.

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 RESA regulatory asset balance. PSCo credited to the RESA regulatory liability balance approximately $5.5 million and $0.6 million in 2015 and 2014, respectively. The cumulative credit to the RESA regulatory liability balance was $110.6 million and $105.1 million at Dec. 31, 2015 and Dec. 31, 2014, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds. The current sharing mechanism, without modification, extends through 2017.

SPS

Pending and Recently Concluded Regulatory Proceedings — PUCT

SPS – Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on a HTY ending June 2014, adjusted for known and measurable changes, a ROE of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent.

SPS requested a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014. In June 2015, SPS revised its requested rate increase to $42.1 million.

In December 2015, the PUCT made the following decisions:


•	Disallowed SPS’ proposed adjustment to jurisdictional allocation factors to reflect Golden Spread Electric Cooperative, Inc.’s (Golden Spread’s) wholesale load reductions from 500 MW to 300 MW, effective June 1, 2015;


•	Disallowed incentive compensation;


•	Approved an equity ratio of 51.00 percent instead of the actual 53.97 percent; and


•	A ROE of 9.70 percent.

The following table reflects the ALJs’ position and PUCT’s decision.



	ALJs’ Proposal			PUCT
(Millions of Dollars)	for Decision			Decision
SPS’ revised rate request	$	42.1		$	42.1
Investment for capital expenditures — post-test year adjustments	(8.9		)	(8.9		)
Lower ROE	(6.3		)	(6.3		)
Lower capital structure	—			(3.7		)
Annual incentive compensation	(0.2		)	(0.3		)
O&M expense adjustments	(4.6		)	(4.6		)
Depreciation expense	(2.7		)	(2.7		)
Property taxes	(0.9		)	(0.9		)
Revenue adjustments	(1.1		)	(1.6		)
Wholesale load reductions	—			(11.5		)
SPP transmission expansion plan	(4.2		)	(4.2		)
Other, net	1.4			(1.2		)
Total, gross of rate case expenses	$	14.6		$	(3.8	)
Adjustment to move rate case expenses to a separate docket	(0.2		)	(0.2		)
Total, net of rate case expenses	$	14.4		$	(4.0	)
New depreciation rates	(11.2		)	(11.2		)
Earnings impact	$	3.2		$	(15.2	)

In January 2016, SPS filed its motion for rehearing on capital structure, incentive compensation and known and measurable adjustments, including wholesale load reductions and post test-year capital additions. On Feb. 11, 2016, the PUCT orally denied requests for rehearing. SPS plans to file a second motion for rehearing within 20 days of the date of the PUCT’s written order.

SPS – Texas 2016 Electric Rate Case — On Feb. 16, 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a HTY ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent.

As part of its request, SPS included estimated information regarding increases and decreases in SPS’ cost of service, including certain expenses, capital investments, cost of capital and sales for the period of Oct. 1, 2015 through Dec. 31, 2015. Subsequent to the filing, (i.e., 45 days), the estimated information will be updated to reflect actual results.

The following table summarizes the net request:



(Millions of Dollars)	Request
Capital expenditure investments	$	38.6
Change in jurisdictional allocation factors	10.9
Changes in ROE and capital structure	11.7
Estimated rate case expenses ^(a)	4.5
Other, net	6.2
Total	$	71.9


^(a)	SPS anticipates rate case expenses, for this proceeding, to be separated from the request for consideration in a separate docket.

The final rates established at the end of the case will be made effective retroactive to July 20, 2016 and SPS will be entitled to collect a surcharge for usage from July 20, 2016 through the date SPS implements final rates. A PUCT decision is anticipated in the first quarter of 2017.

Pending Regulatory Proceedings — NMPRC

SPS – New Mexico 2015 Electric Rate Case — In October 2015, SPS filed a New Mexico electric rate case with the NMPRC for a net increase in base rates of approximately $24.3 million. The proposed net amount reflects an increase in non-fuel base rates of $45.4 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power adjustment clause. The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric jurisdictional rate base of approximately $734 million and an equity ratio of 53.97 percent.

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



(Millions of Dollars)	Request
2015 base period deficiency	$	19.7
Capital expenditures — post-test year adjustments	12.3
Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage	3.7
Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects	2.0
ROE, reflecting an increase from 9.96 percent to 10.25 percent	1.6
Rider revenue adjustments - gross receipts tax	1.3
Other, net	4.8
Requested rate increase	$	45.4

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


•	Settlement conference — Feb. 29, 2016;


•	Staff and intervenor direct testimony — April 1, 2016;


•	Rebuttal testimony — April 18, 2016; and


•	Evidentiary hearing begins — April 28, 2016.

A NMPRC decision and implementation of final rates is anticipated in the second half of 2016.

In response to the original 2015 electric rate case previously dismissed, SPS has appealed that decision to the New Mexico Supreme Court. SPS and the NMPRC have filed a joint agreed motion to dismiss the appeal with the New Mexico Supreme Court. The motion provides for the case to be remanded to the NMPRC for entry of an order affirming SPS’ right to use a FTY that begins up to 13 months after SPS files a rate case. SPS will not resume the previously dismissed rate case and will proceed with the October 2015 rate case.

Pending and Recently Concluded Regulatory Proceedings — FERC and Other

MISO ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO TOs, including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in 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 RTO membership and being an independent transmission company), effective Nov. 12, 2013.

Subsequently, the FERC adopted a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

The ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending a ROE between 8.67 percent and 9.54 percent. The FERC staff recommended a ROE of 8.68 percent. The MISO TOs recommended a ROE not less than 10.8 percent. In December 2015, an ALJ initial decision was issued recommending a ROE of 10.32 percent. Briefs on exceptions challenging the ALJ recommendation were filed in January 2016. A FERC order is expected to be issued later in 2016.

Certain MISO TOs separately requested FERC approval of a 50 basis point ROE adder for RTO membership, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. Certain intervenors sought rehearing of the FERC order granting the ROE adder and FERC action is pending.

In February 2015, certain intervenors filed a second complaint to reduce the MISO region ROE to 8.67 percent, prior to an adder. FERC set the second complaint for hearings, and established a refund effective date of Feb. 12, 2015. The complainants and intervenors filed direct testimony in September 2015, the MISO TOs filed answering testimony in October 2015 and FERC staff filed testimony in November 2015. In January 2016, all parties updated their ROE analyses. The complainants and intervenors recommended ROEs between 8.72 percent and 9.32 percent while FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.96 percent. Hearings were held before an ALJ in February 2016. An ALJ initial decision is expected in June 2016 with a FERC decision expected in late 2016 or 2017.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of Dec. 31, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $8 million and $10 million annually for the NSP System.

SPS – Global Settlement Agreement — In August 2015, SPS, Golden Spread, four New Mexico Cooperatives, West Texas Municipal Power Agency, Public Service Company of New Mexico (PNM) and Tri-County Electric Cooperative, Inc. filed a settlement agreement with the FERC that would provide a comprehensive resolution of nine pending matters in dispute between SPS and these wholesale production and transmission customers, including the 2013 SPS complaint orders and three pending ROE complaints. In October 2015, the FERC issued an order approving the settlement agreement. As a result of the settlement, SPS issued refunds to Golden Spread and PNM of $49.1 million, but recognized a reversal of previously recorded reductions in revenue of approximately $7.9 million in the fourth quarter of 2015. The settlement provides a ROE for production services of 10.0 percent and transmission services of 10.5 percent, beginning Oct. 20, 2014, and subject to a moratorium on filings for ROE changes, effective prior to Jan. 1, 2020. On Jan. 29, 2016, the FERC approved the SPS compliance filings required by the settlement and FERC order.

Sale of Texas Transmission Assets — In March 2015, SPS reached an agreement to sell certain segments of SPS’ transmission lines

to Oncor Electric Delivery Company LLC. In November 2015, the transaction closed with the required regulatory approvals and SPS recognized a $3.9 million pre-tax gain after the impacts of sharing with Texas retail customers.

SPP Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded transmission upgrades may be recovered, in part, from other SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. To date, SPP has not charged its customers any amounts attributable to these upgrades. SPP recently indicated it may attempt to quantify and assess charges beginning in late 2016, including amounts for prior periods. Due to the limited information available and lack of historical precedent, the potential loss, if any, is not currently estimable. No accrual has been recorded for this matter.