Rate Matters

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — MPUC

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. In December 2015, the MPUC approved interim rates for 2016. 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

Settlement Agreement

In August 2016, NSP-Minnesota and various parties reached a settlement which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC.

Key terms of the settlement are listed below:


•	Four-year period covering 2016-2019;


•	Annual sales true-up as detailed below:


•	2016 weather-normalized actuals used to set final 2016 rates, no cap;


•	2016-2019 full decoupling for residential and non-demand metered commercial classes with a 3 percent cap; and


•	2017-2019 annual true-up for non-decoupled classes with a 3 percent cap.


•	ROE of 9.2 percent and an equity ratio of 52.5 percent;


•	Nuclear related costs will not be considered provisional;


•	Continued use of all existing riders, however no new riders may be utilized during the four-year term;


•	Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019;


•	Four-year stay out provision for rate cases;


•	Property tax true-up mechanism for 2017-2019; and


•	Capital expenditure true-up mechanism for 2016-2019.



(Millions of Dollars, incremental)	2016		2017		2018		2019			Total
Settlement revenues ^(a)	$	74.99	$	59.86	$	—	$	50.12		$	184.97
NSP-Minnesota’s sales true-up	59.95		—		—		(0.20		)	59.75
Total rate impact ^(b)	$	134.94	$	59.86	$	—	$	49.92		$	244.72


^(a)	The settlement revenues are based on the DOC’s sales forecast.


^(b)	The total rate impact reflects an increase of 4.62 percent in 2016; 2.05 percent in 2017; 0 percent in 2018 and 1.71 percent in 2019.

The schedule for the Minnesota rate case is listed below:


•	ALJ report — March 3, 2017; and


•	MPUC decision — June 2017.

A current liability that is consistent with the settlement and represents NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of Dec. 31, 2016.

Monticello 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 in 2015. 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 $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. 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.

2016 TCR Filing — In January 2017, the MPUC issued an order approving NSP-Minnesota’s requested 2016 revenue requirements of $78.4 million to recover costs for three CapX2020 projects and two additional projects.

Electric, Purchased Gas and Resource Adjustment Clauses

CIP and CIP Rider — CIP expenses are recovered through base rates and a rider that is adjusted annually. The estimated average annual electric and natural gas incentives for 2016 are $30.6 million and $3.6 million, respectively, based on the approved savings goals. The MPUC approved the following for NSP-Minnesota:


•	A new CIP financial incentive mechanism for the 2017-2019 triennial period with an average forecasted incentive of $12.5 million for electric conservation and $1.8 million for gas conservation;


•	The 2015 CIP electric and natural gas financial incentives totaling $43.3 million and $5.8 million, respectively; and


•	This proposed 2016 electric and natural gas CIP riders with estimated 2016 recovers of $45.1 million of electric CIP expenses and $15.4 million of natural gas CIP expenses. This proposed recovery through the riders is in addition to an estimated $90.2 million and $3.8 million through electric and gas base rates, respectively.

GUIC Rider — In 2016, 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. NSP-Minnesota requested recovery of approximately $22.1 million from Minnesota gas utility customers beginning April 1, 2017. An MPUC decision is expected in the first half of 2017.

Annual Automatic Adjustment (AAA) of Charges — In 2016, the DOC recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. The DOC’s recommendation could impact replacement power cost recovery for the PI nuclear facility outages allocated to the Minnesota jurisdiction during the AAA fiscal year ended June 30, 2015. NSP-Minnesota expects a MPUC decision in mid-2017.

NSP-Wisconsin

Recently Concluded Regulatory Proceedings — PSCW

Wisconsin 2017 Electric and Gas Rate Case — In April 2016, NSP-Wisconsin filed a request with the PSCW for an increase in annual electric rates of $17.4 million, or 2.4 percent, and an increase in natural gas rates by $4.8 million, or 3.9 percent, effective January 2017.

The electric rate request was for the limited purpose of recovering increases in (1) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted average rate base of $1.188 billion in 2017.

The natural gas rate request was for the limited purpose of recovering expenses related to the ongoing environmental remediation of a former MGP site and adjacent area in Ashland, Wis.

No changes were requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 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, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.

In December 2016, the PSCW issued an order approving an electric rate increase of approximately $22.5 million, or 3.2 percent, and a natural gas rate increase of $4.8 million, or 3.9 percent. The differences between NSP-Wisconsin’s original electric rate request and the PSCW’s approved electric increase are summarized below:



Electric Rate Request (Millions of Dollars)	NSP-Wisconsin Request			Final Decision
Rate base investments	$	11.0		7.6
Generation and transmission expenses (excluding fuel and purchased power) ^(a)	6.8			6.1
Fuel and purchased power expenses	11.0			10.7
Subtotal	28.8			24.4
2015 fuel refund ^(b)	(9.5		)	—
Department of Energy settlement refund	(1.9		)	(1.9		)
Total electric rate increase	$	17.4		$	22.5


^(a)	Includes Interchange Agreement billings. For financial reporting purposes, these expenses are included in O&M.

^(b)

In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision, when combined with the increase in forecasted fuel and purchased power expense, effectively increased NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.

PSCo

Pending Regulatory Proceedings — CPUC

Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. The 2016 earnings test did not result in a material customer refund obligation as of Dec. 31, 2016. PSCo will file its 2016 earnings test with the CPUC in April 2017. 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 400 GWh in 2015 and 2016 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 2017 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual spending limit of $84.3 million.

In February 2017, the CPUC approved PSCo’s 2017-2018 DSM plan:


•	A 2017 DSM electric budget of $80.4 million and a natural gas budget of $13.1 million; and


•	A 2018 DSM electric budget of $77.7 million and a natural gas budget of $12.8 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 $5.8 million and $5.5 million in 2016 and 2015, respectively. The cumulative credit to the RESA regulatory liability balance was $116.3 million and $110.6 million at Dec. 31, 2016 and Dec. 31, 2015, 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 Dec. 31, 2017.

SPS

Pending and Recently Concluded Regulatory Proceedings — PUCT

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $64.8 million, which it subsequently revised to $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. A decision by the Texas State District Court is pending.

Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, base 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 historic test year 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. In September 2016, SPS revised its requested rate increase to $61.5 million and along with recovery of rate case expenses made for an overall revised request of $65.5 million.

In December 2016, SPS reached an unopposed settlement that resolves all issues in the rate case. The following table reflects the total estimated impact:



(Millions of Dollars)	Settlement
Base rate increase, retroactive to July 20, 2016	$	35.2
Power factor revenues ^(a)	12.6
Rate case expenses to be addressed in a separate proceeding	4.0
Total estimated impact	$	51.8


^(a)	SPS’ request assumed customers would adjust their power factors, which would reduce revenue. To the extent power factor revenues are less than $12.6 million, a mechanism will be established to ensure SPS recovers this amount and effectively offset lower anticipated power factor charges.

Additional key terms are as follows:


•	SPS’ next TCRF application will have a cap of $19 million in additional annual revenue and parties will make reasonable efforts to obtain PUCT approval within 100 days of SPS’ initial filing;


•	No disallowance of SPS’ requested capital additions; and


•	No restrictions on filing future rate cases or rate riders.

Pursuant to legislation passed in Texas in 2015, the final rates established in the case will be effective retroactive to July 20, 2016. In December 2016, an ALJ approved interim rates, effective as of Dec. 10, 2016. In the fourth quarter of 2016, SPS deferred certain costs associated with this rate case. In January 2017, the PUCT approved the settlement and no refund of interim rates was necessary. SPS expects to file a surcharge to recover the additional revenue associated with final rates, for the period of July 20, 2016 through Dec. 9, 2016, by the third quarter of 2017.

Texas 2016 TCRF Application — In February 2017, SPS filed an application with the PUCT to recover additional annual revenue of approximately $16.1 million through its TCRF, or 1.79 percent. The filing is based upon expenses and investments through Dec. 31, 2016. Based on the settlement agreement approved in the Texas 2016 electric rate case, SPS expects a PUCT decision and implementation of TCRF rates by mid-2017.

Pending Regulatory Proceedings — NMPRC

New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the NMPRC for an increase in base rates of approximately $41.4 million, representing a total revenue increase of approximately 10.9 percent. The rate filing is based on a future test year ending June 30, 2018, a requested return on equity of 10.1 percent, an equity ratio of 53.97 percent and an electric rate base of approximately $832 million.

SPS has excluded fuel and purchased power costs from base rates. This base rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the service life of SPS’ Tolk power plant to a remaining life of 2030 based on the investments to provide cooling water and the risks of investments in additional environmental controls.

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



(Millions of Dollars)	Request
Capital expenditures	$	20.1
Allocator changes, including wholesale load reductions	11.5
Transmission expense, net of revenue, including charges paid to SPP for construction of regionally shared transmission projects	4.7
Depreciation, including adjustment of service life for the Tolk generating station	3.6
Rate case expenses	1.1
Other, net	0.4
Requested rate increase	$	41.4

Key dates in the procedural schedule are as follows:


•	Deadline for settlement — Feb. 28, 2017;


•	Staff and intervenor testimony — April 14, 2017;


•	Rebuttal testimony — May 3, 2017;


•	Hearings — May 15, 2017; and


•	An NMPRC decision and implementation of final rates is anticipated in the second half of 2017.

Pending Regulatory Proceedings — FERC

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 for being an independent transmission company), effective Nov. 12, 2013.

In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent, which the FERC upheld in an order issued on Sept. 28, 2016. This ROE is applicable for the 15 month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE is 10.82 percent, which includes a previously approved 50 basis point adder for RTO membership.

In February 2015, a second complaint seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent prior to any adder was filed, which the FERC set for hearings, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, NDPSC, SDPUC and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. On June 30, 2016, the ALJ recommended a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow range. A FERC decision is expected later in 2017.

As of Dec. 31, 2016, NSP-Minnesota has recognized a current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the FERC order, as well as a current liability representing the best estimate of the final ROE for the second complaint period.

SPP Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to collect charges since 2008, but SPP had not been charging its customers any amounts attributable to these upgrades.

In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008. The FERC approved the waiver request in July 2016. SPS and certain other parties requested rehearing of the FERC order. Amounts due to SPP are expected to be paid over a five-year period commencing November 2016 under an optional payment plan that was approved by the FERC in September 2016 and elected by SPS in October 2016. In October 2016, SPS filed applications for deferred accounting and future recovery of related costs in Texas and New Mexico. In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges. In December 2016, SPS’ New Mexico application was consolidated with its base rate case and SPS’ Texas application was referred to the ALJ for hearing. A decision is expected in the first half of 2017. SPS anticipates these costs will be recoverable through regulatory mechanisms.