Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2015, and in Note 5 to NSP-Wisconsin's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Public Service Commission of Wisconsin (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 is 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 is for the limited purpose of recovering expenses related to the ongoing environmental remediation of a former manufactured gas plant (MGP) site and adjacent area in Ashland, Wis.

No changes are being requested to the capital structure or the 10.0 percent return on equity (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 August 2016, the PSCW Staff (Staff) and the intervenors filed their direct testimony in the case. The Staff recommended an electric rate increase of $19.5 million, or 2.7 percent and a natural gas rate increase of $4.8 million, or 3.9 percent. The Staff adjustments reflect revisions to previously forecasted rate base as well as fuel and purchased power expense. The Staff’s recommended rate increase also encompasses the PSCW’s July 2016 decision to remove the $9.5 million fuel refund credit from the rate case and refund that amount directly to customers in 2016. Adjusting for the treatment of the fuel refund, the Staff’s recommendation is $7.4 million less than NSP-Wisconsin’s request.

On Oct. 26, 2016, the PSCW verbally approved 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 difference between the Staff’s recommendation and the PSCW’s approved electric increase is attributable to an increase in forecasted fuel and purchased power expense. Consistent with long-standing PSCW policy, these costs were updated prior to the PSCW’s decision to reflect current market forecasts. The PSCW approved NSP-Wisconsin’s requested natural gas rate increase consistent with the Staff’s recommendation.

The major components of the retail electric rate increase, the Staff’s recommendation, and the PSCW’s approval are summarized below:



Electric Rate Request (Millions of Dollars)	NSP-Wisconsin Request			Staff Recommendation			Final Decision
Rate base investments	$	11.0		$	7.6		7.6
Generation and transmission expenses (excluding fuel and purchased power) ^(a)	6.8			6.1			6.1
Fuel and purchased power expenses	11.0			7.7			10.7
Subtotal	28.8			21.4			24.4
2015 fuel refund ^(b)	(9.5		)	—			—
Department of Energy settlement refund	(1.9		)	(1.9		)	(1.9		)
Total electric rate increase	$	17.4		$	19.5		$	22.5

^(a)

Includes Interchange Agreement billings. The Interchange Agreement is a Federal Energy Regulatory Commission (FERC) tariff under which NSP-Wisconsin and its affiliate, NSP-Minnesota, own and operate a single integrated electric generation and transmission system and both companies pay a pro-rata share of system capital and operating costs. For financial reporting purposes, these expenses are included in operating and maintenance (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 increases NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.

NSP-Wisconsin anticipates a final written order later this year, with new rates effective on Jan. 1, 2017.

Pending Regulatory Proceedings - Michigan Public Service Commission (MPSC)

Michigan 2017 Natural Gas Rate Case — In October 2016, NSP-Wisconsin filed a request with the MPSC to increase base rates for natural gas service by approximately $347 thousand annually, or 6.5 percent. The filing was based on a 2017 forecast test year, a 10.2 percent ROE, an equity ratio of 52.56 percent and a forecasted average rate base of approximately $6.4 million. The primary driver of the requested increase is investment in natural gas distribution infrastructure, mainly in conjunction with the company’s Distribution Integrity Management Program (DIMP). NSP-Wisconsin also proposed an Infrastructure Cost Recovery Mechanism (ICRM) rate rider to recover ongoing costs associated with the DIMP. In addition, the filing requested recovery of approximately $129 thousand, or 2.4 percent, through the ICRM, beginning in January 2018. Under the proposal, the ICRM rider would be adjusted annually.

Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello life cycle management (LCM)/extended power uprate (EPU) project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW) in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (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. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million.

Pending Regulatory Proceedings — FERC

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (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 regional transmission organization (RTO) membership and for being an independent transmission company), effective Nov. 12, 2013.

In December 2015, an administrative law judge (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, the North Dakota Public Service Commission, the South Dakota Public Utilities Commission and the Minnesota Department of Commerce 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 issued an initial decision recommending a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow (DCF) range. A FERC decision is expected in 2017.

As of Sept. 30, 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