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Prairie Island Nuclear Plant EPU — In 2009, the MPUC granted NSP-Minnesota a CON for an EPU project at the Prairie Island
nuclear generating plant. The total estimated cost of the EPU was $294 million, of which approximately $78.9 million had been
incurred, including AFUDC of approximately $12.8 million. Subsequently, NSP-Minnesota made a change of circumstances filing
notifying the MPUC that there were changes in the size, timing and cost estimates for this project, revisions to economic and project
design analysis and changes due to the estimated impact of revised scheduled outages. The information indicated reductions to the
estimated benefit of the uprate project. As a result, NSP-Minnesota concluded that further investment in this project would not benefit
customers. In February 2013, the MPUC issued an order terminating the CON for the Prairie Island EPU project.
NSP-Minnesota plans to address recovery of incurred costs in rate cases for each of the NSP-Minnesota jurisdictions and to file a
request with the FERC for approval to recover a portion of the costs from NSP-Wisconsin through the Interchange Agreement. NSP-
Wisconsin plans to seek cost recovery in a future rate case. Based on the outcome of the December 2012 MPUC decision, EPU costs
incurred to date were compared to the discounted value of the estimated future rate recovery based on past jurisdictional precedent,
resulting in a $10.1 million pretax charge in December 2012 which is included in O&M expense for that year.
Pending and Recently Concluded Regulatory Proceedings — NDPSC
NSP-Minnesota – North Dakota 2013 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 was based on a 2013 FTY, 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 August 2013, NSP-Minnesota filed rebuttal testimony revising the requested increase in retail electric rates to approximately $14.9
million, based on a revised ROE of 10.25 percent and incorporating updated information.
In December 2013, a comprehensive settlement agreement between NSP-Minnesota and the NDPSC Staff was filed for approval,
proposing resolution to the rate case and resolution of various regulatory proceedings for wind and natural gas generating resources
pending before the NDPSC. The settlement agreement provided for a four-year rate plan including a 5.0 percent annual increase in
retail revenues in North Dakota, effective Feb. 16, 2013 through Dec. 31, 2015, with no increase in 2016. As filed, the estimated 2013
settlement impact was $11.6 million. On Feb. 18, 2014, NSP-Minnesota filed an amended settlement agreement revising the annual
increase to 4.9 percent, effective Feb. 16, 2013 through Dec. 31, 2015, with no increase in 2016.
The table below reflects the amended settlement’s 2013 impact.
(Millions of Dollars)
Amended
Settlement
Impact
Proposed 12 month settlement base rate increase . . . . . . . . . . . . . . . . . . . . $ 9.0
Pre-effective period impact (Jan. 1, 2013 - Feb. 15, 2013). . . . . . . . . . . . . (1.6)
Proposed settlement base rate increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.4
Retention of DOE settlement proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9
Other, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.3)
Amended settlement’s 2013 impact. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 11.0
Additional settlement terms include:
• An approval of two new rate rider tariff mechanisms to recover transmission and North Dakota renewable costs;
• An authorized ROE of 9.75, 10.0, 10.0 and 10.25 percent in 2013 through 2016, respectively;
• A 50 percent earnings sharing mechanism for amounts earned in excess of the authorized ROEs during the term of the
settlement;
• The continued use of a 12 month CP demand allocator for certain rate base and operating expenses;
• A commitment to develop a generation cost allocation mechanism over the next 16 months that reflects North Dakota energy
policy; providing for the exclusion of resources deemed inconsistent with North Dakota energy policy beginning in 2016
(such as certain Minnesota wind and biomass purchase power agreements) and reflecting replacement of those costs based on
either system average costs or like resource costs (base load for base load generation, etc.) and recognizing the time needed to
address complexity among multiple jurisdictions by providing that a plan for this mechanism be filed by June 2015;
• The commitment to construct up to 400 MW of thermal generation in North Dakota by 2036 subject to least-cost resource
planning principles; and
• The retention of DOE settlement proceeds received in 2012, 2013 and expected in 2014.
A final NDPSC decision on the case is anticipated in the first quarter of 2014.