Xcel Energy 2015 Annual Report Download - page 27
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• NDPSC Staff support for continued use of 12-Coincident Peak system allocator through 2025; and,
• Development of a framework to address future generation resources to be filed with the NDPSC by Jan. 1, 2017.
The NDPSC conducted a work session in February 2016, to discuss their view of the Negotiated Agreement with their Advisory Staff.
Next steps would include further NDPSC hearing(s) to continue discussion or take action on the Negotiated Agreement. No specific
procedural schedule has been established for this matter.
NSP-Minnesota’s Petition for an Advance Determination of Prudence — In February 2016, the NDPSC discussed NSP-Minnesota’s
Petition for an Advance Determination of Prudence (ADP) for 345 MW of capacity and associated energy to be added to the NSP
System through a 20-year PPA with Mankato Energy Center, LLC, an affiliate of Calpine Corporation. While a certain commissioner
indicated support for the opportunity to add larger, low-priced, dispatchable generation, other commissioners were concerned the
resource would not be necessary by the 2019 expected in-service date and not supportive of the ADP. Commissioners are expected to
vote on the matter on March 9, 2016. The North Dakota portion of the PPA is approximately $1.2 million per year.
CapX2020 — The estimated cost of the five major CapX2020 transmission projects listed below is $2 billion. NSP-Minnesota and
NSP-Wisconsin are responsible for approximately $1.1 billion of the total investment. As of Dec. 31, 2015, Xcel Energy has invested
$1.0 billion of its $1.1 billion share of the five CapX2020 transmission projects. The projects are as follows:
• Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 161/345 Kilovolt (KV) transmission line — The Wisconsin portion
of the project includes a new substation and approximately 50 miles of new 345 KV transmission line, at an estimated cost of
$211 million. The final 161 KV segment of the project went into service in January 2016, while the final 345 KV segment of
the project is expected to go into service in the fall of 2016;
• Brookings County, S.D. to Hampton, Minn. 345 KV transmission line — The project was placed in service in March 2015;
• Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line — The project was placed in service in September 2012;
• Monticello, Minn. to Fargo, N.D. 345 KV transmission line — In April 2015, the final portion of the project was placed in
service; and
• Big Stone South to Brookings County, S.D. 345 KV transmission line — Construction on the line began in September 2015,
with completion anticipated in 2017.
Minnesota Solar — Minnesota legislation requires 1.5 percent of a public utility’s total electric retail sales to retail customers be
generated using solar energy by 2020. Of the 1.5 percent, 10 percent must come from systems sized 20 kilowatts or less. NSP-
Minnesota anticipates it will meet its compliance requirements through large and small scale solar additions.
NSP-Minnesota also offers customer solar programs: a solar production incentive program for rooftop solar, called Solar*Rewards®,
and a community solar garden program that provides bill credits to participating subscribers, called Solar*Rewards® Community®.
Additionally, the DOC offers the “Made in Minnesota” program, providing incentives for the installation of small solar systems that
were manufactured in-state, which generates renewable energy credits for utilities including NSP-Minnesota.
In August 2015, the MPUC issued an order regarding the Solar*Rewards Community program, limiting the size of solar installations
eligible to participate in the program to five MW or less through Sept. 25, 2015. Subsequently, projects must be one MW or less. In
October 2015, the MPUC denied requests for reconsideration of the project size limitation. Sunrise Energy Ventures, a Solar*Rewards
Community developer, has appealed this decision to the Minnesota Court of Appeals.
Minnesota Legislation — In June 2015, the Minnesota governor signed the Jobs and Energy bill into law. Several approved
mechanisms may provide additional options and opportunities in future rate cases, including the duration of future MYPs and more
certainty regarding recovery of costs and the impact to customers. This bill provides:
• Increased flexibility for utilities to submit a MYP of up to five years;
• The potential for full capital recovery for all proposed years;
• O&M cost recovery based on an index;
• Distribution costs that facilitate grid modernization are eligible for rider recovery;
• Natural gas extension costs for unserved areas can be socialized and are eligible for rider recovery;
• Recovery of plant closure costs, should the MPUC order early plant closure, such as in a resource plan; and
• Allows implementation of interim rates for the first and second years of the MYP.