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ELECTRIC UTILITY OPERATIONS
NSP-Minnesota
Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s
operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC also has regulatory
authority over security issuances, property transfers, mergers, dispositions of assets and transactions between NSP-Minnesota and its
affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s ERPs for meeting customers’ future energy needs. The
MPUC also certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV that will
be located within the state. No large power plant or transmission line may be constructed in Minnesota except on a site or route
designated by the MPUC. The NDPSC and SDPUC have regulatory authority over generation and transmission facilities, along with
the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.
NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric licensing,
accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric
reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. As approved by the FERC,
NSP-Minnesota operates within the MISO RTO and MISO wholesale market. NSP-Minnesota is authorized to make wholesale
electric sales at market-based prices. NSP-Minnesota is a transmission owning member of the MISO RTO.
Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — NSP-Minnesota has several retail adjustment clauses that
recover fuel, purchased energy and other resource costs:
• CIP — The CIP recovers the costs of conservation and demand-side management programs that help customers save energy.
• EIR — The EIR recovers the costs of environmental improvement projects.
• RDF — The RDF allocates money collected from retail customers to support the research and development of emerging
renewable energy projects and technologies.
• RES — The RES recovers the cost of new renewable generation in Minnesota.
• RER — The RER recovers the cost of new renewable generation in North Dakota.
• SEP — The SEP recovers costs related to various energy policies approved by the Minnesota legislature.
• TCR — The TCR recovers costs associated with new investments in electric transmission and distribution costs that facilitate
grid modernization.
• Infrastructure — The Infrastructure rider recovers costs associated with specific investments in generation and incremental
property taxes in South Dakota.
NSP-Minnesota’s retail electric rates in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for
changes in prudently incurred costs of fuel, fuel related items and purchased energy. NSP-Minnesota is permitted to recover these
costs through FCA mechanisms approved by the regulators in each jurisdiction. In general, capacity costs are not recovered through
the FCA. In addition, costs associated with MISO are generally recovered through either the FCA or base rates.
Minnesota state law requires NSP-Minnesota to invest two percent of its state electric revenues and half a percent of its state gas
revenues in CIP. NSP-Minnesota was in compliance with this standard in 2015 and expects to be in compliance in 2016. These costs
are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.
Minnesota state law also requires NSP-Minnesota to submit a CIP plan at least every three years.
CIP Triennial Plan — In 2012, the DOC approved NSP-Minnesota’s 2013 through 2015 CIP Triennial Plan, which increases the
energy savings goals and budgets over the previous plan. The plan sets an annual energy savings goal for electric of saving the
equivalent of 1.5 percent the volume of electric energy sales (calculated on a historical three-year average, excluding opt-out
customers) and an annual natural gas goal of saving 1.0 percent the volume of gas energy sales. During 2015, NSP-Minnesota
submitted an extension to the triennial plan for 2016 which was approved by the DOC. NSP-Minnesota anticipates submitting a 2017
through 2019 plan during the first half of 2016.
Capacity and Demand
Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2016,
assuming normal weather conditions, is as follows:
System Peak Demand (in MW)
2013 2014 2015 2016 Forecast
NSP System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,524 8,848 8,621 9,327