Xcel Energy 2013 Annual Report Download - page 24

6
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 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. NSP-Minnesota has been
granted continued authorization from the FERC 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 programs that help customers save energy. The CIP includes a comprehensive list of
programs that benefit all customers including Saver’s Switch®, energy efficiency rebates and energy audits.
• 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.
• 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.
• Infrastructure — The Infrastructure rider recovers costs associated with specific investments in generation and incremental
property taxes.
The MPUC approved NSP-Minnesota’s request that the recovery of the costs associated with the EIR and RES be included in base
rates in the Minnesota electric rate case in 2012. No costs are being recovered through the EIR at this time. NSP-Minnesota will
continue to track PTCs associated with company-owned renewable projects and reflect the difference between the base rate amount
and actual costs in the RES adjustment clause.
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 in CIP. NSP-Minnesota was in
compliance with this standard in 2013 and expects to be in compliance in 2014. These costs are recovered through an annual cost-
recovery mechanism for electric conservation and energy management program expenditures.
CIP Triennial Plan — In October 2012, the DOC approved NSP-Minnesota’s 2013 through 2015 CIP Triennial Plan, which increases
the savings goals and budgets over the previous plan. The plan sets an electric goal of annually saving the equivalent of 1.5 percent of
sales (calculated on a historical three-year average, excluding opt-out customers) and an annual natural gas goal of saving 1.0 percent
of sales. The combined electric and gas budgets average $104.9 million per year over the 2013 through 2015 period.