Minnesota

State Profile
5,489,594
45
Utility Revenue (Millions) $1,194.90
$1,033.30
n/a
$141.70
$19.90
Consumption (Billion Cubic Feet or BCF)

Consumption by Sector In-State

25,072
419
118
93
157
52
Customers 1,637,529
1,496,790
138,871
1,868
Industry Infrastructure
n/a
n/a
33,458
Utility Gas Efficiency Program Funding $44,092,522.00
$23,258,165.00
$5,019,400.00
$11,902,272.00
$3,912,685.00

Sources

AGA Survey and Statistics System; AGA-CEE Natural Gas Efficiency Programs Survey: Utility expenditures for gas efficiency programs exclude data that have not been released by participating companies at the state level; U.S. Energy Information Administration; and U.S. Department of Transportation.

Statewide Elected Officials Next Election: 2018
Mark Dayton (Dem.)Governor
Tina Smith (Dem.)Lieutenant Governor
Lori Swanson (Dem.)Attorney General
Legislature Next Election: 2018Session Dates: 03/08/16-05/23/16
Senate
Term: 4 year term when elected in years ending in 2 and 6; 2 years when elected in years ending in 0
President: Sandy Pappas
President Pro Tempore: n/a
Senate Majority Leader: Tom Bakk
Senate Minority Leader: David Hann
Senate Member Breakdown
Democrats: 33
Republicans: 34
House of Representatives
Term: 2 year
Speaker of the House: Kurt Daudt
Majority Leader: Joyce Peppin
Minority Leader: Paul Thissen
House of Representatives Member Breakdown
Democrats: 57
Republicans: 76
Other: 1
Minnesota Public Utilities Commission Commissioners: Gubernatorial appointment, Senate confirmation: 6 year termChairperson: Gubernatorial appointment: Indefinite term
Current Commissioners:
Beverly Jones Heydinger (D), Chair Appointed as Chairman by Governor Mark Dayton in 2012; term ends in 2017
John Tuma, Commissioner Appointed by Governor Mark Dayton in 2015; term ends in 2021
Matthew Schuerger, Commissioner Appointed by Governor Mark Dayton in 2016; term ends in 2022
Nancy Lange (D), Commissioner Appointed by Governor Mark Dayton in 2013; term ends in 2019
Dan Lipschultz (D), Commissioner Appointed by Governor Mark Dayton in 2014; term ends in 2020

CenterPoint Energy currently has a CHP Project under development. This project may be eligible to be counted towards a utility's natural gas or electric energy savings goals, subject to department approval. These projects do not count towards the state's renewable energy sources requirement.

Every four years, Minn. Stat. 216C.18 obliges the Department of Commerce to issue a report on energy issues and information for the state. Summary of key energy policy strategies: Encourage coal-fired generation facilities to convert to less polluting fuels or to install state-of-the-art emissions control technologies; Enhance the state and region’s energy delivery infrastructure to assure reliability and provide access for electricity from low-cost and/or environmentally superior sources; Support state conservation programs; Reduce regulatory and government barriers—The Department believes that state regulatory requirements for new energy infrastructure investments should be sufficient to weed out bad projects from good but should not act as a barrier to critical infrastructure investments.

Minnesota has had a shared benefit incentive in place since 1999, which was approved in Docket No. E,G-999/CI-08-13 and most recently continued in 2012. The incentive increases as the percentage of savings of retail sales increases. There is a cap of 20% of net benefits on the amount of incentive that may be earned. The incentive is set such that at savings of 1.5% of retail sales gas utilities will earn and incentive of $9.00 Mcf saved. The percentage of net benefits to be awarded to each utility at different energy savings levels will be set at the beginning of each year. In 2007, Minnesota enacted the Next Generation Energy Act, which amended Minnesota Statute § 216B.241. The law laid out a new state conservation and efficiency strategy. The law established a 1.5% annual natural savings target, which began in 2010. Under the law first 1% must be met with direct energy efficiency energy savings, or conservation improvements. This may include savings from efficiency measures installed at a utility’s own facilities. The law allows savings to be achieved indirectly through energy codes and appliance standards. Up to 0.5% may be met by efficiency enhancements to each utility’s generation, transmission, and distribution infrastructure.

During the 1990s the Minnesota PUC investigated the problems in funding new extension lines in remote areas. In 2012, the PUC approved a New Area Surcharge (NAS) rider for MERC which is designed to permit the utility to extend service into a new area that would be uneconomic to serve at tariffed rates, by permitting that utility to collect the surcharge on tip of the tariffed rate. In the late 1990s, the MN PUC approved NAS riders for CenterPoint (CNP) and Xcel. In 2014, the MN PUC extended the maximum time frame from 15 years to 30 years for CNP and MERC. In March of 2015, the Minnesota legislature took up MN SF 1263. This measure would allow a public utility to petition the commission outside of a general rate case for a rider on all of the utility's customers, including transport customers, to recover the revenue deficiency from a natural gas extension project. The commission shall approve a public utility's petition for a rider to recover the costs of a natural gas extension project if it determines that: (1) the project is designed to extend natural gas service to an unserved or inadequately served area; and (2) project costs are reasonable and prudently incurred. This bill died at the end of the legislative session. In March of 2015, the Minnesota Senate took up SF 1431. This bill would allow a public utility to petition the Commission outside of a general rate case for a rider that shall include all of the utility's customers, including transport customers, to recover the revenue deficiency from a natural gas extension project. The petition shall include: (1) a description of the natural gas extension project, including the number and location of new customers to be served and the distance over which natural gas will be distributed to serve the unserved or inadequately served area; (2) the project's construction schedule; (3) the proposed project budget; (4) the amount of any contributions in aid of construction; (5) a description of efforts made by the public utility to offset the revenue deficiency through contributions in aid to construction; (6) the proposed method and amount of recovery by customer class and whether the utility is proposing that the rider be a flat fee, a volumetric charge, or another form of recovery; (7) how recovery of the revenue deficiency will be allocated between industrial, commercial, residential, and transport customers; (8) the proposed termination date of the rider to recover the revenue deficiency; and (9) A description of benefits to the public utility's existing natural gas customers that will accrue from the natural gas extension project. This bill died at the end of the legislative session. On June 13, 2015, Governor Mark Dayton (D) signed HF 3 into law. The bill provides that a public utility may petition the commission outside of a general rate case for a rider that includes all of the utility's customers, including transport customers, to recover the revenue deficiency from a natural gas extension project. Each petition must include the following information: (1) a description of the natural gas extension project, including the number and location of new customers to be served and the distance over which natural gas will be distributed to serve the unserved or inadequately served area; (2) the project's construction schedule; (3) the proposed project budget; (4) the amount of any contributions in aid of construction; (5) a description of efforts made by the public utility to offset the revenue deficiency through contributions in aid to construction; (6) the amount of the revenue deficiency, and how recovery of the revenue deficiency will be allocated among industrial, commercial, residential, and transport customers; (7) the proposed method to be used to recover the revenue deficiency from each customer class, such as a flat fee, a volumetric charge, or another form of recovery; (8) the proposed termination date of the rider to recover the revenue deficiency; and (9) a description of benefits to the public utility's existing natural gas customers that will accrue from the natural gas extension project.

In May 2013, the Minnesota legislature passed an Omnibus jobs, economic development, housing, commerce and energy bill which included a rider for the recovery of gas utility infrastructure costs. Under the legislation, a gas utility may submit a gas infrastructure project plan report and a petition for cost recover. Upon receiving those items, the Minnesota Public Utilities Commission may approve a rider provided that the costs included for recovery through the rate schedule are prudently incurred and achieve gas facility improvements at the lowest reasonable and prudent cost to ratepayers. In August of 2014, Xcel Energy said in a recent regulatory filing that it intends to spend $15 million in 2015 on pipeline safety improvements, which is roughly a twofold increase over past levels. In future years, the company envisions even larger safety-related investments, peaking in 2019 at more than $50 million. Should the Minnesota Public Utilities Commission approve the 2015 investment, it would increase customers' bills 3.5 percent in January, about $2 per month for a typical customer, the company said. Future investments could bring more increases, though they would need separate regulatory approval. On January 27, 2015, The Commission approved Xcel’s proposed GUIC rider, rate-adjustment factors, and tariff sheets with the following modifications: o A rate of return calculated using the capital structure and cost of debt from Xcel’s electric rate case, Docket No. E-002/GR-13-868, and the cost of equity from its last natural-gas rate case, Docket No. G-002/GR-09-1153; o A rate design that allocates the 2015 revenue requirement to Xcel’s customer classes in the same manner as revenues were apportioned in the Company’s February 28, 2011 compliance filing in its last natural-gas rate case; and o An effective date of the date of this order, with final rate-adjustment factors calculated to recover the 2015 revenue requirement over the remaining months of 2015. The Commission also determined that sixty days in advance of its next annual GUIC filing, Xcel shall submit information on what it believes the appropriate rate of return should be for the coming year. Lastly, in the initial filing in its next natural-gas rate case, Xcel must submit detailed schedules, any necessary supporting documentation, and an explanation of all O&M costs that were being recovered in the rider and are now included in the test year for recovery in base rates.

CenterPoint energy owns a public CNG station in Minneapolis, MN. WEC Energy Corp. subsidiary Trillium CNG owns and operates stations in Sauk Centre, Duluth, and St. Paul and two stations in Minneapolis. In March of 2015, Representative Pat Garofalo introduced HF 2081, which would require certain public utilities to file plans with the Public Utilities Commission promoting electric and compressed natural gas vehicles and to recover costs of such promotion and provide rebates and incentives to electric and compressed natural gas vehicle purchasers and salespersons.

Minnesota Energy Resources operates under a full decoupling mechanism. On May 8, 2014 The Minnesota Public Utilities Commission (PUC) issued an order in CenterPoint Energy’s (CE) general rate case. In Its decision, the PUC authorized CE to implement a pilot, three-year, full RDM effective July 1, 2015. The RDM is to apply to all customer classes except market-rate customers, subject to a cap on annual adjustments under the mechanism that is equal to 10% of non-gas margin revenue, after removing conservation costs, for decoupling adjustments due to revenue under-recovery by CE.