MN PUC Establishes New Environmental Costs for Use in All Proceedings

Today, the MN PUC concluded a nearly four-year effort on updating environmental costs established under section 216B.2422 subd. 3 of the Minnesota Statutes.  Before getting to the decision, a bit of context.


Under section 216B.2422, the MN PUC is required to, “to the extent practicable, quantify and establish a range of environmental costs associated with each method of electricity generation. A utility shall use the values established by the commission in conjunction with other external factors, including socioeconomic costs, when evaluating and selecting resource options in all proceedings before the commission, including resource plan and certificate of need proceedings.”  This statute was enacted in 1993, with the MN PUC first establishing final values in 1997.  Minor updates occurred after that time.  On October 9, 2013, the Izaak Walton League of America – Midwest Office, Fresh Energy, the Sierra Club, the Center for Energy and Environment, the Will Steger Foundation, and the Minnesota Center for Environmental Advocacy, filed a motion with the MN PUC request it to update the cost values for CO2 and NOx emissions, to establish a cost value for PM2.5, and to reestablish a value for SO2.  On February 10, 2014, the MN PUC granted the motion and reopened the investigation.  Significant debate, discussions, and litigation ensued, with the MN PUC ultimately breaking the contested case proceeding into two phases.  In Phase I, the MN PUC directed the parties to assess whether the Federal Social Cost of Carbon (FSCC) is reasonable and the best available measure to determine the environmental cost of CO2 and, if not, what measure would be better supported by the evidence.  In Phase II, the MN PUC directed parties to analyze and offer appropriate values for PM2.5, NOx, and SO2.

Now, on to the decision.  The MN PUC decided both phases, as described below, in an oral decision today.  A written order will follow.

Phase I:

The MN PUC established a new range of $9.05/short ton to $43.06/short ton.  Although the MN PUC did not accept the FSCC as a proxy for environmental cost for CO2 under Minnesota law, it did utilize modeling from the Interagency Working Group, with minor modifications to certain economic framing assumptions.  These modifications include using a range of 3% to 5% for a discount rate (and excluding 2.5%) and using a time horizon for damages from the year 2100 (for the low end of the range) to the year 2300 (for the high end of the range).

Because these values are used in various resource plan and resource acquisition proceedings, which involve decisions on utility investments, the MN PUC reaffirmed a prior decision to incorporate a $0 value input for modeling purposes to provide it with a fuller picture.

Phase II:

Three general geographies are currently utilized for the environmental cost values; rural, metro-fringe, and urban.  The MN PUC updated the ranges in Phase II as follows, assuming metro-fringe values: PM2.5 ($6,450 /short ton – $16,078/short ton); NOx ($2,467/short ton – $7,336/short ton); and SO2 ($4,543 /short ton – $11,317/short ton).

Concluding Thoughts:

Ultimately, it is difficult to state precisely how these new values will influence future proceedings, including resource planning and resource acquisition proceedings. These values will be one of many factors before the MN PUC in those future proceedings, including qualitative factors such as socioeconomic impacts and grid reliability impacts of any decision. But all of the new values are a significant increase from the current values.  And the new values will undoubtedly provide the MN PUC with a fresh look at the impact at the range of environmental costs associated with each method of electricity generation.

Another Court Upholds a State Generation Program and Dismisses Challenges to Illinois’ Nuclear Subsidies

On July 14, 2017, and several weeks after the Second Circuit rejected challenges to Connecticut’s renewable energy procurement process and renewable energy credit program (see Allco Fin. Ltd. v. Robert J. Klee (Docket Nos. 16-2946, 16-2949)), the U.S. District Court for the Northern District of Illinois dismissed challenges brought by independent power producers and customers against Illinois’ nuclear subsidy program (Village of Old Mill Creek v. Anthony M. Star, Docket Nos. 17 CV 1163, 17 CV 1164). This Illinois decision further support the authority of states to promote generation of their choosing and represents another narrow reading of the Supreme Court’s recent ruling in Hughes v. Talen Energy (136 S. Ct. 1288 (2016)).

In the state program at issue in Old Mill Creek, Illinois created a “zero emission credit” (ZEC), a tradeable credit (modeled after a renewable energy credit) which represents the environmental attributes of one megawatt hour of energy from specified zero emission facilities (in this case, selected nuclear power plants interconnected with the Midcontinent Independent System Operator (MISO) or PJM Interconnection (PJM)). The effective purpose of this program is to subsidize Exelon’s Clinton and Quad Cities nuclear facilities in Illinois, which Exelon had threatened to shut down if it did not receive government support. Continue Reading

Massachusetts Sets 200MWh Energy Storage Mandate

Massachusetts recently became the latest state to adopt an energy storage target, following California’s lead, and recent storage legislation in Nevada and New York.

The Massachusetts storage mandate originated in the legislature last year, when the state legislature passed H.4568, which was signed by the Governor on August 8, 2016. The legislation required the state’s Department of Energy Resources (DOER) to determine by December 31, 2016 whether to set targets for electric companies to procure viable and cost-effective energy storage systems to be achieved by January 1, 2020.  If DOER determined that targets were appropriate, then the storage targets were to be adopted by July 1, 2017.

DOER determined the targets to be appropriate, and adopted those targets one day before the July 1, 2017 deadline. DOER adopted a storage target of 200 megawatt-hours, to be achieved by January 1, 2020.

Massachusetts is following a path similar to California, which passed legislation (AB 2514) in 2010 directing the California Public Utilities Commission (CPUC) to consider adopting energy storage procurement targets. In October 2013, the CPUC adopted an energy storage target of 1,325 megawatts for the state’s three largest investor-owned utilities.  The storage must be installed by the end of 2024, and procured through four biennial procurements which commenced in 2014.

In 2015, Oregon adopted an energy storage mandate requiring Portland General Electric and PacifiCorp to procure a minimum of 5 megawatts of energy storage by January 1, 2020. New York also recently passed bills that directed the state’s Public Service Commission to develop a storage procurement target for 2030.

Court Rejects Preemption and Dormant Commerce Clause Arguments and Upholds Connecticut’s Renewable Program

On June 28, 2017, the U.S. Court of Appeals for the Second Circuit rejected challenges to Connecticut’s renewable energy procurement process and renewable energy credit program (Allco Fin. Ltd. v. Robert J. Klee (Docket Nos. 16-2946, 16-2949)). In doing so, the Second Circuit preserved the flexibility of states to enact programs to support renewable energy and became the first federal court to apply the Supreme Court’s ruling in Hughes v. Talen Energy (136 S. Ct. 1288 (2016)). While the Second Circuit’s decision raises some questions about the boundaries of state renewable energy programs, its narrow reading of Hughes v. Talen Energy supports a wide range of state renewable energy programs.

Allco (a renewable energy developer that participated, but was not selected, in Connecticut’s renewable energy procurement process) petitioned the court to overturn Connecticut’s renewable program on preemption grounds. Under Connecticut’s renewable energy procurement process, Connecticut solicits proposals for renewable energy through a competitive solicitation, and then Connecticut’s utilities are directed to enter into power purchase agreements for energy, capacity and environmental attributes with the solicitation winners. In its complaint, Allco argued that, since the Federal Power Act (FPA) grants the Federal Energy Regulatory Commission (FERC) exclusive jurisdiction over wholesale sales of electricity, the FPA preempts any action taken by states dealing with wholesale electricity sales (outside of the Public Utility Regulatory Policies Act (PURPA) and the regulations that apply to qualifying facilities (QFs)). According to Allco, Connecticut’s renewable energy procurement process compelled a wholesale power transaction, similar to what the Supreme Court struck down in Hughes v. Talen Energy (in which Maryland guaranteed selected generators a fixed capacity price for participating in a FERC-approved capacity auction). Continue Reading

California Supreme Court Denies Request to Review Cap-and-Trade Case

Yesterday the California Supreme Court denied a petition for review of the cap-and-trade lawsuits brought by a coalition of business interests, headed by the California Chamber of Commerce and Morning Star Packing Company. The Court of Appeal decision issued in April 2017, which upheld the legality of California’s cap-and-trade auctions in the related cases California Chamber of Commerce v. California Air Resources Board and Morning Star Packing Company v. California Air Resources Board, will thus stand.

With the California Supreme Court’s decision on the petition for review, the legal pall overshadowing the cap-and-trade auctions has dissipated, but questions still abound on the future (and legality) of the cap-and-trade program after 2020. Several cap-and-trade bills introduced in the California Legislature this session failed to meet key deadlines to come up for a vote in 2017, though California Governor Jerry Brown is pursuing efforts to reach an agreement among California legislators to amend AB 32 to explicitly extend the cap-and-trade program post 2020 by statute.  Draft amendments to the cap-and-trade regulation, including to continue the program through 2030, are pending at the California Air Resources Board, but the Board intends to first vote on the AB 32 Scoping Plan Update before turning to cap-and-trade amendments.  The Board delayed consideration of the Scoping Plan Update from its June 22, 2017 meeting and has not yet re-calendared this item.  Without a clear statutory mandate for cap-and-trade to remain in effect after 2020, new lawsuits are likely to be filed.

Updates to Energy Related Bills in the 2017-2018 California Legislative Session

Stoel Rives’ Energy Team has been monitoring and providing summaries of key energy-related bills introduced by California legislators since the beginning of the 2017-2018 Legislative Session. June 2, 2017 was the deadline by which the legislature was required to pass bills out of the house of origin.  Failing to meet that deadline does not automatically prevent a bill from proceeding through the legislative process; however, such failure will prevent the bill from being considered by the full legislature or the Governor during the first half of the Legislative Session.  Below is a summary of bills we have been following that have most recently changed.  We will continue to monitor and update these energy-related bills as the legislative session proceeds.

Assembly Bills

AB 79 (Levine, D): Electrical generation: hourly greenhouse gas emissions: electricity from unspecified sources.
STATUS: Ordered to Senate June 1, 2017.

  • Initially introduced as a bill to decrease the amount energy consumed from coal-fired generation resources, AB 79 was revamped to require, by January 1, 2019, the State Air Resources Board (CARB), in consultation with the Independent System Operator (ISO), to regularly update its methodology for the calculation of emissions of greenhouse gases associated with electricity from unspecified sources. The bill would require the CPUC and the CEC to incorporate the methodology into programs addressing the disclosure of the emissions of greenhouse gases and the procurement of electricity by entities under the respective jurisdiction of each.

Continue Reading

California Agencies Hold En Banc on Retail and Customer Electricity Choice

On May 19, 2017, the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) held a joint en banc on customer and retail choice in California. In attendance were CPUC Commissioners Guzman Aceves, Randolph, Peterman, and President Picker.  CEC Commissioners McAllister, Douglas, and Chair Weisenmiller attended.

The en banc was intended to address a seismic shift in the entities serving load in California. As noted in the CPUC Staff White Paper issued in connection with the en banc meeting, by the end of this year, as much as 25% of the retail load served by the investor-owned utilities (IOU) will obtain their electric generation service from an entity other than an IOU.  Some estimates project that by the middle of the 2020s, over 85% of retail load may be served by sources other than the IOUs.  These changes are driven by the explosive growth of both distributed generation, primarily rooftop solar, and Community Choice Aggregation (CCA).  Direct access customers also comprise a significant portion of the retail load served by non-IOUs.

California has been extremely successful in pursuing its greenhouse gas reduction goals and expanding renewable energy procurement in the electricity sector. The question arises, however, as to how California will continue to pursue these goals under a scenario where 85% of the retail load is served by entities other than IOUs, whose current procurement decisions are not reviewed or approved by the CPUC, unlike the IOUs.  How will California pursue its greenhouse gas reduction goals, while maintaining reliability and affordability, especially for low and middle income residents, under a regulatory and procurement regime that is far less centralized than the regime that resulted in California’s current successes?  The Commissioners acknowledged that they will need to examine the current business models for load-serving entities and determine whether they can achieve the state’s ultimate goals.

Among the topics discussed at the en banc was the issue of exit fees. In order to comply with California’s Renewable Portfolio Standard (“RPS”) mandate, IOUs procured renewable energy under power purchase agreements that are priced much higher than the current market.  As the IOUs’ retail load decreases, their RPS obligations similarly decrease, potentially leaving IOUs with highly-priced RPS contracts that are in excess of their RPS mandate.  Under the statute, implementation of a CCA cannot result in cost shifting between CCA customers and those customers choosing to remain with the IOU.  Thus, as these contracts were procured to serve customers who are now migrating to CCAs, arguably those costs should follow customers.  Other issues arise from potential “double procurement,” where CCAs procure renewable power for the same customers that IOUs have already signed long-term RPS contracts to serve.

The en banc consisted of four panels–a customer panel; a provider panel, consisting of distributed generation providers, direct access providers, and CCAs; a utility panel, and an industry expert panel. Though no clear answers emerged, the Commissioners will take the input from the meeting back to their respective Commissions as they address current and future proceedings dealing with the rapid expansion of retail choice.

MPUC Approves Multi-Year Rate Case Settlement, Opens Docket to Develop Performance Metrics

Yesterday, the Minnesota Public Utilities Commission (“MPUC”) approved a settlement between Xcel Energy and various intervening stakeholders, to resolve the revenue requirement issues in Xcel Energy’s pending multi-year rate increase.  The MPUC appeared to struggle with accepting the settlement in lieu of the full evidentiary record it is used to on financial issues.  Nonetheless, it ultimately agreed with stakeholders’ assessment that the deal was in the public interest, as well as an opportunity to break Xcel’s cycle of continuous rate cases over the last decade or so.

As part of the MPUC’s effort to get comfortable with the settlement, it resolved to open a new docket to develop and potentially apply performance metrics to Xcel Energy’s rates during the pendency of the approved multi-year rate increase.

In addition to approving the settlement, the MPUC addressed various revenue allocation and rate design issues.  With respect to revenue allocation, the MPUC deviated from prior practice of approving one class cost of service study (“CCOSS”), and using that MPUC-approved CCOSS as a starting point for revenue allocation.  Instead, the MPUC broadly commented on the various CCOSSs proposed by parties in the case and then chose a revenue allocation before any further in-depth discussion of the CCOSS or making any particular determination on the CCOSS.

The resulting table of increases by class for 2016 appears below:


Class Increased Revenue (000s) % Apportionment $ Increase (000s) % Increase
Residential $1,135,268 36.74% $63,812 5.96%
C&I Non-Demand $108,512 3.51% $3,063 2.90%
C&I Demand $1,818,873 58.86% $65,964 3.76%
Lighting $27,695 .90% $1,834 7.09%
Total $3,090,348 100% $134,673 4.56%


The MPUC further determined that the same percentage apportionment would be applied to the rate increases in 2017, 2018, and 2019. The MPUC then went on to rate design, making some minor changes to interruptible service and retained the existing residential fixed customer charges.  The MPUC concluded by making several specific determinations on the CCOSS.

A written order detailing the MPUC’s decision will follow.

Behind the Meter Energy Storage Gets a Boost in California

On April 6th, the energy storage market received a boost in California when state regulators authorized $196 million in new rebates for customers who install onsite (behind the meter) energy storage systems.


The change occurs under the California Self Generation Incentive Program (“SGIP”). SGIP provides a financial rebate to energy customers who install new qualifying technologies that meet all or a portion of the customer’s on-site electricity needs. Qualifying technologies include wind turbines, waste heat to power technologies, pressure reduction turbines, internal combustion engines, microturbines, gas turbines, fuel cells, and advanced energy storage systems.

SGIP was established in 2001 and has been one of the longest-running and most successful distributed generation incentive programs in the country.  As of December 2016, SGIP has funded 2,178 completed projects representing over 450 MW of rated capacity. An additional 312 projects representing over 178 MW of rated capacity are in process towards completion.

A Win for Behind the Meter Storage

In 2016, a new California law authorized an increase in the total SGIP budget from $83 million per year to $166 million per year. On April 6, the California Public Utilities Commission (“CPUC”) formally approved this increase for years 2017, 2018, and 2019, raising the total SGIP incentive budget authorized through 2019 to $566,692,309.

The big winner in the decision was the behind the meter energy storage market. The CPUC allocated 85% of the new funds toward energy storage projects, with the remaining 15% allocated to renewable generation projects. That means the California energy storage market will receive a boost of $196 million over the next three years. In terms of the specific details, 90% of the allocation for energy storage projects must be used for projects greater than 10 kilowatts (“kW”) in capacity, with the remaining 10% available for projects less than or equal to 10 kW.

The win reflects the intent of the SGIP program to facilitate the state’s achievement of climate change goals through driving transformation of the energy system. Specifically, the decision finds that as “the proportion of renewable electricity on the grid increases, energy storage can play an increasingly important role in meeting California’s climate goals… and [i]ncentive programs can help facilitate market transformation.” This type of thinking represents continued leadership by California in the field of energy storage policy.

Next Steps

Applications for the new SGIP funding will be accepted beginning on May 1, 2017. Applications can be submitted through a portal on the SGIP portal page available here.


BLM Directed to “Try Again” on NEPA Analysis for Echanis Wind’s Transmission Line: Greater Sage-Grouse Remains Key Issue for Project Development Despite USFWS Decision Not to List Under ESA

In the continuing saga of the Echanis wind project in Eastern Oregon, U.S. District Court Judge Michael Mosman on April 18 vacated the Bureau of Land Management’s (BLM)’s Record of Decision (ROD) on a right-of-way grant decision under the Federal Land Policy and Management Act for a 230-kV transmission line conveying power generated from the wind project proposed for development on private land on the north side of Steens Mountain. The wind project would include between 40 and 69 wind turbines near Diamond, Oregon.

The case was before Judge Mosman on remand from the Ninth Circuit, which instructed Judge Mosman to vacate the BLM’s ROD unless he found it advisable that the ROD remain in place. The Ninth Circuit’s 2016 opinion followed Judge Mosman’s initial decision to grant the BLM’s motion for summary judgment. Judge Mosman had ruled that the BLM had adequately considered the impact of the project on fragmentation and connectivity of sage-grouse habitat, but the Ninth Circuit’s decision reversed that decision based on its determination that the BLM’s environmental review under the National Environmental Policy Act (NEPA) did not adequately assess baseline sage-grouse data during winter at the proposed project site. Continue Reading