NARUC Accepting Comments on Draft Distributed Energy Resources Manual that Seeks to Guide Regulators Through Tricky Territory

The National Association of Regulatory Utility Commissioners (NARUC) recently issued a draft manual on distributed energy resources (DER) compensation to assist jurisdictions in navigating the challenges and policy considerations associated with this hot button issue. The release of the manual marks the first time NARUC has specifically weighed in on DER compensation issues.

DERs are generally smaller-scale electric generation facilities that are located close to customers and can be used to provide a portion or all of their immediate electricity needs, and can also be used by the distribution grid to reduce demand or increase supply. Examples of DERs include solar, wind, thermal, and storage technologies, among others.  Given their contrast to the traditional utility scale bulk electric generation model, state regulators across the country are struggling to determine how to appropriately compensate DERs.  The manual discusses the myriad questions associated with DER compensation, including the cost of integrating DERs with the grid, monetizing the benefits DER resources provide, and determining ownership of the resources.

Seeking to provide flexible advice to jurisdictions implementing DER compensation methodologies, the manual focuses on factors jurisdictions should consider in developing DER rates. It presents key questions for regulators to consider, including “What costs should be paid by DER and what should be recovered from base rates?” and “Does DER avoid utility infrastructure costs?” The manual also discusses the “divisive” issues of cost-shifting between users and non-users of DERs.

Compensation methodologies addressed by the manual include net energy metering (NEM); valuation methodologies, which include value of resource, value of service, and transactive energy; demand charges, fixed charges and minimum bills, standby and backup charges, and interconnection fees and metering charges. NARUC emphasizes that technological advances, such as advanced metering infrastructure, smart transformers, Advanced Distribution Metering Systems, and others can support the grid and integration of DERs, as well as accompanying DER compensation methodologies.

Stakeholders can submit comments on the draft manual by emailing, and comments will be accepted through September 2. The final version of the manual is expected in late November. A copy of the draft manual is available here (pdf).

Minnesota Power Requests Proposals for Wind; Solar, Demand Response & Customer Self-Generation to Follow

Minnesota Power released a Request for Proposals (RFP) yesterday for up to 300 MW of wind generation, with proposals due by September 7, 2016. A copy of the RFP and additional details are available at Minnesota Power also filed its press release with the Minnesota Public Utilities Commission (MPUC).

Minnesota Power will also release several more RFPs over the next few weeks for up to 300 MW of utility-scale solar generation and an unspecified amount of demand response and customer self-generation.

This series of RFPs comes on the heels of the MPUC’s Order issued last week approving and modifying Minnesota Power’s Integrated Resource Plan. The Order requires Minnesota Power to “initiate a competitive-bidding process to procure 100–300 MW of installed wind capacity” by the end of 2017. The Order also requires Minnesota Power to “acquire solar units of 11 MW by 2016, 12 MW by 2020, and 10 MW by 2025” and finds that “up to 100 MW of solar by 2022 is likely an economic resource for Minnesota Power’s system.” Minnesota Power must also “propose a demand-response competitive-bidding process within six months,” and “include a full analysis of all alternatives to natural gas, including renewables, energy efficiency, distributed generation, and demand response, for providing the energy and capacity sufficient to meet the Company’s needs” in its next resource plan. A copy of the Order is available here (pdf).

Minnesota Public Utilities Commission Approves Some Changes to Community Solar Program, Declines Other Changes

The Minnesota Public Utilities Commission (MPUC) approved several major changes to Xcel Energy’s Community Solar Garden (CSG) program yesterday, while also voting to maintain other aspects of the CSG program. Mike Hughlett of the Star Tribune has this report. The MPUC’s decisions are summarized below:

Bill Credit Rate

  • Declined to modify the Applicable Retail Rate at this time or take any action on further bill credit adders.
  • Decided to shift to the Value of Solar for CSGs submitted after next year, with some tweaks to lock in the inflation adjustment, weather normalization and include location specific avoided costs. The Department of Commerce is also tasked with determining whether there should be adders to the rate based on certain locational characteristics of the CSG or type of subscribers.

CSG Development

  • Retained the ban on co-location over 1-megawatt.
  • Eliminated the material upgrade limitation on interconnection.
  • Required Xcel to develop a CSG specifically for low-income customers by March 2017. Other proposals for increasing access for low-income customers are encouraged to file at that time as well.

Timeline for Completion

  • Extended the deadline for developers to complete CSGs by requiring that CSGs achieve Mechanical Completion within 24 months of Xcel finding the application Expedited Ready.
  • Broadened day-for-day extensions to include projects involved in Independent Engineering disputes with Xcel as well as other affected projects lower in the queue.
  • Required Xcel to provide, upon applicant’s request, written confirmation of the then-current Mechanical Completion deadline for an application, accounting for applicable day-to-day extensions.
  • Modified the definition of Force Majeure in the CSG tariff to extend the 24-month deadline by 6 months where there is a local government moratorium that prevents a CSG from obtaining a local permit, but excludes from the extension failure to seek a permit or other permitting delays.
  • Required projects that have been deemed complete but not expedited ready to become expedited ready in 60 days.

The MPUC declined to take action on consumer protection issues, such as how disclosures must be conveyed to subscribers, and will consider those issues at a later date.



What You Need to Know about the Proposed Revisions to California’s Cap and Trade Program

Late Tuesday, the California Air Resources Board (ARB) released draft amendments to California’s cap and trade regulation, including revisions to the current program in place through 2020, an extension of the program through 2030, and setting the stage for continued emissions reductions under the program through 2050. ARB’s proposed amendments come in the middle of a recent milieu of uncertainty:  pending litigation challenging the legality of the existing program, an opinion from the state Office of Legislative Counsel that ARB lacks authority under AB 32 to continue cap and trade past 2020, unprecedented weak demand at the most recent allowance auction, and legislation proposed in the California Senate to establish a statutory emissions reductions mandate for 2030 still in process this session.  With all of these balls in the air, ARB has doubled down and drafted regulations dropping the program’s emissions cap from 334.2 million metric tons (MMT) of CO2e in 2020 to 200.5 MMT in 2030, with major elements of the cap and trade regulation continuing in effect past 2020 to achieve the emissions reductions. Continue Reading

Eighth Circuit Panel Rules Minnesota Climate Change Law Unconstitutional

Today, the Eighth Circuit determined that the Next Generation Energy Act (“NGEA”), a Minnesota law that established power sector standards for carbon dioxide emissions, was unconstitutional (decision available here). In so doing, the Court affirmed the decision of District Court Judge Susan Nelson, whose 2014 decision we covered in “Court Declares Minnesota Coal Law Unconstitutional: Electrons Favor the Laws of Physics to Those of Governments.”

However, the Eighth Circuit panel arrived at Judge Nelson’s conclusion by a different route. Only one member of the panel – U.S. Circuit Judge James Loken – explicitly agreed with Nelson that the NGEA violated the dormant Commerce Clause. Judge Loken found that the NGEA’s “broad prohibitions plainly encompass non-Minnesota entities and transactions” and “regulate activity and transaction taking place wholly outside of Minnesota” because “when a non-Minnesota generating utility injects electricity into the MISO grid to meet its commitments to non-Minnesota customers, it cannot ensure that those electrons will not flow into and be consumed in Minnesota.  Likewise, non-Minnesota utilities that enter into power purchase agreements to serve non-Minnesota members cannot guarantee that the electricity eventually bid into the MISO markets pursuant to those agreements will not be imported into and consumed in Minnesota.”

By contrast, Judge Murphy disagreed with Judge Loken’s extraterritoriality analysis while Judge Colloton never even reached the dormant Commerce Clause question. Judge Murphy reasoned that because the NGEA’s importation prohibition “bans contracts for power from new large power plants, it thus bans wholesale sales of electric energy in interstate commerce” in direct contravention of the Federal Power Act’s grant of exclusive jurisdiction over “the transmission of electric energy in interstate commerce” to the Federal Energy Regulatory Commission.  Meanwhile, Judge Colloton reasoned that, “[b]y demanding offsets or allowance purchases from a North Dakota energy facility as a condition for contracting to provide power to Minnesota customers, Minnesota’s statute conflicts with the regulatory scheme that Congress designed in the Clean Air Act,” which allows each state to regulate emissions from sources within its borders through State Implementation Plans.

Since the panel was divided on the application of the dormant Commerce Clause to the NGEA, the permissible scope of state regulation of the energy sector remains uncertain. The concurrences in today’s decision in the Eighth Circuit add additional complexity and uncertainty by asserting that Minnesota’s law may be in conflict with the Clean Air Act or preempted by the Federal Power Act. In addition, and with respect to the question of whether state energy policy may run afoul of the extraterritorial doctrine of the dormant commerce clause, the Tenth Circuit recently came to a different conclusion in the face of a similar challenge to Colorado’s renewable portfolio standard (the Tenth Circuit decision can be found here). While the ultimate outcome is uncertain, the Eighth Circuit decision is sure to spark continued discussion and debate. Watch this space for updates as these issues move forward.




MN Court of Appeals Upholds PUC’s Community Solar Order

The Minnesota Court of Appeals filed its decision today affirming the Public Utilities Commission’s August 6, 2015 Order in the community solar garden proceeding, which adopted the partial settlement agreement between certain solar developers and Xcel Energy and decided several crucial aspects of Xcel’s community solar program, including the 5 MW cap on co-located gardens.  Sunrise Energy Ventures, LLC, a major developer in the community solar program, argued on appeal that the Commission engaged in improper and unlawful rulemaking, violated due process, and acted contrary to the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Court of Appeals rejected each of Sunrise’s arguments. The Court found that the Commission had not engaged in rulemaking in its Order, but rather had made reasonable determinations consistent with the statute to modify the program in light of the “overwhelming response” of developers. The Court also found that the reservation letter between the developer and Xcel is not an enforceable contract and cannot serve as the basis for a substantive due process claim, and that the Commission did not violate Minnesota’s open-meeting law by taking a break to “talk to staff” and then immediately voting to adopt the co-location cap. Finally, the Court concluded that the Commission did not violate PURPA by allowing Xcel to refuse interconnection for a community solar garden that would require upgrades over $1 million, because Xcel’s Section 10 tariff already offers developers the ability to interconnect pursuant to PURPA.

Sunrise has 30 days to seek review of the decision from the Minnesota Supreme Court.

U.S. Fish and Wildlife Service Issues Proposed Changes to Eagle Permit Regulations, Opens 60-Day Comment Period

Today the U.S. Fish and Wildlife Service (Service) published notice in the Federal Register of proposed changes to its eagle permitting regulations (Proposed Rule).  Concurrent with the Proposed Rule, the Service issued a Draft Programmatic Environmental Impact Statement (DPEIS) analyzing the proposed changes under the National Environmental Policy Act (NEPA), and a Status Report that estimates size, productivity, and survival rates for bald and golden eagles, and provides recommendations on authorized take limits.  The Service is accepting comments on the Proposed Rule and the DPEIS until July 5, 2016.

Although we are still in the process of evaluating the entire package, the proposed changes represent a significant step forward for applicants seeking regulatory certainty through the eagle permitting process. Here’s a quick snapshot of the proposal:

(Re)extends maximum permit term to 30 years.  As we discussed in a previous post, in August 2015, the U.S. District Court for the Northern District of California set aside the 30-year tenure provision of the 2013 revisions to the eagle permit regulations on NEPA grounds, concluding that the Service had failed to demonstrate an adequate basis in the record for deciding not to prepare an Environmental Impact Statement or Environmental Assessment.  The Proposed Rule, now backed by NEPA analysis that evaluates the 30-year maximum term, once again extends the maximum term for eagle take permits from five to 30 years, subject to recurring five-year check-ins.  In the Federal Register notice, the Service acknowledges that the “5-year maximum permit term is unnecessarily burdensome for businesses engaged in long-term actions that have the potential to incidentally take bald or golden eagles over the lifetime of the activity.” Continue Reading

Stoel Rives Partner Jon Wellinghoff to Join SolarCity as Chief Policy Officer

I just wanted to pass along word to readers that Stoel Rives partner and Renewable + Law blog author Jon Wellinghoff will be leaving us to join SolarCity as their new Chief Policy Officer. Read SolarCity’s  official announcement. We’ve enjoyed working with Jon as a member of the Stoel Rives Energy Team. We’d like to wish him the best of luck in his new endeavor and look forward to continuing to work with him when he joins our client, SolarCity. He’s joining the company at a significant moment in the solar industry’s development. As Elon Musk just tweeted yesterday, SolarCity customers recently produced enough energy in one day to charge every Tesla in the world.

Developer Requests Clarification of Minnesota PUC’s Community Solar Garden Order

Minnesota solar developer SolarStone Partners, LLC filed a Motion for Clarification of the Minnesota Public Utilities Commission’s September 2014 Order Approving Solar-Garden Plan with Modifications. Specifically, SolarStone is requesting clarification of the Commission’s interpretation of the requirement in the Community Solar Garden Statute that a project must be located within the utility’s service territory. One of SolarStone’s community solar garden projects planned in Chisago County is primarily located within Xcel Energy’s service territory, but a small portion of the project protrudes outside of Xcel’s territory. Because the project is not entirely within its territory, Xcel declined to advance the project through the interconnection process. SolarStone argues that its project is compliant with the program because its points of interconnection/common coupling are within Xcel’s territory. We will update this story as it develops. A copy of SolarStone’s Motion is available here (pdf).

Oregon legislators pass historic renewable energy bill, with 50% RPS and coal-fired electricity phaseout

Oregon legislators passed Senate Bill (SB) 1547 into law yesterday, creating aggressive timetables for eliminating coal-fired electricity from the State and setting a 50% Renewable Portfolio Standard (RPS) by 2040. A diverse group of utilities, consumer advocacy organizations, and renewable energy advocates support the bill.  Next stop for SB 1547 is Oregon Governor Katherine Brown’s desk, where she is expected to sign the bill into law.

Key provisions and significance of SB 1547 include:

50% RPS by 2040

Oregon’s two largest utilities – PacifiCorp and PGE – will have a 50% RPS standard by 2040, meaning 50% of their electricity supply must be derived from renewable energy sources. The two largest utilities serve approximately 70% of Oregon customers’ electricity needs. There was no change to the existing requirements on consumer-owned utilities.

  • This is one of the most aggressive RPS standards in the nation, matched only by California and New York, which have a 50% target by 2030, Vermont, which has a 75% target by 2032, and Hawaii, which has a 100% target by 2045.
  • The existing ratepayer protections relating to RPS compliance were retained, capping the incremental costs of compliance at 4% of the utilities annual revenue requirement for a compliance year. A new provision was added to permit the Oregon PUC to temporarily suspend RPS compliance if the utility determines that grid reliability is seriously compromised.
  • The Oregon PUC will implement competitive bidding rules governing electric companies’ RPS implementation plans to ensure that electric companies acquire electricity from diverse renewable energy generators.

Continue Reading