Interconnection Modernization Underway in Minnesota

In a recent order from the Minnesota Public Utilities Commission (the “Commission”), Minnesota took a big step to update the state’s interconnection process and standard interconnection agreement for distributed energy resources or “DERs.” This ongoing process relates to Minn. Stat. § 216B.1611 which directs the Commission to establish generic standards for utilities’ tariffs that govern the interconnection and parallel operation of distribution generation with a capacity of up to ten megawatts (“MW”). Minnesota’s original DER standards, which date back to 2004, were forward-looking at the time but have become outdated as technology has advanced and deployment of DERs (especially solar) has exploded.

Citing the evolution of national best practices for interconnection, a group of DER advocates filed a request to update the Minnesota interconnection standards in 2016. The process was largely broken into two distinct topics: the Distributed Resources Interconnection Process and the Distributed Energy Resource Interconnection Agreement that were explored by stakeholder working groups. The process was also broken into two phases: Phase I is the Commission update to the interconnection process, application, data submittal and agreement and Phase II is the Commission update of the technical requirements for interconnection. As part of Phase I, the Commission issued proposed updates to the process and form agreement, and a notice of comment on the proposed updates. After multiple rounds of comments and another draft from the Commission, the Commission adopted updates to standards for the DER interconnection process and the standard form interconnection agreement in a major step for Phase I of the overall process in an order published August 13, 2018.

The following are some of the updates and improvements made to Minnesota’s current DER interconnection procedures:

  • Customers have the option to request a pre-application report with location-specific information;
  • Language has been included to ensure that utilities maintain an orderly queue of interconnection applications, and utilities with large amounts of applications employ a public data queue;
  • “Fast track” processes for facilities within specified capacity thresholds and defined screening criteria to expedite review for smaller projects;
  • Improved communications procedures including electronic applications; and
  • New financial provisions including fee caps based on facility size and type of review.

The Commission set June 17, 2019 as the effective date for the new rules and required rate-regulated utilities to file updated tariffs. Xcel Energy, which has by far the most installed DERs on its system in the state via its community solar garden program, will propose a transition process for that program to the new interconnection standards in its compliance filing. Stakeholders are also continuing to work through updating technical issues in Phase II of this process. Engineers are scheduled to meet on September 29, 2018 in preparation for Phase II.

Finally, in addition to further work on technical standards, DER advocates filed a related petition earlier this year to update the state’s guidelines for the rates paid by electric utilities for DERs 10 MW and smaller. The petitioners argued that, like the DER interconnection standards the Commission is updating, the current DER rates (which are low) are outdated and ripe for review. The Commission recently issued a notice of comment period on this topic, with initial comments due September 19, 2018. If the Commission decides to update its guidelines for the financial relationship between utilities and DER customers, the updated rates and interconnection standards could together offer significant new opportunities for DERs in Minnesota.

Could voluntarily performing environmental cleanup threaten insurance coverage?

This post was guest authored by Stoel Rives summer associate Nina Neff.

Because of the increasing frequency of significant, often multimillion-dollar, environmental claims against businesses and individuals under environmental statutes such as the Comprehensive Environmental Response, Compensation and Liability Act, it is important for any potentially liable entity to fully explore how the costs may be shifted in whole or in part to others. Washington insurance law has traditionally been highly favorable to policyholders, broadly interpreting the insurer’s duty to defend so that remedial investigation costs are covered under the insurer’s duty to defend. Washington’s law has had important benefits for individuals and public and private entities, who without insurance coverage may be bankrupted by cleanup liability, and has also benefited taxpayers and the general public by promoting prompt cleanups. Continue Reading


On June 21, 2018, the United States District Court, District of Minnesota issued an order and memorandum rejecting a challenge to the constitutionality of Minn. Stat. § 216B.246 and granting defendants’ motions to dismiss. The statute, which was enacted after FERC Order 1000 (and eliminating the federal right of first refusal or “ROFR”), provides incumbent electric utilities with the ROFR to build and own electric transmission lines that connect to their existing facilities (thereby creating a State ROFR).  The suit was initiated by LSP Transmission Holdings (“LSP”), alleging that Minn. Stat. § 216B.246 violates the dormant Commerce Clause of the United States Constitution, claiming that the statute facially discriminates, or discriminates in purpose or effect, against interstate commerce regarding the ownership and construction of large transmission facilities.  Defendants moved to dismiss under Rule 12(b)(6) of the Federal Rules of Civil Procedure.

Defendants contended that the U.S. Supreme Court’s decision in Gen. Motors Corp. v. Tracy, 519 U.S. 278, 287 (1997) (“Tracy”) was dispositive, thereby foreclosing LSP’s discrimination claims. In that case, the Supreme Court analyzed a state statute that provided tax exemptions on retail sales to in-state regulated public utilities and denied the exemptions to interstate transmission companies. In upholding the state statute, the Supreme Court recognized that discrimination only exists where two entities are similarly situated.  The Supreme Court concluded that in-state regulated utilities and out-of-state entities were not similarly situated because they did not compete. The Court largely accepted this rationale and the underlying policy arguments and adopted the Tracy opinion, noting that:

[T]he Court grants controlling weight to the monopoly market. Minnesota is entitled to consider the effect on the public utilities and the consumers that the utilities serve and “to give the greater weight to the captive market and the local utilities’ singular role in serving it.”…The reasons cited in support of giving greater weight to the monopoly market in Tracy apply here; namely to avoid any jeopardy or disruption to the service of electricity to the state electricity consumers and to allow for the provision of a reliable supply of electricity.

In addition to the Tracy analysis, the Court also concluded that Minn. Stat. § 216B.246 does not overtly discriminate against out-of-state entities. It stated that the statute “affords companies whose facilities will connect to new transmission lines the first chance to build a new line. The statute’s preference does not apply to all incumbent electric transmission owners, but only to those directly connected to the proposed line.”  The Court also addressed and refuted LSP’s assertions that Minn. Stat. § 216B.246 fails the balancing test set forth in Pike v. Bruce Church, Inc., 397 U.S. 137, 142 (1970).

We will continue to cover additional developments and any appeals in this case.

China’s Renewable Policy Shift and its Global Implications

On June 1, 2018, only two days after the completion of 12th SNEC International Photovoltaic Power Generation Conference, the world’s biggest solar conference and a central gathering of all the Chinese PV manufacturers, the Chinese central government announced a nation-wide solar subsidy cut that resulted in the Chinese solar stocks tumbling with the falling range from 7% to 31%.[1]  Specifically, the National Development and Reform Commission, the Ministry of Finance and the National Energy Administration of China issued the “2018 Solar PV Generation Notice” (the “Notice”)[2], imposing caps and reducing the feed-in tariff (“FiT”) mechanism in connection with China’s domestic PV projects[3], and at the same time setting rules at the central government level to urge marketization of China’s solar industry.[4]

Overview of the Notice


Imposition of Project Cap

Firstly, the Notice imposed a 10 GW cap on capacity for distributed generation projects and stopped utility-scale project for 2018. This is a steep drop from last year’s installation of 19 GW distributed generation projects (out of 53 GW of all PV projects in China).[5] Also, the Notice provided that only those distributed generation projects that are connected to the grid no later than May 31, 2018 would be covered by central government’s budget, whereas the financial responsibility for other distributed generation projects would be shifted to local governments.[6]  In addition, the Notice encouraged the local governments to come up with more solar supportive policies, to reduce non-technological costs, and as a result to reduce the needs for central and local governments’ solar subsidies.[7]  Separately, the Notice abolished the utility-scale projects and instructed local governments not to approve any utility-scale projects until central government’s further notice.[8] Continue Reading

California Approves $768 Million for EV Infrastructure

The California Public Utilities Commission (“Commission”) voted recently to approve $768 million in expenditures for electric vehicle infrastructure programs proposed by the state’s three investor-owned utilities (“IOUs”). The programs are part of a directive of SB 350 that requires utilities to undertake transportation electrification activities.

Here is a brief overview of the approved programs:

  • Approved at $137 million, SDG&E’s program provides rebates to up to 60,000 residential customers that install Level 2 (“L2”) charging stations, which refer to electric vehicle supply equipment (“EVSE”) connected to a 240-volt outlet.
  • PG&E was approved for $22 million to install make-ready infrastructure to support 234 fast charging stations, as well as $236 million to support 6,500 medium- or heavy-duty EVs (like electric buses and trucks).
  • SCE similarly received approval for $343 million to install make-ready infrastructure to support 8,490 medium- or heavy-duty EVs.
  • In addition, the Commission approved $29.5 million for program evaluation.

Here is our analysis of what the Commission’s order means for the future of EVs and what the industry should be paying attention to:

In terms of charging technology, 150 kW fast charging and residential L2 are the minimum.

The Commission’s order emphasizes the need to use up-to-date technology to ensure some longevity for the investments. For example, in response to PG&E’s proposal for three levels of fast charging stations, the Commission directed the utility to forgo the lowest level and only install customer-side electric infrastructure necessary to support EVSE of 150kW or larger, approving a 25% contingency due to the increased cost of the faster chargers. Additionally, the Commission also noted that participants in rebate programs will be responsible for the full cost of proprietary made-to-order EVSE and make-ready infrastructure, since these are not scalable and may result in stranded assets should the manufacturer go out of business or change technology. In the case of SDG&E’s program, the Commission sided with the utility over concerns raised by stakeholders that Level 1 charging (which uses a standard household 120-volt outlet) is sufficient for residential purposes. SDG&E argued that the more advanced L2 will provide grid benefits by allowing for managed charging when paired with time-variable rates that reflect grid conditions. The Commission also noted the ability of these chargers to provide valuable data on patterns of charging. Continue Reading

Energy Storage Is Coming to New Jersey

The New Jersey legislature recently passed a bill (the “Bill”) that would set a goal of reaching 600 megawatts of energy storage capacity by 2021 and 2 gigawatts by 2030.[1] This represents one of the largest energy storage implementation goals in the country and likely signals the coming of a large new market for energy storage.

The Bill requires the Board of Public Utilities (“BPU”), with PJM Interconnection’s consultation, to conduct an energy storage analysis covering a wide range of practical implementation issues for bringing storage onto the grid. This including how to best implement energy storage systems in New Jersey, if any additional technologies need to be deployed and any associated costs for optimal implementation, and how distributed energy resources could be incorporated into electric distribution system effectively.[2]  BPU will have one year from enactment of the Bill to submit a report to the Governor and the legislature laying out the analysis results as well as New Jersey’s needs and opportunities with regards to energy storage.[3] Within six months after completion of the report, BPU is then required to initiate a proceeding to establish a mechanism for achieving the goals.[4]

In addition to the new energy storage goals, the Bill would also establish a 50% renewable energy standard by 2030, adopt “Community Solar Energy Pilot Program,” and provide tax credits for certain offshore wind energy projects, among other things.[5]



[1] Assembly No. 3723 State of New Jersey, 218th Legislature, introduced March 22, 2018, available at (last visited April 19, 2018).

[2] Id. at 1-2.

[3] Id. at 2.

[4] Id.

[5] Id. at 34-36.


On May 9, 2018 the Minnesota Public Utilities Commission issued an order approving Xcel Energy’s residential electric vehicle (“EV”) pilot program (the “Pilot”), designed as an alternative to Xcel’s existing EV tariff, concluding that the Pilot will “benefit all ratepayers by aiding Xcel in its efforts to integrate EV load as cost-effectively as possible.” A full copy of the Commission’s order is available by clicking here.

By way of background, Xcel petitioned the Commission for approval of the Pilot after receiving consumer feedback on Xcel’s initial residential EV tariff filed in January 2015 pursuant to Minn. Stat. § 216B.1614. Under the initial EV tariff, the typical residential customer paid approximately $1,725 to $3,525 to enroll due to various costs including: wiring, installation of additional meters, and electric vehicle supply equipment (“EVSE”). Consumer feedback to Xcel that these costs were simply too high.

Under the Pilot, consumers’ barrier to entry complaints are addressed by employing the use of EVSE that sends usage data to the utility via the customer’s home wireless network, removing the need for an additional meter. Because EVSE transmits customer data through a wireless connection, customers may be wary of data privacy issues. In an attempt to remedy these concerns, the Commission requires that Xcel immediately notify customers of any unauthorized access to data obtained through this Pilot.

As an additional attempt to make the Pilot more accessible, Customers now have the option to pay for the EVSE over a period of time which also reduces initial costs. participants may elect to pay for EVSE through either a monthly customer charge included in a “bundled service” rate option, or under a “prepay” option. Under the “bundled service” option the monthly customer charge will be no higher than $19 and the “prepay” monthly customer charge no higher than $8. Xcel also negotiated with several vendors to supply and install EVSE to further ease the cost of entry. Lastly, like Xcel’s existing EV tariff, the Pilot offers a lower per-kilowatt-hour (“kWh”) rate during off peak hours.

As for accounting treatment, Xcel requested and received Commission approval for it to own all EVSE during the term of the pilot program, to capitalize the EVSE costs as distribution plant, and to earn a return upon the capitalized amounts. Xcel also received approval for recovering a carrying charge on the unpaid balance of the EVSE purchase price in the case of bundled service. These costs, as well as the costs of customer-outreach initiatives, will be recovered in the communications-cost tracker account under Xcel’s existing EV tariff.

Xcel will submit compliance filings by June 1, 2019, providing the Commission with data related to the Pilot. In other words, more to come.  But not just in this docket.

Also issued by the Commission on May 9 was a Notice of Comment Period in Commission Docket No. CI-17-879, which is the miscellaneous docket where the Commission seeks to gain more understanding of: (1) the possible impacts of EVs on the electric system, utilities, and utility customers, including the potential electric system benefits; (2) the degree to which utilities and utility regulatory policy can impact the extent and pace of EV penetration in Minnesota; and (3) possible EV tariff options to facilitate wider availability of EV charging infrastructure. The Commission’s Notice of Comment Period may be accessed here.

Arbitration Clauses in Solar Contracts

This month, a panel of the New Jersey Superior Court, Appellate Division, ruled that a proposed class action brought by customers of a solar energy company was subject to arbitration. The case, Brian and Ananis Griffoul v. NRG Residential Solar Solutions, LLC, Dkt. No. A-5536-16T1, alleged fraudulent marketing under the New Jersey Consumer Fraud Act as well as violations of the state’s Truth-In-Consumer Contract Warranty and Notice Act.

The defendant, NRG Residential Solar Solutions, LLC, responded to the lawsuit with a motion to compel arbitration and to dismiss the claims with prejudice. The trial court judge originally sided with the plaintiffs, finding the case analogous to Atalese v. U.S. Legal Services Group, L.P., 219 N.J. 430, 435 (2014), which found an arbitration clause unenforceable because it failed to clearly and unambiguously state that consumers were waiving their right to seek relief in court. Specifically, in Atalese, the court held the arbitration clause failed to state that consumers were waiving their right to seek relief in court by agreeing to the arbitration clause.

But the appellate court in Griffoul reversed, premising its holding on the arbitration clause’s clear and unambiguous language. It found the arbitration clause expressly “announced” that any dispute was subject to arbitration; that arbitration was the “sole and exclusive remedy”; and “clearly stated the parties were waiving the right to a jury trial.” Importantly, the appellate court also found–unlike the trial court–that the arbitration clause “clearly” limited claims brought in arbitration to individual claims, therefore barring a class action in arbitration.

Griffoul brings more certainty and clarification to the law. When considered alongside Atalese, it underscores the critical importance of using clear language, which unambiguously announces to consumers that any potential claim is subject to arbitration and that they are waiving their right to seek relief in court.

Helping the Hook-Up: FERC’s Generator Interconnection Procedures Reform Seeks to Improve Information Flow, Recognizes Changing Technology and Opens Further Opportunities for Storage

The Federal Energy Regulatory Commission’s (“FERC”) long-awaited Order 845 (Reform of Generator Interconnection Procedures and Agreements) was issued on April 19 after over two years of consideration of the issues. Order 845 is the first grid-wide major reform of FERC’s Generator Interconnection Procedures and Agreements since Order 2003 was issued 15 years ago.  Order 845 adopts reforms that are designed to address three goals: (1) improving certainty for interconnection customers, (2) promoting more informed interconnection decisions, and (3) enhancing the interconnection process.

Order 845 revises FERC’s pro forma Large Generator Interconnection Procedures (“LGIP”) and Large Generator Interconnection Agreement (“LGIA”) to recognize the changing landscape of technology and is intended to provide interconnection customers with new opportunities to interconnect their projects faster and more cost-effectively.  For example, transmission providers must now allow interconnection customers (at the interconnection customer’s option) to build the needed transmission owner interconnection facilities and stand-alone network upgrades in all cases. Previously, interconnection customers only had this option if the transmission owner could not meet the dates proposed by the interconnection customer.  Thus, an interconnection customer has newly granted flexibility in the construction of the transmission owner interconnection facilities and stand-alone network upgrades. If the transmission owner returns a high cost estimate, then the interconnection customer can manage the construction of the transmission owner interconnection facilities. On the other hand, if the transmission owner cost estimate is reasonable, the interconnection customer can choose to leave the construction responsibilities for the transmission owner interconnection facilities and stand-alone network upgrade with the transmission owner. Interconnection customers can now make these decisions based on both timing and cost considerations.

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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. Legislators have been busy moving bills through the legislative process since reconvening from the spring recess. Below is a summary and status of bills we have been following.

An enrolled bill is one that has been through the proofreading process and is sent to the Governor to take action. A two-year bill is a bill taken out of consideration during the first year of a regular legislative session, with the intent of taking it up again during the second half of the session.

  • Since our last update, the Governor has vetoed one bill and signed the others that were sent for approval earlier this session.
  • Several bills we previously reported on have become two-year bills, but without much movement in this second half of the session.
  • Several new bills have been introduced that are currently going through the process of amendments and hearings. 


Bills Passed Since Last Update


SB 549 (Bradford, D): Public utilities: reports: moneys for maintenance, safety and reliability.
STATUS: Approved by Governor September 25, 2017.

  • Existing law places various responsibilities upon the CPUC to ensure that public utility services are provided in a manner that protects the public safety and the safety of utility employees.
    • SB 549 requires an electrical or gas corporation to annually notify the CPUC each time that capital or expense revenue authorized by the CPUC for maintenance, safety or reliability is redirected for other purposes, and requires the CPUC to make the notification available to the Office of Safety Advocate, Office of Ratepayer Advocates, and to the service list of any relevant proceeding.

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