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.

Continue Reading

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.

Continue Reading

5 Key Takeaways from FERC’s Recent Energy Storage Order

In February, FERC issued Order 841, Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators (the “Order”), requiring RTOs and ISOs to establish new market participation rules for energy storage that recognize the physical and operational characteristics of these resources. While the Order set forth some minimal requirements that each RTO/ISO must meet when proposing market rules, the Commission also left considerable flexibility for each RTO/ISO in implementation.

A number of ISOs/RTOs submitted motions for clarification and requests for rehearing in March, and last Friday, April 13 FERC issued a tolling order to allow for more time to consider these motions and requests. As we await FERC’s response, here are our five key takeaways from the Order as it currently stands:

  1. New Revenue Opportunities for Storage. With the Order, there is now a pathway for energy storage to be able to participate in wholesale markets on something like a level playing field with other resources. Market rules, for example, will now need to include storage-specific bidding parameters such as state of charge and allow for market participation of storage assets as both supply and demand resources. For the storage industry, this can open up new opportunities for multiple revenue streams in the Capacity, Energy, and Ancillary Services markets. At the same time, storage resources will not be precluded from participating in existing programs, such as demand response. The end result is that, in markets with existing programs, storage resources will now have more options for participation.
  2. Market Access Does Not Always Lead to More Storage Projects. Opening the door for storage participation is not the same as saying more storage will be built. Like any energy project, it can be hard to finance storage in the absence of fixed revenue contracts. Today, state procurement mandates are largely driving the storage market and how much more storage will be built on the basis of wholesale market access is hard to predict. This will depend in part on how energy storage companies choose to compete in wholesale markets, and whether accessing multiple revenue streams is possible. This will especially be true if wholesale energy prices alone do not make a project cost-effective.
  3. The ISOs/RTOs Are Generally Supportive of the Order, But Have Sought Further Guidance. A number of the ISOs/RTOs submitted motions for clarification on certain implementation issues. These were generally supportive of the overall direction of the Order, and asked for clarifications related to applicability in their specific markets and their role in implementation when there could be overlap with state authority. Reading the tea leaves suggests that while the ISOs/RTOs have already begun to consider these issues in the context of their unique regions, the interaction with state jurisdiction at the distribution level and the opportunity to participate at both wholesale and distribution level will be key to driving more storage procurement. Following the Order, we can also expect new voices in ISO/RTO stakeholder proceedings that will address the technical capabilities of new technologies.
  4. Compliance Filings Are Due in December, But Expect Some Delays. Compliance filings are due December 3rd of this year. While FERC stated that the Order’s allowance for as much regional flexibility as possible is intended to assist in meeting the compliance and implementation deadlines, it is unclear whether RTO/ISOs will have enough time to initiate robust stakeholder initiatives. Especially in markets with no existing programs, unforeseen stakeholder issues could slow down the process. MISO has already requested a 6 month extension in consideration of this time crunch as it relates to the distributed energy resource technical conference held last week.
  5. Individual ISO/RTO Stakeholder Processes Will Be More Important to Track. Once FERC responds to the motions for clarification, the ISOs/RTOs will be working on implementation details. It will be important to follow each one to see how unique details play out in each ISO/RTO region. For example, in light of MISO’s motion, we anticipate new storage market participation rules that go beyond FERC’s Order to address issues specific to distributed energy resources. The CAISO will be another one to watch, though their filings have stated that they already largely comply with the requirements of the Order, because of their recently identified operational issues associated with high levels of renewable integration and the opportunities storage can provide to solve them.

Check back here for updates as implementation of the Order progresses over the rest of the year.

California May Need up to 2,000 MW of New Battery Energy Storage Resources by 2030, Commission Finds

On February 8, 2018, the California Public Utilities Commission (“CPUC”) adopted a new procurement process in a decision which suggested that 2,000 MW of new battery energy storage resources may be needed in California by 2030. This means an additional 2,000 MW of storage on top of the existing 1,325 MW that is already required.

The new integrated resource planning process included modelling to explore the optimal energy resource portfolio designed to meet a greenhouse gas emissions planning target at the lowest possible cost while maintaining system reliability. This portfolio will be updated every two years. Each utility will need to file a procurement plan that either aligns with the optimal portfolio or explains the reasons for deviating from the optimal portfolio.

Here is an illustration of the new resources called for by the decision:

Here are the key things to keep in mind:

First, this calls for additional resources, on top of what is required by existing programs. This means grid planners see the need for an additional 2,000 MW of new battery energy by 2030 to allow the state to meet its policy goals. As shown, this also anticipates the need for substantial quantities of new utility-scale solar resources (9,000 MW) and in-state wind resources (1,100 MW).

Second, this refers to the need for battery energy storage resources, as distinguished from other types of energy storage technologies. In California, the largest source of energy storage other than batteries is in the form of pumped hydroelectric energy storage.

Third, this portfolio will change over time, as each two year cycle will revisit the models and adjust the optimal resource mix. However, the portfolio shown here represents a snapshot of what resource planners see as the future of California’s energy mix as of today. And as you can see, this points to a future that is heavily reliant on new battery storage resources.

Solar PPA Provider That Only “Arranges” Installation of System It Owns Is Not a “Contractor” in California

In the recently issued but unpublished decision Reed v. SunRun, Inc. (Los Angeles County Super. Ct. No. BC498002, Feb. 2, 2018), the Second District Court of Appeal ruled that a solar power purchase agreement (“PPA”) provider that only sells solar energy to homeowners is not required to be a licensed California contractor under certain circumstances. Specifically, the court held that where the PPA provider “arranges” installation by a licensed contractor of the solar energy system (“system”) installed on the homeowner’s house but the PPA provider retains ownership of the system and sells the electrical output from the system to the homeowner, the PPA provider does not need to be a licensed contractor.

This ruling is good news for PPA providers in the state, whether they are marketing PPAs for residential or commercial property owners. Further, the ruling does not harm homeowners or other property owners or otherwise run afoul of the regulatory purpose of the Business and Professions Code (“BPC”) where the actual physical installation of the system must still be performed by qualified licensed contractors. This decision, if published, would also benefit the state by the further refinement of several California decisions that otherwise seem to restrict “arrangers” unless they carefully craft their contracts and actual activities within a narrow aspect of non-construction services.

The facts leading to the SunRun decision are familiar to lawyers involved with clients in both the energy sector and the heavily regulated licensing scheme under California law: SunRun sought to facilitate the use of solar in California through a PPA structure that enables homeowners to purchase energy from SunRun-owned solar systems installed on the homeowners’ rooftops. SunRun itself was not a licensed contractor prior to February 2012, but worked with a number of licensed contractors for the installation of the systems. SunRun and a licensed contractor would 1) visit the home and evaluate what was optimally required for the system, 2) the contractor would present a design to the homeowner for approval, 3) the contractor would install the system (using SunRun’s “best practices” and SunRun’s modular parts), 4) SunRun would retain ownership of the system (including maintenance and insurance obligations), 5) the homeowner would agree to buy energy from SunRun for 20 years, with an option to buy the system during that time, and 6) if the homeowner breached the agreement, SunRun had reserved its right to remove the system (which would take about one day). SunRun’s agreement with the homeowner provided that SunRun would “arrange for the design, permitting, construction, installation and testing of the” system, but specified that a separate contractor would “furnish all installation and construction services” and that separate contractor was to be “solely responsible” for all aspects of the installation related to construction. Although SunRun could refuse to pay a contractor if the installation was not satisfactory, the approval was fairly superficial and cursory, taking “15 seconds to two minutes.” SunRun did not oversee installation nor was it physically present at the installation sites.

In August 2011, Reed contracted to purchase power from SunRun pursuant to a PPA styled as a “Solar Power Service Agreement.” Reed made only four of the monthly payments under the PPA and then sold his home. The new owner assumed the SunRun agreement. Later in January 2013, Reed sued SunRun and sought to certify a class on the grounds that SunRun was an unlicensed contractor and engaged in unfair competition. Although abandoning the “solar energy claims” and not pursuing the subclass he originally asserted, Reed still sought to pursue the contractor license violation allegations. Motions for summary adjudication/judgment followed by SunRun in 2014 and 2016. Relevant to the license analysis, in April 2016 after further discovery, the trial court ruled that SunRun was not a “contractor” under BPC 7026 because 1) it “did not direct or supervise its licensed installers’ work at any job site” and any approval was limited “exclusively to ensur[ing] the local designer and installer’s design matched the agreement,” and (2) even if SunRun were a contractor, it fell within the exception under BPC 7045 for a finished product that was not a fixed part of the home. An appeal by Reed followed.

On appeal of that aspect of the ruling, the appellate court affirmed in full the trial court’s determination. Importantly for those navigating California’s licensing regulations was the court’s reiteration of the public policy undergirding the BPC, while yet noting that the penalties that Reed sought to enforce hinged on whether or not SunRun was a “contractor” under BPC 7026. The court emphasized that a “contractor” historically had to 1) actually perform construction services, 2) supervise the performance of services, or 3) agree by contract to be “solely responsible” for construction services. Citing The Fifth Day, LLC v. Bolotin (2009) 172 Cal.App.4th 939, 947-950, the court stated that “[h]owever, a license is not required if a person merely coordinates construction services performed by others.” Rejecting Reed’s counter arguments outright, the court did not find it necessary to reach the alternative ground ruled upon by the trial court: whether SunRun’s system was within the non-fixture exception to licensing under BPC 7045.

Another helpful element of this lengthy litigation, although not at issue on appeal, was the initial motion for summary adjudication by SunRun in February 2014 where the trial court ruled that the applicable statute of limitations under BPC 7031 was one year. As the trial court succinctly stated:

This statute imposes forfeitures. The contractor’s work can be perfect and the client delighted. Then there would be neither damages nor any equitable basis for compensation or a remedy. Yet the legislature put in this provision to get contractors’ attention: get your license, or else. It is the financial equivalent of flogging. That is simple and harsh by design, and it is to drive home a point. A simple and harsh punishment serves “the clear statutory policy of deterring unlicensed contract work.” (Hydrotech Systems, Ltd. v. Oasis Waterpark (1991) 52 Cal.3d 988, 992; see also id. 995, 996, 997, and 998.) SunRun’s analysis is correct.

While neither the statute of limitations analysis nor the licensing ruling is published, both still serve as very good guidance using common sense in their application under California law. Nevertheless, entities looking to walk that line should be very mindful of the underlying facts and the points highlighted by the appellate court in this case, and ensure that neither their contract language nor their actual activities move them across the line and therefore potentially under the California contractor regulatory scheme found in the BPC.