Reminder of January 1, 2019 Mandatory New Notice Requirement by CA Residential Solar Contractors

In 2017, the California Legislature passed a bill that resulted in Business and Professions Code (BPC) section 7169, which ultimately would require Home Improvement Contractors, which include contractors that install solar systems on residences, to issue specific disclosures to any residential consumers who may want to purchase, finance or lease, and install a solar system on their property. Recently in August, the California Public Utilities Commission “endorse[d] the solar energy systems disclosure document as being compliant with [BPC section 7169]….” The Disclosure terms include:

  • The total cost for the solar system, including financing and energy/power costs (if applicable);
  • The statutory License Board Disclosure statement for contractors and / or the home improvement salesperson who sold the system information regarding with whom to file if there are complaints; and
  • The statutory Three-Day Right to Cancel Disclosure if the contract is not negotiated at the contractor’s place of business.

Continue Reading

And Now the Second Circuit Upholds New York’s Nuclear Subsidy Program

Following up on our recent blog post regarding the Seventh Circuit’s decision to uphold Illinois’ nuclear subsidy program, two weeks later on September 27, 2018, the Second Circuit upheld a district court’s decision finding that New York’s nuclear subsidy program was not preempted by the Federal Power Act (Coalition for Competitive Electricity, et al. v. Zibelman, et al., Dcase No. 17-25640-cv).

The New York program is similar to the Illinois program, with variations in the pricing of zero emissions credits (ZECs).  In New York, the price of the ZEC is based on the federally-determined social cost of carbon, as may be adjusted for renewable energy penetration and forecasted wholesale prices, and is fixed for two year periods.  The Second Circuit found this pricing mechanism was different than the Maryland program struck down by the Supreme Court in Hughes v. Talen Energy Marketing, LLC (136 S. Ct. 1288 (2016) (Hughes) since the ZEC price does not fluctuate to match the wholesale clearing price and therefore receipt of ZECs is not tethered to a generator’s participation in the wholesale markets (the fatal defect in Hughes).

Similar to the Seventh Circuit, the Second Circuit focused on the mechanisms of the New York subsidy program, and determined that the practical effect of the subsidy program exerting downward pressure on wholesale electricity rates was insufficient to justify preemption.  The court noted that ZECs are created when electricity is produced, regardless of whether or how the electricity is ultimately sold (and how generators sell their electricity is a business decision that does not raise preemption concerns).  According to the Second Circuit, “New York has kept the line [between federal and state jurisdiction] in sight, and gone as near as can be without crossing it.”

Along with the Seventh Circuit decision, the Second Circuit decision provides flexibility for states to subsidize generation of their choosing (as long as the state is not directly setting the wholesale market price and only indirectly impacting a Federal Energy Regulatory Commission (FERC)-jurisdictional rate).  But, now that two circuit courts have upheld state nuclear subsidy program, the fight over such programs will very likely be at FERC as the agency considers changes to market rules to address the impact of such state subsidies.

Seventh Circuit Upholds Illinois’ ZEC Program and Leaves the Door Open for State Subsidization of Generation

On September 13, 2018, in Electric Power Supply Association v. Star (Case No. 17-2433 and 17-2445), the Seventh Circuit upheld a district court decision finding that Illinois’ zero emissions credit (ZEC) program (i.e., its nuclear subsidy) was not preempted by the Federal Power Act.  With this decision, the Seventh Circuit adopted a narrow reading of the Supreme Court’s decision in Hughes v. Talen Energy Marketing, LLC (136 S. Ct. 1288 (2016)) (Hughes) (which struck down a Maryland generation subsidy program that required participation in the PJM capacity auction) and left the door open for states to subsidize generation of their choosing (as long as the state is not directly setting the wholesale market price).  Thus, in subsidizing generation, states may achieve indirectly what they are prevented from ordering directly.

Under the Illinois program, certain nuclear generators in Illinois (i.e., Exelon’s Quad Cities and Clinton nuclear facilities) receive ZECs (initially priced at $16.50 per MWh) for each MWh of electric energy they produce.  The price of a ZEC will drop if an Illinois-set market-price index (based on the annual average energy prices in the PJM auction and two of the state’s regional energy markets) exceeds $31.40 per MWh.  The Illinois program does not require that the nuclear facilities participate in the PJM capacity auction (although it is acknowledged that the nuclear generators will very likely be participating in the PJM capacity auction).  Illinois’ nuclear subsidy program was challenged by an association representing electricity producers and several municipalities.

Jurisdiction over the power sector is divided between the federal government and the states.  The Federal Energy Regulatory Commission (FERC) has jurisdiction over wholesale power sales in interstate commerce, while the states have jurisdiction over retail power sales and generation facilities.  State regulation of whole power sales would be preempted by the Federal Power Act, but the courts are still deciding where exactly the line between federal and state jurisdiction lies. Continue Reading

How Should Storage be Counted? FERC Is Asked To Decide the Role of Storage in Calculating QF Capacity

Is a co-located storage facility and wind or solar facility considered to be one qualifying facility (“QF”) under the Public Utility Regulatory Policies Act (“PURPA”)? Or multiple QFs? How will the aggregate capacity of such storage plus wind/solar QF(s) be measured?  If the storage will only be charged from the co-located wind/solar facility, will the aggregate capacity of the storage plus wind/solar QF be the net power production capacity of the wind/solar facility? Or will it include the maximum capacity of the co-located storage facility (in addition to the capacity of the wind/solar facility)?

These questions should be answered when FERC rules on NorthWestern Corporation’s (“NorthWestern”) recently-filed motion (FERC Docket No. EL18-195) (the “NorthWestern Motion”) and an application for QF recertification by Beaver Creek Wind II, LLC (FERC Docket No. QF17-673-002) (the “QF Recertification”).  On August 31, 2018, NorthWestern filed a motion to revoke the QF status of Beaver Creek Wind I, LLC, Beaker Creek Wind II, LLC, Beaver Creek Wind III, LLC and Beaver Creek Wind IV, LLC (collectively, the “Beaver Creek Projects”), arguing that the integration of battery storage facilities causes the Beaver Creek Projects to exceed the maximum 80 MW QF capacity for small power production facilities.  The Beaver Creek Projects are each a proposed 80 MW wind farm with a battery storage system capable of a maximum power output capacity of up to 40 MWh (10 MW over 4 hours).  Each of the Beaver Creek Projects has filed a QF self-certification or an application as a small power production facility.  In the NorthWestern Motion, NorthWestern claims that none of Beaver Creek Projects’ 80 MW wind farms or the battery storage systems qualify as a QF since the storage plus wind facility has an aggregated net power production capacity over the 80 MW maximum to qualify as a QF small power production facility.  According to NorthWestern, the wind farm and the battery storage system should be treated as separate projects for QF purposes and since both the wind farm and the battery storage system use wind as a fuel source and are located within a mile of each other, the capacity of the wind farm and the capacity of the battery storage system need to be aggregated together to determine the QF capacity (which in the case of the Beaver Creek Projects, would put them over the 80 MW threshold).  In contrast, the Beaver Creek Projects (in the QF Recertification) argue that the 80 MW QF maximum capacity limit will not be exceeded since the battery storage system will not increase the renewable energy production of the wind farms and will not be providing any additional generation of energy for the wind farms.  Furthermore, the injection of power to the grid from the Beaver Creek Projects will be limited to 80 MW.

FERC’s decision on these issues may affect the sizing of storage plus wind/solar facilities that are seeking to obtain QF status to qualify for PURPA power purchase agreements.  Comments on the NorthWestern Motion are due on October 1, 2018.

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

STAYING LOCAL: FEDERAL COURT AFFIRMS CONSTITUTIONALITY OF MINN. STAT. § 216B.246 AND ADOPTS SUPREME COURT TRACY RULE

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]

***

Footnotes:

[1] Assembly No. 3723 State of New Jersey, 218th Legislature, introduced March 22, 2018, available at http://www.njleg.state.nj.us/2018/Bills/A4000/3723_I1.PDF (last visited April 19, 2018).

[2] Id. at 1-2.

[3] Id. at 2.

[4] Id.

[5] Id. at 34-36.

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