Source: https://www.lawofrenewableenergy.com/page/2/
Timestamp: 2019-04-19 08:52:59+00:00

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The statutory Three-Day Right to Cancel Disclosure if the contract is not negotiated at the contractor’s place of business.
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).
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.
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.
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.
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.
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.
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.
[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.
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%. 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”), imposing caps and reducing the feed-in tariff (“FiT”) mechanism in connection with China’s domestic PV projects, and at the same time setting rules at the central government level to urge marketization of China’s solar industry.
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.
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.
In terms of charging technology, 150 kW fast charging and residential L2 are the minimum.
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. 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. 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. Within six months after completion of the report, BPU is then required to initiate a proceeding to establish a mechanism for achieving the goals.
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.
 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).

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