On January 29, 2019, the Oregon Department of Land Conservation and Development, the state’s land use agency, filed temporary rules amending the standards for siting solar PV facilities on agricultural lands. Although the Land Conservation and Development Commission stopped short of making the changes permanent in order to further consider stakeholder interests at its May 23, 2019 meeting, the Commission carried forward the bulk of the proposed limitations that we discussed in our previous posts here and here. Notably, the commission opted to retain the prohibition on siting solar on Class I or II, Prime or Unique soils. Under the temporary rules, developers may site solar PV on these particular lands only (1) if the county adopts, and an applicant satisfies, land use provisions authorizing sub-20 acre “dual-use” projects or (2) by securing a Statewide Planning Goal Exception. Written comments are due May 7, 2019, and a public hearing will be held on May 23, 2019.
The CAISO is proposing several changes to the Resource Adequacy framework that will be relevant to generators both within and outside of California. CAISO is in the initial stages of developing their policy changes and it is a good time to voice concerns or offer suggestions before the changes are solidified. We expect more than one straw proposal in this process, as the CAISO works with stakeholders to develop the appropriate policy solutions. Comments regarding this portion of the proposal are due February 6. CAISO’s proposal:
- Reassess the requirements and rules for specifying the sources behind RA import showings (prevent double counting in meeting EIM resource sufficiency requirements and RA requirements)
- Implement real time bidding requirement for all MWs of import RA – not just those awarded in IFM and RUC (day-ahead market)
- Explore expanding must offer obligation for import RA to 24/7
- Require 15 minute bidding/scheduling for import RA
- Change import RA designations to be resource-specific
Resource Adequacy Availability Incentive Mechanism (“RAAIM”):
- Explore moving RAAIM from predetermined hours to event-based triggers
- Implement changes that will resolve gaps in current planned outage approval process, including looking at rules that will incentivize submission of planned outages over reliance on forced outages. Two proposed options are under consideration, namely (i) prohibiting resources that are taking planned outages during a month from providing RA capacity, and (ii) authorizing ISO to procure capacity for any days on which resource is on planned outage using standing CSP bids
- Limit exemptions from various levels of RAAIM penalties
- Consider a RAAIM assessment based on both availability and performance. Currently RAAIM does not assess how resources perform in response to ISO dispatch instructions)
- Seek different pricing structures for each type of capacity (i.e., system, local, flexible)
Local Resource Adequacy Needs:
- Consider proposals to allow slow demand response to help meet local RA needs
- Plan to better outline enhancements to the local capacity technical study to inform stakeholders of availability needs within local capacity areas – including providing additional data
Note that CAISO’s straw proposal part 2 will come out in February with additional changes.
We are happy to provide counsel regarding the impact of the proposed changes on your business and work with you to participate in this process.
As a follow up to last week’s post about the proposed rules that would limit the development of solar PV on certain high-value farmland in Oregon, the Oregon Department of Land Conservation and Development issued its staff report on the proposed rules. The staff report provides an overview of the rationale for the proposed changes and clarification on several key issues, including:
- Continued availability of Statewide Planning Goal exceptions. The staff report confirms that, if the rules are adopted, project developers may still pursue development on Class I, Class II, Prime, and Unique soils by seeking an Exception to the Statewide Planning Goal 3 (Agricultural Lands). Although this is not a practicable permitting pathway in most instances, the Exception option nonetheless remains.
- Treatment of tracts composed of a mix of Class I or II, Prime or Unique soils and “other” soils. The staff report confirms that a county could approve a conditional use permit for a solar PV facility on a tract of land that contains Class I or II, Prime, or Unique soils on the portion of the tract that contains other soils. DLCD staff provided the following example in an email to the rulemaking list serve: “If an 80-acre tract includes 50 acres of class I, II, prime or unique soils and 30 acres of other soil types, those 30 acres of other soil types remain eligible for a conditional use application for commercial solar development.”
- Application of rule to solar PV powering onsite facilities. The staff report clarifies that the new limitations only apply to “commercial utility facilities” and not to solar installations that power onsite facilities such as agricultural buildings or electric fences.
The staff report also contains a case study prepared by DLCD staff that is designed to highlight the effect of the proposed limitation related to Class I or II, Prime or Unique soils. The case study (Attachment E to the staff report) provides several example tracts in Marion County that contain 12 acres or more of high-value farmland that is not Class I or II, Prime or Unique (and thus eligible for solar PV siting without a Statewide Planning Goal Exception). The case study also includes an overview map showing the mix of Class I or II, Prime or Unique soils and “other” high-value farmland in that area of Marion County.
As we noted previously, DLCD is currently accepting comments and will hold a public hearing in Salem on January 24. The agenda is available here.
The Oregon Department of Land Conservation and Development (“DLCD”), the state agency charged with overseeing and implementing the state’s land use planning program, is proposing new regulations that would prevent developers from siting solar PV facilities on certain farmland deemed high value. Over the last several years, opposition to the siting of solar PV facilities has increased, with land use advocates and farmers joining together to lobby for additional protections to the state’s agricultural lands. The proposed rules amend the criteria for when a solar PV facility may be approved on “high-value farmland,” making less farmland eligible for new facilities. The proposed rules also add clarifying language to the existing rules and extend certain wildlife habitat provisions.
The proposed solar rules would make the following changes:
Ban the siting of solar PV facilities on soils that are classified as prime, unique, Class I or II. Under the current rules, there are limits on the size of solar PV facilities that may be sited on these soils without an Statewide Planning Goal Exception, but this proposed change would preclude the siting of solar PV facilities on prime, unique, Class I or II soils entirely. Existing thresholds would remain for other “high-value farmland” that does not contain soils classified as prime, unique, Class I, or II.
Adopt language from 2018 temporary rule, clarifying that farmland acreage thresholds apply where the facility will “use, occupy, or cover” designated farmland. This rule language was adopted in response to efforts by certain developers to remain below applicable farmland acreage thresholds by co-locating solar PV facilities with agricultural operations, such as apiaries. The previous rules provided that a solar PV could not “preclude from use as a commercial agricultural enterprise”: 320 acres (nonarable lands), 20 acres (arable lands), or 12 acres (high-value farmland). Some developers had argued successfully that a solar facility developed for “dual-use” would not “preclude” the entire site from use as a commercial agricultural enterprise. In response to a particular Clackamas County decision on this issue, DLCD proposed and adopted a temporary rule clarifying that the acreage thresholds apply to facilities that “use, occupy, or cover” designated farmland. In other words, when calculating the impact of the solar facility on agricultural lands, local jurisdictions are required to consider the entire footprint. The proposed rules make this language permanent. (Notably, the proposed rules include a provision that would allow counties to adopt land use provisions for “dual-use” development, but the rules prevent those provisions from allowing projects in excess of 20 acres.)
Remove the sunset provision from requirement to complete an assessment of impacts to wildlife habitat from solar facility development. Under current rules, if a proposed solar PV facility is located on land where the potential exists for adverse effects to protected species or habitat, the applicant is required to conduct a site-specific assessment of the project site in coordination with state and federal wildlife agencies. The proposed rules remove the 2022 sunset provision related to this requirement.
The proposed rules are available on DLCD’s website here, and a public hearing will be held on January 24, 2018 in Salem. We are tracking this process closely and are happy to field questions about how the changes may affect your projects.
The Federal Energy Regulatory Commission (“FERC”) issued a Notice of Proposed Rulemaking (“NOPR”) on December 20 proposing changes to its regulations regarding the horizontal market power analysis required for market-based rate (“MBR”) sellers. The proposed rulemaking picks up on an earlier effort in Order No. 816 to ease the regulatory burden on MBR sellers in RTO/ISO markets. The current proposal would eliminate the need for certain MBR sellers to submit indicative screens with their initial MBR application, triennial updates, and change in status notices. The exemption would apply to all MBR sellers in RTO/ISO markets with RTO/ISO-administered energy, ancillary service, and capacity markets subject to FERC-approved RTO/ISO market monitoring and mitigation. For RTO/ISO markets that lack an RTO/ISO-administered capacity market (that would be CAISO and SPP), MBR sellers would be exempt from the requirement to submit indicative screens if their MBR authority is limited to sales of energy and/or ancillary services. FERC also proposed eliminating the rebuttable presumption that FERC-approved RTO/ISO market monitoring and mitigation is sufficient to address horizontal market power concerns for capacity sales in CAISO and SPP.
MBR sellers are currently required to submit two indicative screens, a pivotal supplier screen and a wholesale market share screen, in their initial MBR applications, change in status notices, and any updated market power analyses. Passage of both screens creates a rebuttable presumption that the seller does not have horizontal market power. If a seller fails either screen, it is presumed to have horizontal market power. To rebut the presumption of market power, the seller must present evidence through a delivered price test or other means to show that it does not possess market power. However, sellers in an RTO/ISO market who fail the screens have an alternative. They may instead rely on FERC-approved RTO/ISO market monitoring and mitigation to address market power concerns. In 2014, FERC issued a NOPR proposing to eliminate the indicative screen requirement for those RTO/ISO sellers because it yielded little practical benefit due to their ability to rely on RTO/ISO market monitoring and mitigation. FERC decided not to act on that proposal in Order No. 816 but stated that it may consider the issue in the future.
The Current NOPR
In the current NOPR, FERC states that the indicative screens provide marginal additional market power protections given that FERC has found that RTO/ISO market monitoring and mitigation adequately mitigate a seller’s market power and FERC has access to other data regarding horizontal market power. FERC notes that all RTOs/ISOs have mitigation provisions for energy offers. While not all RTOs/ISOs have market power mitigation provisions for ancillary services, concerns about market power in ancillary service offers are mitigated through the mitigation of energy offers, since ancillary service prices are based on the opportunity cost of not generating energy. Finally, ISO-NE, NYISO, PJM, and MISO all have capacity markets with FERC-approved market power mitigation. Continue Reading
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.
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.
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
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.
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.