CAISO Proposes Second Set of Resource Adequacy Enhancements – Aims to Reduce Reliance on Resource Adequacy Availability Incentive Mechanism (RAAIM)

The CAISO recently issued Part 2 of its Resource Adequacy Enhancements Straw Proposal and stakeholders met with the CAISO this week to discuss the paper and get further clarifications on the initial skeletal structure provided.

As part of the process, the CAISO reviewed the counting rules in other ISO/RTOs and found that most ISO/RTOs use the effective forced outage rate of demand, or the probability that a resource will be unavailable due to forced outages or forced deratings when there is demand on the unit to operate, to assess resource availability up front.  The CAISO plans to take from the best practices, including a review of resources’ forced outage rates to include in RA valuation and ultimately reduce the reliance on RAAIM.  The CAISO’s admittedly ambitious schedule aims to wrap up the policy development and get board approval by the end of the year, anticipating implementation for RA year 2021.

The proposal includes three main topics:

(1) RA counting rules and assessments: The CAISO proposes a new framework that assesses the forced outage rates for resources and is considering how to incorporate these rates in RA assessments. The CAISO is not proposing to adjust NQC, as this will still be important for local RA assessments and studies and must offer obligations, but to also annually publish unforced capacity (UCAP) values, or the installed capacity that is not on average experiencing a forced outage or derating. The intention is to develop RA rules that incentivize the procurement of reliable resources rather than only the cheapest and to encourage showing all RA capacity that is under RA contract, as opposed to the minimum amount as is currently incentivized under the RAAIM framework. The CAISO is exploring options to develop UCAP for all resource types that do not rely on ELCC methodology (solar and wind), as it intends to rely on CPUC ELCC methodology where applicable. Proposals will be included in the revised straw proposal.

Additionally, the CAISO continues to explore a new planned outage substitution concept where planned outages will not be required to provide substitute capacity if LSE’s available unforced capacity exceeds the minimum UCAP threshold. Further, the CAISO believes it is possible to eliminate forced outage substitution as UCAP values will provide incentives for timely maintenance and quick repairs. Resources shown for RA capacity will continue to have a must offer obligation.

(2) Backstop capacity procurement: The CAISO’s proposal includes three pathways for new CPM authority for individual deficiencies including (a) LSE specific UCAP test (b) system UCAP test and (c) capacity incentive mechanism. The CAISO may also modify the competitive solicitation process to implement it with daily granularity as it may be used to allow scheduling coordinators to backstop planned outages in the future.

(3) RA import capability provisions: The CAISO is evaluating whether the current allocation process timing causes barriers for new LSEs beginning operations and commencing RA compliance. It will also consider potential enhancements to the Available Import Capability Assignment including (a) considering modifications to allow for release and relocation or transfer of unused import capability after initial monthly RA showings (b) incorporating an auction or other market based mechanism and (c) enhancing the provisions for reassignment, trading, or other forms of sales of import capability among LSEs.

The CAISO is accepting comments on these proposals until March 20 and anticipates posting a revised straw proposal on May 20.

As always, our attorneys can provide counsel regarding the impact of the proposed changes on your business and work with you to participate in this process.

 

 

Key Energy Related Bills Introduced in the 2019-2020 Legislative Session

The 2019-2020 California Legislative Session has reached its first deadline.  February 22, 2019 marked the deadline by which bills could be introduced for the first half of the Legislative Session. Lawmakers will begin Spring Recess April 12 and reconvene April 22.  The last day for bills to be passed out of the house of origin is May 31, 2019.

Below is a list of some of the key bills Stoel Rives’ Energy Team will be monitoring throughout the Legislative Session.  We note that some bills do not contain language beyond the “intent of the Legislature.”  However, we will continue to monitor these bills in case of substantive amendments.  These bills are set forth separately below under the heading “Legislative Intent.”

The majority of the bills introduced this Legislative Session relate in some way to California’s efforts to reduce greenhouse gas emissions and move to cleaner sources of generation, including legislation governing electric vehicles, energy storage, and renewable energy.  A number of bills introduced in February also attempt to address the impacts of wildfires, or to reduce wildfire risk.


ASSEMBLY BILLS

AB 40 (Ting, D)   Zero-emission vehicles: comprehensive strategy.

Status: Introduced December 3, 2018; referred to Committees on Transportation and Natural Resources January 24, 2019.

AB 40 would require by no later than January 1, 2021, the State Air Resources Board to develop a comprehensive strategy to ensure that the sales of new motor vehicles and new light-duty trucks in the state have transitioned fully to zero-emission vehicles, as defined, by 2040, as specified. Continue Reading

FERC Approves CAISO Tariff Changes re Generator Interconnection and Deliverability Allocation Procedures

FERC approved new changes to the CAISO tariff on February 19, 2019, with a retroactive effective date of November 27, 2018, that will impact projects in the CAISO’s generator interconnection queue. These changes are the result of a several month stakeholder initiative to enhance the interconnection process and follow a history of reforms intended to promote efficiency in the CAISO’s interconnection procedures in light of changes in the generation development marketplace.

Most significantly, the CAISO’s tariff changes include revisions to the Transmission Plan (TP) Deliverability allocation process in order to award deliverability to customers most likely to proceed towards construction. The CAISO will allocate in the following order: (1) customers with an executed power purchase agreement or customers that are load serving entities serving their own load, (2) customers actively negotiating a power purchase agreement or short listed in an RFO, (3) interconnection customers electing to proceed without a power purchase agreement.  This is a departure from the prior provisions that allocated deliverability based on a system that equally weighed three criteria related to financing status: being balance-sheet financed, having a regulator-approved power purchase agreement, and proceeding without a power purchase agreement. The CAISO believes this change better reflects the likelihood of proceeding to construction because projects without a power purchase agreement, in the CAISO’s experience, delay putting construction funds at risk and nearly always withdraw if they do not secure a power purchase agreement.  The CAISO has also changed to a similar priority system for allocating any available TP Deliverability in the Annual Full Capacity Deliverability Option process.

Other changes that will impact potential and existing interconnection customers include:

  • Allowing CAISO to remove network upgrades that are no longer needed from interconnection customers’ financial security postings, even before CAISO issues the next study results;
  • Requiring interconnection customers to provide copies of their power purchase agreements when demonstrating commercial viability;
  • Eliminating the criteria required of withdrawing interconnection customers in order to recover their refundable portion of financial security, which should result in more timely refunds;
  • Aligning the deposits required for customer-requested repowering studies and serial re-studies with current study costs by increasing deposits from $10,000 to $50,000;
  • Prohibiting fuel-type modifications for interconnection customers that have remained in the interconnection queue beyond the anticipated limits of seven years for cluster process or ten years for serial process;
  • Applying the commercial viability criteria to all requests for modifications beyond the anticipated tariff timelines;
  • Requiring projects in the queue beyond the anticipated tariff timelines to have a regulator-approved power purchase agreement to modify their project and retain deliverability (removing the balance-sheet financed option) – this change will not apply retroactively;
  • Allowing interconnection customers to convert to energy only deliverability status at any time, so long as costs are not shifted to other interconnection customers or transmission owners.

Changes also include revisions to suspension notification provisions to include a good faith estimate of anticipated time of suspension, adding project names to the CAISO’s public interconnection queue, and embedding the generator interconnection study process agreement in the interconnection request. Additionally, the CAISO has added a simple provision clarifying that interconnection customers must go through the new resource implementation process prior to synchronization and a clarification that interconnection customers that have not achieved commercial operation are subject to a material modification assessment for proposed changes, whereas online generators may modify their projects so long as they do not increase their capacity nor change electrical characteristics in a way that threatens reliability.

The CAISO has filed additional tariff changes which they have requested to be approved before the April 1, 2019 opening of the interconnection request window. These changes enumerate specific requirements for interconnection requests to be considered complete and valid. A third set of enhancements was approved by the Board of Governors earlier this month but have not yet been filed with FERC. These changes include clarifications to network upgrade cost responsibilities and framework.

Oregon Adopts Temporary Rules Limiting Solar Siting on Certain High-Value Farmlands

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.

Proposed Changes to CAISO’s Resource Adequacy Framework

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:

Import RA:

  • 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.

Oregon Department of Land Conservation and Development Issues Staff Report/Clarifications Regarding Proposed Solar PV Rules

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.

State of Oregon Proposes New Rules That Would Limit Solar PV on Farmland

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. 

FERC Issues NOPR to Eliminate Horizontal Market Screens for Certain MBR Sellers

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.

Background

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

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.

LexBlog