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October 6, 2017
NEM Western Energy Policy Summit

Please mark your calendars and plan to join us for NEM's Western Energy Policy Summit on October 23-25, 2017. The Summit will take place at Caesars Palace in Las Vegas, Nevada. The Agenda is hotlinked here. You may register at this hotlink.

Secretary Perry Proposal on Grid Reliability and Resilience Pricing

Secretary of Energy Perry proposed a rule for final action by FERC regarding grid reliability and resilience pricing. Secretary Perry proposed that FERC exercise its authority under Sections 205 and 206 of the FPA regarding just and reasonable rates for wholesale electric sales to establish rules for RTOs/ISOs "to ensure that certain reliability and resilience attributes of electric generation resources are fully valued." Secretary Perry cites the premature retirement of "fuel-secure" generation that can withstand fuel disruptions during disasters as a rationale.

Secretary Perry proposed that FERC amend its regulations to include a definition of "electric grid reliability and resiliency resources" as follows:
"Any resource that:
(A) is an electric generation resource physically located within a Commission-approved independent system operator or regional transmission organization;
(B) is able to provide essential energy and ancillary reliability services, including but not limited to voltage support, frequency services, operating reserves, and reactive power;
(C) has a 90-day fuel supply on site enabling it to operate during an emergency, extreme weather conditions, or a natural or man-made disaster;
(D) is compliant with all applicable federal, state and local environmental laws, rules, and regulations; and
(E) is not subject to cost of service rate regulation by any state or local regulatory authority."

RTOs/ISOs would establish a rate for the "(A) purchase of electric energy from an eligible reliability and resiliency resource and (B) recovery of costs and a return on equity for such resource dispatched during grid operations."

FERC Staff has issued the following detailed questions on the proposed rule regarding the need for reform, eligibility, rates, implementation, and other issues for comment:

"Need for Reform
1. What is resilience, how is it measured, and how is it different from reliability? What levels of resilience and reliability are appropriate? How are reliability and resilience valued, or not valued, inside RTOs/ISOs? Do RTO/ISO energy and/or capacity markets properly value reliability and resilience? What resources can address reliability and resilience, and in what ways?
2. The proposed rule references the events of the 2014 Polar Vortex, citing the event as an example of the need for the proposed reform. Do commenters agree? Were the changes both operationally and to the RTO/ISO markets in response to these events effective in addressing issues identified during the 2014 Polar Vortex?
3. The proposed rule also references the impacts of other extreme weather events, specifically hurricanes Irma, Harvey, Maria, and superstorm Sandy. Do commenters agree with the proposed rule’s characterization of these events? For extreme events like hurricanes, earthquakes, terrorist attacks, or geomagnetic disturbances, what impact would the proposed rule have on the time required for system restoration, particularly if there is associated severe damage to the transmission or distribution system?
4. The proposed rule references the retirement of coal and nuclear resources and a concern from Congress about the potential further loss of valuable generation resources as a basis for action. What impact has the retirement of these resources had on reliability and resilience in RTOs/ISOs to date? What impact on reliability and resilience in RTOs/ISOs can be anticipated under current market constructs?
5. Is fuel diversity within a region or market itself important for resilience? If so, has the changing resource mix had a measurable impact on fuel diversity, or on resilience and reliability?

General Eligibility Questions
1. In determining eligibility for compensation under the proposed rule, should there be a demonstration of a specific need for particular services? What should be the appropriate triggering and termination provisions for compensation under the proposed rule?
2. As the proposed rule focuses on preventing premature retirements, should a final rule be limited to existing units or should new resources also be eligible for cost-recovery? Should it also include repowering of previously retired units? Alternatively, should there be a minimum number of MW or a maximum number of MW for resources receiving cost-of service payments for resilience services? If so, how should RTOs/ISOs determine this MW amount? Should this also include locational and seasonal requirements for eligible resources?
3. Are there other technical characteristics that should be required for an eligible unit besides on-site fuel capability? If so, what are those technical characteristics and what benefits do they provide? What types of resources can meet the proposed eligibility criteria of the proposed rule? What proportion of total current generating capacity does this represent?
4. If technically capable of sustaining output for a sufficient duration (and meeting other relevant requirements), should resources such as hydroelectric, geothermal, dual-fuel with adequate on-site storage, generating units with firm natural gas contracts, or energy storage (each of which might have a demonstrable store of energy to draw upon to sustain an electrical output, if not necessarily fuel) also be eligible? Why or why not? If technical capability is the appropriate criterion for eligibility, what specific technical capability should be required to be eligible?
5. The proposed rule would require that eligible resources be able to provide essential energy and ancillary reliability services and includes a non-exhaustive list of services. What specific services should a resource be required to provide in order to be eligible?
6. The proposed rule would limit eligibility to resources that are not subject to cost of service rate regulation by any state of local regulatory authority. How should the Commission and/or RTOs/ISOs determine which resources satisfy this eligibility requirement?

90-day Requirement
1. The proposed rule defines eligible resources as having a 90-day fuel supply. How should the quantity of a given resource’s 90 days of fuel be determined? For example, should each resource be required to have sufficient fuel for 24 hours/day and sustained output at its upper operating limit for the entire 90-day period? Would there be any need for regional differences in this requirement?
2. Is there a direct correlation between the quantity of on-site fuel and a given level of resilience or reliability? Please provide any pertinent analyses or studies. If there is such a correlation, is 90 days of on-site fuel necessary and sufficient to address outages and adverse events? Or is some other duration more appropriate?

Fuel Supply Requirement
1. The proposed rule requires that resources must be in compliance with all applicable environmental regulations. How should environmental regulations be considered when determining eligibility? For example, if a unit that was capable of keeping 90-days of fuel on-site was subject to emission limits that would prevent it from running at its upper operating limit for 90 days, should that unit be eligible under this proposed rule?
2. As the proposed rule references the need for resilience due to extreme weather events, including hurricanes, should there be any other eligibility criteria for the resource or fuel supply (e.g., storm hardening)? What considerations should be given to the vulnerability of 90-day fuel supplies to natural or man-made disasters such as extreme cold temperatures, icing, flooding conditions, etc. that may impact the on-site fuel supply?
3. Does the vulnerability or non-availability of on-site fuel supplies vary depending upon fuel type, location, region, or other factors?

1. How would eligible resources receiving cost of service compensation under the proposed rule be committed and dispatched in the energy market?
2. How would eligible resources receiving cost based compensation under the proposed rule be considered in the clearing and pricing of centralized capacity markets?
3. What is the expected impact of this proposed rule on entry of new generation, reserve margins, retirement of existing resources, and on resource mix over time?
4. Should there be performance requirements for resources receiving compensation under the proposed rule? If so, what should the performance requirement be, and how should it be measured, or tested? What should be the consequence of not meeting the performance requirement?
5. Should there be any restrictions on alternating between market-based and cost-based compensation?

1. The proposed rule lists compensable costs that should be included in the rate as operating and fuel expenses, costs of capital and debt, and a fair return on equity and investment. Are there other costs that would be appropriate to be included in the rate? Would any of the listed costs be inappropriate for inclusion?
2. Should wholesale market revenues offset any cost of service payments stemming from the proposed rule?
3. How should RTOs/ISOs allocate the cost of the proposed rule to market participants?
4. How would the requirement that eligible resources receive full cost recovery be reconciled with the requirement, as stated in the regulatory text, that resources be dispatched during grid operations?

1. The proposed requirement for submitting a compliance filing is 15 days after the effective date of any Final Rule in this proceeding, with the tariff changes to take effect 15 days after the compliance filings are due. Please comment on the proposed timing, both to develop a mechanism for implementing the required changes and to implement those changes, including whether or not such changes could be developed and implemented within that timeframe.
2. Please comment on the proposed rule’s estimated burden of $291,042 per respondent RTO/ISO, to develop and implement new market rules as proposed, including the potential software upgrades required to do so.
3. Please describe any alternative approaches that could be taken to accomplish the stated goals of the proposed rule.
4. What impact would the proposed rule have on consumers?
5. The Commission may take notice of relevant public information, including information in other Commission proceedings. If a commenter views information in another Commission proceeding as relevant to the proposed rule, please identify that information and explain how it is relevant to the proposed rule. Such information may include a filing previously submitted by the commenter."

Comments are due on October 23, 2017, and reply comments are due November 7, 2017, although extension requests are pending with the Commission. The full texts of the Proposed Rule, Notice Inviting Comments and Staff Questions are available on the NEM Website.

Click here to view all past updates.
Informal Public Workshop on California Customer Choice

The Commission sent notice of an informal public workshop in its Customer Choice Project entitled, "An Evaluation of Regulatory Framework Options for an Evolving Electric Market." The workshop will be held October 31, 2017, beginning at 9am at the State Capitol.

As described by the Commission, the informal public workshop will be held to, "gather stakeholder input on global and national electric market choice models, including California's 2020 market. Speakers will include California stakeholders and representatives from out-of-state electric markets who will present key insights to help guide the evolution of the regulatory framework for customer choice in California." An agenda and additional details are forthcoming.

A second public workshop will be held after the Commission issues a draft White Paper in early 2018 for public comment.

The Commission also issued a document entitled "FAQs-California Customer Choice Project." It explains that for the purpose of the project "customer choice" is defined as "the range of options in electric markets among which a customer (individual or business) may choose" including:
"* electric service provider;
* rate plan;
* type of generation procured by provider to serve load;
* behind the meter grid assets to self-generate;
* participation in programs offering benefits to the customer for reducing and shifting load; and
* other accommodations supporting grid reliability, greenhouse gas (GHG) reduction and operation of the electric system."

The mission of the Project is to make decisions through:
"a. Evaluating representative national and global models for customer choice in the electric market;
b. Assessing whether the trajectory of the state’s regulatory framework for customer choice in 2020 will allow California to meet fundamental principles of affordability, decarbonization, and reliability; and
c. Conducting comparative analysis to identify trade-offs between the regulatory framework options."
In the short term this will culminate in the issuance of a draft White Paper in early 2018 and final White Paper in Spring 2018.

The three main principles to be utilized in evaluating market models are affordability, reliability and decarbonization. These principles will be supplemented by the following issues:
"* How does this choice model ensure consumer protections?
* How does this choice model support development and incorporation of innovations driven by customer demand?
* Does this choice model ensure universal electric service?
* How does the choice model leverage investment necessary to finance the evolution of the electric grid?
* How does this choice model consider the transition/transfer of utility obligations?
* Does this choice model have competitively neutral rules among market participants?
* Can customers determine their level of participation and are they informed to participate at their desired level?
* How does this choice model impact and benefit local communities?"

The full text of FAQs-California Customer Choice Project is available on the NEM Website.

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