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FERC rejects ISO New England energy security proposal

November 4, 2020

by Paul Ciampoli
APPA News Director
November 4, 2020

The Federal Energy Regulatory Commission on Oct. 30 issued an order finding that ISO New England’s Energy Security Improvements (ESI) proposal “is unjust and unreasonable because it would impose substantial costs on consumers without meaningfully improving fuel security.”

Background

On April 15, ISO-NE submitted to FERC proposed ESI tariff changes, which the ISO described as “necessary to address the fuel security challenges facing the New England region.”

The proposal came in response to a July 2018 order in which FERC denied the ISO’s request for a tariff waiver to allow for reliability-must-run (RMR) agreements with Units 8 and 9 at the Mystic Generation Station for fuel security purposes.

FERC instead directed ISO-NE to submit interim tariff revisions providing for the filing of short-term, cost-of-service agreements to address demonstrated fuel security concerns, and “to submit by July 1, 2019 permanent Tariff revisions reflecting improvements to its market design to better address regional fuel security concerns.”

The ESI proposal responded to this second requirement, the deadline of which was extended twice since the July 2018 order.

The proposal called for the creation of new day-ahead ancillary service products that would allow market participants to voluntarily offer to sell options to the ISO to ensure the availability of energy in real time.

Details of FERC order

The Commission’s decision centered on three findings:

The New England Power Pool (NEPOOL) Participants Committee did not support the ESI proposal, so NEPOOL submitted an alternative ESI proposal along with ISO-NE’s proposal.

FERC determined that while the alternative “would result in lower costs to consumers than ISO-NE’s ESI proposal, we also reject the NEPOOL alternative as unjust and unreasonable because it contains the same deficiencies that render ISO-NE’s proposal unjust and unreasonable.” 

The Commission did not make a finding on whether ISO-NE faces a fuel security or energy security issue, but acknowledged the concerns leading to the proposal and stated that if ISO-NE “decides to pursue a solution to address these concerns, we encourage it to explore a market-based reserve product that provides resources sufficient lead time and ability to acquire fuel or take other steps necessary to be able to deliver energy when needed.”

FERC said it expects that such a market solution would be designed to:

“We are not, however, directing ISO-NE to pursue any particular approach.  We further note that nothing in this order prohibits ISO-NE from proposing a day-ahead reserves market independent of any proposal to address the concerns at issue here,” FERC said.

The Commission also rejected ISO-NE’s associated proposal to sunset interim fuel security programs one year earlier than currently provided for in the tariff, stating that “ISO-NE may propose to the Commission other steps it believes are warranted to address fuel security, such as submitting a revised long-term fuel security proposal or seeking to extend one or more of the interim programs.” 

MMWEC, others protested ISO proposal in May

The Massachusetts Municipal Wholesale Electric Company (MMWEC), New Hampshire Electric Cooperative and Connecticut Municipal Electric Energy Cooperative protested the ISO-NE proposal in a May 15 filing at FERC.

While the ISO’s proposal “is presumably intended to bring operational enhancements to bear, it is at best an incomplete solution to the region’s fuel security issues,” MMWEC, New Hampshire Electric Cooperative and Connecticut Municipal Electric Energy Cooperative said in their protest.

The ISO has acknowledged that its proposed solution was incomplete for lack of a market mitigation plan and a seasonal forward market, they noted. “Each of the missing elements is critical, and their omission should be fatal,” MMWEC and the others said.

Without a seasonal forward market, the ISO’s filing “fails to address the root cause of the region’s fuel-security problems: that generators must make fuel-procurement decisions long before they know whether they will clear in the day-ahead or real-time markets and be able to recoup those costs,” they went on to argue.

“And without a market mitigation plan, the proposal not only fails to solve the key problem; it potentially exposes consumers to the exercise of unmitigated market power in the newly created markets.”

MMWEC, the New Hampshire Electric Cooperative and Connecticut Municipal Electric Energy Cooperative said that in the absence of these essential components, “neither the Commission nor stakeholders should be forced to draw conclusions now about whether this one piece of a larger program is just or reasonable—particularly where these other components of the ISO’s comprehensive solution would also require this Commission’s approval in another proceeding.”

Therefore, they argued that FERC should reject the ISO’s compliance filing, without prejudice to the day-ahead ancillary services proposal being re-filed when the ISO has completed work on the totality of its response, at which time the Commission and stakeholders can conduct a comprehensive review of the total package of reforms.

Alternatively, MMWEC, the New Hampshire Electric Cooperative and Connecticut Municipal Electric Energy Cooperative said that if the Commission does not reject the filing, it should:

“But, to be clear, acceptance of the NEPOOL Alternative — while an improvement over the ISO’s proposal — will not solve New England’s fuel security problem. Like the ISO proposal, the NEPOOL Alternative does not include a seasonal forward market nor a mitigation plan,” they noted in their filing.

In a news release, MMWEC said that under ESI, New England electric customers would have paid the region’s generators up to an additional $257 million dollars a year, “based on the hope that doing so would encourage them to procure fuel supplies under tight operating conditions.”

MMWEC, the New Hampshire Electric Cooperative and the Connecticut Municipal Electric Energy Cooperative argued that the ESI proposal did not allow sufficient time for the generators to purchase fuel supplies.

They also pointed out that the proposal was voluntary, meaning that generators could choose not to participate in providing fuel security when the system needed them the most.

In a separate filing in the proceeding made on May 15, a group of New England consumer-owned systems and Energy New England (ENE) argued that ISO-NE’s ESI Proposal was unjust and unreasonable in three substantial respects, and incomplete in a fourth respect.

Among other things, they said that ISO-NE’s ESI proposal sought to impose on load-serving entities a year-round obligation to procure “Demand Quantities” of Day Ahead options for energy to supply Replacement Energy Reserves, “which produce no benefit during the months of March through November, when the New England gas pipeline system is not subject to constraint during periods of low temperatures and high heating demand.”

ISO-NE’s ESI proposal was incomplete in its lack of an appropriately designed market power mitigation strategy, the New England consumer-owned systems and ENE said.

“In substance, this case represents a replay of the ‘jump ball’ over ISO-NE’s 2015-2018 Winter Reliability Program,” they said.

“Here, as in the earlier case, ISO-NE has pursued a theoretical market design construct without regard to its cost or efficacy. Here, as in the earlier case, NEPOOL has proposed an alternative rate design that achieves the objectives outlined in the Commission’s July 2 Order without imposing irrational and unjustifiable cost burdens on consumers.”

As in the earlier case, the New England consumer-owned systems and ENE argued that the Commission should accept the NEPOOL Alternative, and should require a number of modifications to the ISO-NE ESI proposal.

GHG reduction goals in PJM states best met with an RTO-wide carbon price

November 2, 2020

by Peter Maloney
APPA News
November 2, 2020

The PJM Interconnection, the largest wholesale power market in the nation, could create “substantial opportunities for low cost decarbonization” by pursuing policies such as establishing a charge on carbon dioxide (CO2) emissions, consulting firm Energy and Environmental Economics (E3) said in a new report.

A CO2, or “carbon,” price that would apply across the board in PJM’s marketplace, which operates in 13 states and the District of Columbia, would be a better option than “continuing to rely on fragmented and restrictive clean energy policies and subsidies,” the report, Least Cost Carbon Reduction Policies in PJM, argued. The report was commissioned by the Electric Power Supply Association.

Several states within the footprint of the regional transmission operator (RTO) have set up a variety of policies aimed at encouraging renewable energy resources or curbing greenhouse gas emissions, creating a patchwork of regulations

RTO specific policies establishing a carbon price recently gained a glimmer of support when the Federal Energy Regulatory Commission (FERC) on Oct. 15 issued a proposed policy statement, affirming that it has jurisdiction over organized wholesale electric market rules that incorporate a state-determined CO2 price in those markets. FERC’s proposal encouraged operators of organized markets to consider the benefits of establishing a price on CO2.

“Our study of decarbonization policies in the PJM region finds that the most effective policies are ones that maximize market participants’ choices and leverage diversity across the PJM footprint,” Arne Olson, senior partner at E3, said in a statement.

From a near-term policy perspective, current policies aimed at reducing greenhouse gas emissions by subsidizing specific technologies or in-state resources, such as renewable portfolio standards, are inefficient and will become less and less cost-effective as policy targets reach higher levels, the E3 report found.

The report put the cost of existing state policies at more than $3 billion per year by 2030, or $50 per person each year across the 65 million customers served by the PJM system, for a 12% reduction in net GHG emissions.

Instead, E3 said its analysis shows that technology-neutral policies that enable the broadest array of potential solutions will generally be “the most cost-effective by incentivizing coal-to-gas switching, retaining the most competitive zero-emission nuclear generators, and developing the lowest-cost renewables that harness the diversity benefits of PJM’s geography.”

Some current state policies are “well intentioned” but may not have the intended effect, the report said, citing the Regional Greenhouse Gas Initiative (RGGI) as an example of how a partial carbon pricing approach can undercut emission reduction goals.

RGGI, which includes New England and four adjacent Eastern Seaboard states, has limited or negative impact on emissions because of leakage across state lines where compliance costs within RGGI incentivize a shift in energy production to less efficient resources outside of the RGGI region, the report said.

E3 recommended improvements to RGGI to mitigate leakage by expanding the program to encompass more PJM states. Only three PJM states, Delaware, Maryland and New Jersey, are currently in RGGI and such an expansion could drive “significantly deeper emissions reductions.”

E3 also found that that current resource specific mandates for offshore wind and battery storage in PJM “appear premature if immediate GHG reductions or cost savings are the intended goals” and may not be needed to achieve decarbonization goals until after 2030. Such technology-specific policies could cost over $1 billion per year compared with more readily available GHG savings opportunities. Instead, E3 said, targeting cheaper onshore resources would reduce emissions at “significantly lower cost over the next decade.”

Beyond 2030, efficient policy design and resource usage will become increasingly important if GHG reduction goals are going to be met at a reasonable cost, the report said.

While there are sufficient renewable resources to meet 2030 goals, the report identified the availability of land, potential transmission constraints and flexible generation capacity to backstop those resources as key to achieving long-term decarbonization goals.

E3 said there is a “deep pool of flexible gas capacity in PJM” that will allow it to integrate renewables at low cost, though the authors noted that gas plant operations will look significantly different in the future. They will see increased levels of cycling and more seasonal operation.

By 2050, E3 sees at least 35 gigawatts (GW) and likely 50 GW to 80 GW of existing gas capacity remaining valuable for grid reliability. The price of that reliability, though, will likely be more volatile energy prices in certain hours or higher capacity prices may be required to keep these plants online, the report said.

The report also noted that there are limitations to the ability of existing technologies to reach a 100% reduction in GHG emissions by 2050 at a reasonable cost whether those goals are met by renewable resources or clean energy resources.

Moving from an 80% target to a 100% target “would lead to exponential increases in costs,” the report said. Moving from 80% GHG reductions to 100% reductions in 2050 would drive additional costs of over $20 billion per year, moving from an 80% to a 100% renewable portfolio standard policy would increase costs by over $30 billion per year, E3 said.

In conclusion, E3 said the diversity of the PJM system’s loads and resources offers significant cost savings for meeting the collective climate goals of the region and recommended that policy makers should “see the regional marketplace as a critical tool for enabling long-term decarbonization. Efficient policy will be key to meeting climate goals at manageable costs.”

Missouri regulators open proceeding to determine long-term RTO membership benefits

October 22, 2020

by Paul Ciampoli
APPA News Director
October 22, 2020

The Missouri Public Service Commission has opened a proceeding to determine the long-term benefits of continued membership in a regional transmission organization (RTO) by the state’s investor-owned electric utilities.

“The Commission believes there are benefits in RTO membership but long-term costs and commitments of RTO membership, especially given the structure, services, and membership of both Southwest Power Pool (SPP) and Midcontinent Independent System Operator (MISO) continue to change significantly with the passage of time,” the PSC said in an Oct. 19 news release.

In order to determine whether continued membership in an RTO is in the ratepayers’ best interest, the PSC “must inquire into the nature of the benefits of RTO membership, the monetized value of those benefits, and what time horizons should be employed to compare asset lives (costs) to the values of benefits streams,” it said.

The PSC directed the state’s investor-owned utilities to take part in a workshop and cooperate with Commission Staff in its investigation.

PSC Staff and the electric utilities will determine:

PSC staff will file a report related to its findings by June 30, 2021.

The PSC order opening the proceeding is available here.

AVANGRID to acquire New Mexico-based IOU PNM Resources

October 21, 2020

by Paul Ciampoli
APPA News Director
October 21, 2020

Connecticut-based energy company AVANGRID will acquire New Mexico investor-owned utility PNM Resources in a transaction with an $8.3 billion enterprise value, the companies announced on Oct. 21.

As a result of the transaction, which has been approved by the boards of the two companies, PNM’s shareholders will receive approximately $4.318 billion in cash. 

PNM said that the transaction will create a large, diversified national regulated utility and renewable energy platform with approximately $14 billion of rate base and more than four million electric and natural gas utility customers.

AVANGRID is the third largest wind operator in the U.S. and has more than 7.5 gigawatts of installed wind and solar capacity.

“The strategic combination with PNM Resources also provides a platform for AVANGRID to expand its renewables business in the Southwest beyond its existing 1.9-gigawatt capacity wind projects in New Mexico and Texas and 200 megawatts of wind and solar capacity in Arizona,” PNM said in a news release.

PNM said it remains committed to exiting coal

PNM said it remains committed to exiting coal through the approved abandonment of San Juan Generating Station in 2022 and the continued efforts to exit its 200-megawatt ownership interest in the Four Corners Power Plant earlier than originally planned. The plants are located in New Mexico.

PNM said that it sees the potential for additional customer savings by exiting the plant sooner than the expiration of the ownership and coal supply agreements in 2031. “An earlier exit from Four Corners also opens the door for the combined company to bring additional renewable resources onto the grid in support of New Mexico’s increasing renewable energy standards and 2045 carbon-free mandate,” it said.

The transaction is subject to PNM Resources shareholder approval, regulatory approvals from the New Mexico Public Regulation Commission, Public Utility Commission of Texas, Federal Energy Regulatory Commission, Department of Justice, Nuclear Regulatory Commission, Federal Communications Commission and Committee on Foreign Investment in the United States, and other customary closing conditions.

The transaction is expected to close between October and December 2021.

Connecticut-based AVANGRID has two primary lines of business: Avangrid Networks and Avangrid Renewables.

Avangrid Networks owns eight electric and natural gas utilities, serving more than 3.3 million customers in New York and New England. Avangrid Renewables owns and operates a portfolio of renewable energy generation facilities across the United States. Spain’s Iberdrola owns 81.5% of the outstanding common stock of AVANGRID.

Through its regulated utilities, Public Service Company of New Mexico and Texas-New Mexico Power, PNM Resources has approximately 2,811 megawatts of generation capacity and provides electricity to approximately 790,000 homes and businesses in New Mexico and Texas.

FERC approves CAISO’s EV, storage-related demand response proposals

October 21, 2020

by Peter Maloney
APPA News
October 21, 2020

The Federal Energy Regulatory Commission (FERC) has approved tariff revision proposals by the California Independent System Operator (CAISO) designed to enhance demand response using electric vehicle charging stations and energy storage.

The first proposal allows electric vehicle supply equipment (EVSE) to participate in CAISO’s demand response program independently from a host facility.

CAISO said it is seeing a growing number of EV charging stations at large load centers like grocery stores, movie theaters, and offices that frequently operate under the same retail meter and account as their host. Thus, the entire facility must participate as a single metered resource even though the load profiles of the charging station and the host may be very different.

CAISO told FERC that failing to capture the unique load profile of the charging station may send the wrong price signals to the owners of electric vehicles.

To enhance demand response participation in its markets, CAISO proposed allowing EVSE to be treated as a separate load curtailment measure when providing demand response at facilities with onsite load.

CAISO’s proposal does not require those resources to separate EVSE from the rest of their load but, where demand response resources elect to measure EVSE performance separately, CAISO will require the resource to sub-meter the EVSE to avoid co-mingling the EVSE load and the onsite host load’s performance.

The EVSE and onsite host load will continue to operate under a single resource identity and to bid and meet CAISO schedules together as a single resource but will be settled separately based on their individual baselines.

In addition, a proxy demand resource can consist entirely of one or more EVSE resources, with no onsite load, and nothing requires the demand response provider to include onsite load in a proxy demand resource consisting entirely of EVSE. CAISO said the revisions would provide transparency and more accurate price signals for EVSE and onsite load that participate in demand response programs.

In the order, (ER20-2443-000), FERC agreed with CAISO that the revisions would “better capture EVSE’s distinct characteristics, provide more accurate price signals to EVSE owners, and create incentives for them to participate in demand response programs.”

In the second proposal, CAISO requested that behind-the-meter energy storage be required to submit separate bids, for a consumption resource when charging and for a curtailment resource when discharging.

Each bid would have a separate resource identification and its own baseline and demand response energy measurement to establish typical use, using methodologies nearly identical to CAISO’s existing metering generator output methodology.

FERC said that accounting for both energy storage functions “should provide incentives for behind-the-meter energy storage resources to consume energy during oversupply conditions and supply energy during periods of high demand,” enhancing reliability and market efficiency and potentially increasing participation in demand response programs.

FERC, in the Sept. 30 order, also granted CAISO’s request to set the effective date for both proposals to Oct. 1.

CAISO board OKs storage and DER enhancements

In a separate action, CAISO’s board of directors on Oct. 2 approved energy storage and distributed energy resource enhancements designed to make it easier to integrate and operate those resources while maintaining grid reliability, and authorized CAISO management request FERC approval of the proposal.

The approval of Phase 4 of the Energy Storage and Distributed Energy Resources (ESDER 4) enhancements included:

CAISO noted that batteries, both stand alone and hybrid, are fast growing components of the resource mix, with more than 1,500 MW scheduled to connect to the grid by the end of 2021.

FERC issues final rule allowing DERs to participate in wholesale power markets

September 17, 2020

by Paul Ciampoli
APPA News Director
September 17, 2020

The Federal Energy Regulatory Commission on Sept. 17 approved a final rule that allows for distributed energy resource (DER) aggregators to compete in regional organized wholesale electric markets.

The action took place at the Commission’s monthly open meeting, which was held virtually due to the ongoing COVID-19 pandemic.

The final rule, Order No. 2222, enables DERs to participate alongside traditional resources in the regional organized wholesale markets through aggregations, opening U.S. organized wholesale markets to new sources of energy and grid services, FERC said in a fact sheet (Docket No. RM18-9-000).

The rule allows several sources of distributed electricity to aggregate in order to satisfy minimum size and performance requirements that each may not be able to meet individually.

Order 2222 “is a landmark, foundational rule that paves the way for the grid of tomorrow,” said FERC Chairman Neil Chatterjee.

Chatterjee noted that some studies have projected that the U.S. will see 65 gigawatts of DER capacity come online over the next four years, while others have projected upwards of 380 GW by 2025.

“While these estimates and analytical frameworks vary, there is no doubt that investments in these advanced technologies will only accelerate in the years to come, continuing the seismic shifts we’re seeing in our energy landscape,” he said.

Background

In November 2016, FERC issued a notice of proposed rulemaking (NOPR) that proposed to require RTOs and ISOs to revise their wholesale power tariffs to remove barriers to RTO-run wholesale market participation by energy storage resources such as large battery systems.

The NOPR also proposed to require RTOs and ISOs to allow aggregators of distributed energy resources to participate directly in the organized wholesale electric markets, and similarly remove barriers to DER aggregator participation.

In February 2018, FERC voted to remove barriers to the participation of electric storage resources in the capacity, energy and ancillary services markets operated by RTOs and ISOs.

At the same time, the commission said it would convene a technical conference that would be used to gather additional information to help determine what action to take on DER aggregation reforms proposed in the NOPR issued in late 2016, as well as discuss other technical considerations for the bulk power system related to DERs.

At the technical conference, the Commission heard from a wide range of power industry participants, including Paul Zummo, the Association’s director of policy research and analysis and Christopher Norton, director of market regulatory affairs at American Municipal Power.

APPA stressed need for local decision-making in DER aggregation

In response to a Commission notice inviting comments following the technical conference on DER aggregation issues, APPA said that FERC should defer to retail regulatory authorities on whether or not DERs should participate in wholesale aggregation programs and put aside the idea that successful DER participation in the wholesale markets would be best achieved by dictating a uniform approach for RTO and ISO DER aggregation programs.

Specifically, APPA supported a opt-out/opt-in framework for retail regulatory authorities similar to existing regulations for aggregated demand response bids in RTO and ISO markets. Under that framework, large utilities would be given the option to opt-out of DER aggregation and small utilities would need to opt-in. APPA also stated that if Commission declines to adopt such a mechanism, it should, at a minimum, adopt an opt-in mechanism for small distribution utilities.

Final rule builds off recent court ruling on Order No. 841

FERC said that Order No. 2222 builds off a recent ruling from the U.S. Court of Appeals for the District of Columbia Circuit on Order No. 841 in which the court affirmed the Commission’s exclusive jurisdiction over the regional wholesale power markets and the criteria for participation in those markets.

In July, the appeals court issued an opinion that denied an appeal filed by the American Public Power Association and several other parties that challenged certain aspects of Order Nos. 841 and 841-A, which established rules for the participation of electric storage resources in RTO and ISO markets. 

Retail regulatory authorities and small utilities

The rule does not allow retail regulatory authorities to broadly prohibit DERs from participating in the regional markets. However, it does allow retail regulators to continue prohibitions against distributed energy aggregators bidding the demand response of retail customers into the regional markets.

The rule also establishes a small utility opt-in. Specifically, it prohibits grid operators from accepting bids from the aggregation of customers of small utilities whose electric output was four million megawatt-hours or less in the preceding fiscal year, unless the relevant retail regulatory authority for a small utility allows such participation.

“Several commenters raised concerns that costs borne by small utilities and their customer bases may outweigh the benefits of DER aggregation participation in RTO/ISO markets and that small distribution utilities may not have the resources needed to coordinate with aggregators and RTOs and ISOs,” a FERC staff member noted during the meeting.

The rule said that state and local authorities remain responsible for the interconnection of individual DERs for the purpose of participating in wholesale markets through a DER aggregation.

Grid operators must revise tariffs

As a result of the final rule, ISOs and RTOs must revise their tariffs to establish DERs as a category of market participant.

These tariffs will allow the aggregators to register their resources under one or more participation models that accommodate(s) the physical and operational characteristics of those resources, FERC said. Each tariff must set a size requirement for resource aggregations that do not exceed 100 kW.

The tariffs also must address technical considerations such as:

The rule also directs the grid operators to allow DERs that participate in one or more retail programs to participate in its wholesale markets and to provide multiple wholesale services, but to include any appropriate, narrowly designed restrictions necessary to avoid double counting.

Final rule takes effect 90 days after publication in Federal Register

Order No. 2222 takes effect 90 days after publication in the Federal Register.

Grid operators must make compliance filings to FERC within 270 days of the effective date and each compliance filing must propose an implementation plan appropriately tailored for its region and must outline how the final rule will be implemented in a timely manner.

Commissioner James Danly offered a dissent to the final rule.

“I dissent because, regardless of the benefits promised by DERs, the Commission goes too far in declaring the extent of its own jurisdiction and because the Commission should not encourage resource development by fiat,” wrote Danly.

The Federal Power Act delineates the respective roles of the Commission and the states, assigning powers in accordance with each sovereigns’ core interests, he said.

“The federal government is tasked with ensuring just and reasonable wholesale rates, prohibiting state action that would either encumber interstate commerce or harm other states. The states retain authority over the most local of concerns: choice of generation, siting of transmission lines, and the entirety of retail sales and distribution. Each sovereign has a sphere of authority, and in each sphere, the relevant sovereign’s powers are supreme,” wrote Danly.

Respect for the states’ role in the federal system and under the FPA “would counsel against even modest, non-essential declarations of our authority, if done at the states’ expense. Why, when issuing a directive to the RTOs and ISOs (undoubtedly Commission-jurisdictional entities), must we also declare that ‘retail regulatory authorit[ies] cannot broadly prohibit the participation in RTO/ISO markets of all distributed energy resources or of all distributed energy resource aggregators’? Perhaps the states should not or cannot prohibit such participation.”

But it is not “for us to make sweeping declarations regarding the States’ jurisdiction over distributed generation,” Danly argued.

Rather, he argued that the Commission’s jurisdiction over wholesale rates “would ideally be vindicated, were it to collide with a state prohibition, through a challenge to a specific enactment or regulation by making arguments ‘armed with principles of federal preemption and the Supremacy Clause.’”

Apart from FERC’s “injudicious jurisdictional declarations, today’s order stands as an imprudent exercise of the Commission’s power. Why promulgate a rule at all? Reluctance to govern by fiat is counseled particularly in a case like this in which the generation resources the majority seeks to promote, by their very nature, inevitably will affect the distribution system, responsibility for which is assigned, with no ambiguity, to the states.”

FERC should allow the RTOs and ISOs “(or the states or the utilities) to develop their own DER programs in the first instance. If the promises of DERs are what they purport to be, the markets will encourage their development. And if those programs result in wholesale sales in interstate commerce, then the question of the Commission’s jurisdiction will be ripe. Commission directives are unnecessary to encourage the development of economically-viable resources.”

Danly said he has “greater faith in the power of market forces and in the discernment of the utilities and the states.”

PJM market monitor protests market-based filings submitted to FERC

September 16, 2020

by Paul Ciampoli
APPA News Director
September 16, 2020

Monitoring Analytics, the Independent Market Monitor (IMM), recently filed identical protests in at least thirteen market-based rate (MBR) triennial filings at the Federal Energy Regulatory Commission.

Sellers of energy, ancillary services and/or capacity at market-based rates must submit indicative screens to assess whether they have horizontal market power. Certain sellers are required to submit updated screens and other information every three years in these triennial filings.

Last July, FERC issued Order No. 861, which eliminated the requirement for MBR sellers to submit horizontal market power screens for regional transmission organization or independent system operator administered energy, capacity, and ancillary services markets that are subject to FERC-approved market monitoring and mitigation. 

APPA in joint comments with the National Rural Electric Cooperative Association and the American Antitrust Institute, opposed this change to FERC’s regulations. 

Order No. 861 preserves the requirement for MBR sellers to submit horizontal market power screens in RTOs and ISOs without capacity markets — currently the California Independent System Operator and Southwest Power Pool — unless the MBR seller will limit its MBR sales to energy and ancillary services.

In its protests, Monitoring Analytics is not seeking market power screens, but instead argues more fundamentally that “current PJM market rules for market power mitigation are insufficient to support such authorizations.”

The IMM requests that “unless and until the deficiencies in PJM’s market power mitigation rules are corrected, the Commission should authorize participation in the PJM capacity market at market based rates only on the condition that market sellers offer their resources in the PJM Capacity Market at or below the competitive capacity offer,” which is “equal to the Avoidable Cost Rate adjusted for expected Capacity Performance penalties and bonuses.”

Monitoring Analytics also asks the Commission to condition participation in the PJM energy market at market-based rates on market sellers offering their units “at or below the defined cost-based offer” and submitting “operating parameters that are at least as flexible as the defined unit specific parameter limits in the PJM energy market.”

According to the protest, “the Market Monitor has provided ample evidence that the PJM Capacity Market is not competitive due to inadequate market power mitigation” and “of the inadequacies of PJM energy market power mitigation in its State of the Market Reports.”

With respect to the capacity market, the protest references Monitoring Analytics’ complaint from last year arguing that the current default capacity market seller offer cap is excessive and therefore prevents effective mitigation of market power.

APPA, American Municipal Power and the Public Power Association of New Jersey all filed comments in support of that complaint.

Monitoring Analytics said that in the energy market, some sellers that fail the structural market power test, the Three Pivotal Supplier test, are able to set prices with a substantial markup over their cost-based offer, and some “are able to operate, set prices, and collect uplift payments with operating parameters that are less flexible than their defined parameter limits.”

With respect to the submission of screens, the protest said that without adequate market power mitigation, passing indicative market power screens does not provide customers protection from the effects of market power on prices. “Accordingly, it would serve no useful purpose for the Commission to request indicative screen information.”

In each protest, Monitoring Analytics recommended institution of a Federal Power Act section 206 proceeding to investigate whether the existing RTO/ISO mitigation continues to be just and reasonable.

NYISO’s proposed modifications to capacity market rules are rejected by FERC

September 11, 2020

by Paul Ciampoli
APPA News Director
September 11, 2020

The Federal Energy Regulatory Commission on Sept. 4 issued an order rejecting changes proposed by the New York ISO (NYISO) to the buyer-side mitigation rules in its capacity market.

FERC’s decision drew a stinging rebuke from FERC Commissioner Richard Glick, who argued in a dissent that the order is “just the latest in the Commission’s ever-growing compendium of attempts to block the effects of state resource decisionmaking.”

The NYISO’s proposal, which the grid operator said received full stakeholder and market monitor support, would revise the process by which the NYISO determines exemptions from buyer-side mitigation when capacity prices are forecast to exceed certain thresholds following the entry of the new resource, which is referred to as the “Part A” exemption (Docket No. ER20-1718-001).

These provisions are intended to allow for the possibility that a new resource may be entering service at a time of tight capacity, and therefore would not need to have its offer price mitigated.

The NYISO said that the modifications were designed to better reflect the expected expansion of renewable resources and storage resulting from state laws and regulations.

The proposed tariff changes would increase the likelihood that such “Public Policy” resources would qualify for the Part A exemption, primarily by changing the order of preference for the exemption from resources with the lowest project cost to Public Policy resources, among other modifications.

The project cost is no longer the main factor determining which resources will be constructed, the grid operator said. The NYISO said that resources that meet public policy needs are likely to be built and become operational, even if they do not have the lowest Net Cost of New Entry because such resources are “favored by new laws and policies that govern siting and operation of these resources. They are thus more likely to have firm off-takers and receive favorable financing terms from private lenders.” 

The NYISO’s proposed change to the Part A exemption to give preference to Public Policy resources would not reduce capacity prices, and only would change which specific resources receive an exemption.

FERC decision

FERC determined that the NYISO proposal is unduly discriminatory because it does not provide sufficient justification for prioritizing the evaluation of Public Policy Resources before non-Public Policy Resources, independent of cost.

“Further, our finding that NYISO’s proposal is unduly discriminatory is dispositive; we need not reach NYISO’s arguments that its proposal would not cause price suppression,” the Commission said.

In contrast to its orders on the PJM MOPR expansion, in which FERC sought to avoid what it terms  “price suppression” from the participation of state-sponsored resources in the capacity market, in the NYISO order FERC focused only on this differential treatment between Public Policy resources and other types of capacity resources.

Commissioner Glick’s dissent

In his dissent, Glick argued that the Commission “has perverted NYISO’s buyer-side market power mitigation rules into a mind-boggling series of unnecessary and unreasoned obstacles aimed at stalling New York’s efforts to transition the state toward its clean energy future. As a result, those rules have become an unprincipled regime that has little to do with buyers or the exercise of market power.”

Responding to the other Commissioners’ reason for rejecting the proposal, Glick said that Public Policy Resources are not similarly situated for the purposes of the Part A Exemption Test “because they are subject to relatively favorable siting regimes and, as a result of their status under New York law, are more likely to secure the customers and financing that help ensure that they get developed successfully.”

He said that given that the purpose of the Part A Exemption Test “is to facilitate the entry of resources when capacity margins are getting tight and additional resources are needed, the likelihood that the exempted resources actually appear is a highly relevant and distinguishing feature that would support differential treatment.”

Glick said that until recently, the Commission “has long asserted an interest in balancing the effects of state policies with measures to address how those policies affect capacity market prices.  While reasonable minds can disagree over how effectively the Commission struck that balance in years gone by, it is hard to argue that today’s order does anything but confirm that the era of respect for state decisionmaking is over.”

And that, in turn, puts regional transmission organizations and independent system operators “in an impossible position, forcing them to juggle the Commission’s ideological antipathy toward state efforts to shape the resource mix with the realities that Congress gave states responsibility over resource decisionmaking and that the physical system will ultimately, and rightfully, reflect those state choices.” 

The NYISO’s filing “sought to strike a balance between those concerns by taking into account the effects of New York law while avoiding any of the ‘price suppression’ concerns on which the Commission has been so focused. And NYISO appeared to have done so admirably,” Glick said. 

The proposal received a super-majority of votes in the stakeholder process and not a single party protested this issue before the Commission, he noted, including any of the generator groups “that have cheered on the Commission’s slew of recent buyer-side mitigation orders. But, of course, the Commission thinks it knows better than NYISO’s stakeholders, better than NYISO’s Market Monitoring Unit, better than the New York State Public Service Commission, and better than the people of New York.” 

In rejecting the NYISO’s proposal, “the Commission makes clear how little it cares about stakeholder compromise or the consequences its actions will have for the practical reality of running an organized wholesale market,” wrote Glick.

This decision comes in the midst of a New York Public Service Commission proceeding, launched last August to consider how to reconcile the NYISO resource adequacy programs with the State’s renewable energy and environmental emission reduction goals.

Navigating the complex waters of competitive power markets

September 9, 2020

by Peter Maloney
APPA News
September 8, 2020

The complexity of wholesale power markets can seem daunting, especially for smaller players without a deep bench of analysts and traders. But public power utilities looking to navigate those markets can find help in the form of partners such as The Energy Authority (TEA).

Wholesale power markets operated by Regional Transmission Organizations and Independent System Operators use auctions to sell power and other services at the lowest cost, but over time the variety of auctions needed for the various attributes of electric power and its delivery have evolved, creating a bewildering array of rules and regulations.

In addition to day-ahead and real-time spot energy markets, wholesale power markets also often have auctions for products such as capacity and financial transmission rights (FTRs).

The risks of trading in some of those markets were underscored in 2018 when GreenHat Energy defaulted on $150 million of FTRs in the PJM Interconnection market.

GreenHat’s default highlighted some of the complex issues involved in trading in wholesale power markets. 

TEA, which is headquartered in Jacksonville, Fla., provides public power utilities with access to resources and technology that enables them to respond competitively in the changing energy markets.

First and foremost, TEA listens to the goals of the utility, and seeks to understand their focus and goals, Joanie Teofilo, CEO of TEA, said. “We look holistically at their portfolio whether it is solar, gas – whatever those assets are – and how best to optimize their assets and manage risk.”

TEA was founded 23 years ago when it executed its first trade on behalf of its founding members, JEA of Florida, Santee Cooper of South Carolina, and Municipal Electric Authority of Georgia (MEAG Power).

The company was formed in the wake of two landmark orders from the Federal Energy Regulatory Commission, 888 and 889, that were designed to create a competitive market for trading electricity.

Recognizing the “existential threat and unique opportunity” those orders created for public power, the founders came up with a business model that uses economies of scale to give community-owned utilities access to the financial expertise, advanced technology, and operational experience needed to compete in the new environment, according to TEA.

Any one of the founding partners could have done their electricity trading in house, but they realized the economies of scale that belonging to a much larger organization would confer, Jamie Mahne, TEA’s chief client officer, said.

Since its founding, TEA has evolved from a bilateral power trading firm to a company offering public power utilities a range of products and services that include wholesale market management and trading, portfolio management, power supply management, natural gas management, and advisory services.

TEA’s ownership has also expanded, from its three founding member-owners in the Southeast to seven member-owners in locations throughout the country, including American Municipal Power, City Utilities of Springfield, Missouri, Gainesville Regional Utilities, and the Nebraska Public Power District.

TEA now serves about 60 public power utilities and represents over 30,000 megawatts (MW) of generation across all fuel types. The company also consistently ranks as the top power trader by volume among community-owned utilities with approximately 200,000 transactions per year.

While it started in the Southeast, TEA now operates in the wholesale markets of the PJM Interconnection, the Midcontinent Independent System Operator, the Southwest Power Pool, the Electric Reliability Council of Texas, and the California ISO, as well as in bilateral power markets in the Southeast, Northwest and West.

Despite its broad reach, TEA is “agnostic” when it comes to the relative benefits of different regional power markets, Teofilo says. For the most part a utility’s market participation is guided by their geographic location, though some utilities have load and/or generation in multiple markets, she said. “We help utilities derive the most value from whatever market they are in.”

In addition to expanding its geographic scope, TEA has also moved beyond trading for its partners. TEA does portfolio management for some clients, advising them on issues such as when to run their gas-fired generation and when to buy power in the wholesale market or how to hedge their exposure to natural gas price volatility.

The underlying idea is, “What’s the most cost-effective way to deliver lowest cost electric power with minimal risk?” Mahne says. He compares it to “meeting with your financial advisor.”

TEA was built to capture economies of scale, Mahne says, but “now we have this analytical engine that we can point at new problems that have nothing to do with wholesale markets.”

“We are seeing tremendous disruption” in the utility industry, even before COVID-19, in the form of decentralization, digitization and decarbonization, Teofilo says. “Our focus is working together with utilities to take advantage of those opportunities.”

As examples, she noted that TEA has worked with clients to help them decipher and act on the oceans of data generated from Advanced Metering Infrastructure (AMI) and to help clients streamline their requests for proposals (RFPs) process to be able to “see across the board what different developers are quoting.”

TEA can also help clients navigate the more arcane corners of the wholesale markets, for example, virtual products such as FTRs. The use of those products has attracted new players and ignited controversy about the appropriate role, if any, of financial players in wholesale power markets.

Despite failures like the GreenHat default, financial products can be valuable tool in competitive markets, Teofilo says. “They support a well functioning market,” Mahne adds. “It comes down to a liquidity discussion. The more buyers and sellers there are, the more efficient those markets are going to be,” he says.

One of those financial players is TPC Energy Fund, a privately funded power trading firm based in Washington, D.C., that focuses on FTRs.

TPC began trading FTRs in PJM in 2016 and now also trades similar products in the New York ISO and ERCOT.

By providing market liquidity and price discovery, TPC Energy and similar firms allow companies like TEA “to more effectively and efficiently transact in these markets to benefit their clients,” Noha Sidhom, TPC’s CEO, says. “We are the creditworthy counterparties.”

While the GreenHat default has shed a negative light on financial players in the FTR market, “The discussion we should be having is, ‘Do we have rules in place to protect market participants from any type of default?’” Sidhom said.

“PJM has made significant improvements, and we continue to work with them to refine the rules and set up a more secure infrastructure,” Sidhom says. “It’s important for them to have proper collateral requirements and to know their customers’ practices.”

Intense heat, power demand stress California electric grid; DOE issues emergency order

September 8, 2020

by Paul Ciampoli

APPA News Director

September 8, 2020

Several days of intense heat and a spike in power demand has stressed the California power grid, with the California Independent System Operator issuing calls for conservation and the Secretary of Energy issuing an emergency order to help preserve the reliability of the state’s grid.

Despite temperatures of 100 degrees or more over the weekend and the increase in power demand in the state, CAISO was able to avert the need for implementing rotating outages, which it had to turn to last month.

On Saturday, Sept. 5, CAISO reported that consumer conservation helped avoid rotating power outages that day. The grid operator had declared a Stage 2 Emergency, when wildfires took 1,600 megawatts of resources off the grid, but conservation helped avoid further emergencies, including rolling outages.

The ISO issued a Flex Alert to urge consumers to conserve energy during the statewide heatwave that drove up energy consumption.

On Sunday, Sept. 6, CAISO issued a statewide Flex Alert and later in the day declared a statewide Stage 2 emergency due to excessive heat driving up electricity use and putting strain on the grid.

The ISO called the emergency after a transmission line carrying power from Oregon to California reduced its capacity by 900 MW due to the heat and an generation totaling 260 MW tripped offline unexpectedly. The cause of the outages was not immediately known.

The emergency declaration allows the grid operator to use reserve power and to tap into emergency assistance from neighboring balancing authorities.

Ultimately, CAISO said it was able to avoid rotating power outages on Sept. 6 thanks to consumer conservation.

On Labor Day, Sept. 7, CAISO again issued a statewide Flex Alert, noting that temperatures were expected to be above normal statewide for the third consecutive day, driving up electricity demand, primarily from air conditioning use.

The ISO also said that day that it was monitoring several serious wildfires throughout the state threatening power lines. “Weather forecasts show wind will pick up beginning late tonight through Wednesday, increasing fire danger. Wildfires can trip or destroy power lines, reducing transmission and shrinking energy supplies,” CAISO said in a news release.

California governor signed emergency proclamation

California Gov. Gavin Newsom on Sept. 3 signed an emergency proclamation to free up additional energy capacity amid extreme temperatures across California.

The proclamation permits power plants to generate more power by suspending certain permitting requirements, helping to alleviate the heat-induced demands on the state’s energy grid.

Facilities are required to report any violations of these suspended permitting requirements to relevant local and state regulatory bodies. The proclamation also contains provisions related to the use of generators and auxiliary ship engines.

The text of the Governor’s proclamation can be found here and a copy can be found here.

DOE emergency order

On the evening of Sept. 6, the Department of Energy issued an emergency order under section 202(c) of the Federal Power Act to preserve the reliability of the bulk electric power system. The order was issued in response to a request from the CAISO for authorization for “specific electric generating units located within the CAISO balancing authority area to operate at their maximum generation output levels when directed to do so by the CAISO, notwithstanding air quality or other permit limitations.” These generating units, totaling up to 100 megawatts, are referred to as “specified resources.”

Secretary of Energy Dan Brouillette “concurs with the California Independent System Operator Corporation that a grid reliability emergency exists which demands immediate federal intervention,” said DOE spokeswoman Shaylyn Hynes.

CAISO anticipates that the DOE order may result in exceedance of National Ambient Air Quality Standards under the Clean Air Act and notes that specified resources are located in different communities within California and should not result in any disproportionate impact on a single community, Bruce Walker, the DOE’s Assistant Secretary for Electricity, said in the order.

“To minimize adverse environmental impacts, this order limits operation of dispatched units to the times and within the parameters determined by the CAISO for reliability purposes.”

From September 6 to September 13, “in the event that the CAISO determines that generation from the Specified Resources is necessary to meet the exceptional levels of electricity demand that the CAISO anticipates in California, I direct the CAISO to dispatch such unit or units and to order their operation only as needed to maintain the reliability of the power grid in California between the hours of 14:00 Pacific Daylight Time and 22:00 Pacific Daylight Time on days when the demand on the CAISO system exceeds expected energy and reserve requirements,” wrote Walker.

The order also said that CAISO should select the combination of units that meets the reliability emergency and minimizes environmental impact. “Consistent with good utility practice, the CAISO shall exhaust all reasonably and practically available resources, including demand response and identified behind-the-meter generation resources to the extent that such resources provide support to maintain grid reliability, prior to dispatching the Specified Resources.”

The petition that CAISO sent to the DOE and the emergency order are available here.

Public Power Safety Shutoffs

Meanwhile, investor-owned Pacific Gas and Electric Company (PG&E) on Sept. 8 confirmed that customers in the Sierra Foothills, Northern Sierra and elevated North Bay terrain who were notified of an impending Public Safety Power Shutoff (PSPS) were without power.

The PSPS event was affecting approximately 172,000 customers in 22 counties: Alpine, Amador, Butte, Calaveras, El Dorado, Humboldt, Lake, Lassen, Mariposa, Napa, Nevada, Placer, Plumas, Shasta, Sierra, Siskiyou, Sonoma, Tehama, Trinity, Tuolumne and Yuba, PG&E reported.

The process to turn off power to these counties was completed between approximately 9 p.m. Monday evening and 6 a.m. Tuesday morning. Power was scheduled to be shut off in Kern County at approximately 2 p.m. Tuesday.

“PG&E only undertakes a PSPS as a last resort, when it is necessary to do so to protect public safety from extreme wildfire threat,” it said.

The PSPS decision was based on forecasts of dry, hot weather with strong winds that pose significant fire risk. The National Weather Service has placed most of Northern and Southern California, including 1.5 million PG&E customers, under Red Flag Warnings for fire danger. 

Forecasts indicate that the peak period of winds should end Wednesday morning, the utility said.

LADWP experienced power outages over the weekend

The Los Angeles Department of Water and Power reported experiencing power outages over the weekend.

On the evening of Monday, Sept. 7, LADWP reported that crews continued to make progress throughout the day, restoring power to over 22,000 customers since that morning. As of 9 p.m., 23,000 customers remained without power as crews continued working 16-hour shifts around the clock, it reported in a news release.

CMUA details how public power utilities helped CAISO respond to heat wave, stress on grid

In a recent letter to a California state lawmaker, the California Municipal Utilities Association (CMUA) details how public power utilities in the state took a number of actions on the supply and demand side to help CAISO manage stress placed on the California power grid last month due to soaring temperatures.

California last month experienced a record setting heat wave that caused CAISO to initiate at least two Stage 3 emergencies that led to load shedding events, commonly referred to as rolling blackouts.

WAPA, U.S. Bureau of Reclamation tapped hydro to help response to Calif. energy emergency

The Western Area Power Administration and the U.S. Bureau of Reclamation joined forces between Aug. 14 and 19 to generate and transmit roughly 5,400 megawatt-hours in response to California’s energy emergency, the two federal agencies reported in late August.