Power industry participants got their first “peak” at a potential organized market that could rival CAISO’s efforts to expand its own operations into the rest of the West.
During a conference call Tuesday, Peak Reliability and PJM Connext sketched out details on their proposed new Western electricity market, possibly setting up a battle with CAISO over who will oversee markets and reliability across the broad region.
Vancouver, Wash.-based Peak has for months been developing a proposal to expand its Reliability Coordinator (RC) services into a new West-wide energy market. It has partnered with PJM, which brings extensive experience and sophisticated knowledge from its Eastern market covering 13 states and the District of Columbia. (See PJMUnit to Help Develop Western Markets.)
Peak and PJM officials said the market would be nodal, with locational marginal pricing, real-time and day-ahead energy transactions, financial transmission rights, consolidated credit and market settlement, and optional services if desired by participants. These could include ancillary services such as regulation and reserve markets, demand response, a capacity market, and other features.
“Together we have climbed quite a mountain if you will, and this is the next logical step,” said Brett Wangen, Peak’s chief engineering and technology officer. He added that members would have a direct say in the market design and governance with the goal of reducing operating costs and improving reliability. “We definitely have been hearing the message that the industry is in need of these tools.”
Peak and PJM say they will leverage existing market tools and services | Peak Reliability
Wangen also addressed CAISO’s own plans to withdraw from Peak and offer its own reliability services to Western participants. (See Horse is Out of the Barn for CAISO RC Effort.) The ISO recently said it plans to allow Peak participants enough time to review its new RC proposal and switch from Peak to CAISO for services by spring 2019.
“This urgency that is being created is a red herring,” Wangen said. “People believe they have to make a decision in the next few weeks … clearly that is not the case.”
Peak said it is fully funded to provide its current reliability services through August 2019 and it could explore full RTO status after it deploys a new market structure. The organization will continue to be funded at current levels through June 2020, assuming no other members withdraw before September 2019.
Peak/PJM’s Concept for new market offering | Peak Reliability
Peak pointed out that participants could keep Peak as their RC whether they join the Peak/PJM market, participate in other markets such as SPP or CAISO, or continue with self-scheduling and bilateral contracts. They can also use Peak’s balancing authority services or continue with separate balancing authorities regardless of market participation.
Peak said it is developing a straw design for its proposed market and will complete a business case by the end of March or beginning of April. It will then lock in a final design and develop a memorandum of understanding for participation.
CAISO cited increased costs when it announced its plans to depart Peak and provide RC services across the West at much lower costs than are currently charged by Peak. During a conference call earlier this month, ISO officials said they plan to quickly transition current Peak members to CAISO services.
CAISO last month also said it will enhance and expand its day-ahead market across the footprint of its Western Energy Imbalance Market. (See CAISO Plan Extends Day-Ahead Market to EIM.) Peak Reliability member Mountain West Transmission Group is also in discussions to join SPP, and has asked SPP to become its reliability coordinator if it links up with that market.
Peak in 2014 split off from the Western Electricity Coordinating Council, a North American Electric Reliability Corp. Regional Entity based in Salt Lake City, Utah.
Peak on Tuesday said that the partnership’s existing capabilities will allow a relatively quicker development of a market and that a multiple state/province market “offers public policy balance.”
FERC last week rejected a key part of PJM’s controversial proposal to reallocate uplift costs, saying it had failed to justify its plan to begin charging up-to-congestion (UTC) transactions (ER18-86).
The order addresses Phase 2 of a three-phase proposal by PJM to address how to spread the costs associated with uplift more equitably. PJM proposed allocating uplift to UTCs in the same way it is applied to incremental supply offers (INCs) and decrement demand bids (DECs). INCs receive balancing — or real-time — operating reserves. DECs, which are treated like demand, are allocated both balancing reserves and day-ahead operating reserves because they allocated equally to demand bids and exports.
UTCs aren’t allocated any uplift because they were originally created as a way for market participants wheeling power through PJM to hedge against real-time congestion. They later evolved into purely financial products through a series of market rule changes, prompting FERC to open a Section 206 proceeding in 2014 to determine whether they were being improperly favored compared with other virtual transactions. (See FERC Orders Review of UTC Rules.)
Following a lengthy stakeholder proceeding that failed to produce a consensus proposal, PJM proposed treating UTCs as a separate INC and DEC, with the source side receiving balancing operating reserves and the sink side being allocated day-ahead and balancing operating reserves.
PJM argued that although UTCs can change what resources are committed in the day-ahead market and therefore affect uplift, it was “effectively impossible” to measure the impact of individual transactions.
But FERC said because the RTO had “not attempted to quantify the approximate magnitude of UTCs’ impact,” the filing lacked justification for the proposed cost allocation.
“We find that PJM has not adequately justified its supposition that UTCs behave in the markets with sufficient similarity to paired INCs and DECs to support allocating uplift to UTCs in the same way it allocates uplift to INCs and DECs,” the commission wrote. “While PJM claims that its proposal treats UTCs equivalently to INCs and DECs, we find that the proposal essentially allocates uplift to a UTC twice because the proposed allocation methodology would allocate uplift to a UTC as if it were instead a separate INC transaction and a separate DEC transaction.”
Commissioners also questioned the argument that UTCs are identical to a combined INC and DEC because the latter clear the market separately — “allowing for the possibility that one side of a pair may not clear” — while UTCs clear as a whole.
Uplift Proposal Not Dead
While FERC shut the door on this proposal, it remained open to an alternative method for allocating uplift to UTCs, saying, “We recognize that it may be appropriate to allocate some uplift costs to UTCs.”
Proponents of the proposal, including PJM’s Independent Market Monitor, had argued that UTCs carry comparatively lower costs per transaction than do INCs and DECs but are not exposed to the same energy pricing risk, fueling their growth to 80% of the virtual transaction market.
Monitor Joe Bowring found hope in the commission’s ruling.
“The IMM is disappointed in the commission decision but is encouraged by the commission’s openness to UTCs paying uplift,” Bowring said in an emailed statement. “It is clear that the current rules, which entirely exempt UTCs from paying uplift, provide a noncompetitive advantage to UTCs over other virtual trading instruments, as evidenced by the fact that UTCs have pushed the other instruments almost completely out of the market. Any proposal to continue a noncompetitive advantage for UTCs, even a reduced one, will not resolve the market design problem.”
Ruta Skučas, who represents the Financial Marketers Coalition, said members are “thrilled” by the ruling but frustrated that PJM’s stakeholder process did not pre-emptively address FERC’s concerns. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
“We think FERC made the right call,” she said. “We also wish that conversations with PJM and the stakeholders would have been more productive over the five years of the [Energy Market Uplift Senior Task Force]. We spent the better part of two years arguing that a double deviation could not possibly be just and reasonable, instead of working on more productive solutions.”
FERC last week denied FirstEnergy’s request to transfer ownership of a struggling coal-fired merchant generator to a regulated affiliate, saying the deal isn’t in the public interest because it resulted from an “overly narrow” solicitation (EC17-88).
The affiliates argued that the transaction was ostensibly exempt from meeting a rule prohibiting cross-subsidization because it must also be approved by the West Virginia Public Service Commission, but FERC said that didn’t satisfy necessary standards.
“Applicants have provided no evidence that any ratepayer protections regarding cross subsidies are proposed in the proceeding before the West Virginia commission,” FERC wrote.
RFP
The issue dates to March 2017, when FirstEnergy merchant affiliate Allegheny Energy Supply requested permission to transfer ownership of the 1,159-MW Pleasants Power Station to Monongahela Power, with the latter assuming a $142 million obligation for pollution controls Allegheny installed at the plant.
Pleasants Power Station
Mon Power is a regulated utility in northern West Virginia, where Pleasants is located. The utility issued a request for proposals to acquire approximately 1,300 MW of unforced capacity and up to 100 MW of demand response in PJM’s Allegheny Power Systems zone after its 2015 integrated resource plan indicated it would begin having a capacity shortfall in 2016. Charles River Associates, which managed the RFP, identified 28 suitable prospects and recommended acquiring the Pleasants facility, located in Willow Island, W.Va.
Restrictive Requirements
FERC said the RFP was “overly narrow … because the stated objective could have been achieved if the RFP considered [power purchase agreements] and resources that were outside of the APS zone.”
Mon Power’s requirement that it acquire facilities — because of the “increased control and flexibility asset ownership affords,” it said — could instead have been an evaluation factor, “rather than eliminating from consideration an entire class of offers that could have been used.” The commission said two bids for PPAs that weren’t evaluated showed “the desire of bidders to offer PPAs.”
The utility had argued that getting a resource in the APS zone “eliminated” the risk of incurring Capacity Performance penalties because PJM allows resource performance to be netted within zones. But FERC called that risk “rare,” making the limitation “overly restrictive.”
FERC also criticized the RFP’s evaluation method for lacking transparent scoring criteria; announcing a preference for facilities that “can be cost-effectively and efficiently incorporated” into Mon Power’s existing “operating and corporate frameworks;” and using a 15-year net present value metric.
“While we acknowledge that the estimates of future expenses and revenues become more uncertain the further into the future that they are projected, and that the NPV contribution of the years beyond 15 is less important than those within the evaluation period due to discounting, ignoring those future years nevertheless would give advantage to a facility with a low purchase price and higher future costs, such as the affiliated Pleasants facility,” the commission found. “An NPV calculation that calculates the total value of the proposal, including a terminal value, would more closely capture the comparable economics of each proposal.”
Guidance
The commissioners also provided guidance for how Mon Power should have conducted the solicitation.
“While we appreciate and recognize Mon Power’s legitimate need to address a potential capacity shortfall and to provide for its future capacity and energy needs, it should do so in a way that provides non-affiliate competing suppliers with the same opportunity as an affiliate to meet the utility’s needs,” the commission said.
It disagreed with arguments questioning the need for generation or the accuracy of the load forecasts in Mon Power’s IRP, which it said is the role of the state PSC. FERC also dismissed concerns about Charles River’s independence and the restrictiveness of submission timelines.
Consumer advocates and environmental activists had opposed the proposal.
The West Virginia Consumer Advocate said the deal was an attempt to relieve Allegheny of “an aging coal plant that is no longer economic in the PJM” markets.
“In this decision, the FERC commissioners — four of whom were appointed by the current president — unanimously rejected a brazen attempt to force Mon Power … customers to guarantee profits for FirstEnergy and its shareholders,” said Earthjustice attorney Michael Soules. “This is a major victory for West Virginia customers, who would have likely paid hundreds of millions of dollars if FirstEnergy’s scheme had succeeded.”
FirstEnergy spokesman Todd Meyers said the company believes “the decision does not recognize the benefits this vital transaction would bring to our West Virginia customers, including reliable electricity and reduced electric rates, along with creating additional benefits for West Virginia’s economy.”
“We will thoroughly review FERC’s order and carefully evaluate our next options,” Meyers added.
FERC’s ruling last week that “resilience” is not simply a matter of onsite fuel supply won nearly universal praise outside the coal and nuclear industries.
Foley | American Council on Renewable Energy
On Tuesday, a coalition of clean energy advocates and trade groups for the wind, natural gas, solar and storage industries held a celebratory press conference where they praised the ruling as a win for consumers and a sign that the new commission — including three Republicans appointed by President Trump — will remain independent.
“FERC continues to demonstrate that it takes its independence very seriously,” said Todd Foley, senior vice president for policy and government affairs for the American Council on Renewable Energy.
“The professionalism of the [staff and commissioners] — in looking at the question posed by the secretary based on the record before them and thoughtfully determining a path forward — I think is encouraging,” agreed Malcolm Woolf, senior vice president of policy for Advanced Energy Economy.
But while the coalition found unity in opposing Energy Secretary Rick Perry’s price supports for coal and nuclear plants, their interests may diverge in the new docket the commission ordered.
FERC directed RTOs and ISOs to answer questions on how they assess and obtain resilience. The initiative could result in proceedings that pit renewables, natural gas and storage against each other — as well as nuclear and coal — in seeking compensation for their resiliency attributes. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Seeking Market Solutions, Fair Competition
FERC made clear in its ruling that it did not agree with Perry’s embrace of onsite fuel storage as a resiliency panacea.
“That’s maybe one element, but it’s certainly not the only element,” Woolf said. “What really matters is overall system reliability and resilience. We saw from the bomb cyclone of the last week that a nuclear plant — Pilgrim, otherwise perfectly reliable — was forced to shut down because of transmission issues.
“We’re confident [that] as they do this, [FERC] will recognize that advanced energy technologies, including distributed energy resources, energy efficiency, demand response, storage, renewables [and] natural gas … all have a role to play in making a robust system and that the market needs to value the attributes of all of those different technologies.”
Jason Burwen, vice president of policy for the Energy Storage Association, said at the press conference that his group will be watching “whether there will be an opportunity for market mechanisms to be employed such that the full range of resilience attributes — not just a single one like fuel assurance — can be valued and compensated. … Additionally, we look forward to seeing whether there will be a discussion of the infrastructure component of this — not simply the generator resources or demand resources side of this.”
Wiggins | U.S. Energy Association
The California Public Utilities Commission in 2013 ordered the state’s three large investor-owned utilities to add 1.3 GW of energy storage by 2024. The order implemented Assembly Bill 2514, in which the legislature ordered procurement of storage to reduce investments in new fossil fuel plants, integrate renewables and minimize greenhouse emissions.
Dena Wiggins, CEO of the Natural Gas Supply Association, said her group was “relieved” by FERC’s decision. “What we were looking for all along was a robust discussion that would value the attributes of all of the fuels. All of the fuels … bring something to the conversation.”
Whitten | SEIA
“It’s not only valuing those essential reliability services but … making sure there’s no discrimination as to who can actually compete to provide those services,” said Amy Farrell, senior vice president of government and public affairs for the American Wind Energy Association. “The market should reward the desired resilience attributes in a resource-neutral manner, with every provider being paid the same price for providing the same unit of service,” she added afterward.
“I think we’re all in violent agreement,” said Dan Whitten, vice president of communications for the Solar Energy Industries Association. “What we want is the opportunity to compete, and we think the FERC decision … presents that opportunity.”
The new proceeding ordered by FERC will require the RTOs to show how they are obtaining what NERC has named “essential reliability services,” including frequency and voltage support, ramping capability, operating reserves and reactive power. (See NERC Report Urges Preserving Coal, Nuke ‘Attributes’.)
| PA Consulting Group analysis
Last August, the American Coalition for Clean Coal Electricity (ACCCE) released a PA Consulting Group study it commissioned that ranked generation resources on 11 attributes, giving coal high marks in all but black start capability. (See Echoing DOE Report, Industry Study Touts Coal ‘Resiliency’.)
The report followed a study done by The Brattle Group for the American Petroleum Institute (API), which concluded that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes it identified. (See NG Lobby Goes on Offensive vs Coal, Nukes.)
The next best alternative source, according to Brattle, was pumped hydro with 10. Nuclear and coal, the potential beneficiaries of policies favoring traditional “baseload” generation, fared far worse at five and four respectively, as did wind (one) and solar (two).
| The Brattle Group
The API-Brattle report ranked coal as “neutral” on two categories for which ACCCE claimed a full score — frequency response and ramp rates (referred to as “ramp capability” by ACCCE). API did not score three categories in which ACCCE said coal had an advantage over gas: onsite fuel supply, reduced exposure to a single point of disruption and price stability.
AWEA said the API-Brattle findings are “largely consistent” with those of the Analysis Group in a report the organization commissioned. But the wind group disputed Brattle’s designation of wind as “relatively disadvantaged” in frequency response, saying wind turbines “can provide frequency response that is an order of magnitude faster than conventional power plants.”
The Nuclear Energy Institute (NEI) responded that “the Brattle study reinforces the conclusion that grid reliability would be hopelessly compromised without nuclear energy.”
NEI CEO Maria Korsnick said last week that RTOs must take “prompt and meaningful action, including on issues such as price formation.”
“The status quo, in which markets recognize only short-term price signals and ignore the essential role of nuclear generation, will lead to more premature shutdowns of well-run nuclear facilities,” she said.
GHG Emissions and Resilience
Some say resilience efforts also should consider the impact of fossil fuel generators’ emissions.
In his concurring opinion last week, new Democratic Commissioner Richard Glick noted the “irony that the [Department of Energy’s] proposed rule would exacerbate the intensity and frequency of … extreme weather events by helping to forestall the retirement of coal-fired generators, which emit significant quantities of greenhouse gases that contribute to anthropogenic climate change.”
Last month, fellow Democratic Commissioner Cheryl LaFleur said FERC’s environmental reviews of natural gas pipeline applications should consider “the downstream impacts on greenhouse gases.”
None of the three Republicans on the commission has publicly indicated they agree with the Democrats’ concerns, however. As a member of the Pennsylvania Public Utility Commission, Commissioner Robert Powelson was a strong supporter of the state’s shale gas development. Commissioner Neil Chatterjee, of Kentucky, is an unapologetic booster of coal.
“The fact is that we need an electric grid regulatory agency which prioritizes a rapid shift from dirty and dangerous fossil fuels to renewable energy and energy efficiency,” Ted Glick (no relation to Commissioner Glick), an organizer with the anti-gas group Beyond Extreme Energy, said after FERC’s rejection of the NOPR. “We doubt that FERC can become such an agency.”
Coal interests are certain to resist any new FERC rules that speed the erosion of their generation market share.
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
Robert E. Murray, CEO of coal producer Murray Energy, said FERC’s ruling was a “bureaucratic cop-out” that exposed consumers to high costs and service interruptions.
“If it were not for the electricity generated by our nation’s coal-fired and nuclear power plants, we would be experiencing massive brownouts and blackouts,” he said, citing power prices that peaked at more than $500/MWh and natural gas prices that hit $175/MMBtu during the cold snap in early January. “At least 37,000 MW of supposedly natural gas-powered electricity were entirely unavailable due to the priority for home heating use and the inability of natural gas to flow at cold temperatures.”
What is “resilience?” How can you measure it? And how much can be achieved through just and reasonable rates?
Those are the questions FERC and grid operators will be answering following the commission’s rejection last week of Energy Secretary Rick Perry’s proposed rulemaking to benefit coal and nuclear generators (RM18-1).
FERC’s ruling created a new docket (AD18-7) and requires RTOs and ISOs to respond to two dozen questions about how they assess resilience. The commission said it will use the responses to determine whether additional action is necessary. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Defining, Measuring Resilience
FERC teed up the new proceeding by inviting comment on its suggested definition of resilience: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”
It also asked grid operators to identify what attributes contribute to resilience and how they will obtain them. They are likely to look to NERC’s definition of “essential reliability services,” which the commission also referenced in its order. (See NERC Report Urges Preserving Coal, Nuke ‘Attributes’.)
FERC offered less guidance on how the grid operators can measure resilience. There is no widely embraced equivalent to the one-day-in-10-years loss-of-load expectation used as a reliability benchmark.
Also unclear is how much it could cost to meet such a resiliency target; any proposal that increases costs is likely to face opposition from stakeholders serving load. In PJM, for example, load representatives — who have long complained of paying for excessive capacity reserve margins — are opposing the RTO’s “price formation” proposal that could boost costs by as much as 5%.
In FERC filings in October, RTO officials and their Market Monitors unanimously rejected Perry’s Notice of Proposed Rulemaking as expensive, inefficient and counterproductive. (See RTOs Reject NOPR; Say Fuel Risks Exaggerated.)
Predictions
Stoel Rives attorney Jason Johns | Stoel Rives
ClearView Energy Partners said it is “skeptical of FERC making findings within this docket that lead to determinations that existing tariffs in particular RTOs are suddenly unjust and unreasonable on resiliency grounds.”
“Substantive changes to energy market tariffs to increase compensation for ‘baseload units’” are unlikely, ClearView added. FERC “may be more likely to pursue a rulemaking, or set of issue-specific rulemakings or policies, instead.”
“I think it’s safe to say that what comes of compensating resources for ‘grid resiliency,’ to the extent it occurs, will look little or nothing like what Secretary Perry had intended,” wrote Jason Johns, a partner with Stoel Rives, in a blog post.
Prior Efforts
The commission started the grid operators’ 60-day clock with the issuance of the order, making the deadline for their answers March 9. Responses to the filings will be due in an additional 30 days.
The new proceeding will be informed both by state initiatives to preserve in-state generation and RTO efforts that began before Perry’s NOPR and the Department of Energy grid study that preceded it.
The coal and nuclear industries say the RTOs have not addressed market failures unfairly punishing their generators.
“The few revisions to existing RTO/ISO tariffs and related market structures and rules have so far been much too little and far too late,” the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association said in a joint FERC filing in October. “Without action by the commission to remedy these tariffs and market structures, the electric system will devolve to lose the value of fuel diversity and end up overwhelmingly dependent on intermittent renewable and natural gas generation.”
Below is a summary of the RTOs’ prior comments on their resilience efforts and issues that may factor in the new proceeding.
CAISO: Resilience ‘Mechanisms in Place’
CAISO told FERC last year that Perry’s proposed rule would not apply to it because it does not have a capacity market, nor coal or nuclear resources that would be eligible for compensation.
CAISO “already has mechanisms in place that ensure” its resilience, the ISO said. “Regional planning, procurement, coordination, programmatic and reliability efforts in the CAISO [balancing authority area] have produced a diverse infrastructure and ‘set of tools’ that have enabled the CAISO to operate a system that has remained both reliable and resilient in the face of significant threats to the loss of supply such as with the restricted operations of the Aliso Canyon gas storage facility, the unexpected shutdown of the San Onofre Nuclear Generating Station, fires affecting transmission lines, severe droughts and the solar eclipse.”
ISO-NE: ‘No Urgent Need’
ISO-NE told FERC in October that “New England has no urgent need to rush to a solution, given that the three-year Forward Capacity Market has ensured resource adequacy until at least 2021, and the region has already taken steps to improve operating procedures and generator incentives to secure firm fuel supplies.”
Last week, the RTO asked FERC for approval of a controversial two-stage capacity auction intended to replace aging fossil fuel generators with renewable resources from state procurements. (See ISO-NE Files CASPR Proposal.)
| PJM
The RTO says it has improved gas-electric coordination to mitigate supply problems arising from natural gas pipeline constraints. Its Pay-for-Performance program, which offers compensation for dual fuel generators and increases penalties for those who fail to meet capacity obligations, takes effect June 1.
But New England remains vulnerable to the limits of its gas pipeline system, leading some to suggest resilience measures should include contingency plans that consider the loss of a pipeline supplying multiple generators.
“You’d probably be the market that keeps me up at night,” Commissioner Robert Powelson told ISO-NE Vice President of System Operations Peter Brandien in October, when RTO officials made their annual presentations on winter preparedness.
SPP, Exempt from NOPR, ‘Will be Engaged’
SPP was not covered by Perry’s proposal because the RTO lacks a capacity market. The RTO said last week it “applauds FERC’s decision and appreciates [its] commitment, through the opening of a new docket, to continue to ensure our nation’s electric grid is both reliable and resilient. As with all of FERC’s efforts, SPP will be engaged in this new docket.”
The RTO has been integrating increasing amounts of wind, thus far without reliability problems. Last month, the RTO set a new record for wind penetration (56.25%), lending credence to its claims that it can handle penetration levels as high as 75%.
SPP’s 40% capacity margin is well above the 12% minimum required by the SPP Tariff, Keith Collins, executive director of SPP’s Market Monitoring Unit, noted in comments to FERC in October.
MISO Welcomes ‘Broader’ Discussion
MISO spokesperson Mark Brown said last week the RTO is looking forward to a “broader industry discussion around resilience and its importance” with FERC, state regulators and other industry officials.
“As FERC noted in its order, MISO is involved in ongoing development of a long-term plan to address changing system needs as the resource mix evolves,” Brown said in a statement to RTO Insider. MISO’s plan involves multiple studies, including an analysis on the challenges of integrating growing volumes of renewable generation and how the natural gas supply affects its dispatch ability. (See MISO in 2018: Storage, Software, Settlements and Studies.)
The RTO has been stymied in its attempts to address resource adequacy concerns in Zone 4 in Southern Illinois, where Dynegy has threatened to close some of its coal-fired generation, citing insufficient capacity revenues.
The Illinois Clean Jobs Coalition responded to the FERC ruling by urging the ICC “follow the lead of FERC and reject Gov. Rauner’s proposal to bail out uneconomic coal plants in Illinois.”
The commission will hold another workshop Jan. 16. Final comments on the issue are due Jan. 30, and the commission is expected to issue a summary report by Feb. 26.
PJM Price Formation Proposal Faces Opposition
PJM responded to the DOE NOPR by calling for rule changes that would allow inflexible generators, including coal and nuclear plants, to set LMPs. At its final stakeholder meeting of the year, the RTO won endorsement for a stakeholder task force to examine the current rules and recommend fixes.
PJM estimates the energy market changes will reduce capacity market costs but still increase overall costs between 2 and 5% ($440 million to $1.4 billion annually). (See Rule Changes Could Spur $1.4B Jump in PJM Market Costs.)
Conesville Coal-Powered Plant
Monitors, regulators and other RTOs filed comments opposing PJM’s proposal in November. PJM Independent Market Monitor Joe Bowring said the plan would undermine the RTO’s markets and suggested that the RTO was acting in the interest of Exelon, which would be the biggest winner from a boost to nuclear plants. (See NOPR Reply Comments Bring More Criticism of PJM Proposal.)
Beginning in delivery year 2020/2021, all PJM capacity resources must meet the RTO’s Capacity Performance requirements. The CP program employs performance penalties and bonuses like ISO-NE’s Pay-for-Performance initiative.
ERCOT Joining with PUC on Response
At the Texas Public Utility Commission’s open meeting Thursday, Chair DeAnn Walker said she is working with ERCOT CEO Bill Magness and General Counsel Chad Seely to prepare a response to FERC’s order.
ERCOT’s markets are not regulated by FERC, but the grid operator is subject to mandatory reliability rules overseen by the commission and NERC. The PUC has always aggressively defended ERCOT’s independence from federal oversight.
Walker characterized the filing as informational, saying it would “explain how we do things here.” She said she, ERCOT’s leadership and Texas Reliability Entity CEO W. Lane Lanford “have similar thoughts about how broad” FERC’s request is. She promised further details for a February open meeting.
FERC’s influence on the future of coal and nuclear generation will not be limited to the new docket. It may again be asked to weigh in on whether state efforts to support in-state generators violate federal jurisdiction. The Supreme Court has ruled on three cases concerning state-federal jurisdiction since 2015. (See Court’s Reticence Frustrates Energy Bar.)
The commission already has pending a request from the Electric Power Supply Association to apply the minimum offer price rule to nuclear units receiving payments under Illinois and New York’s zero-emission credit programs. The ZEC programs are also being challenged in federal court. (See Ill. ZECs Defenders Face Harsh Questioning on Appeal.)
NYISO Moving on Carbon Pricing
Despite the legal challenge to its ZEC program, New York officials last week continued working on their plan for funding the subsidies — integrating carbon pricing in NYISO’s wholesale electricity markets. (See New York Stakeholders Debate Carbon Policy ‘Issue Tracks’.)
“There is no imminent threat to reliability,” NYISO told FERC in October. During the 2014 polar vortex, NYISO noted, it set a new record winter peak load and “met all reliability criteria and reserves requirements without activating emergency procedures at any time during the winter operating period. It did so despite significant generator capacity derates on some of the coldest days, including generation resources that would appear to qualify under the NOPR as ‘eligible grid and reliability resources.’”
The ISO said it has made improvements to its energy, ancillary service and capacity markets, including basing the downstate installed capacity demand curves on peaking plant designs that include dual-fuel capability.
State Initiatives
Here are some of the state initiatives that could become factors:
The New Jersey Legislature is expected to consider a ZEC-style plan in its 2018-19 session. ClearView analysts last week gave the plan a 65% chance of success, saying the Democrat-controlled legislature’s refusal to consider the bill in the lame duck session was intended to deny outgoing Republican Gov. Chris Christie a policy “win.” (See NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
Ohio lawmakers last year proposed legislation (H.B. 381 and S.B. 128) that would create a ZEC-style program that would benefit First Energy Solutions’ Davis-Besse and Perry nuclear plants, but the bills did not move out of committee. The term of Gov. John Kasich, who has opposed a nuclear “bailout,” expires in January 2019.
Connecticut is also considering whether it needs to sign a long-term power purchase agreement to keep the Millstone nuclear plant operating amid a dispute over the plant’s profitability. (See related story, Conn. Regulators Hear Conflicting Advice on Millstone.)
“We applaud the commission for upholding the rule of law and taking the only appropriate actions under the circumstances,” the National Association of Regulatory Utility Commissioners said in a statement last week. “We also appreciate FERC’s acknowledgment that resilience issues ‘extend beyond the commission’s jurisdiction’ and its explicit encouragement for interested entities to engage with state regulators and others to address resilience at the distribution level.”
Amanda Durish Cook and Tom Kleckner contributed to this article.
AUSTIN, Texas — Taking a cue from other state regulators, the Public Utility Commission on Thursday took its first steps in determining how to share federal corporate tax cuts with ratepayers.
PUC Chair DeAnn Walker directed staff to begin gathering information from utilities and considering legal options to recover the savings. She referred to 1987, “when similar things were done” following tax cuts under President Ronald Reagan.
Southwestern Electric Power Co., Oncor and El Paso Electric have already agreed to claw back tax savings during recent rate-case settlements. Two additional utilities are scheduled to undergo rate reviews in May.
The commission, which hopes to avoid a rulemaking, will take up the issue again during its Jan. 25 open meeting.
Commission to Strengthen Education Efforts with Legislature
The commission agreed with Commissioner Brandy Marty Marquez’ suggestion to “re-up” its efforts to educate state legislators and others about potential price spikes this summer in the wake of recent plant retirements.
“To quote someone else, this is an opportunity for our market’s finest hour,” Marquez said, referring to Winston Churchill. “I think we’re going to be fine … we just need to make sure people are educated about how our market works. People need to know what’s going on and prepare for it, because this is part of a natural cycle.”
Cheaper renewable and gas-fired energy has reduced coal generation’s share of ERCOT’s production to less than a third and led to a wave of coal-fired retirements last year. That, in turn, sliced the ISO’s planning reserve margin to 9.3% for this summer. (See Wind Nearing Coal as ERCOT Ponders Thinning Reserves.)
Walker said she has already briefed Gov. Greg Abbott on possible “price elevations” this summer. She decried comments made last year during PUC-led workshops on scarcity pricing and other price-formation issues in ERCOT’s energy-only market (47199). (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
“A lot of people used 47199 as rhetoric to scare people, including us,” Walker said. “We need to say we think we have this.”
Staff Publishes Revisions to IOU Earnings Reports
PUC staff on Friday published its proposal for revising the earnings monitoring reports that investor-owned utilities must file. The reports reflect the 12-month period ending Dec. 31 and are due by May 15.
Staff originally intended to make only minor revisions but added other modifications reflecting recent changes to federal income tax law and eliminating two schedules because of recent legislation.
Invenergy-CSW Energy Joint Venture Approved
The PUC approved a joint venture between Invenergy Renewables and CSW Energy to repower a pair of West Texas wind farms. Invenergy will become a 20.1% owner of the Trent Wind Farm and Desert Sky Wind Farm, with CSW holding on to the remaining 79.9% (47637).
Desert Sky Wind Farm | AEP
The wind farms currently have 207 1.5-MW turbines for a capacity of 310.5 MW.
CSW is a wholly owned subsidiary of American Electric Power, retaining its name following the 2000 merger between AEP and Central and South West.
FERC last week allowed NYISO to temporarily waive energy offer caps in response to recent natural gas price spikes stemming from this winter’s extreme cold snap in the Northeast.
The commission’s order granted NYISO a limited waiver on incremental energy offer caps in both the real-time and day-ahead markets from Jan. 4 through Feb. 8, allowing generators to recover exceptional costs for procuring high-priced fuel (ER18-604).
“The waiver addresses the concrete problem that generators might be required to provide service to reliably serve load but without being able to recoup the incremental operating costs that they incur, which could discourage generators from offering service at a time when they are needed,” the commission said.
In its Jan. 4 filing, the ISO noted that New York City temperatures were 24 degrees Fahrenheit below average early this month and that the resultant spike in natural gas prices could cause some generators’ actual costs to exceed the offer restrictions.
In granting NYISO’s request, the commission noted that such waivers will no longer be necessary at the end of this year when the ISO implements the reforms required by Order 831 “because these reforms are intended to provide for a long-term solution to the issues associated with NYISO’s offer cap.” Order 831, issued in November 2016, requires each RTO/ISO to cap a resource’s incremental energy offer at the higher of $1,000/MWh or its verified cost-based incremental energy offer, and cap verified cost-based incremental energy offers at $2,000/MWh when calculating LMPs.
The commission said the ISO’s Market Mitigation and Analysis Department will verify after-the-fact analysis of costs submitted by generators. It directed NYISO to file by March 28 the total amount of energy that received compensation under the terms of the instant waiver; the related costs in total and on a unit cost basis; and a list of rejected requests for compensation under the waiver and why the ISO rejected them.
Record Cold, Record Gas Pull
NYISO noted that Jan. 5 day-ahead natural gas prices at the Transco Z6 NY hub exceeded $48.99/MMBtu, “more than double the highest price posted for that hub in 2016 and 2017, and more than five times the highest price seen at the Transco Z6 NY hub in January or February of 2017.”
Weekly changes in natural gas storage | EIA
Gas prices at the hub exceeded $100/MMBtu on Jan. 6, after NYISO submitted its filing.
John F. Kennedy International Airport set a record low of 8 degrees on Jan. 6 and several ski resorts in Vermont shut down that day because of wind chill factors as low as minus 50.
According to the Energy Information Administration, during the recent cold snap, more natural gas was withdrawn from storage fields around the country than at any other point in history: “Net withdrawals from natural gas storage totaled 359 Bcf for the week ending Jan. 5, exceeding the previous record of 288 Bcf set four years ago.”
VALLEY FORGE, Pa. — Despite stakeholder requests, PJM remains disinclined to create procedures to analyze any other cost containment guarantees beyond construction cost caps, the RTO’s Sue Glatz said at last week’s Planning Committee meeting.
The issue arose during a discussion of proposed changes to Manual 14F that would allow PJM to consider construction cost caps, for which the RTO was seeking stakeholder endorsement. The position created an unusual endorsement vote, which had to be manually counted.
“This is representative of what we’ve decided we’re doing now,” PJM’s Steve Herling said.
The proposal passed with 83 votes in favor, one abstention and 27 votes in opposition, the last of which included LS Power, the Consumer Advocates of the PJM States (CAPS), the PJM Industrial Customer Coalition, American Municipal Power and the Public Power Association of New Jersey.
LS Power’s Sharon Segner was concerned that PJM seemed to have changed its stance from limiting itself to only enforcing construction cost caps because they provide the best opportunity for controlling costs, to deciding it doesn’t have the legal authority to consider other parts of proposals, such as return on equity.
“We think that PJM does have the legal authority. It’s really an issue of will,” Segner said.
“We don’t have the ability to enforce all those other elements. Those are regulatory decisions, and they have to be enforced through regulatory processes. We have the legal authority to do whatever FERC tells us to do,” Herling said. “We believe … based on our perception and our opinion that the most value is in capping the construction costs. … We’ll see what FERC says.”
“Any limit to cost caps … limits the benefit that customers can receive,” AMP’s Ryan Dolan said.
“We certainly want [PJM] more involved in this process,” said Greg Poulos, executive director of CAPS.
PJM’s Alex Worcester informed stakeholders that the Trial 3B cases and contingency errors from the Regional Transmission Expansion Plan were sent to transmission owners Jan. 5 and that all “pre-final” RTEP cases will need to be delivered to the transmission planning division by Feb. 1. Pre-final cases for 2020 RTEP short circuits were sent to TOs on Dec. 22. Final cases will be sent on Jan. 16, along with draft 2023 cases. TO feedback is due Jan. 23, with the pre-final case sent back to TOs on Jan. 29.
Interconnection Agreements
PJM’s proposal to add another installment to its Manual 14 series created concerns for some stakeholders. The RTO is planning to move some information from Manual 14A into a new Manual 14G focused on generation interconnection requests.
The RTO would also change some procedures, including adding a clarification that developers that subdivide a project into multiple projects behind a point of interconnection (POI) will have one interconnection agreement with PJM and a single entity controlling the POI. This change would require all projects to be grouped into a single company, or move the POI closer to each cluster of generating units, rather than grouping them all together.
| PJM
“Moving the point of interconnection gives us pause in a couple of areas,” said John Brodbeck of EDP Renewables. He noted additional construction work and coordination “that adds a whole series of risks,” along with questions about who owns and operates the interconnection lines and whether that entity has regulatory obligations.
“We don’t know why PJM wants to move away from the shared facilities agreement. It works for us, and it seemed to work for you,” he said.
PJM’s Lisa Krizenoskas said the current process creates unnecessary complexity in the contracts and is administratively burdensome because all the agreements have to be updated to reflect later changes. There are also differences in requirements that can be hard to measure.
Brodbeck asked that PJM assure that requests already in the interconnection queue be able to retain their single interconnection agreement.
High-Voltage Solution in Dominion Zone Draws Questions
PJM’s plan to address high-voltage issues in southern Virginia by installing two static synchronous compensators, known as STATCOMs, raised eyebrows among some stakeholders who questioned whether cheaper alternatives were available. A STATCOM is an AC network regulating device that can act as either a source or sink of reactive power.
“I’m just looking at it trying to determine if we are we adding options that we don’t really need,” said Dave Mabry, who represents the PJM Industrial Customers Coalition.
Dolan asked why “optimally” sized shunt reactors weren’t used instead.
“Switching of reactors is a pretty disturbing system event,” PJM’s Mark Sims explained. “We don’t consider the reactors in this situation to be a solution, which is why we’re recommending STATCOMs.”
“The bottom line is the reactor is not an acceptable solution,” Dominion Energy’s Ronnie Bailey said. “I don’t care how many you want to put on the system. … Can it meet the performance required for the job? It cannot meet the performance.”
Sims said that STATCOMs provide a “larger dynamically variable device.” The project is expected to cost $100 million.
PSE&G Project Sparks Prudency Debate
A $546 million project from Public Service Electric and Gas to replace a 50-mile 230-kV line in western New Jersey continued to cause debate at last week’s Transmission Expansion Advisory Committee meeting.
According to PSE&G, the facilities have reached their end of life based on FERC Form 715 criteria and condition assessments, but Dolan and Ed Tatum, also with AMP, questioned how those determinations were made. AMP argued that there’s no standardized analysis for others to confirm PSE&G’s findings, nor any scenario planning to determine if more or less construction is the best route.
PSE&G and PJM agreed the line can’t be removed completely, nor can it be determined — with several southern New Jersey generator closures imminent — what the future power flow will look like.
“We’re property constrained. We have a right of way. To do something out of that right of way would be cost-prohibitive, and we can’t do nothing,” PSE&G’s Alex Stern said.
“If it goes away, you could lose it forever,” Sims said. “We’re going to build it to double [circuit]; we’re going to string one circuit, then we’re going to wait and see.”
“If we’re accounting for scenarios, we should study for those scenarios,” Dolan said. “If the line’s loading [above its rating] … I’m not going to question that [prudence]. I’m just saying show it to us.”
Other stakeholders agreed that the right of way must be maintained.
“I like scenario planning, but it’s hard to get corridors, especially in New Jersey,” Calpine’s David “Scarp” Scarpignato said. “It seems prudent to me. I think it saves ratepayers money in the long run.”
Dolan expressed concern that PSE&G is “gold plating” the system. PJM’s Paul McGlynn said TOs have criteria that they build to.
“You can just thank me for my comment on this one and move on: My sense is you guys haven’t gotten all your homework done on this one,” Tatum said.
“OK. Thank you for your comment,” Sims responded.
“This is a 90-year-old line,” Stern said. “To say that it’s not prudent, that we’re gold-plating or that we haven’t done our homework borders on the absurd.”
PSE&G also addressed questions about whether it delayed presenting the project until it was needed immediately. The question arose from pictures of structural issues on the line that are dated from 2013. PSE&G said that year it did foundation-condition assessments in accordance with its maintenance practices. It reviewed the structure foundations and fixed any issues. However, the analysis confirming the end of life for the tower structures occurred after that and was only recently completed.
The project will be presented to the PJM Board of Managers for approval at its February meeting. Tatum asked if his remaining questions would get answered before the meeting. McGlynn said PJM would attempt to do so.
“I don’t think there’s any outstanding questions … is the facility at the end of its life or not,” Sims said. “It doesn’t change the need for the project or what we’re going to present to the board.”
AUSTIN, Texas — State regulators Thursday agreed to “marinate” on an administrative law judge’s order approving AEP Texas’ request to connect a pair of utility-scale lithium ion battery facilities to the ERCOT grid.
Public Utility Commission Chair DeAnn Walker said she will file a memo in the docket (46368) explaining how she would like to move forward, while Commissioner Brandy Marty Marquez asked for another chance to discuss the matter publicly and said a rulemaking may be needed.
“The PFD [proposal for decision] did make some strong points,” Marquez said. “A lot of what we’re working through is a market that we all love and how to [incorporate batteries]. They are coming, so how does that happen?”
The order is opposed by a “diverse range of market participants,” observed Emily Jolly, legal counsel for Luminant and TXU Energy, which oppose AEP’s proposal. The opponents include Calpine, the state Office of Public Utility Counsel and several consumer organizations, who argue that allowing the assets to be included in AEP’s regulatory base would harm competition.
“The goal of competition is to minimize regulatory facilities, not encourage them to proliferate,” Jolly said. “What the PFD does not explain is why preserving the market structure is beneficial. Competition fosters innovation and efficiency. We’ve seen that play out” in ERCOT.
Attorney Kerry McGrath, representing AEP, said the batteries would be used “very, very infrequently. Twelve times a year, on average.” They would also not be used for commercial activities, he said.
AEP filed its application in 2016. ALJ Stephanie Frazee’s October decision would allow the facilities to be classified as distribution assets and included in AEP’s cost-of-service rates.
The company wants to install the 1-MW and 50-kW battery facilities in remote areas of West Texas, setting them to automatically discharge during an outage or to serve additional loads. It has proposed the energy be accounted for as “unaccounted-for energy (UFE),” which ERCOT defines as the difference between the system’s total generation supply and the total system load plus losses.
“By allowing these facilities to be settled through UFE, you would be charging one set of customers when the battery is charged, then give free energy away to another set of customers,” said attorney Katie Coleman, speaking for the Texas Industrial Energy Consumers trade association. “The settlement mechanism was never intended for this purpose. We’re concerned about distortions to pricing in the market and ratepayer-subsidized facilities participating in the wholesale market.”
PUC staff also intervened, saying the commission should open a rulemaking if it approves the ALJ’s order. OPUC’s Sara Ferris agreed with staff and said the batteries should be classified as generation assets.
“The rulemaking should be sufficiently broad to encompass other alternatives besides batteries,” Ferris said.
“I agree a rulemaking is in order here,” Marquez said. “This is new.”
VALLEY FORGE, Pa. — PJM’s Tim Horger provided an update on the RTO’s efforts to comply with FERC’s plan on fast-start pricing at last week’s Market Implementation Committee meeting. The commission last month withdrew its Notice of Proposed Rulemaking on fast-start pricing because it said a uniform set of requirements isn’t appropriate for all RTOs and ISOs. Instead, it called on PJM, SPP and NYISO to make changes. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
Horger said PJM’s initial response is due Feb. 12 and that a final order is expected on Sept. 30. FERC indicated that PJM should:
Allow for relaxation of all fast-start resources’ economic minimum operating limits by up to 100%, such that the resources are considered dispatchable from zero to their economic maximum operating limit for the purposes of setting prices;
Apply the relaxation of a resource’s economic minimum operating limit to all fast-start resources, not just block-loaded fast-start resources;
Consider fast-start resources within dispatch in a way that is consistent with minimizing production costs, subject to appropriate operational and reliability constraints;
Modify pricing logic to allow the commitment costs of fast-start resources to be reflected in prices;
Include in the definition of fast-start resources a requirement that those resources have a minimum run time of one hour or less;
Include in the definition of fast-start resources a requirement that those resources be able to start up within one hour or less; and
Set forth its rules and practices regarding the pricing of fast-start resources.
Horger said PJM plans to “generally support” the suggestions and provide additional feedback, including the definition of “fast start.” It will also supply recommendations on the relaxation method between economic minimum and “integer relaxation” — a pricing method designed to minimize uplift costs.
Day-Ahead Market LMP Confusion
Horger also provided an explanation of a situation that created stakeholder confusion when PJM announced it planned to revise day-ahead market LMPs, then retracted that plan: The aggregate percentages for the IMO interface — the pricing point between PJM and Ontario’s Independent Electricity System Operator — for Dec. 26 to 30 were “slightly off.”
Upon further review, staff determined that the issue was minimal and didn’t violate the Tariff, so they decided to retain the original values instead of disturbing the market.
Stakeholders pointed out that PJM’s series of communications, which initially said a change would be made before later reversing that decision, was confusing.
“Your feedback is on target. … We probably caused some confusion by jumping the gun,” PJM’s Stu Bresler said.
The normal process would be to announce that an issue was found and then later announce revisions will be made once the determination is complete, he said, instead of announcing them both initially.
“Historically, when we think a situation is cut and dry, we combine the first two steps: announcing the issue and saying we’re going to change things,” he explained. “We should have issued the notification that we found something, but not” the announcement that changes would be made.
Market Impacts of Cold Weather
PJM’s Joe Ciabattoni told stakeholders to expect more uplift from the cold snap that occurred over the holiday break, but “nothing near” the market impacts from the cold streak in 2014 known as “the polar vortex.”
“We had a couple of $2 million days,” he said, but “I don’t think that the magnitude will be anything near what we saw in the polar vortex” when there were days of $86 million and $50 million. The difference this time, he said, was that the cold temperatures were sustained.
“In 2014 and 2015, the temperatures were more extreme, though not as long of a time frame,” he said.
Unplanned outages began to “crop up” near the end of the cold period on Jan. 6, but conditions never triggered requirements that maintenance outages close out within 72 hours. Ciabattoni said there were “plenty” of new 30-minute reserves measurements developed to help address gas pipeline contingencies.
“We’re getting [outage] tickets in early, as opposed to the polar vortex, when we were surprised by some outages,” he said.
Stakeholders approved a problem statement and issue charge on remapping financial transmission rights nodes. PJM’s Brian Chmielewski explained that the nodes where FTRs begin or end can be terminated based on changes in load, generation or system topology. When that happens, an “electrically equivalent” node must be identified to replace the terminated one. PJM’s current process for that search “may not guarantee an optimum substitute” that provides the same economic value and might lack transparency.
Direct Energy’s Marji Philips expressed concern with the wording of the problem statement.
“The problem is if PJM can’t find [an electrically equivalent node], it just flat out terminates the FTR,” she said. “I’m not sure the statement actually captures that.”
Rules Endorsed for Enforcing Regulator Requirements on EE
With three abstentions, stakeholders endorsed rule changes that will allow state and local regulators to manage energy efficiency participation within their jurisdiction if they receive FERC approval.
PJM’s Pete Langbein explained the process, which stems from a December ruling in which FERC established its “exclusive authority” over EE participation in wholesale markets while also preserving a carveout it had previously approved for Kentucky utilities. (See FERC Claims Jurisdiction on EE, OKs Ky. Opt-Out.)
Under the new process, PJM must alert all affected electric distribution companies about the impact of any such FERC approvals. EE that cleared the auction but isn’t allowed to deliver into a particular jurisdiction may be relieved of the commitment. EE providers will need to itemize deliveries in American Electric Power and Duke Energy zones whether or not they are in Kentucky. EDCs will review a list of whether that provider is allowed to deliver in Kentucky based on the relevant regulators.
Financial Traders Question IMM on Long-Term FTR Concerns
Seth Hayik of Monitoring Analytics, PJM’s Independent Market Monitor, presented analysis of data that the Monitor argues show that long-term FTRs aren’t improving the market. Financial stakeholders, who trade in the long-term FTR markets, questioned the findings.
Long-term FTRs, which are available for each of the next three planning years or a combination of all three, are intended to provide hedges for transmission congestion by reflecting the conditions expected in the future situations.
“They’re not reliable,” Hayik said. “What comes out of the long-term FTR modeling doesn’t necessarily reflect what’s going to” happen. PJM has taken steps to correct what it could in the model for the nearest planning year, but “I don’t know that there is a solution for those models” for the subsequent years, he said.
Financial traders acknowledged that the risk of erroneous predictions is intrinsic to forward markets.
“Generally, forward markets are forward markets, and you buy in those markets without perfect vision of what will happen when those become spot markets,” Vitol’s Joe Wadsworth said. “That’s true of any future market. You don’t have foresight into what could go right or could go wrong in those markets. You make your decision on value.”
“Look how competitive the markets have become,” DC Energy’s Bruce Bleiweis said. “That’s the evolution of a market; they become more and more competitive over time.”
The Monitor said prices have really been driven down by 50% reductions in line congestion, but Bleiweis said its data showed that market alignment has improved by 90%. He credited the long-term FTR market for the additional improvement.
“We support what [the Monitor] is doing,” she said. “We would like to understand the impacts.”
Monitor Joe Bowring said better market structure in the single-year products “doesn’t mean the outcomes are competitive, and the outcomes are what we need to focus on.”
“In a competitive market we would expect to see the excess profits competed away, but that has not happened,” he said.
Stakeholders Battle PJM, Monitor on Market Path Alignment
Stakeholders continued to criticize proposals by PJM and the Monitor on a rule for evaluating designated market paths for energy sales coming into the RTO. The members have called for caveats that would allow them to explain their reasoning for paths PJM or the Monitor find questionable.
Along with their existing joint proposal, PJM introduced one that didn’t include Monitor endorsement. It excludes applying the rule to scheduled long-term path activity — annual, monthly or weekly — but allows for “potential referral” to FERC enforcement if “manipulative behavior” is suspected.
The proposal placated no one.
“The whole point of the original proposal was to have a rule. If there is no enforceable rule … then the rule is meaningless,” Bowring said. “I think the point of the rule is clear: It’s to prevent one participant from taking actions at the same time in different directions, explicitly manipulating the market.”
American Electric Power’s Brock Ondayko complained that the proposals seemed to tell participants “you can’t do this transaction because when we put it together with your other transactions, we see this grander transaction and that’s not allowed even though it might make complete financial sense to do that.”
“I don’t think we’re going to be very supportive of the idea of just prohibiting paths and referring people” or immediately resettling transactions because stakeholders could “get caught in a net,” said Carl Johnson, who represents the PJM Public Power Coalition.
Bowring assured that there’s no “automatic referring” in the joint proposal, but he reiterated that a definitive rule is necessary. “These can occur and will occur if permitted. We know that for a fact,” he said.
“A lot of what PJM [and the Monitor are] suggesting they’re going to do is discriminatory,” said Stephen Kelly of Brookfield Energy Marketing. “Every other company in this room is able to do that transaction.”
He called for allowing stakeholders “to present hard evidence … that these are separate transactions” based on different strategies. “We don’t think that’s asking too much.”
Emergency Pipeline Switching Instructions Sparks Rights Debate
PJM’s Rich Brown presented a proposed problem statement and issue charge on fuel switching that sparked pushback from stakeholders.
The proposal focuses on how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as backup oil or a different pipeline. Gas-fired operators argued that PJM’s plan would disincentivize flexibility and fails to recognize or sufficiently compensate operators who have paid extra for guaranteed pipeline capacity.
Being forced to switch fuel sources can decrease unit performance and increase the risk of the plant tripping off, Calpine’s David “Scarp” Scarpignato said, so “I’m actually being put in a worse situation for being more flexible.”
PJM’s Chantal Hendrzak acknowledged the RTO might need to identify other “attributes” for which generators should be compensated.
“There’s a recognition to do that,” she said. “It’s something that we realize that we need to talk about, but not only talk about, but figure out how to do.”
“In general, what you’re trying to do is a good thing,” said John Horstmann of Dayton Power & Light. “Given the fact that you’ve never done this before … what is the rush? … It looks like a short-term reaction with some big implications for generation-ownership rights and financial risk that are unresolved.”
“We have learned a lot,” Brown said. “As we educate ourselves, that has led us to operationalizing gas contingencies.”
Putting it all together, Hendrzak said, “that conversation might take a while.”
Bowring called the proposal “very reminiscent of cost-of-service in its worst sense. … This approach relies on command and control rather than market forces.
“I would ask you to put the market design elements into this,” he said. “How to get gas constraints into the market, that’s the real issue.”
Other stakeholders questioned who would pay for the additional compensation.
“We don’t think the costs should be on load,” said Dave Mabry, who represents the PJM Industrial Customer Coalition. The costs should be on the generators who don’t have guaranteed service to ensure “we are incenting folks to get the fuel supply they need and firm that up if necessary.”
Citigroup Energy’s Barry Trayers noted that the Capacity Performance rules and payments were designed to handle those needs.
PJM staff said they are in contact with pipeline companies to discuss these issues but stopped short of confirming they will be involved in the stakeholder process.
“It would be great if we could get some participation in the stakeholder meetings,” Hendrzak said. “I’m not sure if that will actually happen.”
