Speaking during a Sept. 26 Planning Advisory Committee meeting, Director of Planning Jeff Webb said the RTO hopes to get a final proposal in place in time for the 2019 MISO Transmission Expansion Plan cycle.
Webb said stakeholders have asked how storage projects providing reliability transmission services will be able to enter the MTEP.
“Well how does any other transmission project get in? It’s proposed as a solution in the planning process,” he said.
Webb explained the projects would be proposed in MTEP as either a baseline reliability project driven by NERC criteria and allocated to local pricing zones, or as an “other” reliability project not eligible for regional cost allocation. If the storage project solves the issue at the lowest cost, it will be included in the annual plan.
He stressed that MISO’s plan only serves to treat storage comparably to other transmission assets, clarifying that storage projects would not necessarily take priority over traditional wires projects because “storage has a lot of hurdles and costs” to overcome.
“There will be opportunities, I think, to use” storage, Webb added.
‘To Queue or not to Queue’
Webb said storage as transmission would not be required to enter the interconnection queue as long as the project will not participate in the energy and ancillary services markets. If a storage asset is planned for both reliability transmission services and market services, the asset must first respond to reliability needs in the transmission market. If MISO doesn’t need the asset for reliability transmission purposes, it would be free to participate in the energy market pursuant to MISO’s future Order 841 compliance plan, provided it has completed the interconnection queue.
The queue is required “if for no other reason than comparability with other resources that the project would be competing with in the energy market,” Webb said.
“There’s a lot of controversy; to queue or not to queue,” he said of stakeholder reactions. He also said opportunities for market participation by storage projects intended for transmission use will vary according to location, noting that, for example, storage located in rural Iowa with few generation options nearby will have different market opportunities than storage added in a large metropolitan area where generation is already abundant.
“So maybe the answer comes down to significance factors: Where and how big?” Webb mused.
Reliability storage projects will be required to complete asset registration to allow MISO to control the asset when it’s required to maintain system reliability. The asset will receive notice of need in the day-ahead schedule and be recalled as needed during the operations day. Like other transmission assets, the storage assets will be price-takers when under RTO instructions.
Webb said MISO hasn’t proposed rules to credit a storage asset’s market revenue against its transmission asset cost recovery. Some stakeholders have said that allowing the two revenue streams would incentivize dual-use storage to the point that transmission reliability is diminished.
Webb said he expects MISO and stakeholders to discuss storage as reliability transmission services through the first half of next year. He noted that MISO could possibly schedule a workshop on the topic in response to stakeholder requests.
NERC Chief Sees Need for Inverter, Fuel Assurance Standards
By Rich Heidorn Jr.
WASHINGTON — NERC CEO Jim Robb said Thursday he is pushing for new reliability standards to address fuel assurance concerns and ride-through settings for inverters on solar generation and storage.
“I think a standard will be called for” on inverters, Robb said during a press conference at NERC’s D.C. office marking six months since he took the organization’s helm. “I feel the same way about fuel assurance. But my eyes are wide open to the challenges in crafting those appropriate [requirements] and figuring out which entities should be accountable for them.”
NERC has issued two alerts on inverters, one after the 2016 Blue Cut wildfire near Los Angeles caused transmission line faults and disconnected 1,200 MW of solar resources, and a second following a fire in spring 2018. Both were Level II alerts, which required registered entities to respond to NERC’s recommendations and answer questions about solar generation in their footprints and how they plan for the loss of the resources.
NERC is now finalizing a reliability guideline to ensure inverters are configured “so they play nicely with the rest of the system,” Robb said. “An inverter can do almost anything you want it to do. You just have to tell it what to do.”
Robb said the issue is a concern not only in California and the Southwest but also in North Carolina, Massachusetts and Texas, where solar penetration is rising. Battery storage also uses inverters and presents similar issues, he said.
“The issue around the standard that we’re currently struggling with is that right now all of our standards … are technology-agnostic and fuel-agnostic,” Robb said. “So, this would be the first that we would put in for a specific technology. And not everyone’s embracing that notion, so we have some work to do.” (See Solar Inverter Problem Leads CAISO to Boost Reserves.)
Fuel Assurance Standard
The shift from baseload coal and nuclear generation to variable resources and natural gas also justifies a reliability standard, Robb said.
“Loads are becoming much less certain than what we’ve had in the past. In fact, to be perfectly honest, we don’t know what the load curve of California looks like anymore because so much of it is masked by the distributed solar panels on peoples’ roofs,” he said. “We have a lot of tools and a lot of rules … we use to operate and manage and plan the system that are all largely based on a 1950s view of the world [that’s not] really true anymore.”
One of the challenges is aligning the natural gas industry’s infrastructure, scheduling policies and modeling to the real-time needs of the electric industry.
“Those [gas] power plant ramp rates are getting steeper and steeper” in the afternoons, when solar generation drops as loads peak, Robb said. “And effectively what we’re seeing is power plants were sucking gas out of the distribution system faster than pipelines could pack it in.”
Although pipelines can provide some storage by increasing pressure in their systems, “what we’re seeing in areas like the Southwest … is some of the pipeline corridors are running 90 to 95% of capacity. So they don’t have the same degree of flexibility they would have had five, 10 years ago.”
In addition, because of the way gas is regulated, “there is really no [one] who can solve these problems with the stroke of a pen,” Robb said.
Natural gas problems are most acute in New England and Florida, which have limited pipeline infrastructure, and California, which has lost most of Aliso Canyon’s storage capacity. (See related story, CAISO Seeks to Extend Aliso Canyon Rules.)
Although NERC’s current standards address planning for contingencies, they are “relatively vague as to how to think about fuel as a contingency,” Robb said.
“So we’re talking through getting a guideline in place that would make clear that any particular entity ought to look at a major pipeline disruption for example [or] a problem on the rail system … and start to factor that into their operating and shorter-term planning.”
Still to be determined is which entities would be subject to a pipeline contingency rule. “The challenge in evaluating the gas system is you need to really look at it over a fairly wide area, probably a bigger footprint than a planning coordinator, certainly a bigger footprint than in individual utility. It might be something that might be best applicable to [a reliability coordinator] but the RCs aren’t really set up to do that kind of planning,” Robb said.
He acknowledged that the industry generally prefers guidelines over standards because the latter can result in enforcement actions. “I choose to think of them as providing great clarity around how things should be done, particularly around these very disparate resources around the system that can interact in ways that don’t contribute to the community event that we call reliability. But it will take us a while to get there.”
Robb also acknowledged that the issue has become politicized by the Trump administration’s efforts to provide price supports for money-losing coal and nuclear generators. “My goal is to make sure that our work remains technically unimpeachable so it’s there to inform people who are making important decisions around these issues but not get drawn into the political and ideological arguments around them.”
RENSSELAER, N.Y. — An independent study suggests New York’s effort to price carbon into its electricity market could result in reduced CO2 emissions from generators in neighboring areas, rather than an uptick due to “carbon leakage,” the state’s Integrating Public Policy Task Force (IPPTF) learned Monday.
That so-called “negative leakage” in other parts of the Eastern Interconnection would be the result of electricity price changes that very slightly favor natural gas over coal generation, analysis by the nonprofit Resources for the Future (RFF) found.
At the IPPTF’s Sept. 24 meeting, RFF’s Dan Shawhan presented the study, which modeled the impact of carbon pricing on emissions and prices in New York and neighboring regions based on expectations for 2025. The group used its own Engineering, Economic and Environmental Electricity Simulation Tool (E4ST) to project effects in New York and throughout the interconnection.
New York’s carbon policy could produce “negative leakage,” reducing emissions not only in New York but in the rest of RGGI and the non-RGGI parts of the Eastern Interconnection. | Resources for the Future
In terms of 2025 dollars, the study estimates an environmental benefit of $288 million per year, mostly from a slight reduction in emissions outside New York, and a net total benefit of $279 million per year.
Because New York will have no coal-fired capacity in 2025, less than a quarter of the estimated environmental benefit is from NOx and SO2 emission reductions, Shawhan said. Estimated SO2 damage actually increases slightly because a carbon charge would shift some emissions to locations that cause larger estimated health damage per pound emitted.
Excluding the positive environmental benefits, collective end-user costs in New York come in at $562 million per year, equivalent to $3.60/MWh, with a “somewhat smaller profit gain” for New York generators.
The Brattle Group
The study estimates a 0.9% reduction in generator CO2 emissions in the state and a 0.2% increase in in-state generation. RFF attributes a 1.1% reduction in New York power sector CO2 emission intensity primarily to equalizing the CO2 emission price applied to in-state fossil fuel generators both exempt from and subject to the Regional Greenhouse Gas Initiative. A carbon charge would reduce damage from New York generator emissions by $17.4 million per year. With the RPS still binding in 2025, the study finds no change in the state’s volume of renewable generation due to carbon pricing.
The study estimates an LBMP price increase of approximately $20/MWh in zones A-E, $22/MWh in zones F-I, and $23/MWh in zones J and K, while the renewable energy credit price would drop from $45.88/MWh to $27.28/MWh, and the zero-emissions credit (ZEC) price would plummet from $13.64/MWh to zero.
Upstate nuclear unit revenue would climb under the model from $65/MWh to $67/MWh, while the RGGI price would rise slightly, from $11.28 to $11.90 per ton CO2.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said: “If one were to rely on your study results to decide whether New York should do this or not, it would be tough to make that decision on a single-year snapshot, so I’m trying to get a feeling for whether your model is likely to produce consistent results over time.”
“I think of this as an approximation of the average effect over the multiyear period … however, it is not exactly the same as what we would get if we simulated each of those years,” Shawhan replied.
Zonal Allocation
The Brattle Group’s Sam Newell presented analysis on carbon revenue allocation — the process of crediting carbon prices back to electricity consumers. The analysis shows the implications of four alternative allocation approaches that NYISO had proposed and provides a spectrum of options along two competing allocation objectives: to align LBMPs with the marginal cost of serving load while avoiding major cost shifts among customers.
NYISO recommends ‘Levelizing Allocation’ because it prioritizes avoiding major cost shifts across zones, despite eliminating an efficient price signal that internalizes the costs of CO2 emissions. | Brattle Group
“As soon as you get into debating how best to allocate money, that’s a very difficult discussion,” Newell said.
Newell said transmission constraints into New York City represent one of the key challenges related to allocation.
“So if you add a carbon charge, you’d have a greater increase in LBMPs there than elsewhere, and that’s one of the things we need to account for… and how that can possibly be offset by different allocation approaches,” he said.
All the individual zone results in the study’s appendix reflect nodal modeling, he said. To the extent there are transmission constraints going into Zone J (New York City), the model tries to capture them.
But the model found the biggest constraint “by far” is really across NYISO’s Central-East Interface, “much more than it is going into southeast New York,” Newell said.
“We did the math, and not surprisingly, with the load-share approach, everybody in every zone, whether upstate or downstate or any part of those, gets about $10/MWh” in allocations, Newell said.
To levelize the net effect (what an LSE pays for the carbon component of the LBMP minus the allocated residuals), downstate zones would need to receive about $4/MWh more in allocated residuals than upstate zones, he said.
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said, “When we would go to do the allocations, there are only two things we can observe: one is the carbon component of the LBMP, and the other is how much money we collected from generators.”
The ISO cannot observe whether a carbon scheme attracted more investment downstate than upstate and thereby lowered capacity prices downstate, lower than the non-carbon component of LBMPs downstate, Newell said.
A carbon charge opens up a bigger gap between the upstate price and the downstate price, and the markets will tend to levelize the impacts somewhat as suppliers respond to and partially undo the price stimulus, he said.
“What are dynamic effects?” Newell said. “That’s the market responding to price signals.”
Seams and MER
Newell also presented analysis on seams, reiterating a presentation he made in April on applying carbon charge border adjustments to the ISO’s external transactions.
Newell backs the ISO in proposing to levy import charges and export credits in such a way that makes the effects of carbon pricing invisible to external transactions, with external resources competing on a “status quo” basis. However, if NYISO were to consider an alternative approach, levying charges based on the emissions associated with transactions, several key concepts would have to be addressed, Newell said.
“What is the relevant rate?” Newell asked. “Is it the average rate of their fleet? No, it is the marginal emissions consequences of taking a transaction from there. That’s how spot pricing is supposed to work — to create efficient marginal incentives in the operating timeframe. So they’re not average emissions; it’s the marginal emissions rate.”
One stakeholder questioned the study’s hypothetical resource shuffling that might result from a “status quo” approach to carbon pricing, saying the ISO has import limits and it’s probably impossible for all of the nuclear generation in PJM to flow in while all the fossil generation in New York state flows out.
“Yes, it can happen,” Bouchez said. “When you look at imports and exports today, in any one hour, it’s almost unheard of to see transactions only going in one direction … physically there are people importing and exporting at the same time on the same interface. What matters are the net flows, which we calculate as the net of the imports and exports.”
Tariq Niazi, ISO senior manager and Consumer Interest Liaison, presented a study summarizing the Brattle report, finding that a carbon charge would reduce CO2 emissions approximately 3% by 2030, causing only limited fuel switching, and that most emission reductions would result from dynamic effects such as renewable shifts, nuclear retention and price-responsive load.
Speaking of the need to reconcile various reports and their differing cost estimates, Niazi said, “Our focus is to get this NYISO analysis done between now and mid-October, when we plan to come back.”
Brattle will present the final version of its customer impact analysis at the next IPPTF meeting on Oct. 15 at NYISO headquarters, with an additional task force meeting possible in the interim.
A new stakeholder-led proposal would require MISO load-serving entities to develop a 20-year base load forecast that includes monthly predictions for energy and non-coincident peaks.
The Coalition of Utilities with an Obligation to Serve in MISO (CUOS), an ad hoc group of MISO utilities and regulators, advanced the plan after the RTO earlier this month requested stakeholder ideas for improving load forecasting.
LSEs must currently provide just two years of monthly forecast data to MISO, but WPPI Energy economist Valy Goepfrich said long-term forecasts the RTO obtains from the Purdue University State Utility Forecasting Group — which are compared against LSE projections — so far “have confirmed the validity of the LSE base load forecasts.”
Under the CUOS plan, the LSEs’ base load forecasts would be applied to MISO’s base case Transmission Expansion Plan (MTEP) future, the “limited fleet change” future. The other futures include a continued fleet change future, an accelerated fleet change future and a future in which distributed and emerging technologies become more widely used in the MISO footprint.
“The CUOS proposal is leveraging the forecasts that LSEs already develop,” Goepfrich explained during a Sept. 26 Planning Advisory Committee meeting. She said the proposal is more cost-effective than continuing to pay Purdue for independent load forecasting.
The CUOS proposal would also direct LSEs to provide data on transmission losses, as well as demand served by energy efficiency planning resources, demand resources and behind-the-meter planning resources. LSEs would not be required to provide numbers on demand served by energy efficiency programs and other resources not classified as planning resources. Goepfrich said MISO can continue to use consulting firm Applied Energy Group for distributed resource data predictions in the three other MTEP futures.
Goepfrich referenced an address at this year’s MISO Market Symposium in which RTO Director Trip Doggett cited “The Parable of the Ox,” a story included in James Surowiecki’s book “The Wisdom of Crowds.” The story recounts how in 1906, statistician Francis Galton studied a competition to guess the weight of an ox at a country fair, observing the average guess was accurate to within 1% of the actual weight of the 1,200-pound animal. Doggett used the story to illustrate that the RTO’s large stakeholder community is needed to lend their ideas about what shape the future grid should take.
Goepfrich said the story also applies to load forecasting. An average of many forecasts, she said, will be more helpful than a forecast designed by a few individuals.
“It doesn’t make sense to have a forecast that is divorced from the LSEs’ forecasts,” Goepfrich said. She added that MISO should be more transparent about the “behind the scenes” analyses that might lead it to prefer an independent load forecast over one originated by LSEs.
MISO Director of Planning Jeff Webb said the RTO will evaluate and respond to the load forecast proposal. The RTO committed to soliciting stakeholder opinions on load forecasting after taking a break this summer from ordering more independent load forecasts from Purdue. (See MISO Looks to Members for Load Forecasting Ideas.)
Facing widespread stakeholder disapproval, MISO in June abandoned a proposal to have its 140-plus LSEs annually assemble four distinct 20-year load forecasts with hourly load shapes to align with each of the four futures in the annual MTEP. (See MISO Nixes LSE Load Forecast Plan.)
FERC on Wednesday rejected a rehearing request over PJM Transmission Owners’ revised processes for planning supplemental projects, ruling it in compliance with Order 890.
The commission denied a request by American Municipal Power, Old Dominion Electric Cooperative and others seeking rehearing of the commission’s Feb. 15, 2018, ruling that the TOs’ processes for developing supplemental projects fell short of Order 890’s transparency and coordination requirements. FERC also approved PJM’s and the TOs’ compliance filing in response to the February ruling (ER17-179, EL16-71-002).
PJM stakeholders have long complained about the rules involving supplemental projects — transmission expansions or enhancements not required for compliance with PJM system reliability, operational performance or economic criteria. TOs can develop, build and seek reimbursement for such projects without the approval of PJM, which only reviews them to ensure they don’t harm reliability.
The Feb. 15 order approved a proposal to move the TOs’ process for planning supplemental projects from the Operating Agreement to Attachment M-3 of the Tariff but required PJM and the TOs to make changes to the attachment and the OA. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
The commission said the rehearing request “largely repeats arguments” made earlier in the docket. “We are not persuaded that the commission erred in the February 15 order, which we believe appropriately responds to these concerns.”
AMP, ODEC and others argued the commission erred in permitting Attachment M-3 because it circumvented the division of filing rights in PJM, including the supermajority vote of the Members Committee required for changes to the Operating Agreement. They also said the commission should have required the TOs to respond to stakeholder comments under the supplemental process.
“Order No. 890 requires that stakeholders be afforded the opportunity to provide meaningful input, and that public utility transmission providers ‘craft a process that allows for a reasonable and meaningful opportunity to meet or otherwise interact meaningfully,’” the commission said. “Its requirements are not so prescriptive as to dictate whether and how the PJM Transmission Owners must respond to that input. While we encourage the PJM Transmission Owners to be as responsive as possible to stakeholder comments, we also realize that not all comments may require answer.”
In addition to AMP and ODEC, those seeking rehearing and challenging the March 19 compliance filing were the Delaware Division of the Public Advocate, PJM Industrial Customer Coalition, Illinois Citizens Utility Board, Office of the People’s Counsel for the District of Columbia and Public Power Association of New Jersey, which FERC named the “Load Group.”
“The Load Group’s requests for various additional provisions go beyond what the commission required in, and constitute requests for rehearing of, the February 15 order,” the commission said. “We therefore find these requests to be outside the scope of the compliance proceeding, and were we to consider them as requests for rehearing, would deny them.”
FERC on Tuesday approved MISO’s plan to replace its retirement notification process with a more general three-year generation suspension period.
MISO’s proposal places all generation owners submitting an Attachment Y retirement notice into a catch-all three-year suspension period, with suspended units maintaining interconnection rights for the full three years unless they formally decide to retire (ER18-1636). Units that do not return to service after three years are presumed retired and their interconnection rights dissolved. The changes became effective July 16, 2018.
| MISO
After FERC issued a July deficiency letter on the proposal, MISO said the new suspension process would still allow it to designate resources seeking suspension as system support resources needed to keep operating for reliability reasons. (See FERC Seeks Details on Proposed MISO Retirement Rules.) The RTO also explained its old suspension process wasn’t working as intended, saying that out of 77 suspensions over the last five years, only eight generators returned to service at the end of the originally designated suspension period.
For modeling purposes, MISO will treat approved suspensions as unavailable resources with no specified date of return service. MISO also said its proposal requires no notice from a generation owner should it want to change its suspension status into a permanent retirement anytime during the three years.
FERC said MISO’s proposal that modeling not anticipate suspended units will return to service “better reflects the inherent uncertainty of planning.”
” … We agree with MISO that its current requirement to provide a return-to-service date in Attachment Y Notices to suspend may at times create an illusion of certainty that does not actually exist,” the commission said.
The 2nd U.S. Circuit Court of Appeals on Thursday upheld New York’s zero-emission credits (ZEC) for nuclear generation, rejecting claims they intrude on FERC jurisdiction (17‐2654‐cv).
“We conclude that the ZEC program is not field preempted, because plaintiffs have failed to identify an impermissible ‘tether’ under Hughes v. Talen Energy Marketing between the ZEC program and wholesale market participation; that the ZEC program is not conflict preempted, because plaintiffs have failed to identify any clear damage to federal goals; and that plaintiffs lack Article III standing as to the dormant Commerce Clause claim.”
In upholding a district court’s dismissal of the complaint by the Electric Power Supply Association and others, the appellate court said its finding was “consistent” with the 7th Circuit’s Sept. 13 ruling upholding Illinois’ own ZEC program. (See 7th Circuit Upholds Ill. ZEC Program.)
EPSA on Thursday asked the 7th Circuit to rehear its ruling, alleging the court had made legal and factual errors. “The panel overlooked or misapprehended three key legal arguments under which appellants would prevail,” EPSA said.
Threading the Needle
The New York Public Service Commission created the ZEC program in August 2016 as part of its Clean Energy Standard (CES), which set a goal of reducing greenhouse gas emissions by 40% by 2030. The PSC said it crafted the program to avoid the issues behind the Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets. (See NY Attempts to Thread Legal Needle with Clean Energy Standard, Nuke Incentives.)
The court said that ZECs, like renewable energy credits (RECs), are certifications of an energy attribute separate from the purchase or sale of wholesale energy. Although the ZEC program “exerts downward pressure on wholesale electricity rates, that incidental effect is insufficient to state a claim for field preemption under the FPA [Federal Power Act],” the court said.
The court said the PSC avoided the defects of the Maryland contract for differences, which required the generator to participate in PJM’s capacity market.
“Plaintiffs point to nothing in the CES Order that requires the ZEC plants to participate in the wholesale market,” the court said. “ … As the district court concluded, a generator’s decision to sell power into the wholesale markets is a business decision that does not give rise to preemption concerns.”
“Until 2019, the ZEC price cannot vary from the social cost of carbon, as determined by a federal interagency workgroup. After 2019, the ZEC price is fixed for two‐year periods, and does not fluctuate during those periods to match the wholesale clearing price,” the court said.
The court also said the ZEC program was permissible under the dual federal/state regulatory system over electricity because it “does not cause clear damage to federal goals.”
The PSC approved the program to prevent the premature retirements of three New York nuclear power plants, Exelon’s FitzPatrick, Ginna and Nine Mile Point.
Nine Mile Point Nuclear Plant | Constellation Energy Nuclear Group
EPSA and the other plaintiffs — the Coalition for Competitive Electricity, Dynegy, Eastern Generation, NRG Energy, Roseton Generating and Selkirk Cogen Partners — claimed they were harmed because the ZEC program allows “favored New York power plants to prevail in interstate competition against” their generation by underbidding them in the wholesale electricity markets.
“If the PSC awarded ZECs in a non‐discriminatory manner to out‐of‐state nuclear plants (as it may do in the future under the terms of the CES order), there would be no abatement in the injury plaintiffs claim to suffer from the general market‐distorting effects of the ZEC program. In short, plaintiffs’ injuries ‘would continue to exist even if the [legislation] were cured’ of the alleged discrimination,” the court said. “Because plaintiffs’ asserted injuries are not traceable to the alleged discrimination against out‐of‐state entities, but (rather) arise from their production of energy using fuels that New York disfavors, they lack Article III standing to challenge the ZEC program.”
Win for RECs?
“The decision is a win for both ongoing state efforts to preserve existing nuclear plants — New Jersey regulators expect to finalize a ZEC program by the end of the year — and long-standing renewable energy policies,” said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School. “The panel held that renewable energy credits (RECs), instruments that are used for compliance with renewable portfolio standards, are legally indistinguishable from ZECs. Today’s decision thus implicitly concludes that RECs are not preempted under the FPA, an issue which no court has ever squarely addressed.”
CAISO is seeking to extend measures for another year that deal with the continuing threat to electrical reliability posed by limited operations at the Aliso Canyon natural gas storage facility, where a massive release of methane occurred in October 2015.
CAISO is seeking to extend for another year interim market measures designed to deal with gas supply restrictions at the damaged Aliso Canyon facility. | California Governor’s Office of Emergency Services
“Our hope is to be able to keep these measures in place for another 12 months,” Anna McKenna, an assistant general counsel for the ISO, said in a conference call with stakeholders Tuesday.
The provisions include a measure allowing the ISO to enforce constraints on the maximum amount of natural gas that can be burned by gas-fired plants in the areas served by the Southern California Gas and San Diego Gas & Electric. The constraints would be based on limited supply anticipated by CAISO during specific hours.
The provisions also allow CAISO to suspend or limit the ability of scheduling coordinators to submit virtual bids if it’s determined virtual bidding could undermine reliability or grid operations.
Similar provisions have been in place for the past two years to prevent blackouts or grid disruptions caused by the natural gas supply in Southern California being over-taxed.
The current proposal, called Phase 4, would extend the temporary provisions now in place for another year beyond Nov. 30 and Dec. 16, when they are set to expire.
CAISO planned to file its proposal with FERC by Thursday and ask for a 60-day turnaround so the new restrictions are in place when the first set of rules expires at the end of November.
Before the 2015 blowout, Aliso Canyon was the state’s largest natural gas reservoir, and its damaged status poses challenges to generators and regulators alike.
Despite objections from local residents and Los Angeles County officials, SoCalGas resumed injections into the facility in July 2017 to comply with a state directive to maintain sufficient gas inventories to support reliability on the region’s gas and electric systems. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)
Illinois regulators last week suggested PJM consider ending its capacity market if it continues supporting policies that the state believes discount its generation preferences. [Editor’s Note: An earlier version of this story incorrectly stated that regulators had threatened to leave the RTO.]
The Illinois Commerce Commission convened a Sept. 20 hearing on PJM’s capacity market three weeks before a deadline to respond to a FERC order that rejected both of the RTO’s proposals for revising its capacity market, which sparked a rush to develop alternatives. (See FERC Orders PJM Capacity Market Revamp.)
While several proposals emerged, including one supported by the Illinois Citizens Utility Board, PJM has maintained support for its own plan, which would pair an expanded minimum offer price rule (MOPR) with a two-stage auction that removes subsidized resources and reprices the results.
Already well aware of Illinois’ grievances, PJM staff attending the hearing attempted to explain the RTO’s position.
“We are really trying to make this work,” PJM’s Darlene Phillips said. “We recognize that Illinois and other states have the right to make decisions. We are not trying to fight against those decisions. We are trying to make sure that, at the end of the day, our markets work for the entire region. There are other states that aren’t making those decisions … [and their generators] don’t have the luxury of getting an out-of-market payment.”
Another Way?
PJM’s assurances didn’t sway either the ICC commissioners or the other panelists, largely made up of either environmental advocates or representatives of Exelon, which has two nuclear facilities in Illinois benefiting from a 2016 state law that subsidizes the units with state-funded zero-emission credits. The 7th U.S. Circuit Court of Appeals recently upheld the state’s right to provide the funding.
“What if we throw this capacity market out?” ICC Commissioner John Rosales asked, noting that FERC had already ruled the market unjust. “There’s some rationale we can do it another way.”
He pointed to ERCOT, which doesn’t have a capacity market.
“Is that an option? … Is there something else that we can do? Because the amount of money is uneconomical,” he said. “That’s a lot of money that’s invested in a reserve market that doesn’t seem to be needed most of the periods throughout the year,” Rosales continued. “Understand, there’s times that we’re going to need some help, but you get that [help] from others.”
Jen Tribulski, a PJM attorney, suggested that FERC didn’t intend to do away with PJM’s “capacity market as a whole,” but sought to improve how the market deals with out-of-market payments.
The disagreement came over what is considered a subsidy. Phillips said that “we have to draw a line somewhere. This is not easy.”
However, opponents argued PJM has larger market distortions to address.
“Regulated utilities have the ability to subsidize all of their generation with ratepayer funding, so if you’re going to talk about a market without subsidies, you’ve got to really relook at the whole market. It’s the single biggest market distortion that there is,” said Rob Kelter of the Environmental Law & Policy Center. “When you consider the cost of energy and you don’t consider the cost of environmental externalities, you are creating the biggest distortion you could possibly create. Coal and natural gas pollute.”
“Right now, the proposal on the table is to artificially raise the prices that consumers would be paying to preserve the supremacy of the capacity market,” said Andrew Barbeau of The Accelerate Group. “There’s a certain fealty to the capacity market that we’ve seen in recent years … to use the capacity market to start serving other purposes. It’s always been there to serve as this insurance product. Consumers are paying more and we’re getting less for it, and it’s kind of violating what residents of the state have been pretty consistently demanding, which is that the power be cheaper and cleaner.”
‘Fundamental Disconnect’
Phillips said the market “is doing what it was meant to do when it was put in place” to produce “reliability at the least cost,” but that it didn’t contemplate environmental concerns. She added that she was “not saying there’s not room for improvement.”
“That’s something that states can get together and have a discussion about” in creating a market-based proposal, she said. “You’re getting reliability. You’re getting assurances, not insurance, [but] assurances that three years from our market, three years forward, that we have enough capacity online to make sure the energy needs during that period are met.”
ICC Chairman Brien Sheahan said there is a “fundamental disconnect in PJM’s conception of what ‘accommodate’ is and what ‘mitigate’ is.”
PJM says its proposal accommodates states’ policy decisions, but states argue it instead mitigates their efforts to sponsor preferred technologies.
“You can’t just start doing this kind of line drawing,” he said. “And the end result, I predict, will be if they don’t accommodate, then the states are going to find alternatives. … Legislatures and governors in states that care about climate change and care about environmental policy are not going to bow to how [PJM thinks] they should work.”
ICC Manager Randy Rismiller suggested moving away from capacity markets altogether.
“Energy and ancillary services markets historically have worked quite well. They haven’t been as contentious as capacity markets. This sort of gradual gravitation away from capacity might be a way out of these constant conundrums,” he said.
CUB’s Kristin Munsch urged PJM to “stop trying to separate us, but integrate our preferences into the market.”
“I think PJM in recent years has begun to adjust the construct, a market that we thought was working well, to one that’s no longer reflecting what I think consumers are looking for,” she said.
CAISO moved closer this week to updating its transmission access charge (TAC) structure to include new rules about how to measure transmission usage.
Stakeholders discussed the final draft proposal Monday at CAISO headquarters in Folsom, Calif., with participants also joining by telephone.
The proposed rules are intended to more accurately allocate transmission costs based on current grid conditions to achieve greater efficiency and cost-effectiveness, the ISO contends.
Power lines in Contra Costa County, California | USDA
In particular, the rules would change the current volumetric TAC to a hybrid one that uses historic peak demand data instead of forecasted data.
“It’s kind of a balance we’re trying to strike here,” Chris Devon, CAISO market and infrastructure policy developer, told stakeholders.
The volumetric-only approach is no longer appropriate because of a changing grid, most notably the rise of distributed generation and other distributed energy resources, the ISO and many stakeholders contend. The hybrid approach would help adjust for this new reality so that transmission owners can better recover the costs of building, maintaining and operating transmission facilities, proponents said.
“The proposed hybrid approach is an improvement over the current TAC structure,” the ISO said in its presentation Monday. “[It] captures both volumetric and peak demand functions and reliability benefits provided by the system.”
Planning for the revisions started in April 2017 and has included several stakeholder meetings. The initial straw proposal went through two revisions, with some of the more controversial proposals modified or rejected.
CAISO recently backed off a proposed provision that would have moved the point of measurement for transmission usage away from the end-use customer’s meter to the interface between the transmission and distribution systems to better reflect increased customer reliance on resources directly connected to the distribution network, such as rooftop solar.
“The ISO is willing to revisit the point-of-measurement issue — for purposes of prospectively allocating the costs of future transmission facilities — if state policymakers and regulatory authorities, after careful consideration of the merits and implementation issues, support retail rate changes that provide a transmission cost credit (i.e., relief from retail rate charges for certain new transmission facilities) to load-serving entities that have procured distributed generation resources,” the ISO wrote in the proposal.
The TAC plan still has a way to go before it could be implemented.
A final proposal will likely be submitted to the ISO Board of Governors in the first half of 2019, with board approval coming later next year.
It would then have to be submitted to FERC, with implementation occurring no sooner than 2021 or 2022, according to CAISO planners.
The grid operator previously developed a proposal to allocate transmission costs over an expanded balancing area if the ISO integrates new members from other areas of the West. (See CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area.) That proposal has been shelved until CAISO expands into other regions.
