Planned additions of renewable generation and storage will not compensate for gas retirements in the Western Interconnection, and any major disruption to gas supply would push the system “to the limit,” a new reliability assessment says.
Analysis by the Western Electricity Coordinating Council showed that reserve margins are projected to be tight through 2026, driven by coal and nuclear retirements and increases in power demand. The report forecasts 30% growth in natural gas demand across the interconnection. WECC retained Wood Mackenzie, Environmental Economics and Argonne National Laboratory to undertake the gas-electric interface study.
“We are now effectively in an N-1 scenario with any major disruptions in the gas transmission system or the Bulk Power System pushing the system to the limit,” WECC said. The Salt Lake City-based organization is the NERC-certified Regional Entity for the West.
Restrictions at the Aliso Canyon gas field near Los Angeles — a facility that many want to shut down after a massive gas leak three years ago — have created a situation in which the failure of another large component on the grid could lead to reliability problems. The heavier penetration of renewables will increase reliance on natural gas for system peaks, and the amount of renewable generation needed to meet current state policy goals is not sufficient to entirely offset the loss of roughly 12,000 MW of baseload generation.
The study assumes retirements of about 9 GW of coal and 2 GW of nuclear by 2026 across the West, including major baseload plants in California, the Pacific Northwest and the Desert Southwest, and 9 GW of wind additions to reach 29 GW of total wind. Solar capacity is projected to double to 36 GW, with 18 GW added in California. Total load in the interconnection is project to grow by 7% by 2026.
WECC says system reserve margins are expected to be tight through 2026 | WECC
The report recommends improved regional coordination, including planning exercises, and more transparency around firm gas supply contracts and the power plants they serve. It also suggests designation of specific plants as critical to core reliability, and that there be more clarity around interstate gas curtailment protocols.
While historical natural gas resources have been sufficient, events over the past few years have tightened supply, including outages of Southern California Gas pipelines, a colder winter in 2018 and restrictions at Aliso Canyon. Other factors likely to drive up gas usage are the 2024 retirement of the Diablo Canyon nuclear plant and coal retirements in the Southwest and Northwest.
The CAISO Department of Market Monitoring recently said that tight gas supplies in Southern California drove up wholesale prices by 25% last year. SoCalGas recently told RTO Insider there is no timetable to bring back Line 235-2 in Southern California, which suffered a rupture last October, despite its status as a backbone facility and extreme price spikes of up to $12/MMBtu. (See CAISO Board Approves Forecast Error Measures.)
“Among other things, the report highlights a critical need to focus on better gas-electric coordination between the two sectors but also deploy a combination of solutions to ensure Western Interconnection system reliability,” WECC Vice President of Reliability Planning Melanie Frye said in a written statement.
The report said the region must have “broader conversations” about ensuring that critical power plants have fuel, improving regional coordination around gas supply contingencies and better forecasting, as well as improved response by local distribution companies to curtailments.
HOUSTON — Ordinarily, the power sector would eagerly welcome a coming wave of efficient combined cycle generation, especially when the government has set goals to increase the number of clean energy resources.
But that is not the case in Mexico, where the aging transmission infrastructure is having trouble handling the current generation, let alone what is coming.
“In Mexico, the closer you are to the U.S. border, the greater reliability you have,” Al Garcia, an adviser to public and private sector energy companies in Mexico, said earlier this week during a meeting of the International Society for Mexico Energy (ISME).
Garcia said 10 GW of combined cycle generation is expected to come online through 2020, but he noted that is only part of the problem. He said Mexico’s ISO, CENACE, which was created as part of the country’s electric market restructuring, is still a work in progress.
“It takes more than the engineering side to become an ISO,” he said. “You’re going to see that in the next few years as the combined cycle units come online.”
“The infrastructure is not robust enough in many places, so there are a lot of outages,” said Acclaim Energy Advisors’ Alberto Rios. “It’s a physical obstacle.”
Rios joined Garcia for a discussion before ISME, a nonprofit professional organization focused on Mexico’s energy sectors. The two shared their insights on the nascent Mexican market with a bilingual audience eager to learn more.
“A new market gives you the ability to pick and choose what you’re going to buy, and when,” Rios pointed out. “Some generators in the market can sell to suppliers or on the spot market. Right now, the pricing in the spot market is more favorable. Generators are seeing very competitive pricing.”
Competitive enough that qualified suppliers can find some contracts under the Federal Electricity Commission’s (CFE) transmission retail rates, Rios said. The state-run utility’s regulated rates dropped steadily to 6.4 cents/kWh in February, when a new transitory methodology was established. Rates have climbed 41% since to 9 cents/kWh.
“The effective rate methodology does not provide the guidance that the marginal cost of electricity will show up in that tariff,” Rios said. “CFE is going to have to recover that cost.”
CFE is known to keep its retail rates artificially low and to subsidize its residential consumers by charging the industrials more. To see rising prices in an election year is unusual, Rios said.
“Personally, I thought we would not have had that [increase] before an election,” he said.
The market is somewhat leery of frontrunner Andres Manuel Lopez Obrador, a leftist populist who has advocated keeping the country’s aging thermal plants online. Noting that 15 GW of new generation is expected to become available during the next president’s single six-year term, Garcia said he doesn’t expect to see any changes to the country’s deregulation.
“I don’t think that’s going to happen under a left-wing government,” he said. “What’s going to save them is the influx of new generation. It’s going to keep the prices down. They’ll be able to say, ‘Hey, look at our great policies!’”
Garcia believes Mexico will be long on generation in some regions because of the lack of infrastructure. The government has pushed for new generation, but it has also cited a need for $10 billion in transmission investment. It has two competitive projects out for bids, with more potentially to come. (See Land Rights a Challenge to Mexico Tx Developers.)
“Generation shouldn’t have a problem in a few years. We’ll start having healthier reserve margins once we get through the tough times we’re seeing right now,” he said. “But this is where [the Ministry of Energy] has to come out and be more proactive. Instead of talking about investment in new power generation, it should talk about challenges of going through private land ownership.
“That’s what it should be doing to create sturdier infrastructure on the electric side,” Garcia said. “Let the physical constraints work their way through system, and things should start looking better.”
INDIANAPOLIS — MISO is likely to face an increasing frequency of emergency conditions in the near future, and key officials participating in the RTO’s Board Week sought to understand exactly what’s behind the development.
MISO executives, the Board of Directors and the Independent Market Monitor dissected contributing factors like erratic weather, demand response rules and the RTO’s reserve margin. They also debated whether solutions could be found in the interconnection queue or capacity auction.
Directors were presented the results of the annual resource adequacy survey produced jointly by the RTO and Organization of MISO States, which predicts adequate reserves through 2019, but less certainty thereafter. Over the next five years, the footprint could see anything from a 7.5-GW surplus to a 4.5-GW shortfall. (See OMS-MISO Survey Reveals Dimmer View of Future Supply.)
MISO Executive Director of Resource Planning Patrick Brown said that despite flat load growth, resource retirements and increased forced outages continue to drive up the planning reserve margin, which increased year over year from 15.8% to 17.1%.
Forced outages in MISO South are nearing 14%, compared with about 8% at the time Entergy was integrated in 2013. Brown said the outages will eventually abate as new capacity resources replace retiring generation.
“However, this new capacity will require time and transmission,” Brown said during a June 12 conference call of the board’s System Planning Committee ahead of the quarterly Board Week.
At a June 19 meeting of the board’s Markets Committee, Director Baljit Dail asked if MISO could simply discount the planning reserve margin to shave the probability of emergencies.
RTO President Clair Moeller responded that MISO is currently reconsidering its planning reserve margin altogether as emergencies become more likely in shoulder months.
“The question we’re trying to ask is, ‘How do we evaluate risk every hour of the year instead of those four to five days across summer peak?’” Moeller said. MISO has said its analysis shows that peaks will soon occur during any hour of the year, rather than simply during an annual predicted system peak period.
Queue to the Rescue?
New generation could boost MISO’s resource adequacy, with the RTO possibly seeing as much as 11.4 GW of new generation come online by 2023. Wind generation interconnection requests should taper off as production tax credits expire in 2020, but solar requests should rise as the cost of panels come down, according to Brown.
But a record interconnection queue could impede development of new generation. And while stakeholders typically blame MISO’s lengthy study process for queue delays, Brown said the “true bottleneck” can be found in the physical limitations of the RTO’s transmission system.
Brown said MISO requires billions of dollars in transmission upgrades to support the 93 GW of generation currently in its queue, something particularly true of the nearly 200 proposed projects in MISO’s West region (including the Dakotas, Minnesota, Iowa and part of Wisconsin), where proposed projects can become uneconomic when the costs of new transmission to support them are factored in.
MISO Vice President of System Planning Jennifer Curran said the RTO is also evaluating expanded use of bidirectional HVDC technology to manage the changing fleet and make the grid more interconnected with other RTOs.
Monitor: PRA Should Take Share of Blame
However, Monitor David Patton said he partly blames the increasingly tighter operating conditions on the annual Planning Resource Auction, which he thinks is discouraging construction of new generation. He called the recent $10/MW-day clearing price “near zero.” (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)
“Our markets are telling us not to build anything,” Patton said. “This is why our competitive suppliers are doing whatever they can to export to PJM.” He again urged MISO to adopt a sloped demand curve in its capacity auction.
“This is the first I’m hearing that the market is not sending the right price signal,” Director Michael Curran joked, feigning shock to a roomful of laughter. “The price signal is the price signal, but there’s more than 90 GW sitting in the queue,” he added.
Patton said he remains unconvinced that all the proposed generation in the queue will come online.
“It’s very expensive to let lower-cost generation retire and be replaced with more expensive new generation,” he added.
Patton also said new natural gas generation set to come online in MISO South won’t really benefit MISO Midwest because it will be trapped behind the transfer constraint along SPP’s transmission link between the regions.
He also predicted that the larger amounts of DR cleared in this year’s auction will lead the RTO to call emergency alerts earlier and then possibly cancel them, as occurred during a mid-May near emergency. He also remains concerned that states won’t take sufficient measures to guarantee resource adequacy.
Dail, asked if the situation was really that dire.
“If it’s harder for you to sleep at night, then my mission is accomplished,” Patton responded.
Volatile Spring
MISO’s average load was 72.2 GW this spring, compared with 69 GW a year earlier, and staff attributed the uptick to volatile conditions that saw April temperatures well below normal and May well above. The RTO hit a 111.6-GW systemwide peak on May 29, compared to last spring’s 92-GW spring peak on May 16.
“April was much colder than normal, and we flipped a switch in May to much hotter than normal. … We skipped over spring,” said MISO Executive Director of Market Operations Shawn McFarlane. Compared to the last spring, average load increased about 5% for the quarter, and peak load increased a “pretty incredible 20%, with a few other days approaching similar levels,” McFarlane said.
“This quarter was bizarre,” agreed Patton. “On May 29, temperatures in Minneapolis hit 100 degrees.”
Patton said high temperatures that day forced the RTO to derate transmission and contributed to a local transmission emergency in the central portion of MISO Midwest. He praised RTO operators for successfully managing the transmission emergency.
“We had 15 straight days of heat in May. That will impact day-to-day operations,” said MISO Executive Director of System Operations Renuka Chatterjee.
However, energy prices were down about 3% from last spring, averaging $29/MWh. MISO credited the lower prices to fewer instances of congestion and lower natural gas costs compared to last spring. The RTO also set a 15.6-GW wind peak on March 31, breaking the previous Jan. 17 wind output record of 15 GW. Spring maintenance season brought 29 GW in outages, in line with usual seasonal trends, it said.
The unusually warm May (the hottest in MISO’s history) yielded an emergency alert declaration on May 11 (a Friday) for conditions projected for May 14 (a Monday). The RTO ultimately retracted the warning on May 13 as forecasts changed and later asked stakeholders if they preferred the earlier warning. (See MISO Mulls Additional Emergency Communication.)
McFarlane said MISO issued the alert “out of an abundance of caution.”
Curran asked if load-modifying resources (LMRs) were equipped to respond in that instance.
The LMRs reported they could have furnished about 750 MW had an actual emergency been declared, said Rob Benbow, MISO senior director of systemwide operations. McFarlane reminded the board that LMRs are only required to respond to summer emergencies. May’s near emergency would have fallen outside the required months.
In response to the high spring temperatures, McFarlane said MISO is now exploring the possibility of revising its seasonal forecast model from one that switches over based solely on the calendar to one that also considers weather forecasts one to two weeks out.
MISO predicts above-normal temperatures will continue into summer, especially for MISO South, leading to a higher peak load. The RTO now predicts a 121.7-GW peak load, about 1 GW above last summer’s peak. It also forecasts an 80% chance of deploying emergency resources this summer. (See MISO: Summer Reserves Adequate, but Emergency Likely.)
But calling up DR resources takes careful planning, RTO officials said.
“Many of them have an eight-hour lead time, so you have to see the emergency yesterday,” Moeller said.
Staff have signaled that the RTO will possibly seek rule changes for DR participation, part of a larger effort to address changing resource availability and need times.
“For about eight years, we’ve been recommending that load-modifying resources be moved up in the stack,” said Patton, who noted he has recommended repeatedly that MISO allow itself to call up LMRs at the earliest stage of its emergency process, giving those resources adequate time to generate by the time emergency conditions materialize.
MISO 2019 demand response and emergency procedures | MISO
Director Thomas Rainwater suggested that MISO consider separating its emergency resources into those that can be ready in four hours or less and those that require a longer lead time. He added he was “encouraged” by the idea that some non-traditional generation in the queue could function as more nimble reserves.
Ted Thomas, OMS president and chair of the Arkansas Public Service Commission, said Patton’s concerns about DR were overblown. He said all MISO states except Illinois have a legal obligation to ensure resource adequacy, and he expected the footprint to persevere despite the possible shortfall reported in the OMS-MISO survey.
“While we had some red in some areas of the chart, we’re not going to cruise along for the next five years until we hit a wall,” Thomas said at a June 21 board meeting. “I will be resting just fine, waking up early to work through these issues.”
VALLEY FORGE, Pa. — Calpine and American Electric Power are offering stakeholder alternatives to plans from PJM and its Independent Market Monitor for complying with FERC Order 842, which requires certain generators to provide primary frequency response.
Generation stakeholders have resisted proposals that would require existing units to provide PFR and any mandates that don’t include compensation for the service. (See Stakeholders Oppose PJM PFR Mandate for Existing Units.)
Calpine’s David “Scarp” Scarpignato explained the proposal at a June 19 meeting of the Primary Frequency Response Senior Task Force (PFRSTF). The plan hinges on requiring existing resources that provide PFR to continue doing so, along with the order’s requirement of new resources and any generators that must revise their interconnection agreements after making modifications to their facilities. The plan also calls for allowing any resources that aren’t able to fulfill their obligation to enter bilateral contracting with resources that can.
Units entering into such contracts would have to alert PJM annually. Calpine’s proposal would also require that units be able to both ramp up and down to respond to frequency changes. Just like today, PJM would have the ability to dispatch units to ensure the necessary flexibility of output. Units would also be compensated for their lost opportunity costs, especially during system restoration.
PJM has filed request for clarification on whether Order 842 was meant to include both new and existing resources. The RTO argues it does.
“A lot of the PJM way of doing this thinks that there will be natural headroom on the system,” both up and down, Scarp said. “Those are not my presumptions. Those are the presumptions that must be made under the PJM proposal for it to work. They are not directing anywhere in their proposal to create real-time headroom for primary frequency response. They’re assuming it naturally occurs,” he said. “This proposal is not a small change. It requires a significant amount of work and also encompasses more recordkeeping.”
His plan didn’t contemplate any market transactions beyond the bilateral contracting, he said, because he “didn’t see a ton of dollars” in it, but he would be open to supporting any proposals that do want to address development of a market mechanism.
Locational Issues
In response to criticism that his proposal didn’t address the importance for PFR of units’ geographic location on the grid, Scarp said his proposal, like the others, relied on “expecting diversity of location with new megawatts.”
“I think the locational issue is a significant issue, and it’s not being addressed in the matrix in a very good way under any of the proposals. … I would not be surprised if five years down the road, we reconvene to start talking about locational issues, but right now there are no locational requirements,” he said.
PJM’s Vince Stefanowicz said the RTO’s plan is intended to address locational issues and expressed concern about Calpine’s bilateral contracting idea because during a restoration event, “we really don’t know where the system is going to break up and island,” and “we have to make sure that units in [those] areas have the [PFR] capability.”
Resource connections
Scarp suggested that a second stage of the proposal address units that are interconnected via wholesale market participation agreements (WMPAs), a concern that GT Power Group’s Dave Pratzon also expressed. That phase would examine “not whether to do it [require WMPA resources to provide PFR], but how to do it,” Scarp said.
He said he’d received comments that the package should treat all resources equally, including energy efficiency and demand response, but he acknowledged concerns that adding the necessary inverters to such projects might be infeasible because they don’t inject power into the grid and don’t have WMPAs.
“It seems like a stretch,” CPower’s Bruce Campbell said. “I suspect the commission would consider that a substantive barrier to entry” to require all resources to have to install an inverter, he added. FERC included distributed energy resources in Order 842 because it believed they already needed such inverters, but doing so for DR and EE would be trying to “add capability that just isn’t there,” he said.
“If you require an EE resource to have an inverter, you won’t have any EE resources,” he said.
PJM’s Glen Boyle, who facilitates the PFRSTF, seemed to agree.
“By definition, I don’t know how EE could provide PFR. I don’t know technically if that would be capable,” he said.
AEP Proposal
Under AEP’s proposal, units that already provide PFR would be “encouraged to continue to do so” and can seek compensation at FERC. Units would annually confirm whether they will continue to provide the service, and PJM and transmission owners would revise system restoration plans accordingly.
A company representative attempted to dispel “public assertions by PJM” that AEP’s proposal might “dismiss the important requirement of having primary frequency response during system restoration” by explaining that it “focuses the system restoration conversation where it should be, with transmission owner/operators/PJM and individual generators.”
If a TO discovers it has “inadequate” PFR in its zone, the proposal calls for issuing a request for proposals “so that the most efficient resources, that actually want to provide the service, can participate” in “the most cost-effective mechanism for obtaining services: as needed.” The RFPs would be temporary until enough new units come online or existing units upgrade — both of which would already be required to provide PFR — to mitigate the need.
AEP says PJM’s proposal would force companies to pay to upgrade “resources that are in decline,” namely coal and nuclear, and that prioritizing PFR would limit units’ ability to optimize emissions.
A presentation from AEP argues that “declining” resources, such as coal and nuclear, shouldn’t be required to make investments necessary to supply PFR. | PJM
The company touts its proposal as the only one “that recognizes the potential future need of adequate synchronous inertial response,” meaning from resources that have rotating masses such as nuclear, coal- and gas-fired units.
“Did you know that simple cycle [combustion turbines] have less inertial response than a combined cycle CT? Both have much less than a coal unit,” a company presentation said.
AEP says that units can’t change PFR controls based on immediate needs.
“There is no switch! If you want PFR during system restoration, the unit must be tuned to provide it at all times. Re-tuning valves and governor action when there is a restoration event could increase chance of resource tripping significantly,” it said.
The company also criticized what it sees as PJM’s request to “bypass control limits” to optimize its PFR output.
PJM’s Stefanowicz contested that assertion.
“We’re not intending for anybody to bypass any safety functions,” he said. “We’re talking about removing outer loop controls like megawatt set point in a restoration mode and being responsive to frequency. We realize there’s tuning and controls in place to run unit efficiency day in and day out.”
AEP and Scarp agreed that the wording in PJM’s proposal suggests that company should disable any controls that would impact PFR performance, such as emissions controls.
The task force has canceled its planned June 26 meeting but is maintaining one scheduled for July 25. Boyle predicted the agenda will be “fairly light unless we hear something back from FERC in the interim” on PJM’s request for clarification.
Boyle said a stakeholder vote on the proposals would be planned tentatively for a Sept. 26 or Oct. 24 meeting if FERC hasn’t responded.
Scarp endorsed a vote to at least clarify stakeholder positions in the absence of any word from FERC.
“My tolerance is not indefinite. FERC can and might sit on things,” he said.
California and eight other states rolled out a plan Wednesday pushing for wider adoption of policies that would accelerate the use of zero-emission vehicles (ZEVs) and meet greenhouse gas-reduction goals.
The “Multi-State ZEV Action Plan” calls for increased adoption of ZEV purchase and infrastructure incentives, more consumer outreach and heavier emphasis on the technology at state utility commissions. The plan, which covers 2018 to 2021, comes out of a 2013 agreement signed by California, Connecticut, Maryland, Massachusetts, New York, Oregon, Rhode Island and Vermont, which represent almost 30% of new car sales in the U.S., they said.
The new action plan by the nine states covers 2018-2021
“Transportation electrification is essential to deliver the deep reductions in emissions that are needed to meet state climate goals. The state ZEV programs, which require automakers to deliver increasing numbers of zero-emission vehicles between now and 2025, are a key strategy in state climate plans,” the plan says.
It includes 80 recommendations for states, automakers, dealers, utilities and charging companies in order to bolster plug-in hybrid, battery electric and hydrogen fuel cell vehicles. The new effort follows a similar 2014 multistate plan the coalition said has increased ZEV incentive programs, new education campaigns and new commission initiatives in their states.
With hundreds of millions of fossil fuel-powered vehicles on American roadways, the report acknowledges that ZEV adoption so far has been focused mainly on “enthusiastic early adopters” and that much wider deployment, including commercial/utility vehicle fleets, will be needed to make an impact on climate change.
The report says that automakers are now required to deliver fully electric vehicles to meet specific sales goals in Oregon and other coalition states in the Northeast. More than $500 million in charging infrastructure is planned for the Northeast corridor, and California is now focusing on bolstering its infrastructure through $738 million in utility incentives. (See California to Require Sharp EV Charger Growth by 2025.)
Number of registered plug-in hybrid electric vehicles (PHEV) and battery electric vehicles (BEV) in the nine states | ZEV Taskforce
Total U.S. ZEV sales grew from 200,000 to 750,000 since 2013, as battery costs declined and the number of available models and options increased. The states say light-duty vehicle adoption and public-private partnerships are important tools in wider adoption.
California Attorney General Xavier Becerra and others have challenged in court EPA’s April 4 decision to roll back previous GHG emission standards related to light-duty vehicles, which the agency said “may be too stringent.”
Several governors referenced the EPA decision when announcing the new action plan, with Connecticut Gov. Dannel P. Malloy saying: “When it comes to taking aggressive steps to fend off the most damaging impacts of climate change, the Trump administration not only continues to bury its head in the sand but is actively working to dismantle common sense efforts to reduce carbon pollution.”
Light-duty vehicles, classified as those with gross vehicle weight of 10,000 pounds or less, are the largest contributor to GHGs in the nine states (24% of emissions), followed by the electricity sector (19%) and industry (17%), with the remainder coming from heavy-duty vehicles, agriculture, the residential sector, other transportation and the commercial sector.
The impact of a carbon price would likely reverberate throughout New York’s wholesale electricity markets, industry experts said Monday.
Carbon pricing could be “a real game-changer in terms of likely impacts on the market,” Couch White attorney Michael Mager said during a June 18 meeting of the state’s Integrating Public Policy Task Force (IPPTF), the group charged with exploring how to price emissions into NYISO’s markets. Mager represents a coalition of large industrial, commercial and institutional energy customers.
During the meeting, NYISO presented its proposed approach to analyzing the effects of a carbon charge on various wholesale market processes, including its Installed Capacity (ICAP) market and related demand curve reset.
| NYSEG
NYISO may have to adjust ICAP rules to reflect carbon pricing if it believes the carbon charge is not appropriately reflected in prices, said ISO staffer Nathaniel Gilbraith.
Capacity prices are generally expected to make up for “missing money” from the energy market, and it’s important for capacity rules to capture relevant energy market revenues when setting prices, Gilbraith said.
Issue of Timing
The ISO’s estimation of the energy and ancillary services revenue offset is a key component of its annual process for updating its demand curve. (See FERC OKs NYISO Demand Curve Reset.) But Mager pointed out that if the ISO’s annual update considers only rolling historical revenues and neglects to factor in carbon prices, it will miss the mark.
“One issue is timing. If carbon pricing is implemented, when is it implemented vis a vis the demand curve reset process?” Mager said. “The second is how do you deal with the [energy and ancillary services] revenues in light of a dramatic change like this.”
Power Supply Long Island Director of Wholesale Market Policy David Clarke said, “We would prefer the demand curve to ramp smoothly … consistency would be sensible with what’s assumed in the [locational-based marginal price] and what’s assumed in the bid for demand curve reset purposes.”
Transmission Planning
Ethan Avallone, NYISO senior market design specialist, explained that the ISO performs economic analyses of new transmission facilities in its Congestion Assessment and Resource Integration Study (CARIS) studies and as needed for its Public Policy Transmission Needs Planning Process. Those analyses include production cost simulations and already account for the Regional Greenhouse Gas Initiative price, and would similarly incorporate the carbon charges on suppliers, he said.
Representing New York City, Couch White attorney Kevin Lang said, “We don’t really build transmission on a CARIS basis or on an economic basis in this state, and I’m not sure when — or if — we ever will. … So in terms of priorities, this is a much lesser issue than grappling with the demand curve.”
“If you’re accounting for RGGI you should be accounting for the carbon price; that just makes sense,” Lang said. “From our view, we’d like to see the transmission response of how we’re going to encourage more transmission to be built, and I don’t know whether that’s economic, or whether it’s public policy, or potentially reliability planning.”
Clarke said there is a potential disconnection between the marginal carbon component price in the LBMP and the actual change in carbon emissions associated with a new transmission line.
“For example, suppose wind is on the margin before and after a transmission line is added, but the line also unbundles some additional wind that can be added into the market,” Clarke said. “There would be a circumstance where you don’t have a price difference associated with that — the marginal unit hasn’t changed — but you have changed the amount of low carbon resources that are able to enter the market. The change in the carbon may not be reflected in the marginal price.”
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said such deep transmission planning “is probably a bit beyond what we’re doing here,” adding that the group is “just looking at the impact of a carbon price on the market, not evaluating different transmission opportunities and what the consequences of them are in a carbon adder world.”
Customer Impacts
Timothy Duffy, the ISO’s manager for economic planning, presented three separate planning scenarios. The first case — the reference case — was modeled for three different years (2020, 2025 and 2030), and the remaining two for 2030 only.
The reference scenario presumes 226 MW of offshore wind by 2020, with the state’s full commitment of 2,400 MW calculated into the 2025 and 2030 iterations. All scenarios consider coal plants retired and include western New York and generic AC transmission upgrades.
The scenarios vary on the nuclear component, considering that Indian Point will retire in stages over 2020/21, and that the state’s zero-emission credits supporting nuclear will expire in 2030.
Erin Hogan, representing the Department of State’s Utility Intervention Unit, asked what would happen in 2023 when Indian Point will be retired and the AC upgrade will not yet be completed.
“We didn’t feel that there would be much information gleaned from that particular scenario that wouldn’t be gleaned from running, for example, 2025 with both high and low energy loads,” Duffy said.
The ISO’s broad analysis “captures the bookends of what would be the LMP impacts [and] load-shaving impacts associated with a carbon price,” Duffy said.
Hogan disagreed.
“People talk about price signals, and then the reality is that people have choices with price signals,” Hogan said. “If we are going to have a year with exceptional high price signals with the congestion, not having [Indian Point] and not having the AC transmission, we need to know that. That could go beyond what you’re characterizing as the high load scenario.”
Catch-22
Lang questioned the ISO’s professed need to fit the carbon price analysis into “the allotted time frame.”
“There’s no Tariff requirement, there’s no statutory requirement for that, and we’ve had lots of other cases where things have been delayed because the analysis takes longer than expected,” Lang said.
“I’m extremely troubled that we’re looking at something that could have a very significant consumer impact — we don’t know yet because we haven’t seen the analysis — and all I keep hearing from the ISO is ‘we can’t do the broad analysis that folks are asking for because we don’t have the time to do it.’”
Duffy said the situation was a catch-22.
“You’re telling us that you need to know the results of the analysis before you can decide to move forward, but you’re not letting us get the analysis because we’re debating the assumptions we would use in the analysis,” Duffy said. “We’re trying to get to the point where actually we can run the analysis and present the results.”
If at that point there’s a consensus to continue the analysis, “that’s fine, but please let us get to the point where we start presenting results so we can start talking about those as opposed to what-ifs and maybes,” he said.
The task force next meets July 9 at NYISO headquarters.
American Electric Power on Wednesday announced that Louisiana’s Public Service Commission has approved its proposed mammoth Wind Catcher Energy Connection project.
AEP’s Louisiana operating company, Southwestern Electric Power Co., would own 70% of the $4.5 billion project, a 360-mile, 765-kV line to Tulsa from a 2-GW wind farm being built by Invenergy in the Oklahoma Panhandle. AEP affiliate Public Service Company of Oklahoma would own the other 30%. The two utilities would purchase the wind facility upon its completion, scheduled for the fourth quarter of 2020.
AEP’s Wind Catcher site | Invenergy
SWEPCO agreed to a cap on construction costs, qualification for 100% of federal production tax credits and minimum annual production goals, among other commitments.
“Wind Catcher is a major investment in clean energy that will produce long-term savings for Louisiana customers and further diversify our energy resource mix,” AEP CEO Nick Akins said in a press release. “The Louisiana Public Service Commission’s decision recognizes the benefits Wind Catcher will bring to Louisiana customers.”
Galvez Building housing the Louisiana Public Service Commission | LA.gov
AEP says it expects to save its customers more than $4 billion over the 25-year life of the wind farm, primarily through a reduction in the fuel portion of their bills that begins in 2021.
The PSC joined Arkansas regulators in approving the project. The Oklahoma and Texas commissions have yet to weigh in, but AEP appears to face longer odds before those two agencies.
The head of the Oklahoma Corporation Commission’s Public Utility Division and the state’s attorney general have indicated in regulatory filings that they remain opposed to the project, and landowner opposition to the transmission line has been running high. The OCC has scheduled a public comment hearing for July 2.
Texas’ Public Utility Commission staff has disagreed with an administrative law judge’s preliminary decisions approving Wind Catcher, saying “the evidence presented does not support a sufficient probability of improvement of service or lowering of costs to ratepayers.”
Staff recommend that the commission condition its approval on a requirement that SWEPCO guarantee tax credits in the amounts represented by the utility, and that it guarantee some level of net benefits to customers over and above the annual revenues that customers are obligated to pay for the project’s base rate costs. The PUC will take up the issue at its July 12 open meeting (Docket No. 47461).
Former Senate Majority Leader Trent Lott (R-Miss.) and former Sen. John Breaux (D-La.) have joined a new organization to build political support for the carbon dividend proposal offered last year by Republican party elders James A. Baker III and George P. Schultz.
Lott | Bipartisan Policy Center
Lott and Breaux are co-chairing the advisory board of Americans for Carbon Dividends, which announced itself Wednesday with financial backing from Exelon, First Solar and the American Wind Energy Association, along with a poll it said shows wide bipartisan support for the Baker-Schultz proposal.
Baker and Schultz’s Climate Leadership Council, formed last year, proposed a carbon fee of $43/ton starting in 2021 that would return the funds to Americans as monthly dividends. Backers say the plan would provide net payments to 70% of Americans while reducing emissions more than the U.S. commitment under the Paris Agreement.
Escalating the fee by 3 to 6% per year would reduce carbon emissions by 34 to 36% from 2005 levels by 2025, they say, and eliminate the need for existing carbon regulations such as the Clean Power Plan. (See Baker’s Carbon Dividends Plan Reaches Across Aisle.)
A carbon fee beginning at $43/ton in 2021 and escalating at 4% annually would reduce emissions by 32% from 2005 levels. | Climate Leadership Council
“This is the inevitable climate solution and the most likely to lead to a grand bipartisan climate compromise,” said Hill+Knowlton Strategies Managing Director Richard Keil, the newly formed group’s spokesman in a press conference Wednesday. Keil noted that former Federal Reserve Chairs Ben Bernanke and Janet Yellen and former EPA Administrator Christine Todd Whitman have signed on to the plan as founders of the CLC.
Keil said the new group was formed to signal the move to an “inside the Beltway strategy” after the CLC spent last year on policy development and working outside the Beltway.
Breaux | Squire Patton Boggs
Breaux acknowledged Congress is unlikely to embrace the plan any time soon. “This is an educational program that we’re embarking upon … which means we will be talking to leaders in the Congress in both parties. … This is not a sprint. It’s going to be a marathon.”
“I think that both parties are desperate … to find something that they can agree on,” he added.
“I took quite some time to look at this issue and think about it,” Lott said. “I’m convinced this is the solution that we have been looking for as a country and, frankly, in the world.”
Ted Halstead, CEO of the carbon dividends group and the CLC, said Republicans’ views on climate change have shifted over the last five years. “[There’s] no real differences numerically between where younger Republicans and younger Democrats are on this. I don’t want to overstate it because I don’t have a side-by-side comparison of numbers to do this, but it at least in general reminds me about how … attitudes within the Republican Party shifted on issues like gay marriage over the last 10 years. The next generation of Republicans thinks about these and other things differently than some of their older peers.”
The group released a poll showing 81% of likely voters, including 71% of moderate Republicans and 58% of conservative Republicans, agree the government should act to limit carbon emissions. It said the tax-and-rebate strategy is favored by a 2:1 margin overall.
“Members of Congress pay attention to polls,” Breaux said.
In addition to bringing on Hill+Knowlton to handle communications, Americans for Carbon Dividends has hired Squire Patton Boggs — where Lott and Breaux are senior counsels — as lobbyist and Margaret Lauderback, an ally of Rick Perry and House Majority Leader Kevin McCarthy, to lead fundraising. Political consultant Mark McKinnon, a former advisor to Sen. John McCain (R-Ariz.) and former President George W. Bush, and Joe Lockhart, White House press secretary under President Bill Clinton, have signed on as senior advisers. Former Bush aide Karen Hughes is of counsel.
SACRAMENTO, Calif. — A California State Senate committee advanced a bill Tuesday that would allow CAISO to be transformed into a Western RTO, a major change in the electricity market that has been met with heavy opposition.
Sponsored by State Assemblyman Chris Holden (D), AB813 garnered the six necessary votes in the Senate Energy, Utility and Communications Committee to move on to the Judiciary Committee for review. The Assembly approved the bill on June 1, and with Gov. Jerry Brown a strong supporter of regionalization, the bill is likely to get his signature if approved on the Senate floor.
Proponents say the law would help the state export excess renewable energy and create a more efficient regional market, lowering costs.
“This is an opportunity for California to expand our good policies across state borders and to expand upon that,” Holden told the committee. The recently amended bill was carried over from last year’s session. (See Calif. Energy Bills Move Forward, but Big Ones Stall.)
The bill creates a Western States Committee with three representatives from each state with a participating transmission owner, which would provide input on RTO matters that affect more than one state. Left open is the question of whether state voting power would be weighted by electricity load. It also specifically prohibits the creation of a capacity market.
But memories of California’s 2000/01 electricity crisis remain strong in the state, and many interests have expressed concerns about increased oversight of the market by the federal government. CAISO is already regulated by FERC, but some worry California would lose control of clean energy goals to the federal government and other states.
Committee member Robert Hertzberg (D) said that he “generally likes the notion of regionalization” but added that “I am very unhappy as to how this bill has proceeded.” He said he had many concerns about repeating the mistakes of the electricity crisis and negatively affecting the economy by moving jobs out of the state.
“There is an underlying issue that is legitimate with respect to California jobs,” Hertzberg said. “I am deeply concerned across the board.”
The bill has a long list of opponents, including labor groups worried about exporting energy-related jobs to other states and environmental groups, such as Sierra Club and Earthjustice, who say the changes will make California subject to imports of fossil-sourced generation. More than 12 California cities, the Port of Oakland, Sacramento Municipal Utility District, the Utility Reform Network and other groups oppose regionalization.
Former FERC Chairman Jon Wellinghoff addressed the committee, attempting to ease fears about the commission’s oversight. Wellinghoff said FERC acts independently, pointing out it recently dispensed with the Department of Energy’s proposed Grid Resilience Pricing Rule.
“They are really going after PJM … where most of these coal plants reside,” he said of the Trump administration’s effort to bolster coal.
While the regionalization debate continues, CAISO has proposed bringing its day-ahead energy market to the Western Energy Imbalance Market. That measure would allow more energy trading across the region but does not create a new RTO with new multi-state management as envisioned by AB813. (See CAISO Day-ahead Could be Tailored for the West.)
FERC on Monday ordered Footprint Power to refute a finding that the company violated ISO-NE Tariff rules and federal regulations by filing “false and misleading supply offers” for its Salem Harbor Power Plant in June and July 2013.
Footprint has 30 days from the June 18 order to show cause why it should not forfeit $2,049,571 in Capacity Supply Obligation (CSO) payments for a period during which FERC’s Office of Enforcement staff found that Unit 4 at the plant could not provide capacity. The company must also demonstrate why it should not be assessed $4.2 million in civil penalties.
Salem Harbor Power Plant | Tetra Tech
Enforcement staff allege Footprint submitted supply offers that Unit 4 could not satisfy because Salem Harbor lacked usable fuel. Staff found the company not only failed to report the lack of fuel to the RTO but also “omitted material information from and/or misrepresented the fuel status of Salem Harbor and related operational status of Unit 4.”
Background
In 2012, Footprint bought Salem Harbor, a 748-MW coal- and oil-fired plant with four units, from Dominion Resources Services. Two units at the plant had been retired in 2011, while units 3 and 4 were operational at the time of purchase. Both units had a CSO for both ISO-NE’s Forward Capacity Auction 3 (FCA 3) Capacity commitment period (June 2012 through May 2013) and the FCA 4 commitment period (June 2013 through May 2014).
However, units 3 and 4 were scheduled to retire effective June 1, 2014, coincident with the start of the FCA 5 Capacity commitment period. Unit 3 was primarily a coal-fired unit and Unit 4 was a 437-MW oil-fired unit.
The units have since been demolished, and Footprint is now converting the plant to a 674-MW gas-fired, quick-start, combined-cycle generator, which is expected to go into service by the end of the year. (See “Future Locational Reserve Needs” in ISO-NE Planning Advisory Committee Briefs: June 13, 2018.)
The RTO had rejected earlier de-list bids to retire Unit 4 during FCA 3 and 4, citing reliability needs. In exchange for keeping the unit online and available, “Dominion was not paid the pro-rated capacity auction clearing floor prices in FCAs 3 and 4, but instead received the unit’s cost of service — which was approximately double the amount received by other ISO-NE capacity resources,” the commission noted.
Footprint subsequently collected CSO payments in the same amount awarded to Salem Harbor when Dominion owned the plant, which totaled about $4.4 million from June to July 2013.
Salem Harbor, at the time, had only one fuel storage tank that could hold roughly 200,000 barrels (bbl) of oil used to supply Unit 4. However, Footprint had also sold most of Salem Harbor’s fuel inventory back to Dominion, leaving only 40,000 bbl on site by December 2012, an amount the plant staff believed was less than two days’ worth of fuel.
Enforcement staff alleged that because Unit 4 burned between 14,000 and 16,000 bbl of fuel per day when operating, the plant’s managers were aware the remaining 40,000 bbl would not last longer than two days because only 29,000 bbl could be physically accessed from the tank.
‘Feasible’ Defense
ISO-NE’s internal Market Monitor alerted the commission to Salem Harbor Unit 4’s repeated inability to meet its CSO, also alleging “that false or misleading Day-Ahead (DA) supply offers and verbal communications were made to ISO-NE regarding Unit 4’s availability.”
In 2015, FERC staff and Footprint counsel discussed staff’s preliminary findings and Footprint’s claim that staff relied on assumptions rather than data to calculate Salem Harbor’s usable fuel inventory. Footprint claimed staff used the wrong data in its investigation, but “even after staff used the data source proffered by Footprint, use of that data source did not materially impact staff’s calculations,” said the commission.
In response, Footprint claimed Unit 4’s offers were “feasible” because the unit did not have to operate in accordance with its CSO due to certain environmental limitations on nitrogen oxide emissions.
In February 2018, after Footprint and staff had the opportunity to discuss the settlement, staff issued a letter providing notice of staff’s intent to recommend the commission initiate a public proceeding against Footprint.
Footprint submitted its response on March 12, 2018. “Although staff narrowed the set of violations pursued in light of the additional information it received … staff still concluded that the majority of Footprint’s arguments were not supported by the evidence and did not alter staff’s views that violations occurred,” said the commission order.
Footprint must now provide a concise statement regarding any disputed factual issues and any law upon which they rely, admit or deny each material allegation and set forth every defense relied upon. Failure to answer the order to show cause will be treated as a general denial and may be the basis for summary disposition, the commission said.
Footprint may also choose to apply section 31(d)(3) of the FPA to the proceeding. If the commission then finds a violation, it will issue a penalty assessment and, if not paid within 60 days of the order assessing penalties, it will institute an action in the appropriate United States district court.
