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November 17, 2024

PJM Gens Pitch Order 842 Compliance Plans

By Rory D. Sweeney

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 | © RTO Insider

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.”

Stakeholders at the PFRSTF meeting on June 19. | © RTO Insider

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.

Nine States Call for Rules to Boost ZEVs

By Jason Fordney

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.

ZEVs climate change zero-emission vehicles
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.)

ZEVs climate change zero-emission vehicles
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.

NY Task Force Examines Carbon Pricing Market Impacts

By Michael Kuser

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.

NYPSC demand curve reset carbon price ipptf
| 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.

Louisiana Regulators Approve AEP’s Wind Catcher Project

By Tom Kleckner

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.”

AEP Wind Catcher Project LPSC
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).

Lott, Breaux Join Push for Baker-Schultz CO2 Dividend Plan

By Rich Heidorn Jr.

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.

carbon dividends trent lott john breaux
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.

carbon dividends trent lott john breaux
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.

Senate Committee Advances CAISO Regionalization Bill

By Jason Fordney

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.

Holden, second from right, discusses AB813 with committee Chairman Ben Hueso, second from left. | © RTO Insider

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.

caiso regionalization western RTO
Hertzberg | © RTO Insider

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.

caiso regionalization western RTO
Sen. Henry Stern asks former FERC Chairman Jon Wellinghoff about federal jurisdiction over California. | © RTO Insider

“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.)

Salem Harbor Plant Facing FERC Action

By Michael Kuser

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.

Footprint power salem harbor ferc
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.

Driving Carbon off the Road in New England

By Michael Kuser

BOSTON — Private car ownership in cities will be a rarity in five years, but it may take 30 years to get all the gas-guzzling pickup trucks and SUVs off the road.

Those were two extremes of visions for decarbonizing the transportation sector presented Friday at Raab Associates’ 158th New England Electricity Restructuring Roundtable.

The New England Restructuring Roundtable gathered on June 15 to discuss decarbonizing the transportation sector | © RTO Insider

Pollack | © RTO Insider

Two big challenges in decarbonizing passenger vehicles are geography and scale, said Massachusetts Transportation Secretary Stephanie Pollack.

“Lyft has pledged that its company alone will provide 1 billion autonomous, electrified rides annually by 2035, which would be far more important if we didn’t make 411 billion trips a year in the United States, meaning that the 1 billion trip goal represents less than one day’s travel — and that’s one day’s travel in 2015, not 2035,” Pollack said.

“That, my friends, is the problem of scale in transportation,” she said. “Sometimes I refer to it as the ‘denominator’ problem. We talk about the numerator — we’re going to have 300,000 electric cars, we’re going to have a billion trips — and we forget the denominators, and in transportation they’re enormous.”

Inundating Innovation

“As we sit here today in this low-lying seaport/innovation district — someone in the audience said ‘inundation district’ — the announcement yesterday that Antarctic annual ice loss has tripled in the last decade, and now stands at 219 billion tons of ice per year, should continue to instill a sense of urgency in these matters for all of us,” said moderator Jonathan Raab.

Raab | © RTO Insider

“Although this is our Electricity Restructuring Roundtable — and the electrification of cars is often viewed as the panacea for reducing carbon in the transportation sector — we should not forget the critical importance of strategies to reduce VMT, or vehicle miles traveled in personal vehicles, through mass transit, shared mobility, biking, walking, telecommuting and other strategies, as well as making transportation more efficient generally,” Raab said.

Klee | © RTO Insider

Robert Klee, commissioner of the Connecticut Department of Energy and Environmental Protection, boasted that his state, though small, is keeping up with its neighbors in offshore wind procurements and even moving ahead in setting interim goals for greenhouse gas reduction, highlighting the passage earlier this month of Public Act 18-82 (Senate Bill 7).

The department had announced Wednesday that the state will purchase 200 MW of output from Deepwater Wind’s Revolution Wind project, adding to Rhode Island’s 400-MW procurement. (See Conn. Awards 200-MW OSW, 50-MW Fuel Cell Deals.)

“As Massachusetts is thinking about their interim goals, we’ve actually put them into law, so for 2030, there are 45% reductions in greenhouse gas,” Klee said. “We took where we are today, and where we have to go by statute — 80% by 2050 from 2001 levels — drew basically a straight line, that’s 45% by 2030. That is actually the most ambitious target in the country right now.”

Transportation represents 36% of the state’s GHG emissions, “and that means we have to do a whole lot on deployment of zero-emission vehicles, and transit, and it’s an all-of-the-above strategy for Connecticut,” Klee said.

The state is also pushing against federal rollbacks by working with other states, such as through the U.S. Climate Alliance, he said. It also joined the Transportation and Climate Initiative with eight other states in the Northeast to consider a cap-and-trade system for transportation similar to the Regional Greenhouse Gas Initiative in place for the power sector.

Ridesharing Fix

Corey Ershow, Lyft’s transportation policy manager for the Eastern U.S., wants to help tackle Pollack’s denominator problem through ridesharing, which cuts total VMT by increasing the number of passengers in a vehicle.

Ershow | © RTO Insider

“About three-quarters of commuters not only drive to work every day, but they’re doing so alone, which shouldn’t be all that surprising, but it does cause significant problems — $160 billion a year in congestion costs, and 40,000 American fatalities last year,” Ershow said.

Historically, we haven’t given people a lot of options, he said. “Either you take mass transit, which is great if you live right along an existing route, and it’s operating at high capacity, but that’s not the case everywhere,” Ershow said. “As a result, car ownership looks pretty appealing.”

In the vast majority of use cases, a private vehicle is going to be the fastest way to get from point A to point B in an era in which we are placing an increasing price premium on time, he said.

“But ridesharing has proven demand for an alternative,” Ershow said. “This is going to become that much more ubiquitous as we move into autonomous vehicles,” which when shared on a platform like Lyft could mean dramatic reductions in VMT numbers in the U.S.

The company projects that within five years, fully autonomous vehicles will provide the majority of Lyft rides across the country, and by 2025, private car ownership will all but end in major U.S. cities, he said.

Heywood | © RTO Insider

Mechanical engineering professor John Heywood of the Massachusetts Institute of Technology said that huge swaths of the country are outside urban areas, and drivers who live in rural areas are more prone to be concerned about the range of an EV.

“Long recharging times are also an issue, because if you up the power, you fry the battery,” Heywood said. “Most EVs must recharge at home, and they do 90% of their recharging at home, and 90% of EV buyers buy a home recharger. But how many homes have that potential? Our current estimate is about a third of the 110 million homes in the U.S. So that’s a constraint that we haven’t yet found a way around.”

Efficiency and EVs

Haley | © RTO Insider

Ben Haley, cofounder of Evolved Energy Research, posited three pillars supporting a deep decarbonization strategy for the transportation sector — electrification, energy efficiency and electricity decarbonization.

Reducing carbon emissions to 80% below 1990 levels by 2050, Haley said, would require a threefold increase in the share of energy from electricity, coupled with efficiency gains to reduce per capita energy use by 40%. But even that is not enough, he said.

“Even with energy efficiency, electrification increases load precipitously, but as we are doing that we’re also needing to bring on renewable resources or other decarbonized resources to lower the emissions intensity about 90%,” Haley said.

“These are sobering numbers, undoubtedly,” he said. “Per capita energy use needs to drop, which can be through a combination of electrification, fuel efficiency, a reduction in service demand through conservation or reimagining of service demand through mobility — all of those can reduce energy. Every unit of energy we don’t demand means we don’t have to build a system to support that.”

Lévesque | © RTO Insider

Evangeline Levesque, executive director of sustainable transport and electrification policies for the Quebec Ministry of Transportation, said her province is in the middle of a five-year, $420 million plan to electrify its transportation.

“Quebec has a lot of clean, renewable energy,” Levesque said, referring to the province’s vast hydropower resources. “As it is, we have a lot of it. As it is not too expensive, it was the obvious treatment.”

The difference between Quebec and New England is that it funds its decarbonization programs through an active carbon market, being part of the Western Climate Initiative with Ontario and California. The province set a target of $500 million of investment and 5,000 jobs in the EV industry by 2020, by when it aims to have 100,000 EVs registered.

Monumental Shift

Terence Sobolewski, chief customer officer for National Grid, acknowledged the barriers mentioned by other speakers, such as consumer awareness, high cost and EV model availability. But he said that building charging infrastructure was the most important step now, in the early stages of the industry.

To achieve 80% GHG reductions by 2050, “we need to have half of our light duty fleet be electric by the year 2030, [for which] you actually need to have 100% of sales [be] electric at least two or three years before that to effect that transition,” Sobolewski said.

“That means that in less than 10 years, every car and light duty truck sold in the Northeast would have to be electric,” he said. “That’s a monumental consumer shift we’re talking about achieving.”

RTO Insider Begins Quote Check Policy in MISO

EDITOR’S NOTE: In a continuing effort to ensure the accuracy and fairness of its reporting, RTO Insider has begun implementing a quote check policy for MISO stakeholder meetings.

RTO Insider MISO quote check policy
MISO’s Advisory Committee meeting in March 2018 | © RTO Insider

Excluding breaking news bulletins, every story RTO Insider publishes goes through at least two editors. In addition, they are reviewed by a proofreader before being included in our weekly newsletter. However, given the complexity of the issues we cover, we have found that checking quotes with RTO officials and stakeholders allows us to provide the proper context for their comments and to catch factual errors before they appear in print.

Following its coverage of MISO stakeholder meetings, RTO Insider will submit a story draft or quotes we intend to publish to any stakeholder quoted, including MISO staff. We email such drafts the afternoon or evening following the meeting and will give all quoted until 5 p.m. ET the following day to respond with any corrections or clarifications.

We will do our best to incorporate all feedback in the published story. However, recognizing that stakeholders may have different views of what transpired at the meeting, RTO Insider retains final editorial control on what is published.

We have no higher goal than ensuring our reporting is accurate and fair. If you have any questions about our policy, or a question or complaint about our coverage, please do not hesitate to contact me.

Rich Heidorn Jr., editor and co-publisher
202-577-9221
rich.heidorn@rtoinsider.com

FirstEnergy Calls out FERC ‘Failure’ to Act on Resilience

By Rory D. Sweeney

FirstEnergy Solutions is looking to recent developments in New England to bolster its renewed argument that FERC take emergency action to financially support “fuel-secure” resources to promote resilience of the nation’s electricity grid.

ISO-NE’s request to prop up Exelon’s Mystic gas-fired plant shows FERC’s “failure … to ensure the continued operation of critical nuclear and coal-fired generators while a long-term solution is developed” when it declined to implement the emergency price supports envisioned by the Department of Energy’s Notice of Proposed Rulemaking earlier this year, FES argued in comments filed on Friday in FERC’s resilience docket (AD18-7).

FirstEnergy Mystic FES Exelon FERC ISO-NE
Mystic Generating Station

“On multiple occasions in the past several years, the commission was asked to undertake decisive action to preserve grid resilience but failed to do so,” FES wrote, calling on FERC to implement “the same relief requested by ISO-NE but applied at a level sufficient to protect the resilience of the nation’s electric grid.”

“If the commission acts now to preserve nuclear and coal-fired generators, it will have more options to address resilience problems in the future,” the company said. “These options will not exist if the commission waits years or even months to act.”

‘Things to Come’

FES argued that ISO-NE’s Tariff waiver request to keep Mystic running despite Exelon’s plans to retire the facility (ER18-1509) “foreshadows things to come if the commission does not undertake swift and decisive action to preserve fuel-secure generating resources” and “is the consequence of commission inaction and, particularly, its failure to ensure that RTO/ISO markets contain just and reasonable rules that provide adequate compensation for needed generation.”

ISO-NE’s request inspired a Section 206 complaint from the New England Power Generators Association on the issue (EL18-154), along with dissent from other stakeholders. (See Mystic Waiver Request Spurs Strong Opposition.)

Such individual reliability-must-run agreements “are merely Band-Aids,” and without action “at once and on a national level … the commission soon will face a flood of similar requests … that do nothing to address the underlying problems that necessitate such requests,” FES said.

FES filed for bankruptcy on March 31, just a day after announcing the closure of its three nuclear plants and two days after asking Energy Secretary Rick Perry to issue an emergency order under Section 202c of the Federal Power Act directing PJM to compensate coal-fired and nuclear power plants that have 25 days of on-site fuel. Parent company FirstEnergy has since developed a plan to extricate itself from the woes of its merchant subsidiaries. (See FirstEnergy Announces Mixed Earnings, Plan for FES Bankruptcy.)

FES’ pleas to Perry came less than 90 days after FERC rejected his call for cost-of-service payments to coal and nuclear generators (RM18-1) and opened a new docket (AD18-7) to consider grid resilience. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)

The company’s comments were filed in the new docket — along with the Mystic RMR and NEPGA complaint dockets — calling on FERC to reconsider the company’s proposal in the docket initiated by Perry’s request.

FES frames the current resilience docket as a chance for FERC to rectify past mistakes, laying out what it believes are previous opportunities to address issues the commission missed. They include Maryland’s attempt to subsidize construction of a gas-fired generator in 2009, Ohio’s requests for power purchase agreements in 2016, DOE’s NOPR in 2017 and its 202c emergency relief request.

No Real Markets

The filing also takes on repeated claims by RTOs/ISOs that they have the situation under control.

“ISO-NE’s request represents a breach in the dam. Without immediate and meaningful action on a broad scale, the commission will soon be faced with a flood of requests for waivers. Even that may not even be enough to address the threat to the grid’s resilience if RTOs and ISOs continue to ‘hear no evil, see no evil, speak no evil,’” the company said. “The record also makes clear that the commission can no longer rely on assurances from RTOs and ISOs that ‘all is well’ and that they have the problem in hand.”

The company argues two views that radically diverge from sentiment in much of the industry.

First, even though most electricity outages are caused by disruptions at transmission and distribution facilities, resilience isn’t resolved by adding more redundancy on those networks because “threats to the electric grid’s resilience stem first and foremost from problems with the nation’s fuel supply mix,” the company said. However, the filing doesn’t define the threats.

Second, the company argues that providing supports to nuclear and coal-fired units won’t “blow up” markets because they don’t really exist. The idea “that we have truly efficient markets today, where competition among suppliers actually sets prices” is “fundamentally flawed.”

The company included in its filing a 20-page report done by D.C. law firm Wilkinson Barker Knauer in May that FES said “demonstrates that continued deification of these so-called markets is misplaced.” The paper argues competitive energy markets are “in tatters,” having been “trampled” by out-of-market payments to generators, such as renewable energy credits or RMR contracts.

“An overreliance on natural gas in New England has produced a loss of fuel security and diversity so extreme that the retirement of a single natural gas-fired station that does not rely on pipeline gas will expose ISO-NE’s electric grid to rolling blackouts in the coming years,” FES said, noting that CAISO has recently had to confer RMR contracts on three gas-fired plants. (See FERC Approves CAISO-Calpine RMR Settlements.)