Page 1360 – RTO Insider

June 22, 2018

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.

June 21, 2018

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.)

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.

June 21, 2018

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.

June 21, 2018

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.

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).

June 21, 2018

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.

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.

June 19, 2018February 5, 2025

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.

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.

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.)

June 19, 2018

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 ord e r 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-N E Planning Advisory Committee B riefs: Jun e 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.

June 18, 2018

New York Public Service Commission Briefs: June 14, 2018

Electric reliability in New York state declined last year compared to 2016 because of a severe wind storm in March, Department of Public Service staff told the Public Service Commission on Thursday.

Excluding weather-related outages, overall interruption frequency — the main metric DPS staff use — improved slightly, according to their annual report on reliability. However, some service areas saw longer interruptions, and others saw an uptick in tree-related outages compared to other causes (18-E-0153).

A severe wind storm in early March 2017 downed distribution lines in Rochester, N.Y. | *NY PSC*

But while it led to record wind generation in NYISO, the March storm, with gusts up to 70 mph, easily downed distribution lines in upstate New York. (See “NYISO Sets Wind Energy Record in March,” NYISO Management Committee Briefs.)

The three upstate utilities — National Grid, Rochester Gas & Electric and New York State Electric and Gas — collectively reported about 284,000 outages in their service territories as a result of the storm. A DPS investigation found that RG&E and NYSEG did not follow their emergency response plans, leading to longer outage times, and the utilities have filed a joint proposal with the PSC to settle staff’s alleged violations for $3.9 million.

Staff expect reliability to only worsen because of severe weather. “The weather events dominating the headlines recently indicate weather patterns are producing more frequent and powerful events,” they said. “As a result, this reliability category is expected to decline given the number of significant weather events that have occurred in 2018.”

New York has already experienced several unusually powerful storms this year, including January’s bomb cyclone, a series of March nor’easters, a spate of severe thunderstorms on May 15 and a tornado on May 3.

Pipeline Safety Efforts Improve

Meanwhile, pipeline safety improved overall last year, as local distribution companies improved their damage prevention, emergency response and leak management efforts (18-G-0260). The number of reported damages to natural gas pipelines in the state decreased slightly, from 1,565 to 1,562.

The DPS measures LDCs’ damage prevention by tallying up damages resulting from certain actions, such as mismarking areas or contractors failing to notify LDCs of excavation activities. By this standard, damage prevention improved by 22.5%.

The LDCs’ ability to respond to emergencies within 30, 60 and 90 minutes all improved, staff said. Additionally, the utilities reduced their backlog of leaks by 2,354, or 13.4%.

Staff also presented reports on electricity safety (18-E-0279) and customer service (18-M-0267).

Separately, as part of its consent agenda, the PSC approved a $1.98 million settlement by National Grid for a 2015 pipeline explosion on Long Island that destroyed a house and severely injured two people inside (15-G-0298). A staff investigation found the company failed to disconnect gas service to the house after a resident request.

Central Hudson Rate Increase Lowered; Burman Dissents

The PSC voted 3-1 to approve a $36.4 million electric and gas rate increase for Central Hudson Gas & Electric, 57% below what the utility initially requested (17-E-0459, 17-G-0460).

Empire State Plaza, where the New York PSC meets

Under a joint proposal with DPS staff, Central Hudson agreed to increase its rates over three years, instead of all at once. Eligible low-income customers will also see a 65% rate decrease under the plan.

“The progressive plan that was adopted — endorsed with complete stakeholder support by environmental groups, large business customers and the largest municipality in the region — includes a nation-leading affordability policy that substantially lowers bills for most low-income customers,” Chair John B. Rhodes said in a statement.

Commissioner Diane Burman spoke for more than half an hour explaining the many reasons for her “clear ‘no’ vote.” But she said the single issue that tipped the scales for her was a $264 credit to customers who install geothermal HVAC systems, which the commission says are more energy efficient and emit less carbon.

“We always say that we’re fuel-neutral [and] technology-neutral … here, we would not be,” Burman said. “And there’s no explanation to me why except that it was agreed to in the joint proposal.”

— Michael Brooks

June 18, 2018

MISO Nixes LSE Load Forecast Plan

By Amanda Durish Cook

CARMEL, Ind. — MISO has called off a proposal to rely on data from its load-serving entities to compile its own long-term load forecast, stakeholders learned last week.

The RTO will instead continue to use independent load forecasts (ILFs) prepared by Purdue University’s State Utility Forecasting Group but with a twist: It will now order four versions of the forecast, each tailored to one of the futures used to inform MISO’s annual Transmission Expansion Plan.

MISO LSE load-serving entities load forecasts — Lawhorn | © *RTO Insider*

“After careful consideration of the comments and proposals by stakeholders, MISO will begin to use the independent load forecasts to develop futures-specific load and energy forecasts for MTEP 20 and beyond,” John Lawhorn, MISO senior director of policy and economic studies, told stakeholders at a June 13 Planning Advisory Committee meeting.

Lawhorn said “consistency and clarity, not necessarily increased precision,” prompted the decision, and he stressed that MISO will continue to use LSE forecasts to plan for resource adequacy.

The expanded independent forecast is “for transmission planning purposes only,” Lawhorn said.

“I know we’ve been talking about the ILF for the past five years, with more discussion in the past eight months,” he said.

The change to an LSE-based forecast would have required MISO’s 140-plus LSEs to annually assemble four different 20-year load forecasts to fit with each of the MTEP futures, an unpopular proposition with many stakeholders. (See Advisory Committee Steps up Criticism of MISO Forecast Plan.)

The LSEs themselves were mixed over whether they would be able produce their own 20-year forecasts. An April survey generating responses from one-third of LSEs representing about two-thirds of load showed that LSEs estimated the costs of putting together forecasts would be anywhere from “minimal” to a few hundred thousand dollars, Lawhorn said.

“Costs were all over the map from that perspective, whether they already had a load forecasting group or not,” Lawhorn said in April.

Stakeholders at last week’s meeting asked whether MISO has a plan to monitor its ILFs and compare them with actual loads after the fact.

Lawhorn said although it’s difficult for MISO to line up all variables to compare forecasted load to actual load, Purdue’s own analysis has shown its forecasts “trend well” with actual load in the long term.

Other stakeholders expressed concerns that MISO had no specific plan to hold the ILF to a standard of accuracy.

WPPI Energy’s Steve Leovy said he would have liked MISO to hold more discussion with stakeholders before deciding on the ILF, adding that a single survey of LSEs was inadequate to collect opinions. Organization of MISO States Executive Director Tanya Paslawski said she was likewise concerned about MISO’s short comment period and scant communication about its decision. She noted she would take her concerns to her Board of Directors.

‘Post-capacity’ Planning

MISO said it makes sense for the ILF to be tailored to MTEP futures because energy usage is increasingly driving transmission planning, shifting away from capacity-based planning that relies on an annual system peak. The RTO says it will increasingly experience peaks that can occur during any hour of the year.

“It’s a shift that we’re seeing from a capacity-planning paradigm to an energy-planning paradigm … as we move to more facilities that are small and local. Energy delivery is becoming the driver of a robust transmission system. Moving energy around the system becomes more important as the resource mix changes,” Lawhorn said, pointing to MISO’s 93-GW interconnection queue, which includes 80 GW of potential renewable sources. “This is portending to be a major shift in our system.”

June 18, 2018

ISO-NE Planning Advisory Committee Briefs: June 13, 2018

MILFORD, Mass. — ISO-NE forecasts a net installed capacity requirement (ICR) value of 34,000 MW for capacity commitment period 2023/24, a 275-MW increase from the 33,725 used in February’s Forward Capacity Auction 12 for 2021/22, officials told the Planning Advisory Committee on Wednesday.

The net ICR is forecast to rise by 200-MW increments each period to 34,800 MW for 2027/28 with capacity margins dropping to 15% from 16.7% for 2021/22.

The forecast uses the same capacity and transmission transfer capability assumptions used to develop ICR values for FCA 12 but with the 2018–2027 Forecast Report of Capacity, Energy, Loads and Transmission (2018 CELT) load forecast. The FCA 12 values were based on the 2017 CELT, system planning engineer Manasa Kotha told the PAC. (See ISO-NE Capacity Prices Hit 5-Year Low.)

The RTO modeled three capacity zones for FCA 12: the Southeast New England (SENE) import-constrained capacity zone comprising Northeast Massachusetts (NEMA)/Boston, Southeast Massachusetts (SEMA) and Rhode Island; the Northern New England (NNE) export-constrained capacity zone comprising Maine, New Hampshire and Vermont; and the Rest-of-Pool capacity zone comprising Connecticut and Western/Central Massachusetts.

Comparisons of the 2018 and 2017 CELT load forecasts show that while overall New England load decreased, load in the SENE sub-areas has increased, as it did last year, Kotha said.

Comparison of 2017 and 2018 Net ICR Forecasts (MW) | *ISO-NE*

The increase is attributable to the Massachusetts economy continuing to grow faster relative to the other New England states, she said.

As part of its review of ICR assumptions for Operating Procedure No. 4 conditions (action during a capacity deficiency), the RTO has proposed using 700 MW of minimum operating reserves in the ICR model, an increase of 500 MW over the long-term assumption of 200 MW previously used. The new 700-MW assumption will be used in FCA 13 ICR calculations, Kotha said.

Future Locational Reserve Needs

ISO-NE foresees reserve needs in NEMA/Boston to be in the range of 250 to 700 MW for summer 2019 and 250 to 400 MW for winter 2019, Fei Zeng, technical manager for resource adequacy, told the PAC.

The RTO developed future representative operating reserve needs for the current reserve zones in NEMA/Boston, Southwest Connecticut (SWCT) and Greater Connecticut for summer and winter for study period 2018-2022. The actual requirements reported for 2018 are based on historical data of the last two years.

Investment of New England transmission reliability projects by status through 2022 (numbers represent project quantities) | *ISO-NE*

The forecasts did not consider the impacts of Footprint Power’s new 674-MW combined cycle power plant in Salem, Mass., “which when it goes into service by the end of the year is expected to have an impact on the following year’s calculations,” Zeng said.

Together with upgrades in the greater Boston area, the new Salem Harbor Station will help eliminate the local reserve needs for the study period, Zeng said.

In SWCT, the grid operator expects Competitive Power Ventures’ Towantic Energy Center, which began generating last month, to help reduce local reserve needs to a minimum level for summer 2019. With the assumed addition of Bridgeport Harbor 5, and the SWCT transmission upgrades, forward reserve requirements are expected to be zero for the remainder of the study period. (See related story, CPV: Subsidies — not Gas Shortages — Challenge for New Plants.)

CEII Presentations Describe Aging Infrastructure

The PAC heard five presentations on regional transmission infrastructure, which collectively described the rust in New England’s rustbelt. All five presentations were classified as containing critical energy/electric infrastructure information (CEII).

However, one stakeholder pointed out that much of what the classified material detailed would be visible to any interested commuter in the region. The needed replacements range from vintage control room equipment to brown glass insulators to replacing rusting towers.

Pradip Vijayan, ISO-NE senior engineer for transmission planning, updated the PAC on results from the SWCT 2027 needs assessment, as well as one project related to an older needs assessment for Greater Hartford/Central Connecticut.

Christopher Malone, Avangrid manager for Connecticut transmission planning, presented railroad corridor transmission line asset conditions. Maintenance of century-old catenary structures over the railroad is complicated by railroad control of 22-kV feeder/signal conductors.

Eversource Energy system planning manager Shaun Moran presented on challenges with the infrastructure in Eastern Massachusetts that carries much of the load for Cape Cod.

Kelly Csizmesia presented on behalf of National Grid’s New England Power unit, which operates transmission facilities in every regional state except Connecticut.

Transmission Projects and Asset Condition Update

Jon Breard, ISO-NE associate engineer for transmission planning, presented an update on the Regional System Plan regarding transmission projects and asset conditions, noting that seven new transmission projects totaling $146.8 million have been placed in service since the last update in March.

The RTO estimates about $1.74 billion in active reliability projects are underway now, compared to $1.9 billion in March.

Regarding asset conditions, the RTO reported one new project (the $6.3 million replacement of the Montville 16X transformer in Connecticut), and three projects placed in service since the last update in March, including: the installation of two 40-MVAR reactors on the Scobie 115-kV bus in New Hampshire ($4.7 million); replacement of the Salem Harbor Substation 115-kV oil circuit breaker ($4.6 million); and the 1231/1242 structure replacement project in Massachusetts ($8 million).

— Michael Kuser