Reduced uplift, plunging energy prices and shrinking net revenues punctuated a competitive first quarter in PJM’s energy market, the Independent Market Monitor said Thursday.
Load-weighted, average real-time LMPs declined 39% over the first three months of 2019, averaging $30.16/MWh. The Monitor’s analysis concludes that lower fuel costs explained 40% of the $19.29/MWh drop, while attributing the rest to decreased load, adjusted dispatch and smaller markups. Units operating near short-run marginal cost set the price in most instances, the Monitor said.
Both energy uplift charges and congestion costs tanked by more than 75%, while net revenues for all new units declined by double digits, including 65% for combustion turbine, 42% for combined cycle, 85% for coal plants, 37% for nuclear and 93% for diesel. Renewables likewise saw declines of 40% in onshore wind, 36% in offshore wind and 22% for solar. The Monitor said net revenue represents a “key” measure of market performance and investor incentive to support more generation.
“Energy net revenues are significantly affected by energy prices and fuel prices,” the Monitor said. “Energy prices were lower in the first three months of 2019 than in the first three months of 2018 as a result of lower gas prices in the east. Coal prices were slightly higher.”
Map of net real-time generation by zone: January through March 2019 | Monitoring Analytics
The analysis determined local market structure was not competitive, however, because of “highly concentrated ownership of supply” that led to a failure of the three-pivotal-supplier test.
The Monitor recommended PJM include end-of-life projects in the FERC Order 1000 competitive process in order to boost market performance. He also encouraged PJM to reject temporary commitment exceptions for generators based on unenforced pipeline tariff terms that include “inferior transportation service procured by the generator.”
“The MMU observed instances when generators submit temporary parameter exceptions based on claimed pipeline constraints even though these constraints are based on the nature of the transportation service that the generator procured from the pipeline,” the Monitor wrote. “In some instances, generators requested temporary exceptions based on ratable take requirements stated in pipeline tariffs, even though the requirement is not enforced by the pipelines on a routine basis. If a unit were to be dispatched uneconomically using the inflexible parameters, the unit would receive make-whole payments based on these temporary exceptions.”
ALBANY, N.Y. — The U.S. is moving toward a low-carbon economy, and it can also achieve significant carbon reductions at an acceptable cost while the power industry addresses day-to-day reliability issues.
So said most economists, consultants and environmental advocates Wednesday sitting on a panel to discuss New York’s “Green New Deal” and decarbonization of the electric sector at the 33rd annual Spring Conference of the Independent Power Producers of New York (IPPNY).
New York’s Green New Deal refers to Gov. Andrew Cuomo’s January proposal to require that the state’s electricity generation be 100% carbon-free by 2040, and to increase the state’s Clean Energy Standard mandate from 50% to 70% by 2030. (See New York Boosts Zero-carbon, Renewable Goals.)
“We can make a difference; we can get to 100% carbon neutral New York by 2040. It’s necessary, it’s inevitable and it’s urgent,” said Lisa Dix, senior New York campaign manager for the Sierra Club.
Dix said the state is down to 1 million MWh of power produced by coal annually (from about 20 million MWh 10 years ago) and noted new CO2 emission regulations — announced the following day by Cuomo — that will phase out coal generation by next year.
“We have the bones and structure of a New York transition policy. That is a glide path for communities and workers in transition away from coal,” Dix said.
Natural gas is also in decline, she said, citing Sierra Club tracking of proposed new natural gas-fired plants since 2017.
“There are so far since that time three gas plants — new gas plants, combined cycle plants — that have been terminated,” Dix said, saying there’s approximately 1.8 GW in planning.
She noted “huge opposition here in New York” to new gas infrastructure and called for phasing out existing gas-fired power plants. It’s “not like we’re going to phase out gas tomorrow, for I think the coal story tells a similar situation in which we need to think about how to phase gas out between now and 2030.”
Arne Olson, senior partner with consultancy Energy+Environmental Economics (E3), said “the day-to-day, hour-to-hour and minute-to-minute reliability issues can be addressed with the help of making renewables dispatchable and adding technologies like energy storage. We don’t think that will be a barrier to achieving deep penetration of variable renewable energy resources.”
Olson said that rather than the slogan “it takes a village,” a more suitable phrase describing the value of flexible dispatch is “it takes a portfolio.”
Some form of firm capacity will be needed to ensure reliable electric service on a year-round basis, Olson said, but achieving that last 10% of carbon reduction is tough: “You really have to be careful what that cost curve looks like.”
Olson said another E3 study showed that an 80% reduction of carbon emissions from 1990 levels was achievable in the Pacific Northwest at an incremental annual cost of $1 billion per year by 2050, translating into about a 6% increase in average electricity rates across the region.
“To me this is an acceptable increase in electric rates to achieve the goal of reducing carbon emissions and helping us solve this global problem,” Olson said.
Chuck DeVore, vice president of national initiatives at the conservative Texas Public Policy Foundation, said that opinion polls show people are concerned about climate change, “but when you start assigning a cost to it that they’re willing to pay, the concern very rapidly evaporates.”
“Policies that end up destroying the value of existing capital are going to be very counterproductive in the long run and will be politically unsustainable,” DeVore said.
Howard Fromer, director of market policy for PSEG Power New York and a former IPPNY chairman, asked the panel to opine on NYISO’s effort to price the social cost of carbon into electricity prices.
“There are myriad practical difficulties in implementing a carbon price in a sub-geography, in a single state that operates in a larger national economy and in a larger global economy, within a single electrical system that operates with the context of a multistate interconnection,” Olson said.
DeVore said the social cost of carbon was a “malleable number,” and that U.N. studies suggest that gasoline would have to be priced at about $50/gallon in a decade to prevent another 1.5-degree Celsius rise in global temperature by 2100.
Fromer said that after two years of New York working on carbon pricing, “I think we’ve solved the leakage issue in terms of not allowing external resources to capture the benefit of coming to New York with less expensive, but higher-emitting resources.”
“I’m kind of shocked to hear you say you believe you’ve solved the leakage problem when the U.S. Census Bureau says New York has been losing a net of tens of thousands of people every year, with Texas being one of the states they’re moving to,” DeVore said.
“When you look at Gov. Cuomo himself talking about a $2.3 billion deficit as the result of high-end wage earners leaving the state for greener pastures, you can’t keep doing that and hold on to your share of the GDP of the U.S.,” Devore said.
New York has the highest electric rates in the continental U.S. outside of California and New England, Devore said, and is now ranked fourth behind Florida in terms of population — and will likely be losing members of Congress in the upcoming census in 2020.
ALBANY, N.Y. — With Democrats now in control of both chambers of the state legislature, New York power producers might reasonably expect faster legislative support for Gov. Andrew Cuomo’s goals of 70% renewable energy by 2030 and a carbon-neutral grid by 2040.
But uncertainty still looms around those efforts, according to John Reese, senior vice president of Eastern Generation and chairman of the Independent Power Producers of New York (IPPNY).
“With all the changes going on, it’s hard to assess whether we’re going down the right path or a blind alley,” Reese said Wednesday at IPPNY’s 33rd annual Spring Conference.
A New York City resident, Reese cited a recent move by the mayor and City Council to improve energy efficiency in buildings and to revive the Champlain Hudson Power Express project to bring 1,000 MW of Canadian hydropower to Manhattan.
“IPPNY has been a long opponent to that project, particularly when it comes to the issue of carbon,” Reese said. “If you’re moving existing resources from one place to another, you’re not saving any carbon; you’re playing a shell game. … Certainly the preference would be to have new New York resources that contribute to the tax base, that contribute to jobs.”
The Climate Mobilization Act passed by the City Council on April 18 includes a definition of renewable energy credits that conflicts with the state’s Clean Energy Standard regarding the role of hydroelectric resources, said State Sen. Kevin Parker (D), chair of the Energy and Telecommunications Committee.
“The city’s language would allow certain large-scale hydro resources, which currently are not eligible [for RECs] under CES due to their evolving empowerments, that are not sources of methane emissions, to be eligible for the city’s program, hence the conflict,” Parker said.
“The conflicting RECs mean that the city’s end consumers and taxpayers would need to pay twice, once for the city’s REC and then again for the state’s REC [for other resources], and that Con Ed would be required to buy under the CES … which would require extra payment for Con Ed to secure eligible RECs,” Parker said.
The city’s program to import non-CES-eligible Canadian hydro also sends a negative signal to renewable energy investment in the state, especially for offshore wind, he said.
State Assemblymember Michael Cusick (D), chair of the Energy Committee, said he and Parker co-sponsored legislation that would require a feasibility study on achieving the state’s clean energy goals, “to support the incredible growth in offshore wind, energy storage and other resources.”
“The bill passed out of our committee, and I’ve spoken with people on getting that language in whatever package we have at the end of the session,” Cusick said, adding that he would also be pushing legislation on grid security, particularly cybersecurity.
IPPNY CEO Gavin Donohue thanked both lawmakers for “leading the charge” in dealing with the New York Power Authority in the competitive marketplace and legislating public procurement procedures through “a combination of practicality and reasonableness.”
NYISO Interim CEO Robert Fernandez touched on the same subject when he said, “The focus today is on buyer-side mitigation.
“At the beginning [of NYISO markets 20 years ago], many people were concerned about suppliers setting artificially high energy prices and improper wealth transfers,” Fernandez said. “Instead, today we grapple with uneconomic entry, subsidies and price suppression in the capacity market.
“We have mandatory buyer-side mitigation rules, we apply them, and it’s the economics of a particular project that will determine whether that will be subject to an offer floor or not,” he said. “That’s all that’s going to determine that. There are no outside influences telling us how to move the meter on buyer-side mitigation testing.”
Fernandez also referred to NYISO’s work on pricing carbon into its wholesale energy markets, which has relied heavily on assistance from consulting firm Analysis Group.
Dale Bryk, the governor’s deputy secretary for energy and environment, highlighted energy efficiency as a “huge economic engine” employing thousands of electricians and contractors throughout the state.
Cuomo in January proposed increasing the state’s renewable portfolio standard from 50% to 70% by 2030, nearly quadrupling its offshore wind energy goal to 9 GW by 2035, doubling distributed solar generation to 6 GW by 2025 and deploying 3 GW of energy storage by 2030. (See New York Boosts Zero-carbon, Renewable Goals.)
Bryk dismissed the idea of the state using carbon offsets as an alternative to reducing pollution as “some kind of get-out-of-jail free card.”
“If you look at the experience in New York with Regional Greenhouse Gas Initiative offsets or components, they were never used,” Bryk said. “The way the program was designed, that really never made sense.
“If we’re talking about decarbonizing every sector, there really isn’t any place to get offsets, so the framing is different, but the concept of carbon neutrality and that flexibility is absolutely critical,” he said. “It’s not always linear, it’s not always numeric … we’re all-in for performance metrics, but we want to develop them in a professional way.”
Mark Younger of Hudson Energy Economics said Bryk had neglected to address carbon pricing. “I don’t see how you can do an efficient change without internalizing the externalities … which all the literature shows lets you put the solar resources in an area where they knock out carbon rather than just happen to get subsidies from the state. So how do you do this without putting a price [on carbon], not just in the electric sector, but in all the sectors?”
“We have carbon pricing with RGGI, but I think of it as a cap on pollution that’s going down over time,” Bryk replied. “You sell pollution permits, that’s your price. The driver is the cap. We want people to have a price signal and see the long-term price signal and declining cap. What I care about is pollution going down … so you don’t only have a price, you don’t lead with price. We want to have both the price signal, the cap, and energy efficiency policies, because it’s not all about price.”
Jacob Worenklein, chairman of Ravenswood Power Holdings, which owns the largest power plant in New York City, said the great challenge is technology, “because we can in fact reduce carbon to zero right now, but nobody would do so … because the cost would be so huge.”
“When will we get the technology and when can we expect to begin to test technology that will enable us to do exactly what we’re talking about, say, by the 2035 or so time frame?” he asked.
Bryk likened the idea of encouraging new technologies to that of being “proactive with” workforce development — “and not just assume that that’s going to happen because the investment is there.”
“Just because you have policies … even with the price signal, that doesn’t bring you all of the technological innovation that we may need,” Bryk said. “What can the state be doing to help drive that R&D work and the commercialization demo projects?”
Exelon on Wednesday announced it will permanently shut down the nearly 45-year-old Three Mile Island nuclear plant in Londonderry Township, Pa., by Sept. 30.
The company is making good on its May 2017 promise to close the plant absent the Pennsylvania General Assembly providing it subsidies before June 1 of this year, the deadline for purchasing its fuel. Each house of the legislature has been considering its own bill supporting nuclear generation, but the Senate has adjourned until June 3, and the House of Representatives will only meet three more times before the end of the month.
Exelon’s Three Mile Island
“Although we see strong support in Harrisburg and throughout Pennsylvania to reduce carbon emissions and maintain the environmental and economic benefits provided by nuclear energy, we don’t see a path forward for policy changes before the June 1 fuel purchasing deadline for TMI,” Kathleen Barron, Exelon senior vice president, government and regulatory affairs and public policy, said in a statement.
“While TMI will close in September as planned, the state has eight other zero-carbon nuclear units that provide around-the-clock clean energy, avoiding millions of tons of carbon emissions every year. We will continue to work with the legislature and all stakeholders to enact policies that will secure a clean energy future for all Pennsylvanians,” she said.
But at least one state legislator earlier this week predicted the plant would close regardless of what the General Assembly did. (See Pa. Lawmaker Contends TMI Rescue Unlikely.) The bills being considered would create a third tier in the state’s Alternative Energy Portfolio Standard program, from which suppliers must buy an additional 50% of their power by 2021.
“Today is a difficult day for our employees, who were hopeful that state policymakers would support valuing carbon-free nuclear energy the same way they value other forms of clean energy in time to save TMI from a premature closure,” said Bryan Hanson, Exelon senior vice president and chief nuclear officer. “I want to thank the hundreds of men and women who will continue to safely operate TMI through September.”
Nuclear Energy Institute CEO Maria Korsnick blamed the plant’s closure on “a flawed and distorted energy market that fails to value the attributes of nuclear power.”
“The shutdown will lead to the loss of hundreds of Pennsylvania jobs, more than $1 million in taxes annually to the community and more than 7 million MWh of carbon-free energy,” she said. “It’s in our nation’s best interest for lawmakers both in state capitals and Washington to push for market solutions and polices that value all clean energy sources, or face the economic and environmental consequences for generations to come.”
Three Mile Island is home to two reactors. Exelon has owned Unit 1 since 2000, when the company formed through the merger of Unicom and PECO Energy, the latter of which owned a 50% stake in the unit. The company purchased the other half in 2003 and began operating the plant directly in 2009. The same year, the unit was granted a license extension by the Nuclear Regulatory Commission to April 19, 2034.
Unit 1 was shut down for six years after the partial meltdown of Unit 2 in 1979, the worst commercial nuclear power plant accident in U.S. history. In 1985, over fierce opposition from nearby residents and anti-nuclear activists, NRC voted 4-1 to restart operations.
Exelon plans to begin transitioning staff within six months of the plant’s shutdown, winding down in three phases to 50 full-time employees by 2022. The company will begin to dismantle the plant in 2074.
CenterPoint Energy on Thursday reported that mild weather that reduced customers’ power usage drove first-quarter earnings down to $140 million ($0.28/share), from $165 million ($0.38/share) a year ago.
When adjusted for one-time gains and costs, the Houston-based company’s earnings came in at 46 cents/share, falling 4 cents short of Zacks Investment Research’s consensus.
CEO Scott Prochaska | CenterPoint Energy
Still, CEO Scott Prochaska said he was pleased with the results.
“While weather-related impacts affected first-quarter earnings, we remain confident in our anticipated 2019 full-year performance. Our utilities continue to benefit from strong customer growth and recovery mechanisms allowing for timely recovery of capital invested on behalf of our customers,” he said.
CenterPoint’s earnings excluded costs and other impacts of its $6 billion acquisition of Vectren. The Indiana utility, the acquisition of which was completed Feb. 1, reported a one-month operating loss of $9 million, which included $20 million in merger-related expenses.
The Indiana Utility Regulatory Commission recently recommended CenterPoint consider smaller-scale options instead of a proposed 700- to 850-MW combined cycle natural gas turbine, company officials said.
“The commission wants to see investment made in ways other than a bet on a single large plant,” Prochaska told investment analysts during a call Thursday.
CenterPoint’s share price closed Thursday at $29.25, down almost 4% from the previous close.
CenterPoint Energy’s service territory | CenterPoint Energy
SPP and MISO stakeholders are reviewing an initial draft of the RTOs’ 2019 Coordinated System Plan (CSP), which will jointly evaluate identified seams issues and determine the need for any interregional transmission projects.
CSP process | SPP
SPP staff intend to “leverage” coordinated transmission needs identified in the RTOs’ transmission planning processes to study whether it makes the most financial sense to develop interregional projects that efficiently address seams needs. The RTOs’ have ditched the joint planning model previously used in the first two CSPs, neither of which resulted in an interregional project. (See MISO, SPP Seek Coordinated Plan in 2019.)
Interregional Coordinator Adam Bell told the Seams Steering Committee on Wednesday that the RTOs’ staff will incorporate the feedback into a final scope document, which will be distributed to the Interregional Planning Stakeholder Advisory Committee.
The RTOs’ staff have committed to completing the study by Dec. 31.
MISO’s M2M Tab with SPP Reaches $60M
SPP earned another $2.3 million in market-to-market (M2M) payments from MISO in March, pushing the latter’s deficit to $60.8 million, staff told the committee.
M2M history summary through March 2019 | SPP
It was the 24th month in the last 30 in which M2M distributions have flowed in SPP’s direction. The RTOs began the M2M process in March 2015.
Permanent flowgates along the RTOs’ seam were binding for 141 hours and temporary flowgates were binding for 552 hours, resulting in $958,000 and $1.3 million in payments, respectively.
PG&E Corp. came under criticism this week from a federal judge, who ordered its new CEO and board members to view the scene of the devastating Camp Fire.
Lawyers representing victims of that disaster and others urged a bankruptcy judge Wednesday to order the utility to turn over internal records related to wildfire liability.
And PG&E said May 2 it was being investigated by the Securities and Exchange Commission for its accounting of wildfire losses.
In short, it was another bad week for beleaguered PG&E and its utility subsidiary, Pacific Gas and Electric, which are undergoing Chapter 11 bankruptcy reorganization after devastating wildfires in the past two years. (See Calif. Must Limit Fire Liability, Governor Says.)
PG&E remains on probation for crimes associated with the San Bruno gas line explosion in 2010, which killed eight residents of a suburban San Francisco neighborhood.
In that case, U.S. District Court Judge William Alsup on Tuesday ordered PG&E’s board members to visit Paradise, Calif., where the Camp Fire killed at least 85 people and leveled most of the town of 27,000 residents in the Sierra Nevada foothills. Alsup said he wanted PG&E leaders to see the wreckage of the deadliest fire in state history.
In the bankruptcy case, lawyers for PG&E and those representing thousands of fire victims faced off for two hours Wednesday before U.S. Bankruptcy Judge Dennis Montali in San Francisco.
Attorneys for the creditor committee of tort claimants said they wanted information, which the utility refused to turn over, about the role of the utility and its contractors in starting the Camp Fire and the estimated cost, including any potential government fines that PG&E might have to pay.
The California Public Utilities Commissioned fined PG&E a record $1.6 billion after the San Bruno gas explosion, and plaintiffs’ lawyers said a similar fine could be imposed for the Camp Fire.
State fire officials haven’t concluded their investigation yet, but PG&E has said its equipment likely started the fire, which began beneath the 100-year-old Caribou-Palermo transmission line in rural Butte County on Nov. 8, 2018 — six months before Wednesday’s hearing.
Sounding exasperated, Montali told the lawyers to try to settle the dispute among themselves.
The judge is scheduled to rule soon on a petition by PG&E to enjoin FERC from interfering in the bankruptcy case. The commission recently reaffirmed its own ruling that it shares jurisdiction with the court over PG&E’s wholesale power purchase agreements. (See FERC Denies PG&E Rehearing Over Contracts Dispute.)
PG&E has indicated it may try to rescind or renegotiate hundreds of PPAs worth billions of dollars with generators of renewable energy, and it wants Montali to have sole authority over the contracts.
CAMBRIDGE, Md. — As PJM considers how to best manage future carbon policies, energy industry experts say the unique challenges the RTO faces can be mitigated with strong coordination between policymakers, stakeholders and grid staff.
“You’re not the only ones looking at this,” Dirk Forrister, CEO of the International Emissions Trading Association, said during the General Session of PJM’s Annual Meeting, at the Hyatt Regency Chesapeake Bay Golf Resort, Spa & Marina, on Wednesday. “It is material, and it seems to be an issue, in terms of public sentiment, that’s coming up more and more.”
Forrister, who once served as chairman of the White House Climate Change Task Force under President Bill Clinton, said the U.S. remains an “outlier” internationally as other countries embrace carbon pricing, with varied levels of success.
“Come on in, the water’s fine,” he said. “To get to the levels of climate protection that governments want, it implies a level of reduction that we haven’t seen before.”
PJM isn’t the first RTO to tackle carbon pricing, but its challenge of balancing the markets between participating and nonparticipating states proves unique compared with NYISO and CAISO.
In New York, NYISO is close to voting on a set of rules to price carbon that would include border charges for imported power and credits for exported power — just one way PJM could handle flows among its 13 states and D.C. (See More Details Divulged on NYISO Carbon Pricing Study.)
In CAISO, where power also flows to and from regions without carbon-reduction goals, operators prioritize curbing emissions over importing energy from the cheapest resources. It’s a focus that Ben Grumbles, Maryland’s secretary of the environment, encourages PJM to take as it examines how pricing could work across the grid.
“A carbon-constrained energy sector is absolutely the future,” he said. “Never lose sight of the fact that the goal should be to reduce emissions.”
Maryland and Delaware both participate in the Regional Greenhouse Gas Initiative, a coalition of Northeast and Mid-Atlantic states committed to capping carbon emissions from the power sector. Emissions have been cut in half since 2014, and more than $3 billion have been reinvested into cleaner energy and ratepayer reductions, Grumbles said.
“In RGGI, the key is to have the environment secretary for the governor and the energy regulators together so we can we find common ground,” he said. “It takes time.” He also emphasized the importance of preserving state sovereignty and protecting consumers from “windfall profits.”
Anthony Giacomoni, senior market strategist for PJM, said an ongoing internal study is quantifying the market impacts of a systemwide carbon price, versus a regional or sub-regional system.
“We want to enable state policies while preserving economic and competitive dispatch,” he said, noting that minimizing “carbon leakage” remains a top priority. “High prices will have very high leakage and, as a result, prevent states from reaching carbon-reduction goals.”
Staff are also considering one-way and two-way border adjustments as other tactics to minimize the impact on nonparticipating states and maintain a level playing field for dispatching generation. While not an “exhaustive” study of all the ways PJM could accommodate carbon pricing, Giacomoni said the RTO hopes it will better inform policymakers and stakeholders of the market impacts.
He said staff will provide an update on study results at the May 15 Market Implementation Committee meeting, with a plan to release the full analysis later this summer.
ERCOT said Wednesday that its final resourceadequacy assessment for this summer indicates “a potential need” to enter energy emergency alert (EEA) status in order to maintain system reliability.
The Texas grid operator is forecasting a peak demand of 74.9 GW, 1.4 GW higher than the all-time record of 73.5 GW set last July. ERCOT will meet that demand with 78.9 GW of available capacity, a slight increase from its spring assessment of resource adequacy.
South Texas transmission lines | CPS Energy
The good news: ERCOT’s planning reserve margin for the summer has increased to 8.6% from an historic low of 7.4%. The grid operator’s target reserve planning margin is 13.75%.
“At this reserve margin level, it’s more likely we’ll have to use additional resources available under emergency operations procedures on several occasions this summer,” ERCOT’s Dan Woodfin, senior director of system operations, said during a media call Wednesday.
“We’re confident we’ll be able to maintain the reliability of the system as a whole. That’s our job,” Woodfin said in response to persistent questions about the possibility of blackouts this summer.
“It’s probably one of the lowest planning reserve margins on record — based on all the data we’ve seen historically — going into a summer peaking area,” John Moura, NERC director of reliability assessment, told the electric reliability organization’s Member Representatives Committee in St. Louis on Wednesday. “So [there are] certainly some challenges, but I believe the operators have the right tools in order to keep the system stable and operating the system reliably.”
Woodfin and ERCOT Manager of Resource Adequacy Pete Warnken said the grid operator has a number of tools at its disposal should operating reserves drop to 2.3 GW and force an EEA 1 declaration — the lowest emergency rating. At that point, ERCOT can take emergency imports from SPP over DC ties, use emergency response service and institute load-reduction measures, among other options.
“We have the tools and procedures in place,” Warnken assured his audience.
The ERCOT reserve margin for the summer months (June-September) was raised thanks to the return of a 365-MW NRG gas-fired unit, 111 MW of upgrades to 12 generating units and an increase in the amount of DC tie imports. (See NRG to Bring Back Gas Plant for Summer 2019) The grid operator’s Board of Directors in April approved a change to import forecasts, basing them on the amount of power that could be brought in during emergency conditions and not historical forecasts.
The fall assessment forecasts a peak demand of just over 61 GW, with more than 84 GW of capacity available.
The updated CDR includes an additional 733 MW of installed wind and solar capacity. It also includes 517 MW of battery storage as being newly eligible for inclusion.
The updated CDR forecasts above-normal growth in demand of 2.5 to 3% through 2022. Oil and gas development in West Texas and new industrial facilities on the Texas Gulf Coast account for much of that growth, ERCOT said.
The grid operator expects the reserve margin to reach 15.2% in 2021, when almost 6 GW of planned resources in the interconnection queue, primarily wind and solar projects, become eligible for the CDR. It projects the reserve margin will dip back below 8% in 2024, when peak demand is expected to exceed more than 84 GW.
Rich Heidorn Jr. contributed to this story from St. Louis.
CAMBRIDGE, Md. — PJM stakeholders gathered for a special Members Committee meeting on Tuesday at the Hyatt Regency Chesapeake Bay Golf, Resort & Marina as part of the RTO’s Annual Meeting.
After a “challenging” and “humbling” 2018, PJM CEO Andy Ott said the RTO will better lead stakeholders in 2019 as it works to adapt the grid to emerging state policies and renewable technology.
“It’s not enough anymore to just have reliability at the least cost and have open, competitive markets,” he said during his keynote address Tuesday. “We need to listen to that as an entity. But it’s not just PJM alone. It’s all of us. We’re all in it together.”
While he admitted the ongoing fallout from the GreenHat Energy default looms large, Ott said PJM is working hard to implement staffing and procedural changes that were recommended as part of an independent probe into the situation. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)
He also said PJM will keep an “open mind” as it works to incorporate energy storage and possible carbon pricing into its markets in the coming years and requested clear direction from stakeholders and federal regulators on those issues.
Nothing ‘Magical’ About RPM
Stu Bresler, PJM’s senior vice president of markets and operations, said stakeholders might want to reconsider what market mechanism best accommodates growing generation subsidies as states continue enacting policies to reduce carbon emissions.
“Markets have worked, but we recognize there’s nothing magical about the Reliability Pricing Model,” he said. “It’s one option as far as resource adequacy is concerned. At some point, maybe we ought to talk about whether there are other alternatives we should look at that could better incorporate the policy goals out there that aren’t necessarily RPM as we know it today.”
The comments came during PJM’s “Year in Review Panel,” in which leaders from each department discussed the challenges and successes experienced throughout 2018.
“Well, there’s no shortage of challenges,” said Joe Bowring, PJM’s Independent Market Monitor, citing continued regulatory uncertainty that is beginning to affect investments in the grid. “The challenges are simple to say, very difficult to do. How do we maintain competitive markets?”
But it wasn’t all doom and gloom from the Monitor, who also praised the implementation of hourly offers and five-minute settlements for setting better price signals, especially with gas-fired generation.
Steve Herling, PJM vice president of planning, noted that increasing stakeholder transparency remains a top priority for staff. “It’s critical that stakeholders understand the assumptions, the analyses and the decision-making process,” he said. “We’ve done a lot over the past couple of years to enhance transparency, but we understand there is a lot more that needs to be done.”
Likewise, PJM’s Vice President of Operations Mike Bryson said that addressing fuel security issues should continue to be top-of-mind for stakeholders. “Each year we get surprised by a different aspect of the evolving fuel mix,” he said.
FTR Forfeiture Calculation Change Endorsed
Members endorsed calculation changes for financial transmission rights forfeiture to be incorporated in the Operating Agreement.
PJM and the Monitor agreed the current forfeiture rules should be adjusted because they do not distinguish between on- and off-peak FTRs. (See “First Read on Change to FTR Forfeiture Calculation,” PJM MICBriefs: March 6, 2019.)
FTR forfeitures are intended to discourage traders from cross-market manipulation. Holders subject to forfeiture are credited for the hourly cost of the FTR. Under current rules, a $1,500 off-peak FTR for June 2018 would be credited an hourly cost of $2.08, equivalent to $1,500 divided by 720 hours (30 days x 24 hours). Under the endorsed change, the FTR cost would be divided by only 384 off-peak hours, increasing the credit to $3.91.
Incumbent Board Members Re-elected
Three incumbent members of the Board of Managers won re-election bids: Terry Blackwell, O.H. Dean Oskvig and Mark Takahashi will each serve another three-year term.
