VALLEY FORGE, Pa. — PJM will move forward with its August capacity auction under current market rules, unless FERC says otherwise, CEO Andy Ott told stakeholders Wednesday.
Ott said the PJM Board of Managers settled on that course after determining the RTO’s minimum offer price rule (MOPR) — rejected last year by FERC — impacts only a small number of resources, meaning an updated commission ruling on the matter wouldn’t change prices too much within the current environment.
“We think this is the best approach,” he told the Market Implementation Committee on Wednesday. “There is no way to get absolute certainty. This was not an easy decision.”
PJM filed a request with FERC later that day seeking validation that the commission would not force the RTO to rerun the 2022/23 Base Residual Auction under new rules in the future — an outcome that stakeholders want to avoid at all costs.
“We’re trying our best to provide a path forward that provides as much clarity as we can,” Ott said.
The decision comes three weeks after PJM staff presented the Markets and Reliability Committee with four options for the August BRA, including: doing nothing and running the auction under current rules; filing a delay waiver; filing a request to confirm existing rules for the interim; or proposing an interim rate. (See PJM Mulls Options for August Capacity Auction.) Each option came with considerable drawbacks, PJM’s Stu Bresler said at the time.
PJM delayed the BRA once already after a June 2018 FERC ruling determined its MOPR was unjust and unreasonable because it didn’t address price suppression arising from state subsidies for renewable and nuclear power. The RTO proposed a new rate in October and had hoped for a ruling from the commission by March 15 to no avail.
Ott said Wednesday many stakeholders expressed support for moving ahead as planned. The Electric Power Supply Association said in a press release that the RTO made the right choice and will boost much-needed investor confidence. The group also called on FERC to protect the capacity market from the distortions of nuclear subsidies and those who benefit from them.
“EPSA opposes delaying the 2019 auction to 2020,” the group wrote. “This is merely an attempt by some to buy time to continue seeking costly subsidies. Such out-of-market payments erode PJM’s markets at the expense of consumers and competition.”
Jason Barker of Exelon called the chosen path “short-sighted.” Exelon joined a coalition of utility companies in a letter to the board requesting a delay until April 2020, citing seven outstanding FERC dockets. Consumer advocacy groups from six states likewise sent their own letter pushing for a delay. (See Stakeholders Tell PJM Board to Delay Capacity Auction.)
“We think the path that PJM is taking will make FERC address the underlying subject of MOPR, which they’ve been reluctant to do so far,” he said. “Why is the balance of interest better served by this path than just the delay?”
PJM spokesman Jeff Shields said the RTO remains obligated to run the BRA and, given the uncertainty, staff decided it was best to move forward under existing rules.
“Certainty is needed and we simply don’t know when FERC is going to act,” Shields said. “We don’t even know whether FERC will respond to this request for clarification or would have responded to an additional request for delay.”
A federal judge asked lawyers Wednesday to find common ground in a case that has pitted Pacific Gas and Electric against FERC in a conflict over billions of dollars in power purchase agreements that the bankrupt utility has said it might try to modify or cancel during its Chapter 11 reorganization.
Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco, asked the attorneys to take two weeks to determine if they can “unring the bell” that was rung when FERC declared in January that it shared jurisdiction with the court in deciding the fate of the wholesale power contracts.
Theodore Tsekerides | Weil, Gotshal & Manges
PG&E’s lawyer, Theodore Tsekerides, told the judge he thought a compromise was unlikely. The New York-based litigator, of Weil, Gotshal & Manges, argued strenuously for Montali to impose a permanent injunction against FERC that would prevent it from interfering in the bankruptcy case. He said the bankruptcy code governed the matter, not the Federal Power Act, as FERC contended.
Attorneys for FERC and the wind and solar generators under contract with PG&E argued against an injunction but said a compromise might be possible. FERC’s attorney said he would need to ask for the commission’s approval.
Montali suggested to the attorneys that FERC might somehow soften or change the language in its Jan. 25 order to remove the apparent conflict between the court’s authority and the commission’s jurisdiction.
“Have we got a deal here?” Montali asked the lawyers half-jokingly at one point in the two-and-a-half-hour proceeding. They said they didn’t but were willing to work on it.
The case began in January, when NextEra Energy and Exelon, two companies that have PPAs with PG&E, asked for FERC’s help in anticipation of PG&E trying to reject the agreements in bankruptcy.
PG&E’s efforts to obtain an injuction against FERC center on its renewable power purchase agreements.
PG&E then moved for an injunction blocking FERC from meddling in its bankruptcy, which was brought about by the utility’s potential liability for billions of dollars in wildfire damages. (See Bankruptcy Only ‘Viable’ Option for PG&E, Lawyer says.)
To comply with the state’s renewable power requirements, the utility entered into contracts that were far pricier than they would be today, when wind and solar are among the lowest-priced electricity sources. The utility said it has 387 PPAs with 350 companies worth about $42 billion. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
The PG&E v. FERC matter, known in court as the adversary proceeding, is distinct from, but closely linked to, PG&E’s bankruptcy case. Over FERC’s objections, a U.S. district court judge ruled last month that the adversary proceeding should remain in Montali’s court for the sake of judicial efficiency. (See Judge Sides with PG&E over FERC in PPA Dispute.)
Judge Dennis Montali | Commercial Law League of America
Montali wrote to the judge in that case, saying the “plain language” of Section 365 of the bankruptcy code could answer “the question of whether FERC can decree that [the code section] must be construed to permit FERC to second-guess the bankruptcy court and impose its own decision on that court.”
Montali has not said if he intends to enjoin FERC or dismiss PG&E’s request for an injunction. However, he repeated his view Wednesday that it would be best to issue a permanent injunction, rather than a preliminary one, if he chooses that route.
A preliminary injunction would require a trial to determine if a permanent injunction is warranted and would consume time and energy when there may be no facts in dispute, Montali said. Issuing a permanent injunction would allow FERC to quickly appeal the matter to the higher court, he said.
CARMEL, Ind. — MISO will kick off discussions on distributed energy resources policy after it this month completes a third round of stakeholder workshops on integrating DER into its system, the RTO said this week.
Over the next decade, MISO expects to confront increased volumes of DERs that will “likely challenge utility staff and processes” with possible two-way flows of electricity on the distribution system.
Those challenges were the topic of an April 9-10 workshop that nearly concludes a series of educational sessions hosted by the MISO and the Organization of MISO States.
The events are a precursor to MISO bringing discussion of DER market rules into its stakeholder process as RTO leaders prepare for a possible MISO Contemplates DER Effect, Possible Rules.) MISO will host identical sessions April 17-18 in Little Rock, Ark., and April 24-25 in Eagan, Minn.
MISO staff said they would use input from the final workshops to set policy-level discussions with stakeholders on DER integration.
MISO DER project manager Kristin Swenson said once the workshops are complete, MISO may assemble stakeholders for periodic “debriefs” on what aspects of DER integration MISO might address first.
Swenson also said the RTO is trying to forge deeper connections with distribution utilities after it encountered difficulties assembling a large group of distribution operators for the early April event.
“MISO does not have deep connection with the distribution operators in our footprint. Our main connections are with our transmission operators,” Swenson said, adding MISO might consider holding more local meetings “to move the conversation to them.” She also asked stakeholders in the room for suggestions on how best to involve distribution operators in the DER conversation.
Breakout Session
Attendees broke into groups to consider several DER integration questions with the caveats that representatives from the same companies not sit together and that state regulators not share tables with representatives from the utilities they oversee. Participants observed Chatham House Rules, not attributing discussion points to specific individuals or companies. The idea, MISO representatives said, was to encourage free conversation.
MISO asked the roughly 50 attendees to discuss modeling behind-the-meter generation and how to best approach DER deployment in load forecasting and long-term DER planning assumptions. It also asked distribution operators how they approach generation interconnection on the distribution level and the funding of distribution upgrades, as well as how they might manage reverse flow congestion, real power flow patterns and phase balancing issues.
The RTO also prompted distribution companies to consider how they might alter their under-frequency and under-voltage load shed schemes under circumstances in which the schemes could shed generation as well as load.
Workshop attendees said distribution utilities will need to create interconnection protocols and facilitate a three-way communication system among the DERs, themselves and the grid operator. Many MISO members predicted distribution utilities will become mini system operators themselves. Others said distribution utilities themselves will need better visibility into their own operations before they can hand off DER information to MISO. Some distribution representatives probed MISO on what level of detail it could handle in terms of DER data submissions.
Other participants said MISO should determine when utilities might come to rely on DERs, though some allowed that long-term DER load forecasting is a difficult process. Attendees said MISO must factor in economics, weather patterns and unusual weather and state policies when forecasting DERs for planning. Some added MISO should hire an in-house meteorologist to better predict when certain DERs will be in use.
If DERs are to become market resources in MISO, the resources should be prepared to supply the RTO with the same types of information required of traditional resources, many attendees agreed.
Break with Tradition?
MISO adviser Robert Merring said significant DER penetration could prompt MISO to expand reserve requirements. He also noted that essentially “uncontrolled generation” could further impact transmission constraints.
“Our traditional way of doing business — we plan for an annual peak and we’re good — may no longer work. Those load profiles are changing,” he told attendees.
With significant solar generation on the system, MISO could also experience “huge ramps at sunset,” Merring said. “They have one heck of a race at sunset to cover their ramping needs,” he said of CAISO.
Merring added MISO today has an “amazingly small” amount of regulating reserves, with the RTO handling virtually all load through its energy market.
Merring said while an abundance of low-cost gas has put a “squeeze” on coal profitability in the footprint, distribution-level generation could soon take its turn in driving down price.
“We’re not seeing a slow-down in distributed resources buildout. If that continues, we’re going to see continued revenue constraints on the traditional fleet,” he said.
Merring concluded with a point salient for most stakeholders: As an increasing volume of load is served by DER generation that bypasses the MISO wholesale market, the RTO’s remaining load could be forced to shoulder more of the cost burden for the system.
NEW YORK — With 30 MW installed, the U.S. has barely dipped its toes into offshore wind. Europe, which has been harvesting its ocean breezes since the 1990s, has 18 GW.
But based on the Scandinavian, German and British accents at the Grand Hyatt in New York this week, a lot of people in the European OSW industry believe the waters off New England and the Mid-Atlantic states are the next big thing.
More than 1,100 attendees crammed into the Hyatt’s ballroom next to Grand Central Station for the Business Network for Offshore Wind’s 2019 International Partnering Forum — double last year’s attendance, according to the group’s CEO Liz Burdock.
The excitement is largely based on pledges by New York and Maryland since January that have boosted the East Coast’s planned OSW pipeline to almost 18 GW from 10 GW in 2018.
“In our view, the Northeast U.S. is the most attractive opportunity for the expansion of offshore wind outside of Europe,” said Sunny Gupta, head of new market development for Danish-owned Ørsted U.S. Offshore Wind.
Gupta recalled that at his first meeting with the fledgling business network about eight years ago, no more than 40 or 50 people were in attendance. “Here we are today with IPF 2019 — four years straight sold out — in a big fancy hotel in midtown Manhattan,” he marveled. “Not many people get to say they helped create an industry, so this is indeed a very unique moment in all of our lives.”
“It feels good to say it’s no longer a question of when offshore wind will ever come to the U.S.,” agreed Gupta’s boss, Ørsted U.S. Offshore Wind CEO Thomas Brostrøm. “Because now it is here, and I think the question is more: How much potential do we actually see? How big can this industry become?”
Eric Thumma, director of policy and regulatory affairs for Avangrid Renewables said the IPF conference reminded him of his introduction to land-based wind power in Los Angeles in 2007. The U.S. has since grown from less than 17 GW to more than 96 GW of land-based wind, he noted. (See AWEA: Another Record-Breaking Year for Wind Industry.)
New York Gov. Andrew M. Cuomo jolted the market in January by proposing the state nearly quadruple its offshore wind energy goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)
Richard Kauffman, chair of the New York State Energy Research and Development Authority, said the response his agency received to its first, 800-MW solicitation for offshore wind is proof the industry is taking the U.S. market seriously. Four groups of companies entered 18 bids; NYSERDA is expected to announce the winners in about a month. (See Four Bidders Vie for NY Offshore Wind Project.)
“Offshore wind on the East Coast of the U.S. has gone from being a distant dream to a huge market opportunity,” Kauffman said.
New Jersey Gov. Phil Murphy said the Board of Public Utilities will announce the results of its 1,100-MW solicitation by the end of June.
“We have a lot of lost time to make up,” said Murphy, a Democrat who revived the state’s OSW plans after taking office in 2018. Murphy replaced Republican Gov. Chris Christie, who had not supported the initiative.
Murphy noted the state issued its OSW plan in 2010. “But for seven-and-a-half years that plan sat on a shelf collecting dust. That was just one of many oversights by the prior administration that stymied our progress as a state.”
Also adding to momentum was the Maryland legislature’s April 8 approval of a bill (SB 516) that boosted the state’s offshore wind target to 1,200 MW by 2030, up from 366 MW.
Burdock said the pressure is now on the industry to show it can execute the development plans on schedule. Some 1,800 MW is targeted to be built and operating by 2023.
“So, we are under [a] severely compressed timeframe,” she said. “That is one of the reasons why I stay awake at night. The one thing I worry about is supply chain capacity. Do we have enough businesses?”
Lessons from Europe
How much the U.S. could, or should, take from Europe’s experience was a recurring theme at the conference.
The U.S. Bureau of Ocean Energy Management (BOEM), which oversees OSW development in federal waters, met with counterparts from nine countries this week to share experiences and best practices. BOEM Acting Director Walter Cruickshank said it was the first of what will be an annual forum of global OSW regulators.
Gil Quiniones, CEO of the New York Power Authority, said the U.S. will be looking to the Europeans for guidance for the foreseeable future. While New York hopes to have 9 GW of OSW by 2035, Europe is expected to expand from its current 18 GW to 60 GW by 2027. “So, we are going to learn a lot from the Europeans as this journey happens,” he said.
“The U.S. can learn a lot from the U.K. experience in particular,” said Ørsted’s Gupta. “The U.K. was not the original wind market in Europe, but it quickly became the largest player, and governments made significant investments knowing that is what it would take to attract [a] supply chain. The result of that has been an achievement of significant local content [production] in the U.K. — not only for their own projects but now they’re exporting that technology to other European countries and indeed to emerging markets.”
Gupta said the takeaway is “Don’t do it small. And focus on what you’re good at.”
Still, he acknowledged some lessons won’t translate. “The U.S. is very different … [from] state and federal permitting to the way transmission works, the way the energy market works in general here, there’s only so much you can draw from the European experience.”
Sven Utermöhlen, a board member for E.ON Climate & Renewables GmbH, said there is no one model to follow. “I think you really have to cater it to the specific situation in terms of coastline, number of suitable connection points, number of windfarms and geographical situations.”
VALLEY FORGE, Pa. — PJM on Wednesday proposed an alternative stakeholder process to implement the market rule changes recommended in a special report on the RTO’s role in the GreenHat default.
Last month, three independent consultants completed a six-month probe into how a small trading shop amassed the largest portfolio of financial transmission rights in PJM history without the collateral to back it up, ultimately blaming naïve staff and underlying market flaws for the 890 million-MWh default that could cost members up to $430 million. (See Report: ‘Naïve’ PJM Underestimated GreenHatRisks and PJM: FERC Order Could Boost GreenHat Default by $300M.)
CEO Andy Ott told the Market Implementation Committee on Wednesday he will oversee organizational and procedural changes within PJM itself but will rely on stakeholders to guide the process for market rule changes.
“We are going to suggest a stakeholder process to you all,” he said. “We think the current process may not be the best approach. Let me be clear, it’s a suggestion.”
PJM’s suggestion is to create a Financial Risk Management Senior Task Force that will assemble beginning May 2 to begin the overhaul of credit and risk management requirements, market design, membership qualifications and processes and the stakeholder process itself.
PJM’s Dave Anders wants the Markets and Reliability Committee (MRC) to approve staff’s proposed charter for the task force at its April 25 meeting so an educational session can commence in May. Staff will present their own observations at a May 13 meeting and propose foundational questions for thoughtful discussion over the following two weeks. The task force will then create a work plan and develop packages that produce the report’s recommendations for the Board of Managers to consider at its Dec. 4 meeting.
“Our stakeholder process is a strong one, but it’s not always the most efficient,” Anders said. “We believe we need to adapt the process to provide more efficiency.”
ORDCs Shrink in Updated Energy Price Formation Simulation
A late-stage change to how PJM treats expected generation outages resulted in a smaller Operating Reserve Demand Curve (ORDC) in the RTO’s energy price formation simulation.
PJM’s Adam Keech said changing unit commitment based on real-time instead of day-ahead markets increased locational marginal prices, boosted energy revenues and cut uplift by more than 80% compared with the status quo.
“It’s not exactly what real-time is but it’s the closest we can get to what real-time would be,” he said. “We stayed toward real-time because we think that’s the best tool we have and gives us the best approximation we can get.”
Likewise, implementing a 30-minute reserve market and PJM’s proposed ORDC increased LMPs by an average of $0.46 MWh, assigned an additional 1,350 MWh of synchronized reserve and 3,337 MWh of secondary reserve and generated $550 million more in total energy and reserve market revenues, Keech said.
2018 Simulation Results | PJM
FTR Forfeiture Calculation Change Endorsed
Stakeholders endorsed calculation changes for financial transmission rights forfeitures on Wednesday.
Brian Chmielewski, manager of market simulation, said PJM and the Independent Market Monitor agreed the current forfeiture rules should be adjusted because they do not distinguish between on-peak and off-peak FTRs. (See “First Read on Change to FTR Forfeiture Calculation” in 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.
The proposal will now advance to a first read at the April 25 MRC. PJM hopes to implement the changes in the third quarter of 2019.
MIC Will Work IARR Funding Flaw
Chmielewksi told the MIC last month underfunding of interregional incremental auction revenue rights (IARRs) may occur because MISO’s process cannot guarantee future firm flow entitlements on upgrades consistent with PJM’s rules. (See “Incremental Auction Revenue Rights Funding” in PJM MIC Briefs: March 6, 2019.)
IARRs are granted to the customer only if the transmission improvement provides additional capacity that makes the request feasible. PJM guarantees that awarded IARRs are at least 80% of studied IARR megawatts. Any portion of the FFEs for an affected coordinated flowgate that is less than 80% of the IARR megawatt total will result in inadequate FTR revenues, the RTO has found.
PJM wants stakeholder work completed by Aug. 1 to allow implementation of the new rules for the 2020/21 planning period.
Gas Contingencies on Reserves Spur Manual Changes
PJM will update Manuals 11 and 28 to clarify the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.
“In the existing manual language, based on the triggers that are defined for how PJM identifies a gas contingency, there’s language in there that says very broadly that PJM would increase reserve requirements either in day-ahead or real-time to address the need for reliability for gas contingency,” said PJM’s Natalie Tacka. “So this just clarifies how we would do that.”
The MIC will be asked to endorse the revisions in May.
RT SCED Process Lacks Transparency, Monitor Says
PJM’s Independent Market Monitor wants stakeholders to review processes for real-time security constrained economic dispatch (RT SCED) and pricing that PJM uses in the energy market to send dispatch signals to generators and calculate LMPs.
The monitor presented a problem statement to the MIC and asked for feedback from stakeholders about the status quo. The IMM raised questions surrounding RT SCED case execution and approval processes, who approves the SCED cases, what criteria PJM uses to approve RT SCED cases and what criteria PJM uses for selecting cases to be used in the locational pricing calculator (LPC). Manual language should be updated to reflect the answers to these questions, the monitor said.
“This is all good stuff ,and we as a company, as a stakeholder, have been pushing for greater transparency,” said Gary Greiner, of PSEG. “More of an open kimono where we understand the dispatch decisions that are getting made.”
Lisa Morelli, PJM’s real-time markets operations manager, said staff would be open to exploring the issue further.
“We are certainly supportive of providing education in these areas and take the conversation from there,” she said.
NYISO and PJM Agree to New Flowgate Type
NYISO and PJM will revise their Joint Operating Agreement to create a new flowgate type for the East Towanda-Hillside 230-kV tie line.
The RTOs will classify the line as an “other coordinated flowgate,” defined as a flowgate where constraints are jointly monitored and coordinated for reliability purposes but are not settled on due to a lack of impactful dispatchable generation on the non-monitoring system.
The ISO and PJM last September filed with FERC a joint request for waiver of the JOA to permit them to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. The requested waivers enable PJM to temporarily conduct redispatch operations to control flows to the more restrictive rating on the NYISO side of the line without violating its Tariff while the grid operators work to develop a permanent solution. The commission granted the waiver in November. (See “NYISO, PJM Revising JOA for Tie Line Issues” in NYISO Business Issues Committee Briefs: March 13, 2019.)
The American Wind Energy Association’s (AWEA) annual market report on the wind industry, released Tuesday, marks off one record achievement after another.
U.S. wind capacity grew another 8% last year, helping the industry support a record 114,000 jobs, more than 500 domestic factories and more than $1 billion a year in revenue for states and communities hosting wind farms.
Credit that to the 2020 wind-down of the production tax credit, said AWEA CEO Tom Kiernan.
But how does the end of tax credits help the wind industry if that means it becomes one of the few energy sources without some sort of tax support?
Kiernan said the 2015 extension of the PTC, which included a phased end of tax credits, provided the certainty the wind industry needed after years of on-again, off-again legislation in Washington, D.C. He said the “longer-term policy” was just what AWEA had been looking for, as it created an incentive for further investment in the industry and its technologies.
Kiernan said major turbine designers have all announced new designs, adding longer blades, newer technologies, digitization and “other factors that will continue to increase our productivity.” Noting developers have added roughly 8 GW of wind energy each year since 2015, he said he expects the growth to continue, if not increase, over the next few years.
“Because of that long-term policy, [wind] companies have been able to make investments and keep driving down costs,” Kiernan said. “After the PTCs phase off, there will probably be a softening, but because of that five-year horizon, we’ll be two to three years into our next product cycle. We still think we’ll be able to compete with solar, storage and gas.”
AWEA projects a “record amount” of wind generation to come online in the near future. It says more than 35 GW of capacity is either under construction or in advanced development across 31 states.
‘Americans Want It’
Wind energy now stands at 96.4 GW of cumulative installed capacity, more than double what it was in 2010. AWEA says the United States now has enough installed wind energy to power more than 30 million homes. According to the report, wind energy now “reliably delivers” more than 20% of the electricity produced in six states: Iowa, Kansas, Maine, North Dakota, Oklahoma and South Dakota.
Kiernan attributed the growth to corporate and industrial purchases of wind energy — 11.3 GW of clean wind energy because “Americans want it” — and utility purchase agreements.
“Fifty percent of Americans are more likely to buy products from a company that purchased wind energy,” Kiernan said, citing a Yale University poll. “Wind energy is the cheapest source of new electricity on an unsubsidized basis. Utilities are buying it because it’s clean but also affordable.”
Wind jobs by state | AWEA
To ensure the momentum continues, Kiernan said AWEA is encouraging the continued advancement of tax-abatement policies and other legislation at the state level, while asking for a focus on transmission infrastructure at the federal level.
“Our transmission grid is outdated and not built out to provide clean energy sources for the future,” he said, drawing comparisons to the interstate highway system. “We’re asking Congress to do a better job of permitting transmission, and we’re calling on FERC to do the interregional planning.”
Kiernan said transmission should be a key element in any infrastructure package Congress is working on, and it should include an element “requiring FERC to call on RTOs to do joint planning.”
“[Planning] should be done the same way and at the same time in addressing joint projects,” he said. “Connecting these different grids will allow more efficiency in connecting wind projects to the grid.”
Success in Texas
AWEA officials chose to announce its annual market report in Texas partly because Houston will be the site of its May 20-23 WINDPOWER Conference and Exhibition, billed as “the Western Hemisphere’s largest gathering of the people and technology driving wind power trends.”
But Texas is also a “living, breathing example of what’s happening nationally,” Kiernan said.
Annual lease payments by state | AWEA
AWEA says if Texas were a country, it would rank fifth globally in wind energy capacity, with nearly 25 GW of installed capacity. Texas is home to about a quarter of the nation’s wind capacity, and the 7 GW of additional projects under construction or in advanced development is more wind than all but two other states have installed.
The state’s Competitive Renewable Energy Zones transmission buildout, which connected West Texas wind farms with urban population centers, serves as a model of the type of legislation the organization would like to see nationwide.
“The Texas success story is very much an American success story,” Kiernan said.
AWEA’s 2018 market report is just the latest annual or quarterly report it provides. The report includes market rankings of major players, state-by-state details, economic and environmental impacts and assessments of power offtake, wind capacity ownership and project finance.
RENSSELAER, N.Y. — NYISO on Monday proposed using an estimated fuel cost to help determine the carbon component of locational-based marginal prices (LBMPc), while the state’s largest waste energy producer called for carbon offsets to be included in the ISO’s final carbon pricing plan.
The ISO’s fuel cost proposal is intended to improve stakeholders’ ability to estimate the LBMPc, carbon charges and credits and the carbon residual allocation. It would use the real-time LBMP divided by an estimated marginal fuel cost to provide an approximate heat rate in MMBtus, which would be applied against a “conversion factor” for calculating tons of emissions per megawatt-hour.
“We propose using the lowest-cost fuel on the system, on an MMBtu basis, given the varying costs of natural gas and oil,” Ethan D. Avallone, NYISO technical specialist, told the Installed Capacity/Market Issues Working Group.
The largest operator of New York waste-to-energy plants contends the facilities should get more generous treatment under a carbon pricing scheme because they provide a net reduction in GHGs. | Covanta
The ISO will determine the conversion factor from MMBtus to tons of carbon emissions and will post the factor and the fuel indices used, he said.
The ISO initially proposed calculating the LBMPc using a system of equations to determine binding transmission constraints and the characteristics of marginal resources, but staff found in many cases they could not solve the system of equations or could not determine a system of equations for a given market interval, Avallone said. (See NYISO Looks at Carbon Charge Tariff Impacts, Residuals.)
The new method will calculate the LBMPc in dollars per megawatt-hour by multiplying the tons of carbon emissions per megawatt-hour by the social cost of carbon.
Bias and Accuracy
“How do you determine a statewide lowest-cost fuel given the varying access to pipelines?” asked Howard Fromer, director of market policy for PSEG Power New York. “There’s quite a variation among major pipelines for natural gas prices under peak conditions.”
Avallone said one benefit of the new approach is that it captures price variations among different load zones.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, asked about levels of accuracy and whether the ISO is “comparing the former equations-based approach and this heat rate approach.”
“Any approach we use is going to be an estimate, so we will be looking at accuracy factors,” Avallone said.
David Clarke, director of wholesale market policy for Power Supply Long Island, was concerned about the potential for the new fuel-cost method to overstate the carbon component.
“You might end up dividing a high cost by a lower carbon component,” Clarke said.
Mark Reeder, representing the Alliance for Clean Energy New York, agreed with Clarke.
“If you’re using the lowest-cost fuel, and if it turns out the plant on the margin is really using a higher-cost fuel, then you would be overstating the carbon component,” Reeder said. “This method seems a bit biased toward the high side. I recommend the NYISO, when judging the quality of any approach, give significant weight to the goal of a lack of bias and not just to the goal of accuracy. There is often a tradeoff between these two goals.”
Sample LBMPc calculation. | NYISO
In the NYISO market, certain carbon-free resources able to store energy structure their bids to achieve schedules during the most profitable periods of the day. When energy prices are low, the bids from such resources include an estimated opportunity cost of profit relative to intervals with higher prices.
“The proposed LBMPc methodology we just walked through will incorporate carbon adders that are the result of bidding opportunity costs,” Avallone said, noting carbon-free opportunity cost resource bids are also likely to increase as a result of carbon pricing in some hours.
He also said internal generators would be charged for carbon based on their actual emissions — not the LBMPc — and the LBMP used to calculate LBMPc will include the impact of resources’ bidding opportunity costs when such resources are marginal, making any additional adjustments unnecessary.
Referring to an instance when a California gas-fired generator installed batteries as part of its facility, Couch White attorney Kevin Lang, representing the City of New York, asked how NYISO’s carbon pricing would impact carbon resources able to store energy.
“I think you’d have the same treatment … the LBMP would still incorporate the costs of that generator,” Avallone said.
Reeder said he found the ISO approach “an elegant way to determine opportunity costs.”
Waste to Energy
Michael E. Van Brunt, director of sustainability for Covanta Energy, which owns or operates most of the state’s waste-to-energy (WTE) plants, addressed a different challenge his industry faces regarding the carbon pricing scheme.
New York’s 10 WTE plants employ nearly 1,400 people and convert 3.2 million tons of solid waste per year into electricity, with a combined installed capacity of 285.1 MW. Van Brunt said while New York state policy values WTE over dumping in landfills, the facilities do not qualify for renewable energy credits under the Clean Energy Standard (CES) appendices, while landfill methane conversion does.
Landfills are required by state law to capture methane beyond a certain volume and use it to run generators. The latest figures from the state’s Department of Environmental Conservation show landfill methane generated 782,500 MWh of electricity in 2015.
In the voluntary emissions market, the WTE industry generates and sells offset credits from new capacity but “faces a significant penalty under the current NYISO proposal that will directly impact communities using WTE,” Van Brunt said, displaying a slide that shows the industry in New York having a net greenhouse gas factor of -0.8 ton CO2/MWh.
“I think a rational carbon pricing policy has to account for carbon offsets,” said Clarke.
Nicole Bouchez, the ISO’s principal economist, said state policy is “conflicted to some extent” and the CES does not cover WTE, requiring NYISO to have state approval to exempt WTE facilities from carbon pricing.
“The ISO plays an important role as arbiter on policy, and, in this case, where there are policy distortions,” its voice could count, Van Brunt said.
“Are you looking to be held harmless, as if the [carbon] program didn’t exist … or do you want to keep all the incremental revenue from carbon pricing?” asked Fromer.
“We look for equal treatment with landfills from the state,” Van Brunt said. “If landfills are going to be exempted, so should WTE.”
Bouchez said the ISO will soon announce a date for a second presentation by Analysis Group, which last month revealed the outline of a new study to provide additional insight into pricing carbon in NYISO’s wholesale electricity markets. (See Analysis Group Presents NYISO Carbon Pricing Study Plan.)
NYISO’s Board of Directors on Monday selected two 345-kV transmission projects intended to address persistent transmission congestion in New York and foster delivery of renewable energy to the state’s population centers.
The projects — part of the broader AC Public Policy Transmission Project — address transmission capacity at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (UPNY/SENY or Segment B) interface.
“The projects will add the largest amount of free-flowing transmission capacity to the state’s grid in more than 30 years,” the board said in a statement.
The board in December issued a mixed decision on project selections made by NYISO’s Management Committee. The MC — along with ISO staff — had backed two joint proposals by North America Transmission (NAT) and the New York Power Authority. (See NYISO MC Supports AC Transmission Projects.) Cost estimates for both projects ranged from $900 million to $1.1 billion.
New York’s AC Public Policy Transmission projects are intended to relieve congestion in key corridors. | NYISO
But while the board accepted the committee’s recommendation for Segment A, it switched Segment B to a competing proposal by National Grid and New York Transco. (See NYISO Board Partially Reverses AC Tx Project Selection.)
The NAT/NYPA Central East project involves construction of a new 345-kV line from Edic to New Scotland on an existing right-of-way; construction of two new 345-kV lines from Princetown to Rotterdam; decommissioning of two 230-kV lines from Edic to Rotterdam; and related switching or substation work at Edic, Princetown, Rotterdam and New Scotland.
The National Grid/Transco UPNY/SENY project involves several different areas of focus, including construction of a new double-circuit 345/115-kV lines from Knickerbocker to Churchtown and on to Pleasant Valley; construction of a new tap of the New Scotland-Alps 345-kV line and new Knickerbocker switching station; and related switching or substation work at the Greenbush, Knickerbocker, Churchtown and Pleasant Valley substations.
The project also entails decommissioning a double-circuit 115-kV line from Knickerbocker to Churchtown and two double-circuit 115-kV lines from Knickerbocker to Pleasant Valley.
National Grid and Transco will also oversee new line traps, relays, potential transformer upgrades, switch upgrades, system control upgrades and the installation of data acquisition measuring equipment and control wire needed to handle the higher line currents resulting from the buildout. The companies also will build a new double-circuit 138-kV line from Shoemaker to Sugarloaf; decommission a double-circuit 69-kV line from Shoemaker to Sugarloaf; and perform related switching or substation work.
“The additional transmission projects selected will improve the flow of power from upstate renewable resources to meet downstate demand and enhance the reliability and resilience of the grid … will alleviate congestion, help deliver power where it is needed most and aid the state in meeting its ambitious renewable energy goals,” interim NYISO CEO Robert Fernandez said in a press release.
The projects are the second and third transmission projects to emerge from the ISO’s Public Policy Transmission Planning Process, a planning activity required by FERC Order 1000 and the state’s Public Service Commission. The PSC identified the public policy transmission needs to increase transfer capability from central to eastern New York by at least 350 MW and from the Albany region through the Hudson Valley region by at least 900 MW.
HARRISBURG, Pa. — Critics of a bill to subsidize Pennsylvania’s failing nuclear fleet on Monday advised state lawmakers to put the brakes on the proposal, saying it would distort the deregulated energy markets it worked long to build.
Glen Thomas
Glen Thomas, president of GT Power Group, testified before the House Consumer Affairs Committee that House Bill 11 upends two decades of regulatory and legislative work and wastes $12 billion in stranded costs spent transitioning to a competitive wholesale power marketplace.
“It’s an absolute competition killer,” he said. “It’s a big deal. It’s a very complicated piece of legislation … that undoes a lot of the hard work it took to get us here.”
HB 11 would create a third tier of resources in the state’s Alternative Energy Portfolio Standard (AEPS) program from which retail providers must purchase at least 50% of their electricity by 2021: nuclear, solar, geothermal and low-impact hydropower. The first two tiers of the legislation include 16 resource types with targets of 8% and 10%.
Prime sponsor Rep. Thomas Mehaffie (R) said the plan would provide consumer protections through capped pricing and the prevention of “double dipping” across programs. He estimated the bill would cost $500 million — one-eighth of the $4.6 billion in annual costs he claims would result should all five nuclear plants in the state shut down: $788 million in higher electric prices; $2 billion in lost GDP; and $1.86 billion in costs associated with carbon emissions and harmful criteria air pollutants, including SO2, NOX and particulate matter. (See Pa. Lawmakers Unveil $500M Nuke Subsidy Bill.)
Exelon will begin the four-month process of shutting down Three Mile Island near Harrisburg in June if lawmakers fail to act. FirstEnergy will retire Beaver Valley in 2021 in what the company described as a growing trend during its testimony before the committee on Monday.
Dave Griffing
“On one hand, emitting plants get to pollute for free, not bearing any of the cost of the pollution they put into the air or water,” said Dave Griffing, vice president of government affairs for FirstEnergy Solutions. “And on the other hand, 16 other forms of technology get a payment, some as high as $55[/MWh], from the federal and state government through tax credits and AEPS credits. The result is not shocking. Pennsylvania nuclear facilities and others across the country have their hands tied behind their backs and are facing early retirement.”
Critics of the plan argue there’s better, cheaper ways to reduce carbon emissions and insist that subsidizing nearly 70% of the market props up aging nuclear reactors at the expense of competition.
“This is a major shift in Pennsylvania’s energy policy from a policy that puts consumers in the driver’s seat to one that puts policymakers in the driver’s seats by dictating where their energy comes from,” Thomas said, noting he’s spent the majority of the last 15 years convincing other states to deregulate their energy markets like Pennsylvania has. “HB 11 puts the thumb on the scale for 68% of the delivered megawatts in this state if approved.”
Tom Ridge
Tom Ridge, former secretary of Homeland Security, and Pennsylvania governor from 1995 to 2001, said preserving the state’s five nuclear facilities maintains reliability. He signed the 1996 bill deregulating the state’s energy markets and allowing it to join PJM.
“I’ve always believed in a diversified portfolio,” he told lawmakers Monday. “We want competitive markets and competitive markets need multiple sources of generation. Other states are doing it because they can’t wait on the feds to do it. In five or six years, we may not have these facilities left.”
Todd Snitchler
Todd Snitchler, vice president of market development for the American Petroleum Institute, said PJM’s generation portfolio will remain balanced, even as trends shift away from nuclear energy. Last month, the Independent Market Monitor said gas-fired energy output exceeded coal in PJM last year for the first time, though sources remain relatively balanced among gas (30.9%), coal (28.6%) and nuclear (34.2%), with renewables accounting for a small but growing share of less than 3%.
“A concern about a dash to gas needs to be tempered by realities on the ground,” he said.
The committee will host a second public hearing on HB 11 in Harrisburg on April 15.
The Senate version of the bill, SB 510, was introduced last week by Sen. Ryan Aument (R). That bill differs from the House version in that it directs the state’s Public Utility Commission to set credit prices and guarantee that between 17 and 23% of Tier III sources purchased include non-nuclear suppliers, like wind and solar. (See related story, Pa. Lawmakers Introduce 2nd Nuke Subsidy Bill.)
ERCOT staff and stakeholders began the long process of implementing real-time co-optimization (RTC) last week with the first meeting of the Real-Time Co-Optimization Task Force.
The group spent its Thursday meeting reviewing ERCOT’s current market design and the changes that RTC will necessitate. ERCOT Compliance Director Matt Mereness, the task force’s chair, said it’s important to understand the elements in RTC’s high-level design principles in order to better understand what is being implemented.
“We have a mandate to implement real-time co-optimization, and we will be working to see what market functions have to be changed to enable that,” Mereness said.
RTC is supposed to efficiently coordinate the provision of energy and ancillary services (AS) in the real-time market and price AS shortages according to their defined demand curves. Its elements include: real-time market and AS deployment; reliability unit commitment; day-ahead market operations; internal and external reporting; and performance monitoring.
Implementation of the process will mean the loss of ERCOT’s supplemental AS market.
The Texas Public Utility Commission directed ERCOT to implement RTC earlier this year (Project 48540). The grid operator has said it will take four or five years and about $40 million to add RTC to the energy-only market.
Bryan Sams, director of regulatory affairs for Lone Star Transmission, is serving as the RTCTF’s vice chair. The group is composed of stakeholders and staff from ERCOT, the PUC, the Independent Market Monitor and the Office of Public Utility Counsel. The task force will report directly to the Technical Advisory Committee.
ERCOT to Ask Board for NPRR916 Changes
ERCOT will ask its Board of Directors during its bimonthly meeting Tuesday to accelerate the implementation date for a previously approved Nodal Protocol revision request (NPRR) and to change its mitigated floor offer as a result of negative gas prices.
The TAC endorsed NPRR916 on March 27. The change sets the mitigated offer floor to $0/MWh for “combined cycle” (CCGTs) and “gas/oil steam and combustion turbine” (CTs) resource categories, replacing the fuel index price-based (FIP) calculation. The change also eliminates the grey-boxed language from NPRR664.
During a Thursday webinar, staff explained that negative fuel prices at the Waha Hub coupled with mitigated floor offers are creating “irrational restrictions” for CTs and CCGTs. When gas prices are negative, a floor of zero is excessive relative to the resource’s optimal offer, staff said.
ERCOT wants to change the offer floor to -$20/MWh, aligning CTs and CCGTs with coal and lignite units’ offer floor.
Texas Natural Gas Prices | ERCOT
The grid operator also wants to move up implementation of NPRR916 from May 1 to April 10. Staff said West Texas fuel prices support the need to “make this system adjustment as soon as practicable.” The proposed change to -$20 requires modifications to ERCOT systems that would become effective upon system implementation.
The current floor for CCGTs is set at 1 MMBtu/MWh x FIP, and 6 MMBtu/MWh x FIP/FOP (fuel oil price) for CTs and gas and oil steam turbines. NPRR916 changes those numbers to a straight value of $0/MWh.
The NPRR916 changes are expected to cost less than $10,000 and will be absorbed by ERCOT’s operations and maintenance budgets, staff said.
