California has moved a step closer to adopting a 100% clean energy standard.
The State Senate on Wednesday passed a bill that would require California load-serving entities to obtain all of their electricity deliveries from renewable resources by 2045 (SB 100).
de León
Sponsored by Senate President pro Tempore Kevin de León, a Los Angeles Democrat, the bill passed 25-13 along party lines. It now moves to the State Assembly.
“When it comes to our clean air and climate change, we are not backing down,” de León said in a statement. “Today, we passed the most ambitious target in the world to expand clean energy and put Californians to work.”
De León said it is now critical for California to “double down on climate leadership” given President Trump’s announcement today that the U.S. would withdraw from the Paris Agreement on climate change. (See related story, Trump Pulling U.S. Out of Paris Climate Accord.)
“We are sending a clear message to the rest of the world that no president, no matter how desperately they try to ignore reality, can halt our progress,” he said.
The new bill would accelerate the timeline for California’s current 50% RPS from 2030 to 2026, with an interim 45% goal put in place for 2023. The 2030 requirement would increase to 60%, and the bill gives the California Energy Commission discretion to establish “appropriate” three-year compliance periods subsequent to 2030.
The bill also directs state agencies to incorporate the planning goal into any energy and climate programs subject to their jurisdiction, which would include the utility integrated resource plans administered by the PUC.
Passage of the bill got expected support from environmental groups and advocates for renewable energy.
“Getting 100% renewable is 100% possible and 200% necessary,” said Kathryn Phillips, director of Sierra Club California. “SB 100 responds to what survey after survey shows that Californians want: clean energy, clean air and a future for the next generation.”
Strela Cervas, co-director of the California Environmental Justice Alliance, said the proposed law would move California away from fossil fuels that that have a disproportionate impact on disadvantaged communities and communities of color.
“The bill charts a pathway for the public health and economic benefits of local renewable energy to reach communities that need it the most,” Cervas said.
“Transitioning to a 100% carbon-free future in an economy the size of California’s requires persistence, commitment and vision,” said Bernadette Del Chiaro, executive director of the California Solar Energy Industries Association.
Solar Field | Sunworks
In urging his colleagues to vote against the bill, Republican Sen. Jeff Stone warned that the state might be getting ahead of its ability to actually implement a 100% RPS.
“If we don’t have the science to back up the methodology to get to 2030 with 60% coming from renewables, then it’s going to increase costs for our constituents,” Stone said. “We need to let the technology drive the innovations in alternative energy and not put mandates out there that may be unachievable.”
If it becomes law, the bill would make California the second state after Hawaii to require LSEs to rely on 100% renewables by 2045.
The Los Angeles Department of Water and Power (LADWP) on Thursday agreed to join the Western Energy Imbalance Market (EIM), adding the country’s largest municipal utility to the growing electricity market.
LADWP is the 11th utility to announce plans to participate in the CAISO-run market, which is designed to better balance supply and demand across the region by making more electricity resources available in real time.
LADWP General Manager David Wright touted the benefits of joining with other utilities across the western U.S. to more reliably integrate renewable energy resources.
“We are pleased to enter the EIM in what will be a solid step forward in partnering with our neighbors to find benefits for the City of Los Angeles,” Wright said in a statement.
While LADWP expects to begin participating in the market in April 2019, that timeline could be extended an additional year to accommodate the utility’s unique configuration and required upgrades. A separate agreement will have to be made once the LADWP system is integrated into the EIM.
Total implementation costs are estimated at $15 million to $20 million, and recurring expenses are projected at about $2.3 million per year. Third-party analysis pegged annual savings for ratepayers at $2 million to $5 million.
About 40% of LADWP’s 7,600 MW of capacity is coal-fired, 20% renewable, 22% natural gas-fired, 9% nuclear and 7% classified as “other.” The municipal utility began distributing electricity in 1917 and serves about 4 million customers.
The utility also individually or jointly controls about 4,600 miles of transmission, which includes the Pacific DC Intertie connecting Southern California with the Bonneville Power Administration system in the Northwest and the Intermountain DC system that carries output from coal-fired generation in Utah.
| CAISO
Already participating in the EIM are PacifiCorp, NV Energy, Puget Sound Energy and Arizona Public Service. Portland General Electric is due to join in October; Idaho Power in April 2018; Seattle City Light and Balancing Authority of Northern California/Sacramento Municipal Utility District in April 2019; and Salt River Project in April 2020.
Vancouver-based Powerex earlier this week became the first non-U.S. entity to announce its intention to join the market starting next spring. (See Powerex Slated to Become First Non-US EIM Member.)
The EIM began operating in November 2014 and now includes participants in Arizona, California, Idaho, Nevada, Oregon, Utah, Washington and Wyoming. CAISO estimates the market has so far produced approximately $173 million in gross benefits for its members.
SPP stakeholders approved a revision request Tuesday that allows the RTO to lower its planning reserve margin as it waits on a quorum-less FERC to act on a proposed Tariff change.
The Markets and Operations Policy Committee approved RR230 during a special conference call, changing SPP’s criteria to allow it to reduce the planning reserve margin to 12% from 13.6% effective June 1.
The new reserve margin was included in SPP’s March filing asking FERC to approve the changes effective June 1 (ER17-1098). SPP COO Carl Monroe said the RTO had yet to hear from the commission, necessitating a vote on an interim solution.
“We don’t know why they haven’t acted … we assume because of a lack of quorum,” Monroe said during the hour-long conference call.
On Wednesday, FERC responded by saying SPP’s resource-adequacy requirement filing was deficient and that additional information is required to process the request. The commission listed 18 questions to be addressed related to:
SPP’s firm power, firm capacity and net peak demand requirements.
How market participants may assign their obligations and responsibilities to other market participants.
The RTO’s annual deliverability study that determines the load a resource may deliver to the balancing authority area without effecting reliability or requiring additional transmission upgrades.
Deficiency payments and distributions of revenues.
FERC has been operating with only two commissioners since February, when former Chairman Norman Bay resigned and left the commission with three vacancies. The Trump administration only recently nominated two commissioners, who went through confirmation hearings last week. (See No Fireworks for FERC Nominees at Senate Hearing.)
SPP stakeholders resisted staff’s initial request to approve RR230 by an email vote, made when it became likely FERC was not going to act by the effective date. American Electric Power, Westar Energy, Kansas City Power & Light, Oklahoma Gas & Electric and Duke Energy were among those requesting further discussion.
Westar Energy’s Murray Gill Energy Center near Wichita, Kansas | Westar
“I feel like we’re pushing something through that would be better in a thought-out process,” Westar’s John Olsen said. “It’s a little item, but I don’t know what the unintended consequences are. If FERC doesn’t approve [the proposed Tariff] language, then where are we at?”
“Had this been advanced as an issue by OGE rather than staff … I would have worked with [OGE] beforehand,” AEP’s Richard Ross said.
As it was, Ross worked with OGE Energy’s Greg McAuley, Omaha Public Power District’s Joe Lang and Midwest Energy’s Bill Dowling to hammer out the final motion’s language. A key addition was language making RR230 effective for only 10 business days after FERC rules on SPP’s filing.
Members overwhelmingly approved the motion, with only five opposing votes and two abstentions.
RR230 earlier cleared the Supply Adequacy, Transmission, and Regional Compliance working groups with two opposing votes and three abstentions.
SPP’s filing came after the MOPC and the Board of Directors in January approved a package of policies that included the 12% planning reserve margin, which translates to a 10.7% capacity margin.
A task force spent two years on that package, which it says will reduce the RTO’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
The original revision request incorporated previously approved policies defining a resource adequacy requirement, identifying who is responsible for resource adequacy, and how and when the requirement should be met. The policies are to become effective this summer, with the exception of an assurance policy requiring entities short on their planning reserve margins to make payments to entities with excess capacity, based on forecasted information.
Members agreed to use 2017 as a “dry run” for the resource adequacy process.
WASHINGTON — President Trump followed through on his campaign pledge to withdraw the U.S. from the Paris Agreement on climate change Thursday, a victory for economic nationalists and conservatives that prompted howls of outrage from other signatories, environmentalists and corporate leaders.
“I was elected to represent the citizens of Pittsburgh, not Paris,” said Trump, who complained the agreement would do little to combat global warming but would cost the U.S. millions of jobs and leave the nation unable to produce enough power to support economic growth of “3 to 4%” — a pace the country has rarely seen.
“At 3 or 4% economic growth — which I expect — we need all forms of American energy,” he said.
The U.S., the No. 2 producer of greenhouse gases after China, joins Syria and Nicaragua as the only countries not party to the 2015 agreement, which was largely brokered by the Obama administration and has been signed by more than 190 countries. The U.S. agreed to a nonbinding goal of cutting carbon emissions by at least 26% below 2005 levels by 2025.
Trump, who has previously called global warming a “hoax,” did not address climate science, instead saying the U.S. would remain the “cleanest, most environmentally friendly” nation in the world and would seek to negotiate a new deal that doesn’t penalize it. “We’ll see if we can make a deal that’s fair,” he said.
Trump said the Paris Agreement would hamstring the U.S. economy while allowing India and China to increase emissions for years. “China can do whatever they want for 13 years,” he said. “India can double its coal production. We’re supposed to get rid of ours.”
In rejecting the agreement, Trump said he was reasserting American sovereignty and undoing a “self-inflicted wound.”
“This agreement is less about the climate and more about other countries gaining a financial advantage over the United States. The rest of the world applauded when we signed the Paris Agreement. They went wild, they were so happy. For the simple reason that it put our country … in a very, very bad economic disadvantage.”
Speaking after the president, EPA Administrator Scott Pruitt praised what he called “an historic restoration of American economic independence.”
“We owe no apologies to other nations for environmental stewardship. After all, before the Paris accord was ever signed America had reduced its CO2 footprint to levels of the early 1990s,” he said, citing an 18% reduction in carbon emissions between 2000 and 2014. “This was accomplished not through government mandate but accomplished through the innovation and technology of the American private sector. … Other nations talk a good game. We lead with action, not words.”
Former President Barack Obama issued a statement rejecting Trump’s criticism. “It was steady, principled American leadership on the world stage that made [the agreement] possible. It was bold American ambition that encouraged dozens of other nations to set their sights higher as well. And what made that leadership and ambition possible was America’s private innovation and public investment in growing industries like wind and solar — industries that created some of the fastest new streams of good-paying jobs in recent years, and contributed to the longest streak of job creation in our history.
“The nations that remain in the Paris Agreement will be the nations that reap the benefits in jobs and industries created,” Obama continued. “I believe the United States of America should be at the front of the pack.”
Little Surprise
Although Trump said in November that he had an “open mind” on the subject, his announcement in the White House Rose Garden was not surprising given his campaign pledge and his executive order directing EPA to undo the Clean Power Plan.
The CPP would have required a 32% reduction in power plant CO2 emissions from 2005 levels by 2030. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.) The U.S. Energy Information Administration says emissions were 12% below the 2005 level as of 2015.
Opposition to the Paris Agreement was led within the administration by Pruitt and political aide Stephen Bannon, who were in the audience for the announcement along with about 100 Trump supporters, including members of the conservative Heritage Foundation and Competitive Enterprise Institute.
During his trip to Europe last week, Trump was lobbied by European officials and Pope Francis to honor the deal. Others who made their case to Trump for remaining included former Vice President Al Gore and leaders of dozens of Fortune 500 companies.
Thirty top CEOs, including Pacific Gas and Electric’s Geisha Williams, signed an open letter urging Trump to remain in the agreement, which they said would strengthen U.S. competitiveness, benefit American manufacturing and support investment “by setting clear goals which enable long-term planning.”
“It expands global and domestic markets for clean, energy-efficient technologies, which will generate jobs and economic growth. It encourages market-based solutions and innovation to achieve emissions reductions at low cost,” they said.
Also weighing in with support were Trump’s daughter Ivanka and Secretary of State Rex Tillerson, neither of whom attended the announcement.
Trump’s speech started 30 minutes late, leaving the hundreds of reporters, photographers and guests sweltering in the sun as a military band played jazz.
Some analysts contend Trump’s decision to abandon the Paris Agreement and the CPP will have limited effect because of decarbonization efforts already adopted by power generators and others. (See EBA Panel: CPP’s Demise not Certain — and it Doesn’t Matter.)Economic consultancy company Rhodium Group estimates the U.S. would reduce carbon emissions by 21% below 2005 levels in 2025 under the CPP but that the reduction would flatten at 14% under Trump’s rollback.
Shortly after Trump’s announcement, Democratic Govs. Jay Inslee (Wash.), Jerry Brown (Calif.) and Andrew Cuomo (N.Y.) announced they had formed the U.S. Climate Alliance, a pact dedicated to upholding the country’s commitments under the agreement. On Monday, the group expanded to include Connecticut, Delaware, Hawaii, Massachusetts, Minnesota, Oregon, Puerto Rico, Rhode Island, Vermont and Virginia.
More than 180 U.S. mayors — including Pittsburgh Mayor Bill Peduto and the chief executives of Los Angeles, Boston, New York, Chicago, Houston, Seattle, Philadelphia and Atlanta — issued a statement saying they would “adopt, honor and uphold the commitments” under the agreement.
The Paris Agreement is intended to prevent the planet’s temperature from increasing by more than 3.6 degrees Fahrenheit, which many experts say would lead to an irreversible future of rising oceans and extreme weather, causing drought, flooding, and food and water shortages.
It will take the U.S. until November 2020 to complete its exit from the agreement.
Reaction
The Business Council for Sustainable Energy, which has been an observer at the United Nations Framework Convention on Climate Change for the past 25 years, was dismayed by the news. “Withdrawing from the Paris Agreement weakens the U.S. government’s ability to protect U.S. commercial interests in these discussions as well as in other important international negotiations,” President Lisa Jacobson said. “This international agreement is an opportunity to bolster American economic development, not a barrier to it.”
Mike Tidwell, director of the Chesapeake Climate Action Network, said Trump’s decision “sealed his reputation as an economic and environmental wrecking ball with few rivals in U.S. history. Locally, his decision to withdraw from the Paris Climate Agreement threatens to reduce jobs and shrink our regional economy. It would do so by embracing fracking and a dying coal industry over the jobs-creating markets for wind and solar power.”
Myron Ebell, director of the Competitive Enterprise Institute’s Center for Energy and Environment, who attended the announcement, issued a statement saying the decision will lower prices. “The agreement involves enormous costs for zero benefits, and requires member countries to submit new, steeper commitments to reduce emissions every five years,” he said. “Its global energy-rationing regime consigns poor people in developing countries to perpetual energy poverty.”
Heritage Foundation President Ed Feulner said the withdrawal was “a commonsense approach that helps the American people and businesses. … From lost jobs, higher electric bills or more overzealous government regulations, the Paris Agreement was by all accounts a rotten deal.”
Senate Majority Leader Mitch McConnell (R-Ky.) thanked Trump for “dealing yet another significant blow to the Obama administration’s assault on domestic energy production and jobs.”
Senate Minority Leader Chuck Schumer (D-N.Y.) called the withdrawal “a devastating failure of historic proportions. Future generations will look back on President Trump’s decision as one of the worst policy moves made in the 21st century because of the huge damage to our economy, our environment and our geopolitical standing.”
Corporate, International Responses
Several corporate leaders blasted the move, with Tesla CEO Elon Musk and Walt Disney Co. CEO Bob Iger pledging to quit a White House advisory council. “Leaving Paris is not good for America or the world,” Musk said.
General Electric CEO Jeff Immelt tweeted his disappointment. “Climate change is real. Industry must now lead and not depend on government,” he said.
IBM issued a statement rejecting Trump’s view that the agreement would hurt the economy. “IBM believes that it is easier to lead outcomes by being at the table, as a participant in the agreement, rather than from outside it.”
But Peabody Energy, the largest coal mining company in the U.S., praised the decision. It said it “continues to advocate for greater use of technology to meet the world’s need for energy security, economic growth and energy solutions through high-efficiency, low-emissions, coal-fueled power plants, and research and development funding for carbon capture.”
The decision was not well received in Europe.
“The Paris Agreement provides the right global framework for protecting the prosperity and security of future generations, while keeping energy affordable and secure for our citizens and businesses,” U.K. Prime Minister Theresa May said.
French President Emmanuel Macron rejected Trump’s call for renegotiation. “I tell you firmly tonight: We will not renegotiate a less ambitious accord,” he said. “There is no way. Don’t be mistaken on climate; there is no plan B because there is no planet B.”
Powerex has signed an agreement with CAISO to become the first non-U.S. participant in the Western Energy Imbalance Market (EIM).
Vancouver-based Powerex markets the surplus generation of parent BC Hydro, Canada’s third largest utility. The company’s role is similar to that of U.S. federal power marketing agencies, such as Bonneville Power Administration and the Western Area Power Administration.
Powerex is wholly owned subsidiary of BC Hydro, responsible for marketing the utility’s surplus hydroelectric generation to customers throughout the West. | Kootenay Canal Generating Station image courtesy of BC Hydro
Mexican grid operator El Centro Nacional de Control de Energía (CENACE) last year announced that it was exploring having its Baja California Norte join the market, but it has not yet signed a participation agreement.
Powerex is slated to join the EIM in April 2018, an aggressive timeline compared with other utilities that have signed on to the market. Preparations typically take 18 months or longer, but the company has long experience selling into the ISO’s real-time market.
“Powerex has actively participated in the ISO’s five-minute market since 2005 through a dynamic scheduling arrangement, so joining the EIM is a logical extension of our intra-hour market participation,” Powerex CEO Teresa Conway said in a statement.
Conway noted that Powerex’s participation in the growing EIM footprint will allow the company to engage in sub-hourly transactions across multiple utility service territories, helping to integrate renewables and improve the region’s grid reliability.
With its access to BC Hydro’s ample hydroelectric resources, Powerex is well-positioned to provide EIM participants with the flexible ramping capacity increasingly needed to firm up the growing number of variable renewable resources coming to the region’s grid. That type of resource sharing is touted as a key benefit of the market.
The company also holds transmission rights on lines throughout the West, including the California-Oregon Intertie, a key transfer point between the Pacific Northwest and California. Constraints on that line periodically act as a chokepoint that isolates the PacifiCorp West and Puget Sound Energy balancing authority areas from the rest of the EIM, resulting in prices that diverge from the rest of the market.
Washington’s Puget Sound Energy — whose service area stretches from suburban Seattle to the Canadian border — began transacting in the EIM last October. (See Seattle City Light Signs EIM Membership Agreement.)
Other future participants in the EIM include Portland General Electric (October 2017), Sacramento Municipal Utilities District (April 2019) and Salt River Project (April 2020). CAISO also said that it expects the Los Angeles Department of Water and Power to soon announce a formal agreement to join the market.
Exelon announced Tuesday that it will retire Three Mile Island Unit 1 in September 2019 “absent needed policy reforms.”
The announcement was not unexpected after the company acknowledged May 24 that the plant had not cleared the PJM capacity auction for delivery year 2020/21, the third year in a row it had come away empty-handed.
In a filing with the U.S. Securities and Exchange Commission, Exelon said the plant has lost money for the last five years as a result of “prolonged periods of low wholesale power prices,” its failure to clear the last three PJM capacity auctions and “the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution while contributing to grid reliability.” As a single-unit plant, TMI also had high operating expenses, the company added.
The 837-MW reactor near Middletown, Pa., directly employs 675 workers.
“Today is a difficult day, not just for the 675 talented men and women who have dedicated themselves to operating Three Mile Island safely and reliably every day, but also for their families, the communities and customers who depend on this plant to produce clean energy and support local jobs,” CEO Chris Crane said in a statement. “Like New York and Illinois before it, [Pennsylvania] has an opportunity to take a leadership role by implementing a policy solution to preserve its nuclear energy facilities. … We are committed to working with all stakeholders to secure Pennsylvania’s energy future and will do all we can to support the community, the employees and their families during this difficult period.”
A Successful Strategy
In threatening to close the plant, Exelon is repeating the strategy that won approval of zero-emission credits for its troubled nuclear plants in New York and Illinois.
Last June 2, Exelon announced it would close the Clinton and Quad Cities plants in 2017 and 2018, respectively, because of “the lack of progress on Illinois energy legislation.” The company said the plants had lost a combined $800 million over the prior seven years, “despite being two of Exelon’s best-performing plants.”
Six months later, the Illinois legislature approved the ZEC program on the last day of its veto session. Gov. Bruce Rauner signed the bill Dec. 7. Following the passage of the Illinois legislation, Exelon revised the expected economic lives to 2027 for Clinton and 2032 for Quad Cities.
On June 12, Exelon told the New York Public Service Commission it would close its Nine Mile Point Unit 1 nuclear plant in spring 2017 if the state did not guarantee it a financial lifeline by September.
The company had also told regulators in October 2015 that its R.E. Ginna nuclear plant would not be financially viable following the expiration of a reliability support services agreement with Rochester Gas & Electric.
The PSC approved ZECs for Nine Mile Point and Exelon’s R.E. Ginna nuclear plants last Aug. 1. Receiving payments under the program in addition to Ginna and Nine Mile Point is the James A. FitzPatrick plant, which Entergy sold to Exelon in March after saying it would also close.
Next Steps
Exelon said it will send PJM and the Nuclear Regulatory Commission deactivation notices within 30 days. It complained that nuclear generation produces 93% percent of Pennsylvania’s emissions-free power but is not included in Pennsylvania’s Alternative Energy Portfolio Standard, which benefits solar, wind and hydropower.
The Pennsylvania General Assembly’s Nuclear Energy Caucus said in a statement that Exelon’s announcement shows “there are serious and consequential underlying issues in Pennsylvania’s energy sector that must be addressed.”
“As state lawmakers, we take seriously our obligation to set energy policies that help promote Pennsylvania’s economy,” the legislators said. “We equally are concerned about meeting the commonwealth’s environmental goals. The closure of Three Mile Island will make meeting these challenges even more difficult.”
The 79-member caucus has yet to introduce legislation.
Gov. Tom Wolf’s press office released a statement in which it “expressed a willingness to engage in conversations with state lawmakers about possible energy policy reforms.”
“Pennsylvania is a major supplier of energy and we need a diverse energy sector,” Wolf spokesman J.J. Abbott said. “… As we move forward, we expect a robust conversation about the state’s energy sector. Governor Wolf is open to these conversations and looks forward to engaging with the General Assembly about what direction Pennsylvania will go in regards to its energy sector, including the future of nuclear power.”
Legal Challenges
The ZECs in both Illinois and New York are being challenged in the courts and before FERC by plaintiffs including the Electric Power Supply Association, Dynegy, Eastern Generation, NRG Energy and Calpine.
Exelon’s motion to dismiss a federal lawsuit filed last October challenging the New York ZECs was the subject of oral arguments March 29 (U.S. District Court, Southern District of N.Y., 1:16-cv-08164). Thus far, the court has approved Exelon’s request to intervene, as well as requests to file amicus briefs by the Natural Resources Defense Council, the Environmental Defense Fund, PJM Independent Market Monitor Monitoring Analytics and a group including the New York Public Interest Group.
Independent power producers filed suit in February alleging that the law authorizing Illinois’ ZECs violates FERC jurisdiction over the wholesale electricity market (U.S. District Court, Northern District of Illinois,1:17-cv-01164). (See IPPs File Challenge to Illinois Nuclear Subsidies.)
The judge in the case has delayed action on a motion for a preliminary injunction while he receives a full briefing on Exelon’s motion to dismiss the cases. On April 24, the court invited FERC to file an amicus brief on the jurisdictional question.
In February, the IPPs also sought expedited rulings against the ZECs in FERC dockets initiated over earlier disputes.
Docket EL16-49 had been opened in 2016 to challenge subsidies Ohio regulators had awarded to FirstEnergy and American Electric Power fossil fuel generators. In EL13-62, opened in 2013, the IPPs asked FERC to broaden the use of the minimum offer price rule in New York.
FERC has been without a quorum since February and thus unable to take substantive action on the cases.
At a FERC technical conference May 1-2, NYISO CEO Brad Jones told the commission that the ISO is working on a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. Observers differ on whether FERC — expected to have at least two new commissioners nominated by President Trump soon — will approve Tariff changes to implement the initiative. (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)
TMI’s Place in History
Whether or not Three Mile Island shuts down in 2019, it will occupy a special place in nuclear power history.
The partial meltdown of TMI Unit 2 on March 28, 1979, the most serious accident in U.S. commercial nuclear power history, effectively ended nuclear power construction for decades and resulted in major changes regarding emergency response planning, operator training and radiation protection.
Unit 2, owned by FirstEnergy, never reopened following the accident. Exelon purchased half of Unit 1 in 1999 and became sole owner of the plant in 2003. The plant received a 20-year extension in 2009, allowing it to operate until 2034.
Financial Repercussions
Exelon said it is taking a one-time charge of $65 million to $110 million for 2017, and accelerating approximately $1 billion in depreciation and amortization through the shutdown date, terminating capital investment projects and canceling 2019 fuel purchases and outage planning, impacting about 1,500 outage workers.
It said there could be as much as $25 million in additional charges in each of 2018 and 2019.
WESTBOROUGH, Mass. — ISO-NE’s 2017 Economic Study will reflect the same basic assumptions and use the same profiles as those in the 2016 study, while representing some incremental changes to the former study’s third scenario. Marianne Perben, manager of resource adequacy and technical studies, outlined the 2017 study’s scope of work to the Planning Advisory Committee on Thursday, saying it will produce metrics similar to those in the 2016 report being completed now.
The 2017 study will include analysis that the Conservation Law Foundation requested at the April PAC meeting. The CLF wants the grid operator to determine whether there are viable system topologies other than those analyzed in Scenario 3 of the 2016 study with similar total system emissions but a lower relative annual resource cost.
Strong Mass. Economy Nudges up 2017 CELT Load Forecast
The 2017 Capacity, Energy, Loads and Transmission Report shows a reduced RTO load forecast from 2016 but predicts an increase in load for the Southeast New England area because the Massachusetts economy is growing faster than those in other New England states.
ISO-NE system planner Manasa Kotha on Wednesday presented a report on future capacity requirements, which credited some of the increase to changes in the operating company distribution of the load to the buses, and some to the Massachusetts economy, which is expected to grow at a compound annual growth rate of 2.1% through the forecast horizon.
The report covers net installed capacity requirements (ICR) for capacity commitment periods 2022/23 through 2026/27, ranging from 34,300 MW in the first cycle covered to 35,700 MW in the last.
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The load forecast is net of behind-the-meter solar PV resources. Energy efficiency is treated separately — modeled as a supply-side capacity resource in the ICR calculations.
For additional background, Kotha referred participants to a Reliability Committee presentation on the ICR Values for CCP 2020/21 covered by Forward Capacity Auction 11.
Locational Reserves Good in Key Load Centers
Salem Harbor Generating Station
Generation and transmission additions expected to be completed by 2019 will ensure sufficient operating reserves in Greater Boston, Greater Connecticut and Greater Southwest Connecticut through 2021, according to a report on reserve needs for major import areas.
Forward reserve requirements for the Northeast Massachusetts/Boston zone have ranged from 300 to 500 MW for the last three summers, and 0 MW for the winters. The report calls for 279 MW this summer and 200 to 650 MW for 2018, dropping to 0 to 50 MW after the addition of the 674-MW Footprint Power quick-start combined cycle plant at Salem Harbor, which is expected online by the end of the year.
ISO-NE resource adequacy planner Fei Zeng, who presented the report to the PAC on Wednesday, said that fast-start resources near those major load centers provide flexibility to the grid.
WESTBOROUGH, Mass. — A substantial increase in new clean resources would lower Forward Capacity Auction prices, “crowding out” many existing resources — but their ability to do so will depend on the level of offer mitigation, according to an analysis commissioned by ISO-NE.
ISO-NE last year asked Analysis Group to assess outcomes in the Forward Capacity Market under six resource expansion scenarios evaluated in the second part of the 2016 Economic Study. (See scenario descriptions below.)
Todd Schatzki of Analysis Group briefed the Planning Advisory Committee on Thursday on the study, which assumes all current market rules. The study assumes retirements of 2,457 MW by 2025 and 4,668 MW by 2030. Absent retirements, Schatzki said, there’s limited need for new resources.
“Given low load growth, given what’s going on behind the meter and given that there is not necessarily a lot in the queue that is coming in, absent some market price signal, you’re not going to get new resources coming in,” said Schatzki, who prepared the report with colleague Christopher Llop. “You’re not going to get prices raising back up towards the cost of new entry unless some new resources get in the system.”
Capacity and Energy Market Implications
Total Forward Capacity Market payments in 2025 are projected to range between $2.1 billion in Scenario 3 (“Renewables Plus”) to $3.8 billion in Scenarios 2 (“ISO Queue”) and 6 (“RPS + Geodiverse Renewables”), with energy market revenues projected between $7.7 billion and $8.8 billion.
| Analysis Group
Scenarios with renewable additions would require additional revenue streams from outside the ISO-NE markets because they have a higher cost of new entry, the study says. Substantial expansion of clean resources as in Scenario 3 “would lower FCA prices, crowding out existing resources.”
“As the quantity of new clean resources added to the system increases, the cost (per MWh or MW) of supporting clean resources increases. The gap in revenue requirement (for new entry) needs to be filled by other sources because of decreases in revenues from both the FCM and energy markets.”
These impacts would depend on what portion of new renewables participate in the capacity auction and the extent of offer mitigation under the minimum offer price rule. The study assumes continuation of the current 200 MW/year renewable exemption, evaluating mitigation levels through sensitivity analyses.
Under four of the scenarios (1, 2, 5 and 6), the combination of energy, ancillary services and capacity revenue is sufficient to support the entry of new gas-fired combustion turbines. But market revenues are insufficient to incent the development of all other new resources assumed to enter the market in each scenario and none of the scenarios provides sufficient revenues for new combined cycle plants.
| Analysis Group
“Clean” resources — including offshore wind, hydro imports, battery storage and behind-the-meter solar, — would require other revenues, such as state renewable portfolio standards. “Needed revenues increase with the expansion of clean resources, as these resources reduce prices in both the energy and capacity markets,” the study says.
Total payments in the ISO-NE markets range from $9.7 billion to $15.6 billion, excluding ancillary service payments. The total payments do not include the costs associated with state policies.
ISO-NE completed Phase I of the Economic Study earlier this year and in June will issue the final part.
Robert Ethier, vice president of market operations, outlined the scope of work and for background information referred participants to a study on Forward Capacity Auction results published in December 2016.
Six Resource Expansion Scenarios
The resource expansion scenarios were:
S1 = RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas combined cycle units.
S2 = ISO Queue: Physically meet RPS and replace generator retirements with new renewables and clean energy.
S3 = Renewables Plus: The region retires older generating units, physically meets all state RPS and adds renewables/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage.
S4 = No Retirements (beyond FCA 10): Meet RPS with new resources under development and use alternative compliance payments (ACPs) for shortfalls. Add natural gas units.
S5 = ACPs + Gas: Meet RPS with new resources under development and use ACPs. Replace all retirements with natural gas units.
S6 = RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV.
AUSTIN, Texas — ERCOT stakeholders last week unanimously endorsed Oncor and American Electric Power’s 345-kV Far West Texas Project that addresses continued load growth southwest of Odessa, Texas.
Since 2010, the area has seen annual load growth of about 8%, driven by increases in the region’s oil and natural gas production. While demand growth projections have tapered off recently — only 2.4% through 2020 — Oncor predicts annual load growths as high as 11% within portions of the area over the next five years. More than 1,600 MW of solar resources are expected to come online during that time frame.
| ERCOT
Oncor and AEP’s original request to ERCOT’s Regional Planning Group last April estimated the project’s price tag at $423 million.
However, a staff review of 40 different alternatives lowered the cost to $336 million after settling on the most cost-effective of four options: two separate double-circuit 345-kV lines — each with one circuit in place — substation expansions and other transmission elements. One 85-mile line would run between the Riverton and Moss switching stations, with a second circuit added to the existing 16-mile 345-kV line between Moss and the Odessa line. A second, 68-mile 345-kV line would run from the Solstice switching station to the Bakersfield switch station. ERCOT concluded the upgrades “meet the reliability criteria in the most cost-effective manner and have multiple expansion paths to accommodate future load growth.”
Two of the other options would have closed the 345-kV loop between the two lines, while a third would operate the transmission lines at 138 kV on double-circuit structures. The costs ranged between $446 million and $501 million.
“My only concern is it keeps a tight bandwidth on future growth,” Oncor’s Collin Martin said during Thursday’s Technical Advisory Committee meeting.
Staff admitted the loop could be completed but said its recommended option would provide the best reliability solution while “augment[ing] the load-serving capability … as the outlook for greater load and generation resources in this region becomes more certain.”
The project has been proposed to go in service by 2022. Oncor, AEP and the Lower Colorado River Authority would be responsible for the parts of the project within their service territories.
The project still needs approval from the ISO’s Board of Directors and a certificate of convenience and necessity from the Public Utility Commission of Texas.
Rayburn Country Integration
Staff also updated the TAC on the potential integration of the 20% of Rayburn Country Electric Cooperative load that sits in the Eastern Interconnection. The East Texas co-op is considering connecting the load — approximately 190 MW — to ERCOT as early as December 2019. The ISO already serves the other 80%.
A study has identified a least-cost option of $38 million, primarily for a new 345-kV substation, a 138-kV switching station and the expansion of several 138-kV lines.
Southern Cross HVDC Project
TAC Chair Adrienne Brandt, of San Antonio’s CPS Energy, asked the Reliability and Operations Subcommittee (ROS) to schedule a joint workshop with the Wholesale Market Subcommittee to resolve issues arising from the PUC’s final scoping order related to an HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeast markets.
“This will ensure everyone has transparency between what the other group is talking about and make sure there are no conflicts,” Brandt said.
The PUC has directed ERCOT to complete a number of tasks before it allows the city of Garland to energize an approved 38-mile, 345-kV line that would interconnect the Texas grid to the Southern Cross DC tie in Louisiana. The tasks identified in the commission’s final order include determining Southern Cross Transmission’s “appropriate” market participation classification, necessary transmission upgrades and cost allocations, and resolving price-formation issues (Docket 45624).
ERCOT’s effort to increase visibility into distributed energy resources will begin at the subcommittee level after the TAC declined to get into an in-depth discussion of the growing challenge posed by small generation sources.
Saying she did not want to have the discussion at the TAC “just yet,” Brandt proposed starting it at the ROS. She did not receive any pushback.
ERCOT has proposed a collaborative process involving transmission and distribution service providers (TDSPs), “in which the locations of large DERs or large clusters of small DERs are mapped to their appropriate modeled transmission loads.”
The ISO has published a white paper, in which it proposes working with TDSPs to develop “a standardized method of providing and collecting appropriate data for mapping current and future registered DER units” to their common information model (CIM) loads. Staff said they will also work with stakeholders to develop a process for DSPs in competitive choice regions and non-opt-in entities (NOIE) “to monitor the accumulation of clusters of unregistered (less than 1 MW) DER units connected to specific CIM loads.”
Based on annual reports filed at the PUC, staff estimates nearly 900 MW of distributed generation were interconnected as of Dec. 31, 2015, along with more than an estimated 200 MW deployed in NOIE territories. (The reports use the terms DG and DER interchangeably.) Staff has added 20 new registered DER since November, giving ERCOT a total of 99 registered DER as of May 1.
The ISO suggests working with the TDSPs to jointly develop thresholds for “accumulations” of DER, reporting those that exceed the threshold and mapping clusters that exceed the threshold to a CIM load.
ERCOT defines DER as generation, storage technology or a combination of the two that is interconnected at or below 60 kV and operates in parallel with the distribution system. DER does not currently include demand response.
Woody Rickerson, ERCOT’s vice president of grid planning and operations, told the TAC the white paper builds on the Distributed Resource Energy Ancillaries Market (DREAM) task force’s work, which ended last year. (See “DREAM Task Force’s Work Now Ready for Stakeholder Process,” ERCOT Tech Advisory Committee Briefs.)
He said staff wants to produce annual reports so the grid operator knows how many DER are in its footprint and “what makes sense with aggregation.” Staff will insert the resources into the network model as it maps them to their CIM load points, improving the control room’s situational awareness.
ERCOT Reports Software Issue, Schedules Meeting on Outages
COO Cheryl Mele alerted the TAC to a market notice reporting on a May 22 incident in which a vendor’s issue-tracking system briefly allowed its software clients to view tickets from any other client, including ERCOT. Upon being notified by a non-ERCOT market participant and stakeholder, the ISO asked the vendor to shut down access to the system.
In the market notice, the ISO said it has been told a forensics team “has not found any evidence to suggest that information from ERCOT’s tracking system has been viewed by other software clients.” It is also conducting an internal investigation to evaluate the types of information in the tracking system and to try and determine who accessed or could have accessed the ISO’s information.
Mele also told the committee the Texas grid operator will host a June 15 WebEx on extended 345-kV outages in Northwest Texas this summer. Electric Transmission Texas (ETT) notified ERCOT on May 19 it would be inspecting a number of transmission lines ETT built as part of the Competitive Renewable Energy Zone and, if necessary, replacing components as a part of a warranty claim.
The outages are expected to last through November 2018.
Revision Requests Pass Easily
Confronted with 19 revision requests, the TAC separated onto a consent agenda those requests that had reached the committee unopposed or had impact assessments of more than $10,000.
The only nodal protocol revision request (NPRR) to receive an opposing vote was NPRR831, which also received one abstention, relating to private-use networks — networks connected to the ERCOT grid that contain load that is typically netted with internal generation and not directly metered by ERCOT. The change updates market systems to calculate a net load value for each private-use network that will be included in the load zone price for all markets, when the load is a net consumer from the ERCOT grid.
The NPRR was given urgent status to address instances in which LMPs do not reflect congestion. Kenan Ögelman, ERCOT’s vice president of commercial operations, said from a system perspective, “This is the quickest way to do this accurately.”
The committee passed NPRR827, which bars the ISO from awarding point-to-point (PTP) obligations in the day-ahead market when the corresponding clearing price is greater than the bid price by 25 cents/MWh or more, passed with one abstention.
ERCOT’s Carrie Bivens, manager of forward markets, said there is a market-design problem in the way PTP obligations are currently cleared in the day-ahead market. “We’re contemplating a different design choice for a long-term solution,” she said.
The committee unanimously approved NPRR830, which has an impact assessment of $120,000 to $160,000 and revises the basis of ERCOT’s calculation of the four-coincident peak calculation (4-CP) to be consistent with NERC’s net-energy-for-load methodology. The proposed methodology uses metered net DC-tie flows.
Members approved editing the business case to say the NPRR will “avoid rebilling costs resulting from the assignment of the 4-CP to an incorrect interval” and that it is consistent with direction from the PUC.
A pair of revisions to the Planning Guide (PGRRs) sailed through individual votes without opposition, but PGRR058, which clarifies specific generation to be included in the guide, was sent back to the Protocol Revision Subcommittee.
PGRR056: Accounts for potential subsynchronous resonance (SSR) vulnerability in the transmission planning process, providing references and citations to the appropriate protocol sections related to SSR and removing its definition from the guides. SSR is a potentially harmful phenomenon involving coincident oscillation between two or more transmission elements or generation resources at frequencies lower than the ERCOT system’s normal operating frequency (60 Hz). The change aligns the Planning Guide with ERCOT comments to NPRR562, which was also approved. NPRR562 clarifies responsibilities for affected entities and creates new requirements for the identification, study, mitigation of and protection against SSR. The ERCOT system has become more vulnerable to SSR because of the introduction of series capacitors for voltage support. Without proper mitigation, SSR can quickly destroy resonating elements and/or resources and lead to cascading outages. The NPRR was first introduced four years ago.
PGRR057: Aligns the Planning Guides with NERC Standard TPL-007-1 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing geomagnetic disturbance vulnerability assessments.
The consent agenda included three additional NPRRs, three changes to the Retail Market Guide (RMGRR), a change to the Verifiable Cost Manual (VCMRR), and revisions to the Commercial Operations Market Guide, Load Profiling Guide, Nodal Operating Guide and the Resource Registration Glossary. The guide and glossary changes expand the list of revision requests requiring ERCOT board approval and would first consider those revisions at the voting subcommittee level.
NPRR796: Specifies that character set validations are available within each Texas standard electronic transaction (TX SET) implementation guide, which recognizes all characters within the basic character set.
NPRR820: Aligns the definition of an aggregate generation resource (AGR) with the Protocols, which allow a resource entity to register several generators as an AGR. Intermittent resources are not included.
NPRR824: Aligns Protocol language with NERC reliability standards for energy emergency alerts (EEA) and real power balancing control performance.
RMGRR145: Provides the format for transmission or distribution service providers, municipally owned utilities and cooperatives to use a mass customer list to inform market participants of all customers in its service territories when entering competition or expanding its service territory.
RMGRR146: Expands the list of RMGRRs requiring board approval and provides additional clarifications to the RMGRR process.
RMGRR147: Updates protocol language by providing the option of generating a standalone invoice for meter tampering charges when there is no change in usage consumption.
VCMRR018: Aligns the manual’s revision process with the Protocols and market guides by changing the length of the comment period for newly submitted VCMRRs from seven to 14 days; requires review of all VCMRR impact analyses by the Wholesale Market Subcommittee; aligns the process for submission and review of urgent VCMRRs with other revision-request types; expands the list of VCMRRs requiring board approval; and provides additional revisions to mirror the Protocols and market guides.
ANCHORAGE, Alaska — Organized electricity markets could provide significant benefits for the West, but state regulators should approach their development with a critical eye, market leaders said last week.
“There is value in markets, and as a result, I’d encourage you to get educated about the benefits of them, and seeing also how it may get to change how you regulate utilities,” SPP General Counsel Paul Suskie said during a panel discussion entitled “Energy Imbalance Market or the Wild West Interconnect” at the annual meeting of the Western Conference of Public Service Commissioners.
‘Healthy Skepticism’
“Have a healthy skepticism. That’s what I used to be required to do,” the former Arkansas Public Service Commission chairman added.
EIM Governing Body member Carl Linvill, formerly a Nevada commissioner, recounted how his career path has imbued him with a dose of skepticism about markets. A former economics professor, Linvill moved to Nevada two decades ago to help build a market monitoring framework for the state’s proposed retail deregulation. In the wake of the Western Energy Crisis of 2000-01, the governor handed him the responsibility for unwinding the experiment in restructuring.
“My interest in coming out to Nevada for the job was [that] I was little bit concerned about over-optimism in the markets,” Linvill said. “I like markets, I think markets can be very beneficial, but I think that you have to have the right … legal structure [and] context for markets to work well.”
Linvill noted that each of the Governing Body’s five members is an outsider to CAISO, which operates the market. Members value the expertise of the ISO, as well as its state-of-the art operations, he said.
“But, also, having been outsiders and knowing that we need to be critical, we also take it as part of our job to question and challenge [ISO] staff and to try to push them to understand the perspective [from] our former roles,” Linvill said.
Linvill described to the audience of mostly commissioners and their staff how the Governing Body maintains independence from the ISO and exercises oversight over the market.
After originally being selected by a stakeholder nominating committee and approved by the CAISO Board of Governors, the body now approves its own members. The body — not the board — exercises “primary authority” over any ISO initiatives that wouldn’t have arisen without the existence of the EIM, meaning it can vote to recommend an EIM-related proposal.
“The Board of Governors can accept or reject, but they cannot amend or alter the proposal,” Linvill said.
Suskie touted the benefits of SPP’s own energy imbalance market — the precursor to the RTO’s current market — which saved members $1.1 billion between 2008 and 2013, far exceeding projections of $600 million.
“The higher the gas prices, the better the benefits of trading,” Suskie said, pointing out that the greatest savings occurred during the market’s early years when natural gas prices exceeded $7/MMBtu.
SPP’s incorporation of the day-ahead market in 2014 yielded another $1 billion in benefits, Suskie said.
While comparatively modest, the Western EIM’s benefits have grown consistently with the addition of new participants. The market now encompasses more than 50% of the region’s load, according to Stacey Crowley, vice president of regional and federal affairs at CAISO.
Crowley said the EIM has saved nearly $174 million since its inception in November 2014, including $31 million in the last quarter — an all-time high. (See CAISO EIM Exports Rise with Spring, Report Shows.)
Other benefits include the reduced curtailment of renewable generation, which can be offloaded into neighboring balancing authority areas, and sharing, which has reduced the need for EIM participants to carry flexible ramping reserves.
“The benefits continue to accrue,” Crowley said. “It really comes down to more efficient dispatch. It’s both interregional and intraregional. So we optimize within the balancing authority and between balancing authorities to really take best advantage of the resources that the Western utilities have.”
Qualitative Benefits
Linvill highlighted the importance of the qualitative benefits issuing from the EIM’s approach to dispatch.
“I think that a side benefit of this is that there’s much greater visibility within the utilities and within the [EIM] footprint region on what’s actually going on and what resources are available, what their capabilities are, [and] what the transmission system capabilities are. I think there’s much better information about that now then there was” before the market, he said.
Those qualitative benefits were enough to swing Arizona’s Salt River Project to join the market after determining that membership would be a financial “wash” for the publicly owned utility, Linvill said.
“I asked them, ‘How important were the non-quantified benefits, these other benefits?’ And they said, ‘Those were the driving benefits. We see this as an essential step to modernize our operations now so we can keep up as things evolve,’” he said.
Linvill said he has respect for markets that work well but recognizes that they can go awry.
“So, job one is to protect these benefits that have been created, to take this step-by-step, to add entities to the footprint, to potentially add services at some point. But we’re not rushing to that or even discussing that at this point,” he said. “Really, we want to make sure that we establish a market that has stability and robustness and continues to produce these benefits.”
Patrick Lyons of the New Mexico Public Regulation Commission questioned Crowley about whether EIM participants face exit fees.
“There is no exit fee. Entities can choose not to participate by just not bidding in resources or they can leave altogether, so that’s a nice benefit as well,” Crowley responded.
“So if a company wants to get out, and you’re counting on them being in there, how does that work? It doesn’t seem very stable,” Lyons said.
“I think that the benefit is that we’re not counting on them,” Crowley said. “This is above-and-beyond optimization that we do normally every day, so we’re going to continue to balance the load and resources based on what resources are available to the market.”
LADWP is the 11th utility to announce plans to participate in the 
The Business Council for Sustainable Energy, which has been an observer at the United Nations Framework Convention on Climate Change for the past 25 years, was dismayed by the news. “Withdrawing from the Paris Agreement weakens the U.S. government’s ability to protect U.S. commercial interests in these discussions as well as in other important international negotiations,” President Lisa Jacobson said. “This international agreement is an opportunity to bolster American economic development, not a barrier to it.”
