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.
The shale gas revolution that has undercut the economics of coal and nuclear plants doesn’t appear to be ending anytime soon.
Economists Craig Roach and Vincent Musco say the revolution will continue, despite evidence that “there is a limit to how low natural gas prices can go and for how long low prices can persist.”
In producing their seventh annual looking-forward report for SPP’s Board of Directors, Bates White Economic Consulting’s Roach and Musco say low gas prices will continue “if and only if” technological improvements continue to delay the search for more hard-to-find gas reserves.
Roach said they see two risks to the continued shale gas revolution: underground and aboveground risk.
“The underground risk is whether the technology for shale gas production will continue to improve, so that even as the U.S. turns to more difficult reserves, the price will continue to fall,” Roach said in a presentation to the Board of Directors/Members Committee meeting last month. “That is happening. All new wells drilled last year are producing more gas on average than the wells drilled in previous years.”
In the report, Roach and Musco note “proven reserves reflect not only the physical abundance of natural gas reserves but also estimates of whether those reserves can be produced at prevailing market prices.”
The economists say data indicate a floor of roughly $3/MMBtu, based on a recent 16.6% decline in proven reserves. According to the U.S. Energy Information Administration, Henry Hub spot prices fell 42.4% in 2015, from $4.37/MMBtu to $2.62/MMBtu, and the agency predicted a further 6.1% decline in 2016. April’s spot prices were $3.10/MMBtu, up from $2.88/MMBtu the month before.
“The bet is that big-data analytics of the massive amount of data captured on actual gas and oil wells will be what sustains the technologic improvement needed to keep prices moderate,” Roach and Musco write.
Six states in SPP’s footprint — Arkansas, Kansas, North Dakota, New Mexico, Oklahoma and Texas — account for 46% of the country’s total natural gas proved reserves.
Low gas prices have led to an increased investment in combined cycle resources, which, along with subsidized renewable generation and flattened energy demand, has led to low market prices and the early retirement of baseload plants, the report says.
Concerns over Nuclear Generation’s Viability
“You have people saying this is the markets working. You also have people saying this isn’t the markets working, because prices are artificially low,” Musco said. “The markets aren’t capturing the full value of nuclear generation. They’re not capturing the full reliability value and the zero-emissions value of nuclear generation.”
| U.S. Department of Energy Quadrennial Energy Review; Bates White Economic Consulting
The report notes that reductions in nuclear capacity could increase carbon emissions, citing EIA data that 28% of all U.S. nuclear generation has recently retired or is at risk of retirement by 2030.
Nuclear generation has provided about 20% of the country’s energy each year and accounts for 60% of zero-emissions generation in the U.S. “Developers are turning almost exclusively to natural gas-fired combined cycle generation to replace retiring baseload capacity,” the report says, noting 100 GW of natural gas-fired combined cycle generation is under development. “However, it may also be argued that these retirements are part of the natural course of generation investments. As plants age, uneconomic plants give way for new, more efficient generation to take their place.”
That has already happened within SPP’s footprint. Last October, the Omaha Public Power District retired its 500-MW Fort Calhoun nuclear plant, saying it would save up to $994 million over the next 20 years. OPPD’s board blamed the retirement on low gas prices and load growth, among other factors. The plant’s operating license was good until 2033.
Fort Calhoun’s retirement leaves SPP with only two nuclear plants contributing to its generation mix: Nebraska Public Power District’s Cooper Nuclear Station (771.5 MW) and Kansas’ Wolf Creek (1,205 MW), which is owned by three separate companies.
Moody’s has reported that both plants “could face a ‘similar fate’” because they produce power at a cost that is often higher than SPP’s north pricing hub.
But Roach and Musco say they believe the plants won’t retire early, noting that Cooper and Wolf Creek have lower operations and maintenance costs than the smaller Fort Calhoun, their ownership has less available capacity to offset their loss and NPPD CEO Pat Pope expects a “‘capacity-short environment’ in SPP,” making the nuclear units a “good long-term strategy.”
The report notes efforts to address the problem through out-of-market payments in New York and Illinois, FERC’s Notice of Proposed Rulemaking on fast-start pricing, small modular reactors and other technological improvements.
It also warns of legal challenges to states considering “special action to ‘save’” baseload generation; the “direct impact” to SPP’s markets if FERC changes the way wholesale market prices are calculated and the threat posted to baseload generation as existing power purchase agreements expire.
Other Issues to Watch
The report also evaluates five other market and regulatory issues that could affect SPP’s markets or require the board’s special attention:
The changing utility model in the face of distributed energy resources and decentralization.
The U.S. Supreme Court’s ruling in cases involving PJM stakeholders and the states of New Jersey and Maryland, which held that the Federal Power Act “‘provides FERC with the authority to regulate wholesale market operators’ compensation of demand response bids,’” and other jurisdictional issues.
Lessons from the 2016 Electricity Policy Modernization Act, which died because of unresolved differences between the House and Senate versions but nonetheless raised legislative concerns over the “catastrophic consequences of long-term power outages.” Future legislation could include provisions on grid hardening and security and provisions related to markets and distributed energy resources, the report says.
The outcome of the Trump administration’s plan to undo the Obama administration’s Clean Power Plan. Because the Supreme Court has already ruled that EPA has the authority under the Clean Air Act to regulate carbon emissions, some observers say Trump can’t repeal the CPP without providing a replacement, such as a carbon tax.
Electric vehicles. Although EVs have not gained significant market share to date, the authors say the SHEAM model — shared, electric, autonomous mobility — can significantly reduce their payback period.
The report says while DER are not an “existential threat” to the grid, they are “likely to challenge generation-owning utilities in the production of electricity and could also emerge as alternatives to traditional grid investments.”
While the report was Roach and Musco’s seventh for SPP, it’s their first for Bates White Economic Consulting. The previous reports were done with Boston Pacific, which joined Bates White’s energy practice in November.
WILMINGTON, Del. — Mike Bryson, PJM’s vice president of operations, announced at last week’s Markets and Reliability Committee meeting that a scheduled vote on new pseudo-tie provisions would be postponed because of ongoing negotiations with MISO.
The proposal, developed through the Underperformance Risk Management Senior Task Force, would make deliverability requirements uniform for resources within and outside of PJM’s footprint and require feasibility studies for all pseudo-ties. Existing pseudo-ties would have five years to conform to the deliverability standards for internal resources.
Coal Replaced by Gas and Nuclear in 2020/21 BRA
PJM’s Jeff Bastian reviewed the Base Residual Auction results from May 23, noting that coal-fired generation cleared about 3,450 MW less than last year while gas and nuclear increased 3,700 MW and 1,500 MW, respectively.
“Here we see the reduced offerings of resources that might have a hard time because of their intermittency meeting the CP,” Bastian said.
Roy Shanker, an industry consultant, asked about negative megawatts of capacity transfer rights in the MAAC locational deliverability area, which cleared roughly $9.50 higher than the rest of the RTO at $86.04. The negative CTR megawatts mean there’s less load paying for the capacity in that region than there is capacity receiving the LDA’s price, Bastian said.
“[It’s] a function of that area’s share of the peak load forecast, which is a disconnect completely from the way the load is represented at the clearing of the auction, so you can have that kind of an outcome,” he said.
Exelon’s Jason Barker asked PJM to develop a written explanation of how CTRs were calculated to describe how negative megawatts can occur.
Bastian noted that the Duke Energy Ohio/Kentucky LDA, which cleared about $54 higher than the rest of the RTO at $130, was modeled individually “due to potential for deactivations in that area,” which might reduce the amount of power potentially deliverable to the LDA below the amount PJM feels is required for reliability.
“We find it prudent to model them from a reliability perspective,” he said, noting that it’s been done before in the PPL, BGE and ComEd LDAs. Of the three, only the ComEd LDA has ever separated from the rest of the RTO, he said.
American Electric Power’s Dana Horton asked how 119 MW of solar could clear as Capacity Performance, given that the sun usually isn’t shining during the morning and evening daily demand peaks in winter, when resources are most likely to be called. This auction was the first year in which all resource offers must comply with CP rules that require year-round availability and impose stricter nonperformance penalties if units fail to be available.
“The sun does shine in the winter,” Bastian said. “There was a recognition by the resource owners that there’s more risk involved with offering solar, so that the annual quantity is significantly lower than what those resources were required to offer in the past.”
Greg Carmean, the executive director of the Organization of PJM States Inc., asked if all nuclear units cleared, but Bastian declined to address the specific unit results. Barker confirmed for attendees that not all nuclear plants cleared, apparently referencing the company’s Three Mile Island, which the company announced earlier had not cleared for the second year in a row.
New Black Start Units Will Have New Annual Revenue Requirements
Stakeholders endorsed by acclamation changes to the annual revenue requirements for black start units. PJM and its Independent Market Monitor had previously come to an agreement on the time periods for member submission of data and review by the Monitor. They also agreed on having the revenue go into a non-interest-bearing account for each unit until its costs have been approved, at which point the RTO will conduct a true-up. (See “PJM to Review Black Start Prior to New RFP,” PJM Market Implementation Committee Briefs.)
The move comes as PJM prepares for its second request for proposals on black start units, which is scheduled for 2018 for projects to be available in 2020.
PJM Defends Interest in Paying for Frequency Response
Stakeholders endorsed by acclamation a problem statement and issue charge on analyzing generator requirements for primary frequency response, but not before renewing debate over compensation.
FERC issued a Notice of Proposed Rulemaking last November that would require primary frequency response for all new units except for nuclear plants. The NOPR did not address compensation. At previous meetings, the Delaware Public Service Commission’s John Farber has challenged PJM’s plan to investigate compensation and requested language be added to the problem statement and issue charge that allowed it only “if appropriate or necessary.”
“The intent is to ensure that it’s not a given that compensation is required,” Farber said on Thursday, responding to an inquiry from Public Service Electric and Gas’ Gary Greiner about why the text was added.
PJM staff reiterated the RTO’s desire to study whether units should be paid for maintaining primary frequency response capabilities.
“Back at the [Operating Committee meeting] in the fall, PJM made a statement about how we didn’t think compensation was necessary,” Bryson said. “We’re clearly more open minded about that now, and the wording of the issue charge is intended to imply that.”
Stakeholders eventually agreed on discussing potential compensation mechanisms and recommending compensation changes “if appropriate or necessary.”
FTRs to Get a Longer Perspective
Members endorsed by acclamation a proposed problem statement and issue charge to consider changes to long-term financial transmission rights modeling.
PJM’s Regional Transmission Expansion Plan looks out up to three years into the future in ordering upgrades, but approved projects aren’t captured in FTR analyses because they are only able to capture information on a six-month horizon.
“It is concerning to PJM that today, the current process is not capturing these upgrades. Because what this means to us is that they’re not fully transparent to the market participants,” PJM’s Asanga Perera said.
In the documents, PJM guaranteed that FTR-capability allocations would be made “without violating firm transmission customer priority rights.”
Other FTR changes developed in response to the FERC order impacting the annual revenue rights and FTR process also were endorsed during the meeting, though not without some modifications.
PJM requested endorsement for Manual 6 revisions, which prompted Mike Cocco of Old Dominion Electric Cooperative to request that the phrase “no longer viable” describing transmission paths be clarified.
Monitor Joe Bowring questioned PJM’s planned changes for the FTR forfeiture process.
“I would ask that you give it more thought,” he said.
Steve Lieberman of American Municipal Power followed Bowring’s comment with a motion to defer a vote on that language until next month. (The Monitor is not a member and could not make the motion on its own behalf.)
Stakeholders worked on the proposal, and PJM’s Brian Chmielewski returned later in the meeting to seek endorsement of the revised package. Per Bowring’s request, the forfeiture changes were removed, he said, and “no longer active” was substituted for “no longer viable,” along with a definition of the phrase that matched the definition in the Tariff.
Stakeholder Approvals
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 14D: Generator Operational Requirements. Revisions to develop requirements for solar generation facilities, in compliance with FERC Orders 828 (Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities), issued July 21, 2016, and Order 764 (Integration of Variable Energy Resources), issued June 22, 2012. (See FERC Issues Ride-Through Requirement for Small Generators.)
Manual 36: System Restoration. Revisions developed in response to a periodic review.
Manual 13: Emergency Operations. Attachment E updated with 2017/18 load forecast and Mid-Atlantic load shed allocation information; Attachment F updated with 2017/2018 load shed capabilities and allocation percentages. The data in the attachments affects only transmission owners and has been validated by them.
An updated charter for the Incremental Auction Senior Task Force, which was created in response to a problem statement by Direct Energy that was approved by the MRC in November 2016. The revisions reflect an increase in scope resulting from a problem statement by NRG Energy on replacement capacity that was approved in March 2017. The revisions set a target for completing work and making recommendations to the MRC by January 2018. (See “Stakeholders Approve Variety of Actions,” PJM Markets and Reliability and Members Committees Briefs.)
MISO’s Steering Committee recommended that all but one of a handful of the Independent Market Monitor’s oft-repeated recommendations be included on the 2018 Market Roadmap as potential market rule changes.
Most of the recommendations have already been brought up in Market Subcommittee meetings or are part of past State of the Market reports.
MISO’s 2016 stakeholder redesign process dictates that for issues to be discussed in stakeholder meetings or added to the Market Roadmap list, they must first be submitted to the Steering Committee for a committee assignment. The Market Roadmap is a prioritized and tracked list of market revision goals that stakeholders and the RTO agree to pursue in stakeholder meetings.
The Steering Committee made the decision to move the following recommendations forward during a May 24 conference call:
Establishing regional reserve requirements and cost allocation through expansion of a 30-minute reserve product. MISO stakeholder relations staff member Justin Stewart said the issue might be too similar to a project already on the Roadmap that will create short-term capacity reserves, so the Steering Committee added the Monitor’s recommendation to the existing project candidate.
Changing the day-ahead margin assurance payment and real-time offer revenue sufficiency guarantee (RSG) payment rules and performance incentives to reduce gaming. The Monitor last year suggested some wind generators were deliberately over-forecasting to collect more RSG payments; the issue is expected to surface in this year’s State of the Market report. (See IMM Report Highlights Outages, Wind Over-Forecasting.) Stewart said the issue was similar to an existing Roadmap project to tighten thresholds on uninstructed deviations from dispatch orders, which is currently in the software development phase. Steering Committee members nevertheless assigned the Monitor’s suggestion new candidate status.
Creating a method for validating wind suppliers’ forecasts and using the results to alter dispatch instructions if needed, and improving forecasting incentives by modifying deviation thresholds and settlement rules. The two wind recommendations were added to an existing Roadmap candidate covering dispatchable intermittent resource modifications.
The one recommendation not added to the Roadmap was that MISO consider the economic cost of congestion, not just reliability, before granting planned outages. We Energies’ Tony Jankowski said the issue has existed “for over 10 years.”
The Monitor’s suggested operating reserve demand curve in blue. | Potomac Economics
“You’re venturing down a road here of what’s acceptable congestion or excessive congestion. … I don’t see this as being a simple Roadmap item,” he said.
Other stakeholders agreed to table the issue, with some predicting the topic will be raised again in the next State of the Market report. Last month, MISO stakeholders took up a separate outage issue, debating whether resources on extended outages should be barred from participating in future Planning Resource Auctions. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)
The deadline for submitting candidates for consideration in the 2017 Market Roadmap project selection was May 11. Market improvements submitted after the deadline will be considered for prioritization in the 2018 Market Roadmap process.
ANCHORAGE, Alaska — State policies, market forces and technological advancements will continue the decarbonization of the electric industry regardless of the fate of EPA’s Clean Power Plan, current and former utility regulators said last week.
“I think the Clean Power Plan is pretty much dying,” Doug Little of the Arizona Corporation Commission said during a panel discussion on environmental policy in the “aftermath” of the CPP at the annual meeting of the Western Conference of Public Service Commissioners last week.
“It’s only a question of how it’s going to die. Right now it’s on life support. The question in my mind is, over the next several months, will the EPA pull the plug on the life support and see if it lives in any form, or will they drive a stake through its heart?”
Arizona on Path to Compliance
Little said what happens to the CPP under the Trump administration will make little difference to his state, which opposes implementation of the policy.
The final rule from EPA was “actually something that was achievable” and the state’s utilities “did a tremendous job” of incorporating the emissions targets in their integrated resource plans, Little said.
“And, they’re not, in my view, going to essentially take that whole planning process that they spent the last two years working on and just throw it away,” he said. “The direction that they’re going to continue to take is the direction that they’ve been planning to take over the last couple years.”
Tim Echols of the Georgia Public Service Commission echoed Little’s take.
“To continue with Doug’s analogy about the hospital, I really think the Clean Power Plan is going to die — [but] not from the stake. I think it’s going to die from a lack of payment on the hospital bill. And they’re going to have to unplug it because in the regulatory hospital, not everybody gets service regardless of the situation in the emergency room,” Echols said.
The “non-payment” is the Trump administration’s proposed 31% cut to the EPA budget, Echols said.
“I don’t know how they do corporal punishment in Alaska or Hawaii, but I think President Trump is taking the EPA out behind the woodshed, putting them in timeout, whatever you want to call it,” Echols said. “And you know what? That’s not unusual for a president to make those kind of decisions. Think about what President Obama did to the [Nuclear Regulatory Commission] and to Yucca Mountain when he got elected.”
Political, Practical Concerns in Georgia
Already speaking of the CPP in the past tense, Echols said that he had two problems with the plan, one political and the other practical.
The political issue: that the CPP would have turned the appointed head of Georgia’s Environmental Protection Division (EPD) into an “energy czar.”
“Now I’m not appointed by the governor, nor are my four colleagues, and this was going to put the EPD administrator essentially in charge of the energy plan for the state,” Echols said. He noted that Georgia’s rural electric cooperatives are nonprofits “that don’t take their orders from the EPD,” leaving the burden for compliance on the state’s major investor-owned utility, Georgia Power.
Echols’ practical concern: “How it picked winners and losers. The big winner, of course — natural gas.”
To comply with the rule, states would be forced to close coal-fired plants. That — along with the trend of nuclear plant closures — would leave the power sector exposed to increase gas prices in the future, Echols contended.
“Personally, I’m glad the EPA’s in timeout. I’m not saying I don’t like clean air. I’m not saying I don’t value clean water. But this agency went way too far, and the president is sending a message, and frankly I think it’s the right message.”
Robert Kenney, vice president of state regulatory relations at Pacific Gas and Electric, California’s largest utility, said he could grasp both sides of the CPP debate.
“California has been very explicitly, vocally and unabashedly supportive of the Clean Power Plan. PG&E in particular has been vocally supportive of the Clean Power Plan. And I think that’s probably not surprising when you think about California’s position relative to taking steps to combat climate change,” said Kenney, a former Missouri regulator.
PG&E is ahead of schedule in meeting California’s 33% by 2020 renewable portfolio standard. Including hydroelectric and nuclear, the company’s portfolio is already 70% greenhouse gas free, so “the Clean Power Plan wasn’t viewed as a barrier,” Kenney said.
“Now contrast that to my experience in Missouri, where 80% of our generation was coal-fired, and the Clean Power Plan presented significant challenges,” Kenney said. “Many of the utilities that I regulated were vocally opposed to the Clean Power Plan on a variety of different legal grounds and on practical economic grounds.”
Those utilities were faced with possibly having to strand coal-fired assets in which they had invested billions to comply with EPA’s Mercury and Air Toxics Standards. That, said Kenney, was “difficult to get your brain around” as a regulator.
“I think what you will see in the aftermath of the Clean Power Plan is that states will continue to individually determine how [they] are going to deal with climate change depending on the particular state,” Kenney said.
Low gas prices in Missouri are already leading to the retirement of some of those coal-fired plants, regardless of the CPP, a development Kenney expects to continue.
Lorraine Akiba of the Hawaii Public Utilities Commission noted that although her island state is exempted from the CPP, the state’s attorney general has weighed in to support the plan against court challenges. Hawaii has enacted the most ambitious RPS in the country — 100% by 2045.
She predicted there will be “big fights” in Congress over the CPP and the EPA budget.
“This is what democracy is about. You know, last time I looked, we’re not an oligarchy and not a dictatorship. That’s the beauty of democracy. You see four different commissioners up here, with four similar but different viewpoints,” Akiba said.
Market Forces
With or without the CPP, the panelists agreed, market forces will continue the drive away from coal and toward gas and renewables.
“What really is affecting the direction towards renewables — and the direction away from some of the fossil fuels like coal — is sub-$3 gas,” said Little, who also touted the fact that his state enjoys more than 300 days of sunshine a year, making it fertile ground for the continued expansion of utility-scale solar.
Still, Little said that he’s “very concerned” about what FERC and the wholesale markets will do to “more properly value” baseload resources such as coal and nuclear to ensure grid reliability.
“I’m going to be interested to see what happens after my friend Rob Powelson and Neil Chatterjee get onto FERC and see how they’re going to address this with some of the changes in the market,” Little said. (See related story, No Fireworks for FERC Nominees at Senate Hearing.)
Kenney said technological advances are key drivers of both the market forces and environmental policy leading to decarbonization. Included among those advances: the improvement in natural gas fracking techniques and advances in PV solar cell production that has dramatically reduced costs.
“We’ve got technological advances that are giving us the tools to” execute low-carbon policies, Kenney said.
Akiba said she agreed that market forces will help determine the future. “I disagree with some of my colleagues that coal is coming back. Coal’s never coming back. Coal’s not economically viable for this country,” she said.
The fight against climate change will continue outside D.C., Akiba argued.
“States are the leaders in this. Cities are the leaders. And I shout out to Atlanta, Ga.,” Akiba said, referring to Echols’ home state. “The City Council and mayor there just adopted a 100% renewable portfolio standard for their city.”
Akiba also encouraged the conference to consider the economic benefits of reducing GHG emissions, saying “the rest of the world is going to decarbonize regardless of the rhetoric coming out of Washington, D.C.”
“There are opportunities for economic growth in renewable energy technology, new developments in electrification of transportation [and] alternative transportation. If we let that opportunity go, China is right there.”
Proclaiming that he wanted to get in his “2 cents” as a former politician, panel moderator Norman Rokeberg of the Regulatory Commission of Alaska offered some sobering personal observations of climate change in his state.
“Alaska is an oil and gas state. It pays the freight up here,” Rokeberg said. “As a result, it’s been difficult to not favor the use of fossil fuels, particularly natural gas. We have 305 trillion cubic feet of natural gas stranded on our North Slope.”
He turned to his point.
“I do want to take this moment to make clear and declare that climate change and global warming is real, and you see the signs of it everywhere in this state.”
Rokeberg listed the evidence: the recorded warming of the Arctic, which is melting sea ice and increasing acidification of the ocean, affecting Alaska’s fisheries; melting permafrost undermining the foundations of the state’s roadways and infrastructure; and a changing habitat in which more plants and shrubs are growing in Arctic areas.
“I’m a gardener — a green-thumber — and I’ve lived in Alaska all my life,” Rokeberg said. “And in the last 25 years, I’ve seen the growing season extend as much as two to four weeks — that is to say from approximately four months to five months in a short period of time. That’s pretty extraordinary when you think about it.”
Rokeberg then took off his politician’s hat and replaced it with that of a regulator.
“It’s real, but make your own decisions about causation, or things like that,” he said. “We don’t need to get into that — not as regulators.”
WESTBOROUGH, Mass. — ISO-NE is working to adopt clustering methodology, already used by every other ISO/RTO in the country, to speed the development of new transmission capacity, particularly to help free wind power trapped in Maine.
Transmission bottlenecks that prevent Maine’s wind generation from reaching load centers in Massachusetts and Connecticut could be relieved by allowing large and small generators to pool their interconnection requests, Al McBride, director of system planning, told the Planning Advisory Committee on Wednesday.
Mars Hill Wind Farm in Maine
McBride presented a Maine Resource Integration Study that showed how generators in the western and northern parts of the state could combine their interconnection applications and thus share costs on required upgrades. The grid operator could also analyze the combined interconnection requests in the same system impact study (SIS).
Interconnection Queue Backlog
ISO-NE has experienced a persistent backlog of interconnection requests in Northern and Western Maine, where several thousand megawatts of proposed resources have requested interconnection. In March, the RTO said it would not issue a competitive solicitation for the proposed Keene Road market efficiency transmission upgrade because the cost would be greater than the production savings. (See ISO-NE Nixes Keene Road Tx Upgrade.)
The proposed clustering methodology comprises two phases. In the first phase, the RTO will identify the initial designs of cluster-enabling transmission upgrades (CETU) in the regional system planning process. In the second phase, the RTO will conduct the cluster SIS to study the interconnection of the individual projects, together with the identified CETU.
New England is going to be looking at applying the clustering methodology to both AC and HVDC solutions. One speaker expressed concern that having two options would mean neither would reach critical mass, saying, “Sounds like you could have two undersubscribed” solutions.
Driven by the Wind
Wind resources looking to be included in such a cluster will have to join the transmission interconnection queue by about August. The study proposes that transmission owners prepare cost estimates by the PAC meeting in June, after which ISO-NE will calculate cost allocations and issue a draft report for comment.
As is currently the case, none of the shared or individual interconnection transmission upgrade and facility costs will be incorporated into regional transmission rates.
| ISO-NE
In June 2015, the American Wind Energy Association petitioned FERC to initiate a rulemaking process to address “complex, time-consuming technical disputes” in the interconnection queue process that “undermine the ability of new generators to compete.”
In response, FERC last December issued a Notice of Proposed Rulemaking that would change the pro forma large generator interconnection rules to increase certainty and transparency for new resources (RM17-8). (See FERC Proposes Changes to Interconnection Rules.)
New Circuits
The Maine Resource Integration Study assesses new 345-kV AC transmission circuits that could connect to the areas with the largest number of interconnection requests. Evaluations include interconnecting with, or bypassing, existing lines and substations.
The New England Power Pool Participants Committee in February supported Tariff changes for the proposed interconnection clustering methodology. Two or more interconnection requests requiring common new transmission infrastructure would trigger the clustering methodology.
Participants in a cluster would be allocated a percentage of costs for shared upgrades and assume sole responsibility for facilities needed solely for their project.
WESTBOROUGH, Mass. — New England will have only enough natural gas capacity to supply about half of its gas-fired generation in winters 2025 and 2030 in most scenarios, according to an analysis presented to the ISO-NE Planning Advisory Committee on Thursday.
Mark Babula, ISO-NE system planning manager for resource adequacy, said the study showed the region will have sufficient pipeline and LNG capacity to supply all the gas generation with capacity obligations during the summer. But in the winter — when generators must defer to firm gas heating customers — the region won’t have sufficient capacity under most circumstances to run all the gas generation that could be economically dispatched.
“When we’re talking about dispatch, what we’re looking at from the natural gas system perspective is meeting the contractual requirements to the [local distribution companies],” said Michael Henderson, ISO-NE director of regional planning and coordination. “That then gives you some extra gas available that can potentially serve natural gas-fired generation. It’s just different looks at how much natural gas-fired generation can be brought on.”
The ISO-NE study considered six natural gas system topologies and six “resource expansion” scenarios to determine whether there is sufficient “spare” gas for electric generation after meeting all firm customers’ needs:
Installed Capacity: All gas-fired generation with capacity supply obligations — a summer focus that represents the upper band of gas consumption by the electric sector. Even under the minimum gas infrastructure case, there is enough spare gas to fuel all gas-fired generation in the summers of 2025 and 2030, but there is only enough spare gas in the winters to serve about half of the gas-fired installed capacity.
Dispatched Capacity: Gas-fired dispatched capacity requirements on the winter peak gas day, when only a portion of installed gas capacity is needed to serve electric demand.
Energy Generation: Whether there is enough gas to satisfy the maximum hourly electric energy production by gas-fired generation on the summer and winter peak gas-days. The analysis found sufficient gas for all summer generation needs. For winter 2025, however, there would be sufficient gas for only 6.8 to 9.6 GW of generation, representing 42 to 59% of the projected installed capacity. By winter 2030, the gas could run between 5.3 and 10.1 GW — as little as one-third of the installed capacity.
Only one of six resource expansion scenarios (“Renewables Plus”) meets the dispatched capacity and energy generation requirements for winters 2025 and 2030, even assuming the “maximum gas infrastructure” — reflecting pipeline expansions, increased peak shaving by LDC, and LNG from offshore and ENGIE’s Distrigas terminal in Everett, Mass.
“In the summertime, we’re good. There’s actually leftover gas: We could actually run another 12,000 to 15,000 MW, there’s so much excess pipe available,” Babula said. “When you get into those polar vortex sort of days, we often hear from generators that have just been called by the gas pipe to get back on their ratable take and shut off the valve.”
Babula pointed out that the analysis studied only winter and summer peak days. ISO-NE is also conducting a Fuel Security Analysis that will quantify the operational risks of insufficient fuel for the entire 90-day winter period. ISO-NE on May 22 published a summary of the analysis, which is expected to be completed this fall.
While the RTO’s analysis looks at the system’s maximum, short-term capability, the ISO-NE study will determine how often the system likely to be stressed during the winter under different scenarios.
LNG’s Role
LNG from Distrigas, the Canaport terminal in Saint John, New Brunswick, and offshore floating storage regasification units are critical for meeting the peak gas-day requirements of the electric sector, according to the study. Without these gas supply sources, approximately ~1.5 Bcfd (~214,300 MWh/d) would be taken out the market.
Management consultant Richard Levitan asked whether the floating storage wouldn’t better be classified as a commodity, considering how inflexible the arrival of LNG carriers can be. Babula said that in the past couple years there have been “ships at the buoy” on most peak gas days, so they included them in the study.
[EDITOR’S NOTE: An earlier version of this article mistakenly said the analysis was conducted by the New England Power Pool. It was conducted by ISO-NE.]
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.
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.”
