ISO New England
ISO New England
ISO New England Inc. is an independent, non-profit Regional Transmission Organization , serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.ISO-NE oversees the operation of New England's bulk electric power system and transmission lines, generated and transmitted by its member utilities, as well as Hydro-Québec, NB Power, the New York Power Authority and utilities in New York state, when the need arises. ISO-NE is responsible for reliably operating New England's 32,000 megawatts bulk electric power generation and transmission system. One of its major duties is to provide tariffs for the prices, terms, and conditions of the energy supply in New England.ISO New England helps protect the health of New England's economy and the well-being of its people by ensuring the constant availability of electricity, today and for future generations. ISO New England meets this obligation in three ways: by ensuring the day-to-day reliable operation of New England's bulk power generation and transmission system, by overseeing and ensuring the fair administration of the region's wholesale electricity markets, and by managing comprehensive, regional planning processes.Its Board of Directors and its over 500 employees have no financial interest or ties to any company doing business in the region's wholesale electricity marketplace.ISO-NE was created in 1997 by the Federal Energy Regulatory Commission, as a replacement for the New England Power Pool , which was created in 1971. Wikipedia.
News Article | May 15, 2017
WASHINGTON--(BUSINESS WIRE)--Wilkinson Barker Knauer, LLP is pleased to announce that former Federal Communications Commission (FCC) Commissioner Kathleen Abernathy is returning home to Wilkinson Barker Knauer. Ms. Abernathy’s unmatched combination of top-level government and corporate experience makes her uniquely suited to counsel WBK’s clients throughout the media, communications, energy, and technology sectors. Ms. Abernathy will provide strategic guidance on business, legal, and policy issues, navigating the firm’s clients through a fast-changing regulatory environment, both domestically and around the world. Ms. Abernathy recently retired from Frontier Communications, where she first joined the company as an independent Board member and then moved into the role of Chief Legal Officer and Executive Vice President, External Affairs as the company pursued major strategic acquisitions. At retirement she was EVP, External Affairs, overseeing all state, federal and external relationships. During her time at Frontier, she guided the company through the regulatory aspects of three major acquisitions of properties from AT&T and Verizon, and was also a key player in the company’s advocacy at the FCC, including recent opposition to the Commission’s business data services (BDS) proposal. Ms. Abernathy also sits on the board of ISO New England, a regional energy transmission organization authorized by the Federal Energy Regulatory Commission (FERC) to ensure the constant availability of competitively-priced wholesale electricity. Nominated by President George W. Bush and unanimously confirmed by the Senate, Ms. Abernathy served as FCC Commissioner from May 2001 until December 2005. As part of the Republican majority during her time as a Commissioner, she advocated for a light regulatory touch as she helped craft policies for broadcast television, cable, satellite, domestic and international telecommunications, wireless telephony, consumer protection and education, and general enforcement of Commission rules. She also chaired the Federal-State Joint Board on Universal Service and participated in international bilateral and multilateral negotiations, including the 2002 ITU Plenipotentiary Conference and the 2003 ITU World Radiocommunications Conference. In 2004 she was selected by the ITU to Chair the Global Symposium for Regulators. Ms. Abernathy was a partner at WBK both before and after her time at the agency. Earlier in her career, Ms. Abernathy worked in a variety of private and public sector roles, including advising prior Commissioner Sherrie P. Marshall and Chairman James H. Quello, working for several telecommunications companies, and serving as an adjunct professor at both Georgetown University Law Center and Catholic University’s Columbus School of Law. Ms. Abernathy is an active member and former President of the Federal Communications Bar Association. She is a graduate of Catholic University’s Columbus School of Law and of Marquette University. Bryan Tramont, Managing Partner of Wilkinson Barker Knauer, said, “Kathleen’s unmatched experience fighting for more limited, thoughtful regulation makes her the perfect catalyst for developing relationships with clients who face federal and state regulatory issues in communications, media, and energy. At a personal level, Kathleen has been a mentor, boss and friend for many years. I am excited to team up again—as they say, the third time’s the charm!” Ms. Abernathy added, “The fun, positive culture and exciting, growing practice areas at WBK consistently pull me back. I have known these people for many years and very much look forward to returning to my WBK team.” Wilkinson Barker Knauer, LLP, one of the largest law firms in the nation dedicated primarily to the practice of communications and energy law, is ranked as a “first tier” firm by Chambers USA (Telecom, Broadcast, and Satellite: Regulatory), and Legal 500 (Telecoms and broadcast: regulatory), and was twice named “Law Firm of the Year” in communications law by U.S. News - Best Lawyers (2012 & 2014). The firm, with offices in Washington, D.C. and Denver, Colorado, advises clients ranging from global Fortune 100 companies to small start-ups in regulatory, transactional, privacy/cybersecurity, consumer protection, intellectual property, corporate and litigation matters involving all aspects of communications and energy law, at both the state and federal levels. Ms. Abernathy will be resident in the firm’s Washington, D.C. office and can be reached at 202-383-3399 and at email@example.com. Additional information about Ms. Abernathy can be found at http://www.wbklaw.com/Our_Team/Kathleen_Abernathy.
News Article | April 26, 2017
HOLYOKE, Mass.--(BUSINESS WIRE)--New England is expected to have the resources needed to meet consumer demand for electricity this summer, according to ISO New England Inc., the operator of the region’s bulk power system and wholesale electricity markets. Tight supply margins could develop if forecasted peak system conditions occur. If this happens, ISO New England will take steps to manage New England’s electricity supply and demand in real time and maintain power system reliability. ISO New England prepares short-term forecasts for summer and winter seasons, taking into account estimated amounts for all resources, including those with and without an obligation through the capacity market to supply electricity; unplanned resource outages; imports from neighboring regions; resource retirements; and any delays in the commissioning of new resources. These estimates help inform ISO New England’s planning on how to operate the grid during the upcoming peak season. Because up to 700 megawatts (MW) of expected new resources are delayed and may not be available this summer, forecast estimates indicate the possibility of a tighter-than-expected margin of supply and reserves. “ISO New England system operators strive to manage the region’s power system reliably despite multiple uncertainties and unexpected challenges,” said Vamsi Chadalavada, executive vice president and chief operating officer of ISO New England. “The ISO is prepared for the possibility of tight supply conditions this summer. Our system operators will take the appropriate steps to maintain reliability if consumer demand outpaces supply.” If these peak summer conditions happen and there is a supply deficit, ISO New England could obtain additional electricity supplies from neighboring regions and implement operating procedures that help keep the grid in balance during such deficiencies. This summer, under normal weather of about 90 degrees Fahrenheit (°F), electricity demand is forecasted to peak at 26,482 MW. Extreme summer weather, such as an extended heat wave of about 94°F, could push demand up to 28,865 MW. These forecasts incorporate the demand-reducing effects of energy-efficiency (EE) measures acquired through the Forward Capacity Market and behind-the-meter photovoltaic (BTM PV) installations. Approximately 2,000 MW (nameplate capacity) of behind-the-meter solar facilities are currently installed throughout New England. New England employs a variety of resources to meet consumer demand for power: generators that produce electricity, such as natural gas, nuclear, oil, coal, hydro, biomass, and wind; demand-response resources that can be activated to reduce their energy use; and power imported into New England from New York and Canada. On May 31, Brayton Point station, a 1,500 MW coal and oil power station located in Massachusetts, will retire; this amount was factored into the forecast estimates. This summer, New England has approximately 29,400 MW of total capacity available. Last summer, demand for power peaked on August 12, 2016, at 25,466 MW. The all-time record for peak demand was set on August 2, 2006, when demand reached 28,130 MW after a prolonged heat wave. Consumer demand for electricity is highest in New England during the summer because of air conditioning use. ISO New England has well-established operating procedures to maintain grid reliability in the event of an unexpected power plant or transmission line outage, an extended heat wave that results in increased consumer demand, fuel supply issues that affect the amount of electric generation available, or a combination of these factors. These procedures include calling on demand-response resources to curtail their energy use, importing emergency power from neighboring regions, utilizing the reserve margin, and asking businesses and residents to voluntarily conserve energy. Created in 1997, ISO New England is the independent, not-for-profit corporation responsible for the reliable operation of New England's electric power generation and transmission system, overseeing and ensuring the fair administration of the region's wholesale electricity markets, and managing comprehensive regional electric power planning.
News Article | February 15, 2017
The Bay State could soon follow the Bay Area as a leading battery boomtown. The Massachusetts Department of Energy Resources (DOER) decided, at the close of 2016, that it would set an energy storage target. Now it has six months to figure out what that number should be and how to implement it, following the timeline set by legislation last summer. Once complete, this will be only the third state-level target after California and Oregon. California's mandate gave it a decisive lead in attracting storage companies and deploying the technology in homes, businesses and on the grid. Massachusetts currently has very little storage deployed, but it is already home to a cluster of storage startups that spun off from research at MIT. With an effective target, Massachusetts could set itself up as the second hub of the U.S. storage industry, while streamlining the operation of its grid and the integration of new renewable generation. Finding the right target, though, requires a careful balancing of competing goals. "DOER should assure the target is large enough that substantial, relevant experience is gained by all, but not so large that it becomes unworkable and a substitute for the fully functioning market," wrote Phil Giudice, CEO and president of Cambridge-based storage company Ambri, in a letter to DOER Commissioner Judith Judson in December. DOER isn't starting from scratch here. The department had a hand in the State of Charge report from September, which comprehensively analyzed the value of storage for the Massachusetts grid and concluded that up to 1,766 megawatts of storage installed by 2020 would maximize savings for ratepayers. Storage can reduce the state's system costs like peak capacity, transmission and distribution upgrades, overall energy prices, integration of intermittent renewables, and ancillary grid services that smooth out the momentary differences between supply and demand. The authors included a humbler proposal -- namely, that 600 megawatts would be achievable given current market and regulatory realities, and still save ratepayers $800 million by 2025. The state could go in a different direction after gathering stakeholder input this month. Questions remain about how exactly the target would be implemented, which will have a significant impact on what kind of real-world changes it drives. Given the uncertainty, GTM reached out to policy experts and storage industry professionals active in Massachusetts to hear what they hope the state decides. Based on current market design and state rules, 600 megawatts is a reasonable target, said State of Charge coauthor Jacqueline DeRosa, vice president of emerging technologies at Customized Energy Solutions. "The 1,766 megawatt number makes some assumptions that the world is a certain way," she said. It's more of a best-case scenario, if storage deployment could proceed optimally without bureaucratic or regulatory obstacles. But, she added, "It’s not that easy to change the world overnight." The 600 MW goal reflects the deployments the state could likely achieve in the near future. It was the outcome of collaborative discussions held by DOER with stakeholders like utilities, project developers and storage vendors. A common refrain among energy storage professionals interviewed for this story was that a higher number would be great, but 600 megawatts is a strong starting point. It would be a big step up from the approximately 2 megawatts of advanced storage capacity the state has now. With two and a half years from the adoption of the targets to their due date, the state may opt for a less ambitious number initially. It would be possible to hit 600 megawatts in that timeframe, though, said Ravi Manghani, energy storage director at GTM Research. For others, like Ted Ko, director of policy at commercial storage company Stem, 600 megawatts is the minimum for attracting a bustling industry. "The state can and should go higher -- the industry has shown time and again that it is ready to respond quickly, at scale, when given a big enough market signal," he wrote in an email Wednesday. The energy storage industry is still young enough that just saying the words "storage mandate" gets folks fired up. The fact of the matter is, though, the number itself doesn't mean very much in terms of what the deployment will look like. The category of energy storage includes systems that operate on a matter of minutes, or for half an hour, or a couple hours, or very many hours. Different jobs require different durations. "My biggest wish is that the storage be discussed in terms of its application, and therefore the type of technology that is best suited to meet that application," said Jonathan Milley, director of business development at Massachusetts-based battery maker Vionx. "If you need a hammer, don’t get a screwdriver." Vionx is scaling its flow battery technology, and has one system operating in Massachusetts, one being commissioned and one under construction. Those three will add up to more than 1 megawatt of capacity at 6 hours duration. It's not surprising to hear a long-duration battery maker recommending a carve-out for long-duration batteries. Without that, cheap, short-duration lithium-ion batteries could swarm the mandate. Similarly, Ambri, which is commercializing a new liquid metal battery technology, recommended that part of the procurement target go to demonstrations of emerging technologies. Company interests aside, there's a strong argument to be made for connecting the storage mandate to particular services on the grid. The State of Charge report found the most lucrative savings from storage come from using it for peak capacity, which defers expensive gas peaker plant construction and lowers prices in capacity markets. If the state decides to prioritize storage taking over the role of peaking plants to save ratepayers lots of money, it could create a mandate with a certain percentage of capacity dedicated to longer-duration storage for peaking capacity. Conversely, if the state wants to ensure that storage can meet certain ancillary service needs in the near future, it could set a target for short duration batteries. DOER asked stakeholders to comment not just on the scale of the target, but the structure, so targeted goals such as these could end up in the final decision. Further guidance could also address whether the storage goes in front of the meter, putting it in the realm of utilities, or behind the meter, under the purview of commercial and residential customers. Ko suggested one-third of the target should be set aside for behind the meter storage, to take advantage of private investment to spur deployment. California set a precedent in this regard, as it required its three investor-owned utilities to procure storage at the transmission, distribution and customer levels. Who controls the storage asset says a lot about what it will look like, so some stakeholders are pushing for the target to address this as well. If the target expects utilities to shoulder most of the burden, they could push for a lower target, because they've have to do all the work. Opening up ownership to a wider range of entities spreads out the responsibility, and diversifies the potential benefits. Ko proposed that a minimum of 50 percent of storage installations should be for customer or third-party-owned systems. That would carve out some territory for Stem, which owns and operates storage systems on behalf of commercial customers, but it would create opportunities for other companies too. "A primary purpose of any storage mandate is to enable all stakeholders to learn from a wide range of business models and see where the market wants to use and evolve the services," he said. "Last year’s energy bill gave the utilities permission to own storage, so if a minimum isn’t set, the mandate could be met with a handful of large projects used in a utility-owned business model." If DOER chooses to prioritize storage as driver of business learning, it could even consider a carve-out for storage designed or built in-state, although out-of-state battery companies would have something to say about that. Massachusetts benefits from the chance to watch a storage mandate unfold in California over the last couple years. "California has absolutely led, they broke open the market, they really put a shock to the utility system and said the world is going to be different," said Matt Roberts, executive director of the Energy Storage Association. One highlight: launching a mandatory storage deployment did not explode the grid. The utilities are chugging along toward the 1.3-gigawatt goal and do not appear to be suffering from overexertion. In the meantime, the policy nourished a once-tiny industry and turned it into a considerably larger one. The grid benefited too. When the enormous natural-gas leak transpired at Aliso Canyon, the Southern Calif. utilities fast-tracked storage deployment to keep meeting local capacity needs in the absence of all that fossil fuel. The storage industry, buoyed by previous deployments, responded with cheaper-than-ever bids and rapid deployment. That said, Massachusetts has differed from California in its approach to forming the policy. The eastern state has prioritized stakeholder buy-in throughout the process as a means to collaboratively form the target. "In California, it was a little more of a top-down, 'Go procure this stuff' type of approach," Roberts said. "Massachusetts is a little more bottom-up, a little more, 'Let's get together and everyone show their math.'" If a utility wants a certain target, it has to explain why. Meanwhile, storage companies have a chance to justify their dream targets. The final product will be some kind of synthesis of many voices. California's mandate benefited from a strong collaboration between the California Public Utilities Commission and grid operator CAISO, which allowed storage to play more of a role at the wholesale market level. That kind of working relationship isn't guaranteed between Massachusetts and ISO New England, Manghani noted. "California had the luxury of an ISO that has jurisdiction in a single state," he said. "ISO New England has to work across multiple New England states. That could cause some friction. Without the successful and wholehearted participation of ISO New England, the mandate would lose some of its effectiveness." There are plenty of rules and policies under Massachusetts' control on which the state can act quickly, like adding storage as a qualified technology under the Alternative Portfolio Standard. To unlock the full potential value of storage, though, the ISO would need to change certain rules governing the wholesale electricity markets for energy, capacity and ancillary services. In a world with a more developed storage industry, Massachusetts has more options to choose from in crafting a target that best serves its own goals and desires. The choices made there in the coming months will model a path forward for the next state to take this plunge.
News Article | February 28, 2017
For Exelon CEO Chris Crane, there’s never been a more dynamic or uncertain period in his career than right now -- particularly when it comes to the future of the nation’s nuclear power fleet. “When you look at the potential risk on one of the more reliable, baseload generating assets, nuclear assets, there are significant challenges with current market design,” said Crane, speaking earlier this month at the National Association of Regulatory Utility Commissioners’ (NARUC) winter meeting. The closure of Exelon’s Fort Calhoun Nuclear Generating Station near Omaha, Nebraska last fall marks the fifth nuclear retirement over the past five years. Economic pressures are expected to trigger a wave of additional nuclear plant retirements across the U.S. in the years to come. The Nuclear Energy Institute has reportedly identified 15 to 20 reactors nationwide that are currently at risk of shuttering. Exelon is the largest nuclear power plant operator in the country, with 23 reactors at 14 facilities located in Illinois, Maryland, Nebraska, New Jersey, New York and Pennsylvania. Several of these plants are now on the brink of retirement as a result of market pressures -- and Exelon is losing money. The investor-owned utility saw its profits slide by 34 percent last quarter. Nuclear power was once a highly profitable business to be in, but the advent of cheap natural gas, combined with increasingly competitive prices for renewable energy projects, is making it more difficult for nuclear to compete. This is especially true in deregulated electricity markets like Illinois, New York and Ohio, where half of all U.S. nuclear reactors are currently located. But things could change under President Trump. With a new U.S. energy policy taking shape and new set of commissioners headed to the Federal Energy Regulatory Commission (FERC), nuclear plants could soon see more favorable treatment for the low-carbon and reliable power they produce. “States and locations we serve want affordable and reliable, but also clean, power,” said Crane. “And how you create a market signal around that to adequately compensate all generators within the stack is very important.” “Hopefully, with some clarity coming from this administration and some clarity coming from FERC, the states and [regional transmission organizations] can do what they need to do to design a reliable and affordable and, where they want it, a clean [resource] stack,” he said. There’s reason to believe nuclear generators could catch a break under President Trump -- although he hasn’t explicitly called for supporting nuclear power since getting elected. Trump has called for expanding U.S. nuclear weapons capability, though, which could produce side benefits for the nuclear power sector. If the new administration boosts the Department of Energy’s nuclear budget, nuclear power could see more support for research and development, and potentially more support for power plants through loan guarantees. In 2014, the Obama administration issued $6.5 billion in loan guarantees for two new nuclear reactors at the Alvin W. Vogtle Electric Generating Plant in Georgia -- the first government-issued loans for nuclear reactors in 30 years. The loan guarantees for Vogtle ultimately totaled $8.3 billion. At one point, the DOE planned to issue around $50 billion in loans for nuclear power (at present there's $12.5 billion available for nuclear projects), but backed off amid concerns around safety, delays and cost overruns (which continue to plague the industry). Trump, looking to increase jobs in traditional energy sectors, could reboot those DOE plans. A leaked questionnaire submitted by Trump’s team to the Department of Energy hinted at greater interest in nuclear power, with questions about how to reduce the bureaucratic burden on exporting U.S. nuclear energy technology and about resuming the Yucca Mountain nuclear waste proceedings. Furthermore, according to Bloomberg, the transition team contacted the DOE about finding ways to help keep nuclear power plants up and running. The nuclear power industry can also pin its hopes on favorable comments Trump made following Japan's Fukushima Daiichi disaster in 2011. "I'm in favor of nuclear energy, very strongly in favor of nuclear energy," Trump said in an appearance on Fox News. "If a plane goes down, people keep flying. If you get into an auto crash, people keep driving." Uranium stock prices shot up after the election due in part to these comments. There are also plenty of other political stakeholders that support the nuclear industry. Several lawmakers, including Oklahoma Republican Sen. Jim Inhofe and Rhode Island Democrat Sen. Sheldon Whitehouse have addressed the importance of nuclear power. Speaking on a nuclear energy panel at the NARUC winter meeting, Andrew Zach, staff member on the House Energy and Commerce Committee, said: “I think it’s time for us to reassert our leadership in this space.” Then there’s FERC, a national body that oversees U.S. electricity markets. There are several pending complaints at FERC against the zero-emission credit programs adopted in New York and Illinois to prevent their nuclear plants from shuttering, but the five-member FERC panel has been stalled since the resignation of Norman Bay on February 3. Trump will soon appoint three new commissioners who may take a pro-nuclear view. FERC Chairman Cheryl LaFleur, who was appointed to the position by Trump last month, announced at the NARUC winter meeting that commission staff would lead a technical conference on how wholesale markets can accommodate state-led initiatives to support particular generation resources (i.e., nuclear), while waiting for FERC to regain a quorum. “While we can’t issue orders in those [complaint] cases, one thing that [Commissioner Colette Honorable] and I have talked about that we can do is to organize a staff-led technical conference to bring people in before us, build a record and hear from the states, from the environmental community, from others -- from the generators and the [independent system operators] -- to try to discuss some of those issues,” said LaFleur, during a keynote discussion. “So that’s something we are going to do.” “Having that discussion about fuel diversity…is really probably first and foremost on your agenda,” said NARUC President and Pennsylvania Public Utility Commissioner Robert Powelson. “Yes,” said LaFleur, who went on to state that adapting wholesale markets to recognize the benefits nuclear power provides “is by far the best solution.” The search for wholesale market solutions at FERC comes after several years of energy policy debates closely tied to the success of renewables. State renewable portfolio standards -- which mandate increased production of energy from renewable sources, such as wind, solar, biomass, and geothermal -- have become one of the biggest targets for nuclear stakeholders. “Right now we definitely see a considerable issue in a lot of states that are in regions that use competitive markets to price resources, but also have state initiatives to select certain resources,” said LaFleur, in an interview. “And now we’re seeing the market designers try to accommodate that.” The availability of cheap natural gas has fundamentally reshaped the U.S. energy landscape, and put intense economic pressure on aging nuclear power plants. And yet nuclear generators haven’t framed their enemy as gas, but rather as other low-carbon resources. One likely reason is that energy companies like Exelon own both nuclear and gas assets. Another is that “there’s so much gas available these days that it’s hard to envision a regulatory change that leads to higher gas prices,” said Prajit Ghosh, head of Americas power and renewables research for Wood Mackenzie. “So the only other way to mitigate some of the impacts on nuclear is to mitigate renewables.” It’s “clean-energy cannibalism,” he said. More wind and solar is wanted to clean up the grid, but it’s adding pressure to existing nuclear plants. “In many of our states, there is a desire for environmental benefits from generation assets. To this point it has been looked at as renewables,” said Exelon’s Crane. “Renewables are an important part of the stack, and they should continue to be an important part of the stack…but we need to look at defining outcomes. If the outcome is higher reliability and a diverse fuel stack, how do you create a market design that compensates for that?” He added: “If the desire is an environmental outcome, then how do you design the market for that outcome versus the technology?” Crane and other speakers at the NARUC meeting described the favorable treatment wind and solar receive through state renewable portfolio standards, as well as federal tax credits and the Public Utility Regulatory Policies Act (PURPA), as flawed and in need of reform. In some states, nuclear generators have declared war. In Illinois, Exelon-owned Commonwealth Edison fought against the state’s 25 percent renewable portfolio standard, while seeking guaranteed income for its struggling nuclear plants. The utility also sought to end net energy metering and implement mandatory demand charges, both of which make distributed solar projects less attractive. Distributed solar is a challenge for utilities like ComEd because it reduces overall electricity demand, lessening the need to build big, new centralized power plants. Similarly, while seeking guaranteed rates for its nuclear and coal power plants in Ohio, FirstEnergy joined with conservative political groups to lobby against the state’s renewable energy and efficiency mandates. Republican Governor John Kasich ultimately vetoed an attempt to maintain a freeze on the state’s clean energy goals -- reinstating more stringent clean energy targets for FirstEnergy to meet. “Renewable power has mandates, which means in electricity land that they dispatch first, whether they’re economic or not,” said lobbyist Mike McKenna of MWR Strategies, who helped lead Trump’s DOE transition team. Wind and solar will become less competitive as federal tax credits ratchet down, he said, “but the mandates will remain in place.” “So you’re going to have a situation where you have a renewable mandate but not a nuclear mandate,” he said. “You could have a carbon-free mandate -- then they’d all dispatch at the same time.” Because nuclear reactors can’t easily ramp power up and down, there are times when renewable generation surges and wholesale prices drop so low that nuclear generators have to pay the grid operator to stay on, explained Ghosh. In 2015, there were 125 hours when wholesale market prices in ComEd territory were negative and 365 hours when prices were at or below $10, he said. These losses are exacerbated by the fact that aging nuclear plants are becoming more costly to maintain. Exelon and other pro-nuclear stakeholders have argued that federal tax credits combined with state renewable mandates are distorting electricity markets in the Midwest, where wind power is growing rapidly. The American Wind Energy Association has pushed back, arguing that these concerns are overblown. To fix the market distortions it sees, Exelon has advocated for regional grid operators PJM Interconnection and Midcontinent Independent System Operator (MISO) to offer capacity payments that reward reliable baseload resources like nuclear. But those prices are volatile and have proven inadequate to meet the revenue shortfall, according to Ghosh. That has left nuclear power generators with the option to either retire their unprofitable nuclear facilities or seek a nuclear subsidy. In Ohio, where FirstEnergy opposed the state’s renewable portfolio standard, the utility sought guaranteed rates for its nuclear and coal plants, which found environmental and consumer groups oddly aligned with big fossil-fuel power producers in opposing what they considered a bailout. FirstEnergy was ultimately approved last fall to charge customers an additional $204 million per year over three years to keep its plants in operation. But CEO Chuck Jones says that amount is not enough, and is pushing for more funds and re-regulation of Ohio’s competitive energy market. In Illinois, lawmakers struck a deal in December to keep the renewable policies in place, and pay out $235 million a year for 10 years to keep Exelon’s struggling Clinton and Quad Cities nuclear plants in operation through a zero emissions credit (ZEC) program. The New York Public Service Commission also recently approved a ZEC program for Exelon-owned nuclear plants in the state. Nuclear advocates are urging more states to amend their renewable portfolio standards to reward all zero-emission resources, including nuclear. But the ZEC model is not a seamless solution. “It’s a start,” said Crane, “But it doesn’t fix the market issues, and you have to continue to kick ball to the next state to have the conversation.” The New York and Illinois ZEC programs are also under legal attack. Earlier this month, coal and natural gas power plant owners Calpine, Dynegy and NRG filed a lawsuit at a federal district court in Illinois against the director of the Illinois Power Agency, arguing the new credit system is a bailout for uneconomic assets that undermines the state’s open wholesale market. A group of ComEd customers have also filed a suit against the ZEC system, over concerns that it will force customers to pay higher rates. Two lawsuits were also filed last fall against nuclear subsidies in New York, and complaints have been filed with FERC that are currently pending review. FERC is where nuclear players are now paying extra close attention, and where Trump’s three newly appointed commissioners could play a key role in addressing the industry’s hardships. FERC will not only address complaints about ZEC credits, but could also help reshape wholesale electricity markets to account for the benefits of nuclear power in new ways. “A lot of the discussion right now is around some of the efforts at the state level to compensate nuclear for its carbon-free attributes, which is not something the markets were designed to price,” LaFleur told GTM. “We’ve seen some cases filed that I can’t comment on, but we’ll be thinking more about ways to adapt energy markets to reflect some of those stated issues, and nuclear is front and center in that discussion.” LaFleur noted that the reliability benefits nuclear provides are being compensated for in some regions, like through PJM’s capacity market and ISO New England’s pay-for-performance program. However, the environmental benefits of nuclear energy are not currently being priced in wholesale markets. On this front, LaFleur said ISO-NE’s carbon pricing proposals could offer a path forward. ISO-NE has held several stakeholder meetings to discuss various wholesale carbon pricing proposals, including a carbon-integrated, forward-capacity market; a forward clean energy market; a clean power plant solicitation proposal; and a forward-capacity market two-tiered pricing construct. The grid operator is also considering a carbon price, which Exelon is advocating for. The New England States Committee on Electricity, the organization representing the interests of the six New England governors, has expressed reservations about carbon pricing, according to law firm Akin Gump Strauss Hauer & Feld. But should the proposal make its way to FERC for approval, it could have support from Commissioner LaFleur, who stated at a December meeting that “Plan A is the region that creates some kind of comprehensive plan that recognizes the state environmental goals and the [role of] pricing in the wholesale market and files it at FERC.” Wood Mackenzie’s Ghosh noted that a carbon price is the best long-term solution for keeping nuclear plants alive, but that there’s no precedent for creating a market design that rewards environmental attributes in the U.S. The concept has bipartisan support, but it’s difficult to see the idea advancing in a Republican-controlled Congress or under a president intent on rolling back climate regulations. A recent report from S&P Global paints a grim picture for the future of nuclear power under Trump, with the likely repeal of the Clean Power Plan and a possible revival of coal assets. But pro-nuclear stakeholders remain hopeful. While the solution for struggling power plants may come in the form of a wholesale market carbon price, the nuclear industry’s federal lobbying is now focused on emphasizing nuclear power’s economic significance. The Nuclear Energy Institute trade group recently sent a letter to the Trump administration urging support through presidential action and the DOE, and for FERC to recognize existing reactors “for all the benefits they bring to the electric system.” When asked if he thought President Trump would revive the nuclear sector, DOE transition team lead McKenna said, “I hope so.” McKenna said he’s optimistic that Trump’s picks to lead FERC will allow for market adjustments that favor nuclear, “but until we get new FERC commissioners, we’re not going to have any idea.” This story was updated to reflect that the DOE issued a total of $8.3 billion in loan guarantees for the Vogtle nuclear power plant.
News Article | September 19, 2016
Electricity generators often claim that prices cannot fully reflect the value of the reliability they offer the market. Hence they insist they need separate capacity payments to justify investments. But according to Mike Hogan of the Regulatory Assistance Project (RAP), the current energy market design is fully able to reflect the value of reliability, even if it doesn’t always do so in practice. In a new report, he describes a smarter approach, one that can ensure reliability in a low-carbon power system at the lowest cost to consumers, without need for capacity markets. Energy markets are often said to suffer from a “missing money” problem, referring to the idea that for various reasons prices in the energy market do not fully reflect the value of investment in the resources needed to meet expectations for reliability. While the analysis behind these claims is often muddled, there can be legitimate concerns about the quality of implementation of markets and whether they are adequately remunerating needed investment. RAP’s new report, Hitting the Mark on Missing Money: How to ensure reliability at least cost to consumers, explores the topic in depth for a non-specialist audience, arriving at a set of recommendations for how electricity markets can meet expectations for reliability at least cost in the transition to a low-carbon power system. There are different pathways to a reliable power system, some more costly than others. Measures to address the missing money problem must address the entire objective—to ensure reliability at the lowest reasonable cost. Many of the remedies proposed to address missing money, in particular the various out-of-market “capacity remuneration mechanisms,” run the risk of creating a different problem, one borne principally by consumers: misallocated money, overcompensating some resources and undercompensating others. Misguided approaches to the missing money problem often originate in a flawed understanding of how energy prices are meant to be formed in the energy market and how they are expected to support needed investment. It is often claimed that energy prices reflect only the instantaneous demand for energy and are limited by the short-run production cost of the highest cost generation to clear the energy market. It is then argued that, since this is the case, some form of additional payment is needed to support investment in reliability, especially as the resource mix shifts to capital intensive, low-operating cost resources. There are big problems with this narrative. The power industry has always been capital intensive. Most highly capital intensive industries – e.g., airlines, real estate, and oil refining – operate on the basis of unit prices. And it’s missing some crucial pieces of how energy markets are meant to set prices. In every hour prices should reflect the fact that the demand for energy and the demand for balancing services compete for the same pool of system resources. Furthermore, in hours when supply margins are tight system operators take a sequence of actions with marginal costs well in excess of the short-run production cost of the last kWh to clear the energy market. Energy prices should reflect that as well. However, it is true that energy prices in many markets today are distorted by legacy practices that socialize or ignore the marginal costs of actions taken by system operators during periods of tight supply margins, and that fail to reflect the price system operators should charge in any given hour to release scarce reserves to meet increased demand for energy (See figure 1). For example, less flexible generators are often paid separately for the extra costs they incur to be available when needed rather than having to recover those costs through their market offers. When such factors are properly reflected, prices can rise to levels many times the short-run production cost of the last kWh to clear the energy market, reflecting the actual cost of reliable energy. This is how the energy market is meant to value the investment needed to meet consumer expectations for reliability, with or without renewables. Thus, as in any healthy commodity market, energy prices can support needed investment both directly and, as importantly, by exposing wholesale market participants to the risks associated with periods of supply shortage and supply surplus. Buyers exposed to risks of higher and more volatile prices should be expected to manage those risks by entering into forward-looking commercial arrangements with producers directly and indirectly, via bilateral contracts and traded hedging products. These arrangements provide long-term support for the investment needed to ensure reliability. As noted, in practice many energy markets currently fall short of this ideal, which is why judicious administrative and regulatory interventions can be appropriate. Electricity is an especially important commodity with its own particular characteristics. First is the difficulty in storing electricity at an affordable cost, which leads to the risk of price gouging by withholding production. Second is the historical tendency for electricity demand to be relatively “inelastic,” unresponsive to real-time conditions of either surplus or scarcity. To address these concerns, market operators have employed, among other measures, price caps and socialization of the costs of emergency measures. As a result, clearing prices in energy markets often fail to reflect the real cost of actions required to “keep the lights on” and the true value of uninterrupted service to end-use consumers. That value can be high—much higher for many services than is currently reflected in most markets during shortage periods—but it is not unlimited. System operators, operating in the background, act on behalf of consumers to position the resources necessary from one hour to the next to meet the demand for both energy and reliability. In doing so, they apply a standard, usually imposed by civil authorities, that balances the value of continuous service against the costs of ensuring it. The result is a cost that system operators charge, or should charge, to relinquish reserves when the demand for or the availability of energy pushes the system close to its limits. In this way the system operator, acting in effect as the buyer or seller of last resort, bridges the gap between the theoretical ideal for an electricity market and the current practical reality. As described below, extending this administrative role to an administrative remedy for restoring missing money to energy market prices represents an excellent option for addressing the problem. In addressing concerns about missing money it is important to ask what kind of capacity resources the proposed remedies are remunerating. As we move farther down the road to a decarbonized power system, one point on which there is nearly universal agreement is that the system will need to become more flexible both on the supply side and on the demand side. Remedies that fail to recognize this, especially remedies that reward capacity resources without regard to their operational capabilities, can lock in the legacy mix of resource capabilities and retard the transition to a more flexible system. Remedies that effectively exclude non-traditional resources, especially innovative new demand-side technologies, will overlook some of the most effective and cheapest alternatives for delivering the needed flexibility. Flexibility is different from capacity. The definition of a unit of firm or reliable capacity is well developed and will remain constant regardless of how the resource portfolio evolves. Flexibility defies clear definition. It may be an increase or a decrease in supply (or a decrease or increase in demand), over milliseconds or minutes or hours or days. The best sources for some kinds of flexibility are usually not the best sources for others. And the portfolio of flexibility valuable to the system will evolve continuously depending on which low-carbon pathway is chosen and how the technologies evolve. Fully formed energy prices are the clearest expression of what flexibility the system needs and what it’s worth. Measures that divert revenues from energy prices to out-of-market mechanisms degrade that functionality. It is difficult to envision an out-of-market remuneration mechanism capable of matching the effectiveness of fully formed energy prices in valuing investment in flexible capacity resources. We propose a response to the missing money problem that is effective, efficient, and durable. That response must begin with the setting of an economically rational standard for reliability and an independent process for determining what investment is actually needed, incorporating opportunities for energy efficiency and flexible demand. “Keeping the lights on” is about more than just reliability, it’s about delivering consumers value for money. Sometimes claims of “missing money” are just rent-seeking in disguise. The tendency in many jurisdictions has been to default immediately to what is actually the third-best option, out-of-market capacity mechanisms. If this is ultimately deemed necessary, it should be a supplement to rather than a substitute for the first- and second-best alternatives described below; it should recognize and reward resources based on desirable capabilities to the extent possible; and it should be designed with the objective of eventually phasing it out. The first priority should be to identify and redress root causes. These tend to range across several categories: While these are common themes in most markets, identifying and rooting out specific problems will take time. In the meantime, some form of administrative market mechanism may be useful. Thus, the second priority, to be pursued in parallel with redressing flaws in the implementation of the energy market, should be developing administrative mechanisms designed to adjust prices in the energy and balancing services markets if and when they fail to reflect the real cost and true value of energy and balancing services, particularly during periods of shortage. There are multiple examples of mechanisms in operation, from the Great Britain, PJM, and ISO New England markets where they operate in parallel with out-of-market mechanisms, to the ERCOT market where this is the principal administrative mechanism deployed to ensure reliability. Figure 3: ERCOT Summer Loads and Resources (System adequacy forecasts in 2013 and 2016) There is good evidence that these two strategies, deployed in tandem, can address legitimate concerns about needed investment. They should be given an opportunity to do so, particularly where the need for more generating capacity remains years in the future, as is the case in most of Europe and North America. They offer the best chance to deliver not just reliability, but reliability at the lowest reasonable cost. Michael Hogan is Senior Advisor at the Regulatory Assistance Project (RAP), a globally operating independent and nonpartisan team of experts. For more information on the report “Hitting the Mark on Missing Money: How to ensure reliability at least cost to consumers”, click here.
News Article | December 3, 2015
A power company worker in a cherry picker connects wires to a power line while working to restore electricity in East Massapequa, New York October 31, 2012. New York's electricity system has the capacity to meet demand for power through the 2015-16 winter season, the New York Independent System Operator (NYISO) said in a statement on Thursday. The grid operator expects a peak load demand of 24,515 MW during this season, lower by 133 MW than the previous winter, and down by 1,223 MW compared to the record winter peak of 2014. If extreme weather conditions produce colder temperatures than average, peak demand could increase to about 26,100 MW, NYISO added. On Tuesday, ISO New England forecast enough power availability to meet the New England's winter needs.
Chao H.-P.,ISO New England
Energy Policy | Year: 2011
Facing growing technological and environmental challenges, the electricity industry needs effective pricing mechanism to promote efficient risk management and investment decisions. In a restructured electricity market with competitive wholesale prices and traditionally regulated retail rates, however, there are technical and institutional barriers that prevent dynamic pricing with price responsive demand. In regions with limited energy storage capacity, intermittent renewable resources present special challenges. This could adversely affect the effectiveness of public policies causing inefficient investments in energy technologies. In this paper, we present an updated economic model of pricing and investment in restructured electricity market and use the model in a simulation study for an initial assessment of renewable energy strategy and alternative pricing mechanisms. A key objective of the study is to shed light on the policy issues so that effective decisions can be made to improve efficiency. © 2011 Elsevier Ltd.
Litvinov E.,ISO New England
IET Generation, Transmission and Distribution | Year: 2010
Locational marginal prices (LMP)-based electricity markets are implemented in different countries around the world and are dominant in the United States. Even after ten years of the operation, some of the properties of the LMP are not well understood. There are many misconceptions about this clearing mechanism that led to some inefficient market designs. This study is an attempt to consistently present the current state of the LMP-based congestion management, including issues that market and system operators are facing, and analyse new directions of the research. The recommendations are made on which areas are of high priority and should be addressed first. Besides giving a systematic description on how the LMPs are produced, the paper describes both the modelling and implementation challenges and solutions. (This paper solely represents the view point of the author and not necessarily ISO New England's). © 2010 © The Institution of Engineering and Technology.
News Article | December 5, 2016
HOLYOKE, Mass.--(BUSINESS WIRE)--Electricity supplies should be sufficient to meet New England’s consumer demand for electricity this winter, according to ISO New England, the operator of the region’s power system. Because possible natural gas pipeline constraints could limit electricity production from natural gas power plants, ISO New England has implemented a Winter Reliability Program that will help protect overall grid reliability. “Reliable power system operations depends on sufficient resources, adequate fuel supplies, and available infrastructure for both fuel and electricity delivery,” said Vamsi Chadalavada, executive vice president and chief operating officer of ISO New England Inc. “The region should have adequate supplies of electricity to meet demand, barring any unforeseen resource outages or fuel delivery constraints.” Managing Multiple Risks Winter has become a challenging time for New England grid operations, especially during the coldest weeks of the year when the availability of natural gas supplies is uncertain. Approximately 44%—about 14,850 megawatts (MW)—of the total generating capacity in New England uses natural gas as its primary fuel, and natural gas generated 49% of the region’s power in 2015. New England’s natural gas infrastructure was not designed to serve demand for natural gas for both heating and power generation, so on cold winter days, New England’s network of pipelines is near or at capacity for commercial and residential heating. Any pipeline capacity remaining after heating customers are served can be sold for power generation. As a result, approximately 3,450 MW of natural-gas-fired generating capacity may be at risk this winter because of pipeline constraints. This year, the completion of the Algonquin Incremental Market (AIM) Project will increase pipeline capacity into the region by 342,000 dekatherms of gas per day and is expected to ease concerns about pipeline capacity this winter. However, in coming years, Local Distribution Companies (LDCs)—that sell gas to heating customers—will continue to expand their infrastructure and use this increased capacity. Moreover, the region will lose 1,500 MW of coal- and oil-fired generation this spring that will be replaced primarily by new gas-fired generation, and no additional infrastructure to deliver or store natural gas is currently being developed. Also, New England has relied on cargoes of liquefied natural gas (LNG) in recent winters, but these LNG tankers follow global market spot prices and may elect to go elsewhere, depending on price. They can also be held up by severe weather in winter. 2016/2017 Winter Reliability Program To help address these multiple risks, ISO New England will again use a Winter Reliability Program to incentivize gas and oil-fired power plants to procure sufficient fuel before winter begins. The program will run from December 1, 2016 to February 28, 2017, and include an oil inventory component, an LNG component, and a demand response component. According to Chadalavada, “Despite planning for these anticipated risks, if the region experiences any combination of extreme cold for an extended time, power plant outages, and limitations on natural gas delivery, maintaining reliability could require the use of emergency procedures. Beyond this winter, the situation will grow even more uncertain because non-gas power plants are retiring and being replaced primarily with new, gas-fired generation. We are currently evaluating how the ISO will maintain reliability in the future under these conditions.” The next non-gas generator to retire will be the 1,500 MW Brayton Point Power Station in Massachusetts that will close at the end of May 2017. Operational Procedures to Maintain Reliability Should unexpected generator or transmission line outages occur, the ISO has procedures in place to maintain reliability, including calling on demand-response resources to reduce their energy use, importing emergency power from neighboring regions, and asking businesses and residents to voluntarily conserve electricity. ABOUT ISO NEW ENGLAND Created in 1997, ISO New England is the independent, not-for-profit corporation responsible for the reliable operation of New England's electric power generation and transmission system, overseeing and ensuring the fair administration of the region's wholesale electricity markets, and managing comprehensive regional electric power planning.
News Article | November 9, 2015
ISO New England (ISO-NE) has given developers of the Northern Pass transmission project permission to move forward after it determined the project will not have a significant adverse effect upon the reliability or operating characteristics of the bulk power system in New England, provided that the project proceeds in accordance with certain requirements, an ISO-NE spokesperson told TransmissionHub on Jan. 2.