The conversation at the ELECTRIC POWER Conference and Exhibition, as underscored by comments made in its keynote address and at the annual event’s executive roundtable, was optimistic yet cautious, owing to regulatory uncertainty and turmoil in power markets.
Compared to just five years ago, today’s U.S. power landscape has been transformed. Low natural gas prices, market dynamics, technical issues, and policies that favor renewables precipitated the closure of five nuclear reactors since 2013, seven others are slated to shutter soon, and at least five will remain open owing only to state programs that deem them too economically and environmentally significant to close. Concerns about the long-term viability of the wholesale market model in the face of political intervention are drawing to a crescendo, prompting the Federal Energy Regulatory Commission (FERC)—which may finally have its quorum restored following President Trump’s nomination of two candidates to fill vacant leadership seats—to set up a technical conference as an outlet for these issues.
Havoc has been unleashed in some traditional markets too. The Westinghouse financial debacle has left the future of the four costly AP1000 nuclear projects uncertain. And while the Trump administration has begun rolling back key Obama-era rules along with key climate policies, average annual net generation from coal-fired units—which reached an annual high of 2 billion kWh in 2007—plunged to 1.2 billion kWh in 2016. In 2016, notably, natural gas generation’s share of the U.S. mix soared to 33.8%, for the first time surpassing coal’s share, which was 30.4%. Also, for the first time, non-hydro renewables’ share of total U.S. generation surged to 8.4%, surpassing hydro’s 6.5% share in 2016 (Figure 1).
|1. Changing power profile. In 2016, for the first time in history, the U.S. consumed more electricity generated from natural gas than from coal, and more from non-hydro renewables than from hydro. Source: EIA|
A Silver Lining
At the ELECTRIC POWER Conference and Exhibition in Chicago in mid-April, concerns about wide-ranging uncertainty afflicting the power sector were echoed by several speakers and attendees. Yet, Bryan Hanson (Figure 2), president and chief nuclear officer of Exelon Nuclear, who gave the annual event’s keynote speech on April 11, provided a glimmer of optimism. Despite recent setbacks that have rattled the nuclear industry, he said, the future of the sector was sound.
Facing stiff competition from cheap gas power and an influx of renewables, U.S. nuclear generators in competitive wholesale markets are forced to grapple with rising costs and falling wholesale power prices, along with more stringent regulatory mandates, and “a lack of federal and state energy policies that value our product,” said Hanson. “And then, there are the political and legal issues … but I’ll stop there.”
Exelon, he noted, stakes the core of its business on its nuclear fleet, generating 20.2 GW of nuclear power from 23 reactors at more than a dozen plants scattered across Illinois, Pennsylvania, New Jersey, New York, and Maryland. Over the years, its profit-making strategy has been transformed alongside efforts to modernize, which have required innovation and technology, and new approaches to operation and maintenance to improve efficiency and reduce costs to make its fleet “as competitive as possible.”
Yet, Exelon’s reinvention efforts would have fallen flat if measures it backed on the public policy front hadn’t succeeded, Hanson said. “As early as 2014, we were looking at potentially having to shut down more than a third of our nuclear fleet simply because the plants were losing money. Two stations in Illinois (Clinton and Quad Cities) and two more in New York (Ginna and Nine Mile Point) were at risk,” he said. “The prospect of shutting the plants down—and putting thousands of our talented, hard-working employees out of work—broke my heart. Policy reforms were the only thing that could save them,” he said.
That’s why Exelon embarked on a hard-fought campaign to underscore nuclear power’s value to local stakeholders, state policy makers, elected officials, and state legislators, and with the crucial backing of a broad coalition of more than 200 business, labor, environmental, and even religious groups, the company managed to help enact the Future Energy Jobs Act in Illinois in December 2016. A similar measure had previously been adopted in New York to preserve the at-risk Nine Mile Point and Ginna reactors upstate. For Hanson, the measures were pivotal for Exelon and the larger nuclear industry. “We had to take action,” he said.
But the fight isn’t over. The states’ measures are being challenged in court by a consortium of non-nuclear merchant generators, including Dynegy, Eastern Generation, NRG Energy, and Calpine Corp., which argue that they interfered with FERC’s jurisdiction over wholesale electric rates and unlawfully interfered with interstate commerce. Even so, Exelon “is confident about the future,” Hanson said. One driving factor certain to underscore nuclear’s value is that “The transition to a lower-carbon economy is irreversible,” he said. Market forces, technology advancements, and consumer preference show an overarching shift towards “energy that is clean and affordable,” Hanson added.
An Era of New Threats
Yet, according to Andrew Ott, who is president and CEO of PJM Interconnection, a regional transmission organization (RTO) that operates a competitive wholesale electricity market within 13 states and the District of Columbia, “competitive markets are working.”
PJM has seen 30 GW of new gas-fired capacity come online over the past six years, 85% of which was on competitive investment—and most are without long-term power purchase agreements, said Ott, who was one of three panelists at the ELECTRIC POWER executive roundtable (Figure 3) on April 11. “What we’re seeing… is a fairly significant fuel swap, where we have in that same period about 24,000 MW of coal plants retiring,” he said. “It’s more than just a fuel swap. It’s actually a technology swap.”
Today, PJM has about 300 MW of grid-scale storage, and an assortment of resources and provided services, like frequency regulation, that is requiring it to interact and coordinate with the distribution system or distribution companies, he noted. The rapid ramp up of gas capacity in PJM’s system—from 4% in 2008 to 30% today—has actually served to boost fuel diversity in the PJM space rather than being a liability. Ott added: “I think the legitimate question is if this is a sustainable approach. Will we build ourselves into a problem?” A report PJM compiled to answer that, he said, basically says, “We think we are fine from a reliability perspective.”
For now, PJM’s biggest worries are rooted in critical infrastructure exposure. More serious than the organization’s past concerns, which were centered on weather-related outages or equipment failure, are cyberthreats and terrorists, he said. Ott later revealed that the organization is so concerned about system corruption that it created a secondary, constantly updated energy management system that it calls its “Golden Image,” and which it keeps in a “dark room.”
“If we find our control systems are unmanageable because they’re corrupted and we just can’t use them anymore, we have the ability to jettison that whole system and bring on the [Golden Image] system within an hour within the current online structure,” he said.
But Ott also suggested there was palpable anxiety about how exposed fuel delivery and power systems are, and, inevitably, about how sturdy efforts to restore systems can be. “There’s a lot more risks that we’re facing as a power industry,” he said. “The question is ‘Are we really accounting for all those risks in our operations?’”
One way to do it is to factor in resiliency, which in the context of the power system includes the ability to harden the system against and rapidly recover from high-impact, low-frequency events. “We need to look at resilience,” Ott said. “We need to start pricing resilience and flexibility into our markets.”
Resiliency should also be a factor driving transmission planning, he said. But rather than rely on state action, such as Illinois’ measures to prop up its nuclear plants as an environmental and economic measure, that action should occur on a regional level. “It’s certainly more logical that if we’re seeing regional benefits to these types of assets we should price it in. Of course, the most efficient way to do that is through a regional carbon price,” he said. “That may not be politically attainable but we think there are ways to look at the way energy prices are formed, look at the way certain aspects of resources are valued.”
One example would be to think about pricing commodities. “Maybe we should price flexibility separately and maybe we should price energy dispatch and balancing of supply and demand a little bit differently,” he said. “The commodity itself then would price out based on just the supply and demand balance.”
The Complexity of Regional Operations
For John Bear, president and CEO of the Midcontinent Independent System Operator (MISO), another panelist on the roundtable, the recent state nuclear incentives posed a conundrum: “We’ve got kind of this crazy incentive trend today going on where you have incentives for renewables, which is really causing some strain on the nuclear fleet. Then you’ll have state incentives to support those nuclear fleets,” he said. “How do we balance those things out?”
He also pointed to federal and state subsidies, which pose complications for operators of regional markets. Wind generators, for example, get incentives to stay running, despite oversupply. “We put some things in place to try to incentivize them not to do that—which is another market mechanism—but then a state will come in and say, ‘This is disadvantaging.’ ”
Bear noted that the RTO he heads serves 15 U.S. states and the Canadian province of Manitoba, and while it “constructively competes” with PJM, the two grid operators are “inextricably linked,” he said. MISO is largely vertically integrated, with the exception of southern Illinois. Like PJM’s, MISO’s power mix has shifted considerably, driven primarily by public policy and economics, Bear said. Since 2011, coal’s share of MISO’s total capacity has fallen from 56.7% to 35%, while gas-fired capacity rose from 30.4% to 41%. Renewables have also more than doubled from 6.1% to 13%. Wind capacity, specifically, jumped from 0.6% in 2011 to 9.3% in 2016, and, according to Bear, it will double from the current 16 GW to 31 GW by 2025 or 2026.
“That’s a significant change in our portfolio,” Bear said. “It’s forced us to go back and look at our queue and interconnection processes to make sure that as all these renewable resources are interconnected to our system, we have the ability to do frequency control, voltage control, all those kind of things are there and we can do them reliably.”
But MISO, too, is grappling with new challenges, including cybersecurity and threats. At the same time, it is looking to modernize its IT platforms, looking to monitor and manage many more points on the grid, and processing a “whole lot more data that will require a whole lot more computational power that our systems need to provide.”
For MISO, price formation and prices are also priorities “to make sure folks that own units—or the resource that’s providing that—can actually be there for them,” Bear said. And like PJM, it would prefer to resolve issues at a regional level.
One issue plaguing MISO, for example, is that it doesn’t have the right transmission system for its projected power mix as industrial load ramps up in the south and slightly shrinks in the north. It still also grapples with resource adequacy, though “we’re learning a lot from [PJM] and what’s going on in New England,” Bear said. Ensuring adequate gas supplies has prompted MISO to look at resource adequacy on a seasonal basis, he said: “What does it look like in the winter and what’s it look like in the summer and how do we accredit assets across those two dimensions and make it work?”
The Western Perspective
Cindy Crane, president and CEO of Rocky Mountain Power, joked that she was the panel’s “token generator representative,” and the only one from the West. Her utility’s parent company Berkshire Hathaway Energy, she noted, also owns Nevada-based NV Energy, Iowa-based MidAmerican Energy Co., and PacifiCorp, which covers Washington, Oregon, California, Idaho, Wyoming, and Utah—all vertically integrated utilities. For PacifiCorp, that means “we have to appease six different state regulatory commissions in addition to FERC with everything we do.”
It’s also different from the rest of the country, because “What is unique in the West is that we actually have 33 balancing authorities… so a lot of coordination needs to occur and a lot of self-balancing,” she explained. PacifiCorp is also unique in that it hasn’t had a general rate case increase in any of its states for “several years,” and it doesn’t plan to over the coming four years either, she said. Rocky Mountain Power was actually able to announce rate decreases and will again this year, she said. “[It’s] a trend we’re trying to stay with there,” Crane said. “[To] very much focus on the customer and the economy and doing our part managing our business to make sure we’re living within our means.”
Among the firm’s most prominent challenges is—as with PJM and MISO—cybersecurity, Crane said. But in the West, the company is also tussling with profitability risks posed by customers who want to “bypass the meter” and generate power for themselves. While smaller self-generators may rely on solar, some of the firm’s larger industrial customers are mulling self-generation, which has become more economical with the flood of cheap natural gas, she said. “Thus the reason rates are so important and critical to us.”
The Regulatory Fog
The panelists addressed a number of policy issues poised to upend the industry. One specific concern was that the Trump administration had not filled three vacancies at the five-person FERC, months after the commission lost the quorum it needs to issue major decisions. FERC had been hobbling along with only two members, both Democrats, since Commissioner Norman Bay resigned on February 3. President Trump formally submitted nominations for Neil Chatterjee and Robert F. Powelson to fill two seats on May 10. Another seat will open when Colette Honorable steps down on June 3.
“I think as time goes on it’ll become more and more difficult, so certainly as we look forward, if it continues for many months into the future I think it will become more and more critical that we don’t have the ability to get a new action, or new activities, or filings,” Ott said. Bear lamented the uncertainty that the lack of leadership poses: “I think the thing we can’t understand is the uncertainty of the long-term plan because we don’t know what the priorities are going to be. All we know is that there will be a new chair, so [Cheryl] LeFleur, the acting chair now, probably won’t be the chair going forward.”
For Bear, a bigger concern is that the new administration had “slowed down” the Clean Power Plan (on April 28, the D.C. Circuit stayed litigation on the Obama-era rule for 60 days while the EPA reviews it). “We don’t know in which direction it will go, what the priorities are going to be going forward, and that uncertainty is concerning,” he said. To that, Ott responded that, while the Clean Power Plan was likely dead, gas generation was already driving a significant reduction in carbon emissions. But sustaining that momentum will require both cost guarantees and revenue certainty, especially for generation assets “exposed purely to the market.” He also suggested that getting pipelines “built and built quickly” would be pivotal to those efforts.
Crane agreed that the Clean Power Plan’s apparent demise would have little impact, though she noted that it eliminates “complexity in the management of our business” because the rule allowed states to choose between curbing carbon emissions by rate or by mass, and there was no real consensus that the states in Rocky Mountain Power’s footprint would elect the same method.
State policies were having a more pointed impact on Western generators, Crane said, and it was likely that Western states would continue clean energy policies in defiance of Washington. She also said that her company was used to seeing negative prices when hydro runs in the Northwest, but starting last year they arrived earlier than usual—in February rather than in spring or early summer—affecting all three western markets. “The way we dealt with that is… we literally took five of our coal units down. Then we had to deal with voltage support issues in the Salt Lake Valley,” Crane said. “But we learned a lot from the process,” she added. This year, the company is armed with new tools to assess the energy and balance market, and it has found ways to “flex that coal fleet like they’ve never flexed it before.”
Still, from the standpoint of a regulated utility, Crane added that once a FERC quorum is established, she hoped that the commission would work to repeal or reform the Public Utility Regulatory Policies Act (PURPA), a 1978 law that requires utilities to buy power at a fixed rate from qualifying facilities that otherwise do not have access to a competitive market.
The System Reliability Challenge
Asked by the moderator whether the U.S. power system was introducing too much risk by increasing its reliance on natural gas and renewables rather than on baseload coal and nuclear plants, Crane observed that “We have continued to be amazed and surprised at the true resiliency that our system already has. We just never tested it as extensively as we’re testing it today.” She also noted that her firm is today “seeing a true value of capacity.” Even with an exponential ramp up in rooftop solar, for example in Utah, Berkshire Hathaway Energy was finding efficiencies and ways to manage, all while achieving emission reductions “without being saddled with mandatory ways to comply.” It may not be the same in the California market, she cautioned, because there’s just not enough redundancy in the gas supply chain and because gas leaks have restrained the system.
Ott and Bear both responded that their operations are rooted in a mission to provide reliability at the lowest possible cost. “Essentially, the point is, are we looking at those operational risks and are we managing the system to account for it?” Ott asked. “Because, again, blackouts don’t happen because of an ‘n minus one.’ They don’t happen because of an ‘n minus two.’ It’s usually the event you never thought of.”
Ott pointed to a September 2016 blackout suffered by South Australia, an Australian state which recently shuttered all of its coal plants owing to a ramp up of renewables (for more, see “After Blackout, South Australia Wrests Control of Its Power Security” in POWER’s May 2017 issue). The event was prompted after two tornadoes damaged a single circuit 275-kV transmission line and a double circuit 275-kV transmission line, some 170 kilometers apart, causing them to trip, and “the system decayed too quickly,” Ott noted. “It sounds like an issue where that same vulnerability can happen anywhere because all of us are seeing change on the system, where traditional resources react a certain way to faults and to disturbances.” ■
—Sonal Patel is a POWER associate editor