Natural gas is the pillar of the US electric grid. It’s also unreliable

Canary Media’s Down to the Wire column tackles the more complicated challenges of decarbonizing our energy systems.

Willie Phillips, chair of the Federal Energy Regulatory Commission, knows the U.S. has a ​“reliability gap” between its electricity system and its fossil gas system, one that’s played a role in causing major wintertime grid outages in the past decade and threatens to wreak even more havoc in years to come.

But he’s not sure how to solve it. 

“People treat these two systems as if they’re different,” Phillips said during a FERC regular monthly meeting this June dedicated to grid reliability. But as fossil gas has become the top source of U.S. electricity generation capacity over the past 20 years, the two systems are ​“more interconnected today than they’ve ever been.”

That entanglement is a major problem for grid reliability. Over the past 11 years, the U.S. has suffered five separate large-scale grid outages, mostly driven by the failure of gas-fired power during periods of extreme cold. The worst of them — the collapse of the Texas power grid during February 2021’s Winter Storm Uri — left 4.5 million homes and businesses without power at its peak, caused billions of dollars of economic damage and led to the death of more than 200 people.

These outages don’t just take a significant physical toll on the country and its residents. They also challenge the logic of arguments in favor of increasing reliance on fossil gas over renewable energy.

Gas is frequently touted by supporters for its flexibility and reliability — especially in comparison to wind and solar — but in moments of extreme heat and cold, studies find that these purported advantages evaporate. In fact, although some politicians, regulators and fossil-fuel industry groups have blamed renewable energy policies for grid crises, in-depth research by FERC and other entities shows this to be untrue.

Climate-change-induced extreme weather is the key driver of summer and winter grid emergencies in the U.S., and fossil-fueled power plants are, if anything, more susceptible to failure under heat and cold extremes than are wind and solar power. And while extreme heat is primarily a risk factor for thermal power plants, extreme cold is a threat not just to power plants but to the gas delivery systems as well.

That’s not to say that switching to 100 percent renewables would magically solve these reliability issues. Nor is it the case that a cleaner U.S. generation mix is without challenges of its own. But fossil gas is also not the no-brainer, ultra-reliable fuel it is often held up to be by those arguing for policies to build more gas plants and block renewable energy growth. (See the recent pro-gas, anti-renewables crusade from Republican state legislators in Texas.)

And despite ongoing efforts from FERC over the past decade to address the reliability issues caused by the increasing reliance on fossil gas, little has changed, Phillips said. Meanwhile, extreme winter storms that used to be considered ​“once in a generation” are now happening ​“every other year,” he said.

But even with its authority over the country’s electrical system, there’s only so much FERC can do to solve the problem, he said.

That’s because a big, if poorly understood, cause of these grid disruptions is the fossil gas network’s vulnerability to extreme cold. Despite the physical intertwinement of the fossil gas system and the electricity grid, FERC does not have full oversight of the gas system. And unlike the nation’s electric system, which is overseen by the North American Electric Reliability Corp. (NERC), ​“we do not have a reliability organization for the gas system,” Phillips said at the meeting. ​“I believe this is a reliability gap.”

Recent efforts to extend FERC’s authority over gas-system reliability — most notably a bill proposed by Representative Bobby Rush of Illinois (D) — have been rebuffed by Republicans in Congress. Fossil fuel industry groups have argued that the country’s gas pipeline networks are already adequately regulated.

“I once again call for some entity to have responsibility for the gas system’s reliability. It doesn’t have to be FERC. But someone needs to have responsibility for that,” Phillips added.

This ​“reliability gap” underscores a key disconnect in U.S. energy policy. Simply put, the interdependence of the country’s gas and electricity systems has grown much tighter, much faster, than the regulatory structures have evolved to manage that interdependence. Electricity regulators have few options to deal with this fact, forcing them to engage in complex workarounds that don’t address the fundamental disconnect.

“I don’t know how many people need to live through an Elliott, a Uri, a 2018 event, a 2011 event” for things to change, NERC CEO Jim Robb told Phillips during FERC’s meeting. ​“At some point, we’ve got to take this problem on. But it’s a bigger problem than any of us can solve individually.”

As the U.S. moves closer toward its goal of 100 percent clean electricity by 2035, grid operators and regulators may see this particular issue, caused by an over-dependence on gas, fade in priority as new challenges related to phasing out fossil gas emerge. But in the near term, the country faces an urgent, life-threatening and worsening problem thanks to its dependency on a fuel with a shaky track record during the most critical times.

The gas-electric nexus: A system set up for cascading failures

Today’s gas pipeline reliability standards were established before the 21^st century, when ​“gas as a fuel for power generation was kind of a hobby,” Robb told Phillips during FERC’s meeting. But ​“now, natural gas is the single largest fuel for power generation, and power generation is the single largest customer for the natural gas industry.”

The dominance of gas has grown over the past two decades, as the fracking revolution has dramatically increased the supply and driven down the cost of the fuel in the U.S. While renewable energy has made up the majority of new generation capacity over the past several years, gas remains the largest source of U.S. electricity generation by far, rising to 39 percent in 2022.

It’s no surprise, then, that ​“every winter event we’ve analyzed has had the supply of natural gas to power generation and the ability of that system to perform to meet the needs of customers as a common theme,” Robb said.

That was laid bare in a joint report from FERC and NERC, presented at FERC’s June meeting, on the causes of widespread grid outages during Winter Storm Elliott over last year’s Christmas holiday. The storm caused the failure of more than 70,000 megawatts of generation capacity across the U.S. Southeast and forced Duke Energy and the Tennessee Valley Authority to institute rolling blackouts impacting millions of customers to maintain grid reliability.

In this case, the failures went beyond deficiencies in generation — production shortfalls also played a key role. In the Marcellus and Utica shale gas region stretching from New York state to West Virginia, production declined by as much as 54 percent during the storm’s peak compared to a few days prior, the report states.

Similar gas production shortfalls also played a role in the Texas grid disaster in 2021, as well as grid blackouts from Texas to Arizona a decade earlier. That 2011 event prompted FERC to issue a report recommending a host of ​“weather-hardening” measures for both electric and gas systems — recommendations that experts say Texas regulators failed to undertake before Winter Storm Uri struck.

Two other cold-weather grid emergencies — the ​“polar vortex” in the U.S. Northeast in 2014 and the ​“bomb cyclone” that struck the Northeast and upper Midwest in the winter of 2018 — led to fewer production failures, the FERC-NERC report noted. But they did see demand for gas for heating outstrip the pace of supply, making it harder for gas-fired power plants to secure needed fuel.

These ​“correlated outage” events — moments when large numbers of power plants using the same fuel fail simultaneously — aren’t fully accounted for in today’s grid reliability regulations and structures. The connection between cold-weather failures at gas wells, compressor stations and other key links in the nation’s gas pipeline delivery network and the ability of gas-fired power plants to serve the grid when they’re most needed are even less understood and accounted for.

The problem with existing regulations is not just that they fail to account for how gas network breakdowns can harm the electricity sector, however. It’s also that they don’t account for how electric system failures can harm the gas system. 

Cold weather can cause ​“freeze-offs” at gas wellheads when water and other liquids contained in the fossil gas stream freeze and halt the flow of gas. Similar freezing risks can impact compressor stations that pressurize gas to move it through pipelines. Power plants need gas to be delivered at certain high pressures to operate, meaning that they can be forced offline even while gas remains in the network.

Many compressor stations and storage terminals also need electricity to operate. If they lose power due to grid outages — including those caused in part by the gas network’s inability to deliver fuel to gas-fired power plants — they can be forced offline, creating a chain reaction of failures.

What happens when a system has grown faster than the methods to manage it?

This rising interdependence of gas and electric systems has not been matched by a corresponding advance in the forecasting and modeling tools that could give grid and pipeline operators a better understanding of them, said Carlo Brancucci, CEO and co-founder of encoord.

Brancucci co-founded the startup in 2019 to commercialize new software tools aimed at helping to solve this disconnect. In his previous five-year stint as an NREL power system modeler, he ​“realized that one thing every study had in common was the assumption that gas-fired power plants would ramp up and ramp down as much as the system needed.”

That’s a highly suspect assumption, as the winter energy crises of the past decade indicate. 

Power plant operators have trouble securing the gas they need to respond to grid emergencies for several reasons, he said. First, federal regulations require gas suppliers to prioritize many customers who need gas for heating over power plants.

Second, even power plants that sign ​“firm” contracts for gas delivery, as opposed to those that rely on spot markets to meet their needs, can’t adequately structure those contracts to reliably provide the shifting amount of gas they may need from hour to hour, according to Brancucci.

That’s because those contracts are built around commitments from gas providers to supply an average amount of gas over ​“nomination cycles,” or the periods of time that they pledge to deliver firm amounts of gas, he explained. In the gas world, these nomination cycles are measured in multihour periods that can range from several hours to multiple days.

In the electricity world, by contrast, ​“things are done on the hourly or sub-hourly level,” he said. That means that when power plant operators need to ramp up their gas consumption to meet grid needs, they’re still stuck with the average amount of gas they ordered up hours ago through the nomination-cycle process.

FERC has taken action to better link how gas is bought and sold with the needs of electricity markets, Brancucci said. In a 2015 order, FERC required pipeline operators to offer three nomination cycles during the latter half of the day, rather than the 24-hour cycles that were previously standard, and to schedule to better match the needs of power plants. 

But even these intraday nomination cycles don’t match the ups and downs in demand that power plants can expect to face when grid imbalances strike, he said. And they still presume that power plants will use a steady and unchanging amount of gas over that multihour period, which isn’t how power plants actually use gas.

These disconnects have been recognized as problematic for years, he noted. In a 2017 paper, researchers with the Environmental Defense Fund highlighted how these gaps have not only exacerbated reliability risks but have also left many power plant operators unwilling to even contract for firm gas delivery, since those contracts don’t guarantee delivery of gas at critical times.

Better coordination and data-sharing between pipelines and power plants could go a long way toward improving the efficiency of the grid, said Brian Sergi, a researcher at NREL’s Grid Planning and Analysis Center who’s worked on several modeling studies with encoord. One such study completed last year revealed that more regular updates on hourly gas flows and availability could yield significant cost improvements, as well as the potential for more reliable service.

But absent a restructuring of the way that gas providers, power plant owners and grid operators and dispatchers share data and conduct business — an overhaul that only Congress could confidently enact — electricity system regulators have been forced to try to solve the problem within the realm of regulation that they do control.

Trying to solve the gas-electric reliability gap on the electric side alone

In lieu of any unified federal approach to dealing with this reliability gap, many U.S. grid operators are attempting to deal with this disconnect by revamping how they manage the risk of weather-related outages.

It’s a particular focus of grid operators struggling with cold weather-related reliability and correlated outage problems like ISO New England, New York ISO and PJM, the grid operator in charge of providing electricity to about 65 million customers from Illinois to Virginia.

Earlier this year, PJM launched an effort to reform its capacity market, which pays power plants and other resources to be available when the grid needs them the most.

PJM revealed its latest proposal in June and reviewed it during a FERC workshop held on the same day the agency issued its latest winter reliability order. The plan is built on a risk analysis indicating ​“a significant shift in the patterns of reliability risk to the winter season,” as opposed to the summertime heat waves that have traditionally caused the most grid stress.

Winter Storm Elliott was particularly hard on PJM’s generation fleet. At the height of the storm, PJM lost nearly 25 percent of its entire power plant capacity to outages and ​“derates,” or reduced performance, with gas-fired power plants making up the majority of the lost power.

PJM’s proposal to restructure its capacity market to account for this risk includes using a metric known as effective load-carrying capacity, which measures how effective different resources can be expected to be when the grid is under the greatest stress. It also involves a process called ​“accreditation,” which assigns different resources different values depending on how reliable they can be expected to be when they’re most needed. It’s a process solar and wind are already subject to, but which would be new for fossil gas plants in the region.

For gas-fired power plants, it’s likely that this accreditation system would end up significantly lowering their capacity value, said Mike Jacobs, senior energy analyst for the Union of Concerned Scientists. That’s because today, those gas plants are allowed to offer their full generation capacity into the market, adjusted only by an ​“average outage rate” of about 8 percent, which reflects the chance that any one of them might fail due to mechanical issues or other problems affecting them individually, he said.

If peak winter failures are taken into account, those plants would be forced to bid a much lower fraction of their total generation capacity into the market, Jacobs said. That could hurt their bottom lines, since ​“the capacity market is a major revenue source for the generator owners,” he noted.

As a result, the proposal has faced fierce opposition from the industry.

“You’ve got outages because of equipment, but then you’ve got fuel outages. They could be caused for a whole bunch of different reasons,” Marjorie Philips, senior vice president of wholesale market policy at LS Power, an energy company that owns fossil fuel power plants, transmission lines and energy storage projects across the country, said at this month’s FERC workshop.

She also pointed to the aforementioned gas delivery contract disconnects as a key barrier to gas power plant operators trying to bolster performance during peak winter events. ​“We have four hours, in most cases, after we nominate gas, that the gas flows,” she said. ​“So when PJM says, ​‘Well, I want you on in an hour,” even if I have firm gas, if I’ve missed the nomination time, I’m screwed.”

But from the standpoint of PJM’s main goal — grid reliability — the proposal could make a lot of sense. That’s because it would both allow the operator to better plan for extreme weather scenarios and also incentivize better preparedness on the part of gas plants by tying compensation to performance.

PJM CEO Manu Asthana said at FERC’s meeting that this market revamp was necessary to ​“figure out the correlation between bad things happening all at once. Those bad things could be really cold weather and high outages amongst certain asset classes at the same time. That creates risk — and that actually influences accreditation as well, because if you can’t perform when we need you to perform, you should get less accreditation.”

A number of other solutions have been proposed for fossil-fuel power plants to address reliability issues on their own.

Requiring generators to keep backup fuel reserves is one option, though who pays for that fuel is a contentious question. ISO New England has a system that pays generators to cover the cost of storing up to three days of extra fuel on-site, Jacobs noted, but environmental groups like the Sierra Club and the Union of Concerned Scientists have opposed aspects of the program.

Penalties offer another route, though they come with a host of practical issues, not least of which being that they are often diluted. PJM levied a total of $1.8 billion in ​“nonperformance charges” on generators that failed to perform during Winter Storm Elliott, prompting the companies hit with the fines to take legal action to overturn them.

But penalties may not solve a key problem for power plant owners, FERC Commissioner Mark Christie said at this month’s FERC workshop: how to encourage them to invest in hardening their plants to withstand cold weather. ​“You can’t talk about mandating weatherization or winterization — which is really a way of mandating capital expenditures — without talking about how they’re going to be financed,” he said.

How to overcome the disconnects between the electric and gas sectors? 

None of these stopgap efforts get at the underlying disconnect between the gas pipeline network and the reliability of the grid, however.

On that front, the first step that regulators could take would be to require grid operators and gas pipeline network operators to deploy better software modeling and planning tools, encoord’s Brancucci said.

But even more modern modeling tools still need data to perform their tasks, and that’s not necessarily easy to come by. Encoord has worked with gas pipeline operators to secure data for its modeling work with NREL, and late last year, it licensed its software to Northeastern U.S. utility National Grid to integrate the planning of its gas and electric distribution networks. But regulatory structures that would enable this depth of data-sharing between gas system operators and grid operators don’t yet exist.

And while studies from NREL and encoord have found time and again that coordinated gas-electric operations could deliver cost and reliability benefits, that might not help during major winter storms unless those risks are built into real-world planning models. So far, encoord hasn’t seen its software applied to the coordination of large-scale gas pipelines and power plant operations.

“We have these two massive infrastructure systems that don’t talk to each other, and they’re becoming increasingly intertwined,” Bri-Mathias Hodge, a chief scientist at NREL’s Grid Planning and Analysis Center, told Canary Media. ​“We have to understand their interactions with each other.”

“The big thing is getting that into industrial practice,” he said, ​“so we can avoid some of the problems” of past winters. 

It’s far from clear if the regulatory structures are in place to encourage this kind of advanced modeling, however, given FERC’s ongoing struggles with the issue.

In late 2021, in the wake of Winter Storm Uri, FERC launched a process with the North American Energy Standards Board to develop new standards focused on ​“commercial information sharing between critical parties during impending extreme weather-related operating conditions.” FERC is hoping to see recommendations from the North American Energy Standards Board, an entity created to coordinate electric and gas market activities, later this summer, Chair Willie Phillips said.

But industry watchers have intimated that this process may not be yielding the kind of deep reforms that may be necessary to meet the grid’s pressing reliability needs. During this month’s FERC workshop, NERC CEO Jim Robb told Phillips that ​“it seems pretty clear to me from my discussions with the principals that they’re going to come back and say we don’t have the policy framework in place to solve these issues.”

Phil Moeller, a former FERC commissioner who is now an executive vice president at the Edison Electric Institute, a U.S. utility trade group, also warned FERC Chair Phillips that key parts of the country’s fossil gas system, such as the wellheads that produce gas, are beyond FERC’s jurisdiction. Meanwhile, guidelines Moeller helped craft during his time at FERC in 2011 for state regulators to harden their pipeline networks against extreme cold have been ​“mostly ignored” by the regulators it was addressed to, he said.

Legislation to give FERC broader authority over gas pipeline reliability could provide a path forward in dealing with these issues. But such a proposal is likely to face challenges in a Republican-controlled House of Representatives, just as it has in recent years.

And a broader concern looms in the not-so-far-off distance, FERC Commissioner Christie said during the workshop: how the increasingly brisk pace of fossil fuel plant closures will impact the reliability of the grid in coming years.

For example, PJM issued a study in February forecasting that it could see between 40 and 50 gigawatts of generation, mostly coal-fired power plants, retire over the coming decade. Meanwhile, the majority of the new resources seeking to be built in PJM territory — most of it wind, solar and batteries — face yearslong wait times due to grid interconnection logjams, leaving the grid at risk of future shortfalls.

Clean-energy backers say that the answer to improving reliability isn’t keeping old fossil-fueled power plants open, but clearing out the interconnection backlogs that are keeping new, clean resources from being added, and expanding the transmission networks that can carry clean energy from other regions.

In response to a reporter’s question about progress on two long-awaited FERC rulemakings aimed at streamlining interconnections and expanding transmission buildouts, Christie replied: ​“We are working as expeditiously as we can.”

But these rulemakings are among the most complex FERC has undertaken, he added. ​“It takes the time it takes.”