Thanks to market trends and new climate rules, the long-standing definition of "baseload" generation is changing.

During a discussion at the annual meetings of the National Association of Utility Regulatory Commissioners (NARUC) on Tuesday, several utilities and regulators from the Midwest and South expressed concerns about how to preserve baseload generation under the Clean Power Plan (CPP).

While market trends were already on this path before the publication of the climate rules this summer, representatives from Southern Company, American Electric Power (AEP) and Exelon worried that the plan will accelerate market patterns that are pushing older coal and nuclear plants offline and replacing them with natural gas and renewables — fundamentally altering the way the power grids operate in those regions of the U.S. and potentially threatening reliability.

Gas is the new 'baseload'

In 2005, AEP's capacity was about 75% coal, according to John McManus, vice president of environmental services at AEP. But now that is down to near 50%, with baseload capacity making up most of the retirements.

“Our CO2 emissions have gone down 15% during that time period and that’s in large part because how those units ran has changed," he said. "Some of the baseload units started to become like cycling units … and since we’ve brought more natural gas online as natural gas prices started to change how we operated.”

Much of the same is true for Southern Company, said Larry Monroe, the company's chief environmental officer.

“Coal generation in 10 years has dropped from 70% to under 35%” for Southern Company, he said. “It’s been made up by natural gas, primarily natural gas combined cycle.”

Due to these trends, the very nature of what utilities consider baseload generation has shifted from coal to natural gas combined cycle plants, McManus said. Utilities are now considered these plants as baseload because they are dispatchable and can support grid reliability. 

Mike Kormos, executive vice president and COO at grid operator PJM, agreed with the assessment.

In the past, PJM saw baseload as a tradeoff between efficiency and flexibility, he said. The region built large non-cycling coal and nuclear plants because their generation efficiency made them the cheapest plants on the market, leaving the more expensive gas plants to run as peakers.

But with the advent of cheap gas and renewables, “we’ve sort of seen that turned on its head,” he said. Now, natural gas plants are cheaper to run than many of the larger facilities traditionally considered baseload, so under PJM’s economic dispatch model, they run more, and look more like baseload generation.

Even in Kentucky, the heart of coal country, natural gas is the “top dog” today, said Commissioner Jim Gardner, a member of the state PUC. “[Natural gas combined cycle] is right now — the models are all showing, at least in Kentucky — that it is the least cost.”

The advent of gas-as-baseload has saved customers money, but it has also put pressure on older, less efficient plants.

Earlier this year, AEP announced 5,500 MW of coal retirements in one fell swoop, illustrating the impact of market forces and the EPA MATS rule on its baseload fleet. Exelon’s nuclear fleet is similarly facing threats of retirement in the PJM market because of the low price of natural gas and wind electricity.

While those trends for baseload generation are expected to continue, if not accelerate, under the Clean Power Plan, Kormos said utilities aren’t yet looking at a situation where all their coal plants will go offline.

“Some of the most efficient coal plants are still very much in the money,” he said. “Based on the forecasts we see, even with carbon pricing, because of their efficiency they are able to compete against gas resources.”

The trouble with gas

Even if there is still significant coal generation on the system, many at the NARUC meetings expressed concern with a grid that relies so heavily on natural gas generation.

“One key factor in whether it is truly baseload or not is gas supply and whether it’s a firm supply or not," AEP's McManus said. "In the coldest days in the winter, it tends to be a challenge to get gas to the power plants.”

Commissioner Asim Haque of Ohio echoed that sentiment, saying that “on the two coldest days we’ve had over the last few years, that has been an issue” for his state.

McManus said the trend could persist into CPP compliance. “I think it has the potential to continue as we move more and more to gas, which is what the CPP would have states do, then I think that concern grows and it needs to be addressed,” he said.

The increased flexibility of gas plants compared to more traditional baseload generation could help solve the problem, PJM’s Kormos said.

“Just because you’re baseload doesn’t mean you’re [generating] full-out, 24/7,” he said, indicating that the ability of gas plants to quickly decrease their generation output when they're not needed can help their economics. That could in turn push generators to invest in secure gas supplies for the plants, he said.

“The more you run, the more you look like baseload, and the better buying firm transmission or firm gas supply then looks to the generator,” Kormos said. “If your capacity factor is 70% or 80%, it starts to make more economic sense to go out and make that investment.”

Kathleen Barron, senior vice president for regulatory affairs at Exelon, pointed out that grid operators PJM and ISO-New England have already taken steps to address the gas supply issue.

ISO-NE’s Winter Reliability program incentivizes generators to stockpile oil and liquefied natural gas to support pipeline deliveries during high demand periods, and PJM’s new capacity performance standards — recently approved by FERC — impose stiff penalties on any generator that cannot dispatch when called upon, incentivizing plants to invest in firm gas supplies.

“We’ve taken some actions we hope that have at least pointed us in the right direction to ensure that not just baseload has firm supply, but every unit out there that we are depending on for capacity,” PJM’s Kormos said. 

Exelon's Barron endorsed the changes. “Those kinds of market incentives that the RTOs have proposed and that FERC has approved have really, I think, changed the dynamic in those two regions where you really do have to think about if you’re going to be able to perform,” she said.

The plight of nuclear

Exelon is the largest nuclear generator in the nation, and Barron reminded panel attendees that nuclear plants are nearly immune from fuel supply issues that apply to gas and coal generators because they only have to be refueled once a year, or less. That makes them “a distinct category of baseload,” distinguishable even from coal plants, which have seen their coal-by-rail shipments curtailed or delayed in recent years.

But as reliable as nuclear plants are for generation, they face their own difficulties amid the changing fuel mix. While market conditions are pushing nuclear generation toward retirement in organized markets, the carbon-free generation is considered by many as essential to meeting emissions goals under the Clean Power Plan.

In the final rule, states with existing nuclear generation had the plants' zero-carbon energy counted toward their baseline emissions rates, meaning if those plants retire their emissions would be higher than anticipated, complicating plans for compliance. Even one or two additional nuclear plant retirements could be “quite significant” in terms of meeting the CPP, Barron said.

The Exelon executive advocated that nuclear operators seek extensions on their operating licenses to operate for 80 years or more, saying “it will be cheaper for customers” if they are allowed to continue generating.

While Exelon worries over the possibility of retirements, the situation for nuclear plants in states with vertically-integrated utilities is quite different, Southern Company’s Monroe said.

New nuclear construction is likely to be limited to such states, the panel agreed. While a new nuclear plant is likely too expensive and risky of an endeavor for any developer to undertake in organized markets where natural gas generation sets the economic standard for dispatch, they can be appealing for utilities insulated from deregulated markets because they can rate-base construction and earn a return on that investment.

Southern Co. is constructing two new units at Plant Vogtle in Georgia. Although the project has been plagued with delays and costs overruns, Monroe said the new generation is “certainly necessary to meet any form of the Clean Power Plan out there.”

For deregulated states, however, the Southern Co. executive was not optimistic about the Clean Power Plan's impact on the continued operation of nuclear fleets.

“While we are certainly sympathetic to the organized markets and the plight of the nuclear plants there,” he said, “it’s a challenging market and I’m not sure how you would make the Clean Power Plan fix that.”

Exelon’s Barron called that perspective “pessimistic,” saying there are compliance paths under the Clean Power Plan that preserve her company’s carbon-free baseload generation. If states opt for a mass-based compliance strategy that includes new sources in the cap and puts a price on carbon, nuclear plants could continue to operate well into the future.

“The Clean Power Plan gives states the first opportunity to jump on a model where the goal is carbon reduction, it’s not any particular technology,” she said. “A mass-based system that covers existing and new units does that – it sets the constraint at the carbon reduction goal, and then any unit that can meet that goal in the cheapest way … gets picked.”

In its comments on the proposed plan, Exelon advocated for a nationwide price on carbon to be added in utilities and RTO’s generation dispatches — a “carbon adder” that would price the pollution into generation markets. While under the final plan a nationwide adder is not as likely as regional pricing and emissions trading schemes, Barron said the basic tenets of the idea are sound.

“We see that being a significant improvement from the way the policy has been run now for the existing nuclear fleet and providing it, once you price that cost of pollution in to the emitting plants, enough benefit to the existing nuclear fleet for most of them to avoid the challenges.”

Clean Power Plan compliance strategies

In terms of whether states should opt for a mass or rate-based approach to Clean Power Plan, the other utilities in the audience were less committal than Exelon in naming their preferred compliance strategies.

While saying that his state of Ohio should “pursue all legal options,” AEP’s McManus said mass-based has a lot of attractive qualities, but any strategy “has to be as broad as possible,” because what one state does will affect the other.

Southern Co.’s Monroe said it is too early to tell which approach — rate or mass based — will be better in his service area.

“Although the mass sort of trading has a lot of attractiveness from the simplicity of it, I think different states have different advantages one way or another, so we’re looking at the full slate of options.”

Power sector observers throughout the week pointed out that regulated states in the Southeast are more likely to choose the compliance path based on emissions rates, especially if they — like Georgia and South Carolina — have new nuclear plants under construction. While existing nuclear generation was included in baseline emission rate proposals, plants still being built were not, meaning that when they come online, a state’s rate of greenhouse gas emissions for every MWh generated in the state will become much more favorable.

The present question for Kentucky, however, is whether or not it will choose to file a state implementation plan at all — let alone what approach it will choose.

When asked which compliance strategy he preferred, Kentucky PUC Commissioner Gardner replied: “None of the above.” But after all the other panelists had their say, he jumped back in the conversation to “say something a little non-humorous.”

“In Kentucky right now, there’s so much political uncertainty, so all we can do is put our heads down and try to figure out which of those [compliance strategies] works best, and I agree that it’s too early to know,” he said.

The fact that a Kentucky regulator would publicly state that he may work to find a compliance strategy came as a surprise to many, as officials from the state, especially U.S. Senate Majority Leader Mitch McConnell (R-KY), have advocated for a “just say no” approach to dealing with the EPA regulations.

Utility Dive caught up with Gardner after the panel to ask if his comments meant that Kentucky is considering filing a state implementation plan, but he declined to comment.

Commissioner Haque and the two utilities on the panel also expressed concerns over the concept of emissions leakage — the worry that the building of new gas facilities, not covered by CPP pollution rules for existing plants, could damage emissions reduction goals.

To address this problem, EPA is allowing states to cover new units under the Clean Power Plan pollution standards, set aside renewable energy credits to ensure they are not traded, or prove to the agency that leakage is not an issue.

Haque lamented the new level of uncertainty, both legal and operational, that the leakage provisions put into the plan. He told Utility Dive after the panel that he didn’t think the provisions were necessary due to the pace of coal retirements and the emissions reductions they beget.

PJM’s Kormos, however, was less concerned. “The markets will be able to handle it,” he said.

PJM would like it if there was one price on carbon throughout its entire footprint, but that is probably not realistic, he said. What worried Kormos most about the leakage provision is that it could drive separation between the multiple potential carbon prices in the PJM service area. While the RTO is used to working with different prices — RGGI exists in PJM and it “works fine” — more divergent prices could make the job of managing the grid more complex.

“We’ll stay reliable, I’m not worried about that,” he said, “but the out-of-market actions we might have to take to do that could be problematic.”

Thinking differently about the grid

While the Clean Power Plan appears to solidify the trends that are redefining baseload generation, their genesis came long before publication of the plan. To that point, Ohio's Haque asked the panelists whether its time to start thinking differently about baseload generation and the way we operate the grid in general.

Will utilities and regulators simply need to deal with a grid that’s “primarily bolstered by these intermittent resources that we don’t see today as our traditional grid?” he asked the panelists.

Each utility responded affirmatively.

Even without the Clean Power Plan, AEP's McManus said, these trends were coming down the pike anyway, and power companies need to reassess how they think about the traditional grid.

The question put into contrast the regional differences in generation mixes, grid operations, and general attitudes toward change in the power sector. While utilities from the Midwest and South are only just now talking about how to integrate high levels of renewables on their system while keeping costs at a minimum, power companies and regulators in other parts of the nation are actually doing it — and some have been for a while.

In California, utilities like San Diego Gas & Electric (SDG&E) are already dealing with more than a third of their generation coming from renewables, not taking into account rooftop solar, which pushes the utility’s renewables total to about 40%. The state’s IOUs are now mandated to deliver 50% renewable generation by 2030, a goal that California ISO officials told Utility Dive is within their grasp, without sacrificing reliability.

Critics of aggressive renewables mandates say high energy prices in states like California or Hawaii make renewable generation more appealing, hence the wider adoption and the more advanced abilities to manage grid integration.

But, clean energy advocates say, prices for renewables are coming down fast, and there’s mounting evidence that renewable energy is helping moderate power prices in the states that go after it:

Beyond variable renewables, utilities in states committed to decarbonization are already thinking beyond building out gas infrastructure, and towards a future where energy storage costs drop low enough in price to reduce or eliminate the need for fossil fuels to balance the grid.

At an energy storage conference in San Diego last month, SDG&E chief development officer explained his dream for the power grid of the future: “I see a future where there will be no gas turbines.”

For the utilities in the Midwest and South trying trying to shift from coal and nuclear to gas for baseload needs, that dream must seem a distant one.