Four industry executives sometimes agreed, and sometimes disagreed, about the great unknowns concerning the Environmental Protection Agency’s Clean Power Plan during the Executive Roundtable at this year’s ELECTRIC POWER Conference & Exhibition. 

What problems will the Obama administration’s upcoming Clean Power Plan (CPP) deliver to the executives who manage the companies that make the power? That topic quickly arose at the Executive Roundtable during the ELECTRIC POWER Conference & Exhibition (sponsored by POWER) in Rosemont, Ill., in April—coincidentally on Earth Day. Predictably, the perspective varies according to the economic interests of the companies (Figure 1).

1. Agreements and disagreements. Participants in the Executive Roundtable were (left to right): Joseph Dominguez, executive vice president government/regulatory affairs and public policy, Exelon Generation LLC; Lee Davis, executive vice president and regional president, east, NRG; B. Keith Trent, executive VP of grid solutions and president of Duke Energy’s Midwest and Florida regions; Robert C. Flexon, president and CEO, Dynegy Inc.; and John Shelk, president and CEO, Electric Power Supply Association. Source: POWER/Gail Reitenbach

For Robert Flexon, president and CEO of Dynegy, a large non-utility generator that operates in multiple states, the plan—forced by the underlying Clean Air Act to operate on a state-by-state basis—will create unintended consequences that lead to “carbon leakage.” Because Congress couldn’t agree on a way to reach common ground on carbon controls, the Environmental Protection Agency (EPA) took the only tool it had, the air act, to formulate its program.

That leads to state-by-state reduction targets that create strange outcomes, Flexon said. For example, Illinois and Indiana have about the same generating profile and the same reduction targets. But the less-efficient plants in terms of carbon emissions are in Indiana. So Illinois will have to take more stringent measures to reduce CO2 emissions. “The less-efficient plants in Indiana will survive at the cost of the more efficient units in Illinois.” That leads to fewer carbon reductions than are achievable. State-by-state, he said, is “not the way to go.” He also predicted that the plan will be “heavily litigated,” which will make meeting the timelines in the regulations even more difficult.

Timing Trials

Under the draft of the EPA plan (the final rule is expected this summer), the EPA establishes an interim reduction mandate for 2020 and a second reduction target for 2030. This approach, said B. Keith Trent, executive vice president of grid solutions and president of Duke Energy’s Midwest and Florida regions, will impose reliability threats and unnecessary costs to customers. In North Carolina and Florida, where Duke has its largest state-regulated operations, the company will have to hit 75% of its emissions reductions for 2030 by 2020. “It doesn’t work,” said Trent (Figure 2). He added that by the time the EPA plan emerges from a certain blizzard of litigation, it will be “2018 to 2019.” That leaves little time for his company to hit its 75% of 2030 target by 2020.

2. Timing troubles. Duke Energy’s Keith Trent commented that, by the time the EPA plan emerges from a certain blizzard of litigation, it will be “2018 to 2019.” That leaves little time for his company to hit its 75% of 2030 target by 2020. Source: POWER/Gail Reitenbach

The plan will also create stranded utility costs, which will flow to customers, said Trent. Duke has invested considerable capital in coal plants in recent years to meet new EPA regulations, such as the Mercury and Air Toxics Standards (MATS). Under the CPP, the company likely will have to close some recently upgraded plants, and customers will eat the costs.

For Lee Davis, executive vice president and regional president, east for NRG, an aggressive non-utility generator that is concentrating on expanded and enhanced distributed generation, the interim reduction, by 2020, “looks like a cliff to us, not a transition. We’ve been advocating for a glide path.” That’s a point that NRG’s Steve Corneli raised the day before at the conference’s “Environmental Mega Session—Rebalancing the Electric System for Environmental Consideration.”

A phase-in, said Davis, would allow for systems to become more resilient and flexible. The EPA plan, as it appears from the draft, is “overly reliant on generation that’s completely inflexible.” By that, he was referencing wind and solar, which cannot work within the conventional model of economic dispatch, with the output from the lowest-cost plants being dispatched first.

Joseph Dominguez, Exelon Generation’s executive vice president for government and regulatory affairs and public policy, noted a particular problem for Exelon, the nation’s largest nuclear generator. The EPA draft, he said, “does not provide full credit” for carbon-free nuclear generation. If nuclear power is excluded from contributing fully to carbon reductions, “it will present a challenge” to keeping nuclear plants operating.


Then Dominguez offered a dose of iconoclasm. “We’ve had this discussion before,” he said. He noted that the utility industry was exuding gloom and doom, predicting that the lights would go out and customers would face ballooning electric rates, during the MATS discussion years ago, during the acid rain debates during the 1980s, and virtually every time the EPA has proposed a new rule aimed at generating electricity.

Echoing Edison Electric Institute (EEI) comments to the EPA on its draft rule, Dominguez said the lights are not going out, and we won’t freeze in the dark. The simple solution is to “allow states to put a price on carbon in their dispatch system,” similar to what is happening in the Northeast states that are members of the Regional Greenhouse Gas Initiative (RGGI). He said RGGI has accommodated large carbon emissions reductions in its member states (see sidebar).

Can States Implement Carbon Markets?

The Edison Electric Institute, the lobbying group for the nation’s investor-owned utilities, has suggested that the Environmental Protection Agency’s (EPA’s) regulations on carbon reductions give the states the ability to implement their own carbon pricing models, based on the Northeast’s Regional Greenhouse Gas Initiative approach. Exelon’s Joseph Dominquez characterized this as a “very lower price” approach to carbon emissions reductions.

Are the states ready to implement their own carbon markets? As reported in an SNL energy newsletter the same day Dominquez was addressing the ELECTRIC POWER audience in Illinois, at an industry forum a week earlier, hosted by the Center for Climate and Energy Studies, states and utilities agreed this was a good idea—but almost impossible under the EPA’s time frame. Martha Rudolph of the Colorado Department of Public Health & Environment said, “The robust trading plans would be, frankly, in the time frame, nearly impossible for us to set up.”

If the EPA takes this approach, said Dominguez, it will trigger switching from coal to gas dispatch, an easy outcome. In Illinois, he said, Exelon has combined cycle gas-fired plants “operating at less than 20% capacity, so there is lots of capacity” to offset coal plants if a state has a carbon price system. Under the EEI proposal, a state opting for a carbon price system “would get a free pass” on the EPA reduction requirements until 2029. “We can deal with the carbon issue at a very low price if we put a price on carbon at state levels,” he said.

Dominguez’s approach drew some skepticism from the rest of the panel. Dynegy’s Flexon asked him, “If RGGI is working, why do you need a special rate deal for the Ginna plant?” Ginna is an old (1969-vintage), single nuclear unit outside Rochester, N.Y., which Exelon owns and is losing money on. But the New York Independent System Operator (ISO) needs the plant’s capacity for reliability and wants to keep it running. Dominquez answered that Ginna’s problem is not related to the RGGI market but to the reliability issue in the ISO.

NRG’s Davis observed that putting a price on carbon through RGGI has not made much of a difference in dispatch in the Northeast. “RGGI hasn’t affected much. The problem is more complex,” he said, including the major shift from coal to gas in the region. He said NRG’s position is not that there should be no carbon emissions regulations, “But we should do it correctly.”

Storage: Solution or Problem?

The panel also addressed the role that energy storage might play in the future. “Will storage be viable soon?” moderator John Shelk of the Electric Power Supply Association asked the panel.

Duke’s Trent wryly observed, “Storage is one of those technologies always five years from now.” He said Duke’s experience with battery storage has been disappointing. “It’s not going to be a game-changer in the near term.” He said the use of battery storage for ancillary services such as grid voltage support is near, “but not for energy storage.”

Davis agreed that “storage isn’t there yet. We’ve got to find other ways to get flexibility into the system.” He said energy storage is a bit perplexing. “Is it part of the grid, or is it part of generation?” he asked, answering his question: “It’s really a hybrid.”

Dominquez noted that most of the discussion about storage is related to how to store solar-generated electricity in the short term, dealing with the predicable problem of periods of time when the sun isn’t shining. But solar is a small part of utility renewables of late, and wind is the dominant renewable technology. The problem with wind storage, Dominquez said, is capturing wind that is generated in April when the wind is blowing and using it in July when the wind doesn’t blow. “We are nowhere close on that,” he said. “Solar and storage is easier.” ■

Kennedy Maize is an energy journalist and long-time contributor to POWER.