NRG says markets could adjust to carbon trading: analysis
By Brian Hansen
December 3, 2013 -
Wholesale power markets such as PJM Interconnection dispatch the generating units within their footprints strictly according to the facilities' operating costs, regardless of what type of fuel they burn, how much pollution they spew into the air and other such factors.
So anything that alters those operating costs — such as the Obama administration's forthcoming carbon regulations for thousands of existing generating units that burn coal, natural gas and other fossil fuels — could significantly shake up grid operators' cost-based dispatch schedules.
Those potential shake-ups may not be far off, as the US Environmental Protection Agency is aiming to propose the first-ever federal carbon regulations for existing power plants by June 1 — less than six months from now — and to finalize them within 1 year.
But one key market player — NRG Energy, the US' largest merchant electricity generator — is confident that PJM and other grid operators will be able to adjust their dispatch models even if generators' unit-specific operational costs change significantly due to EPA's carbon regulations.
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And notably, NRG says the cost-based dispatching model could continue largely unfazed even if EPA incorporates a type of compliance mechanism into its carbon regulations that has been both championed and vilified over the last few decades: emissions trading.
NRG, which sells power from its 47 GW portfolio into PJM, the Electric Reliability Council of Texas and other competitive markets, has been quietly encouraging EPA to incorporate some kind of emissions-trading mechanism into its forthcoming carbon regulations for existing power plants.
NRG has called for a trading mechanism and certain other provisions in closed-door meetings with EPA in recent months, Platts has learned.
To be sure, NRG is just one of many electricity generators, grid operators and other power-sector stakeholders that has met privately with EPA this year about how the carbon standards should be designed, so NRG may not be alone in calling for emissions trading.
Still, NRG's views on the subject are important because the company has ample coal and gas-fired assets in several major competitive markets that will be impacted by EPA's regulations.
In an interview for this analysis, Steve Corneli, NRG's senior vice president for sustainability, strategy and policy, declined to say what kind of feedback EPA has given him regarding his pitch to incorporate an emissions-trading component into the looming carbon standards.
But Corneli said the system he envisions would give generators more operational flexibility than they would have if trading were prohibited, and that his approach would also likely reduce the compliance costs of EPA's regulations without undermining their environmental effectiveness.
And significantly, Corneli said the trading-based approach he favors would not force any major changes on cost-based market operators such as PJM.
“Bidding schedules” to change on daily basis
According to Corneli, the only thing that a carbon-trading mechanism would change on a daily basis for those markets would be the so-called "bidding schedules" that generators use to tell grid operators how much money they need to make in order to start up their plants.
That would change, Corneli explained, because dirtier plants that need to buy "credits" to comply with EPA's carbon regulations would likely see their variable operating costs go up, while cleaner plants that could generate excess CO2 credits and sell them would probably see those costs come down.
Corneli acknowledged that those kinds of regulatory-driven cost changes could absolutely affect which generating units get dispatched on a given day, but he emphasized that grid operators such as PJM would have no problems incorporating those new inputs into their dispatch models.
"Market operators can completely handle changes in the marginal cost of operation of power plants; that happens every time fuel prices change," he said.
"They can also deal with changes in retirements and additions, provided it happens in an orderly fashion and with enough foresight so that people can make their bids into the forward capacity markets knowing what's going to happen."
The starting point for the emissions-trading system that Corneli envisions would be for EPA to establish carbon-related "performance standards" for specific categories of fossil-fuel-fired generating units, such as facilities that burn subbituminous coal, lignite coal or gas.
Each category would have an emissions "rate" that would put a ceiling on the amount of carbon that individual units within those groups could emit per every megawatt hour of electricity they generate.
Hypothetically, for example, EPA might set the standard for subbituminous coal units at no more than 2,100 pounds of CO2 per MWh, Corneli said. Then, any subbituminous coal units whose CO2 emissions are lower than that (hypothetical) 2,100 lb/MWh standard would generate "credits" that could be sold to other power companies that operate the same types of coal units whose CO2 emissions exceed EPA's standard, Corneli said.
Asked if a hypothetical, standard-surpassing subbituminous coal unit would have to sell its excess carbon credits on a market set up and managed by EPA, Corneli said: "I don't know that the market would have to be run by EPA. But it could certainly sell those credits to another power plant that couldn't meet the 2,100-pound standard."
Corneli's approach would also allow power companies to generate additional credits by taking certain actions that cut carbon emissions "beyond the fencelines" of coal or gas power plants, such as by deploying more renewables or investing in demand-side management programs.
Companies could comply by “averaging” emission rates
Companies could also comply with EPA's carbon standards by "averaging" the emissions rates of two or more units in the same category.
For example, if EPA's standard for subbituminous coal plants was 2,100 lb/MWh, a company would not need to buy any credits if it had one subbituminous coal unit that emitted 2,200 lb/MWh and a second unit that emitted only 2,000 lb/MHw (assuming both units operated the same number of hours).
However, Corneli said he does not favor a system that would allow companies to average the carbon emissions of their coal units with zero-emitting sources they may also have in their fleets, such as nuclear plants or renewables.
He said that would undermine one of the primary objectives behind EPA's forthcoming carbon regulations: to encourage electricity generators to retire their oldest, least efficient, most polluting power plants and replace them with cleaner facilities.
Of course, Corneli's approach would also allow power companies to meet EPA's carbon standards by physically modifying non-compliant units to reduce their emissions to permissible levels.
Corneli acknowledged that it may be technologically impractical or cost-prohibitive to undertake such modifications in some cases, which is why he says an emissions-trading program would work for both generators and the markets that they serve.
Nevertheless, Corneli noted that several studies have concluded that coal-fired power plants could indeed reduce their carbon emissions by at least a few percentage points by undertaking various projects to improve their heat rates, which is the amount of fuel — measured in BTUs — needed to produce 1 kWh of electricity.
In July, for example, a Washington think tank called Resources for the Future found that US coal plants could curb their carbon emissions by an average of 4% by making heat-rate improvements to their boilers, turbines and other components, Corneli noted.
RFF pegged the cost of those improvements at about $2.9 billion, and estimated that electricity prices would rise by only 1.3%.
In any event, Corneli said EPA's carbon standards for existing power plants should require only the levels of emissions reductions that could be achieved through "adequately demonstrated, reasonable cost technologies."
Generators should also be able to implement those technologies "behind the fence" of their own coal and gas plants, as opposed to having to cut emissions elsewhere in their systems or in some other sector entirely, Corneli said.
Corneli said that if EPA adheres to those principles, and also incorporates the kind of emissions-trading system that he favors, the least-efficient coal and gas plants would operate less frequently, and would have to buy carbon credits when they do run.
Conversely, the most efficient units would operate more frequently, he said, generating surplus carbon credits in the process. The net result would be a reduction in power-sector carbon emissions, he said.
Corneli said even larger carbon reductions would be achieved over the long term as generators shut down dirtier plants that earn less money for their owners because they operate fewer hours.
"Because they run less and make less money, they create less value for their owners, and they are more likely to shut down sooner than they would otherwise," he said. "They would be replaced by something significantly cleaner in terms of their emissions footprint."
Grid operators tight-lipped about closed-door talks
Grid operators, for their part, have also been meeting privately with EPA in recent months to discuss the impending carbon standards. But like Corneli, they have been tight-lipped about the details of those closed-door talks.
"We have discussions with EPA that are ongoing, but at this point, we can't comment on a lot of things," said Gary Helm, PJM's lead market strategist for emerging markets.
Notably, though, PJM has faulted a carbon-reduction plan for existing power plants that the Natural Resources Defense Council, an influential environmental group, has pitched to EPA.
Craig Glazer, PJM's vice president of federal government policy, said NRDC's plan is flawed from a power-dispatching standpoint because it would allow states to set their own, differing carbon-reduction standards according to how much coal, gas and other fuels the electricity generators within their borders burn.
Glazer said that approach would make things very complicated for grid operators such as PJM, which dispatch power according to how it is priced on a regional — as opposed to a state-by-state — basis.
"We at PJM dispatch units on a regional basis, and these units compete on a regional basis," Glazer said at Washington forum in August.
"And what state they happen to be in is an accident of history, as to what side of the river they are on, etc. So you would start getting some strange results if you've got different standards based on the generation mix within a state. It's just not how the system is dispatched today."
NRG's Corneli echoed that point in his interview with Platts, saying EPA's forthcoming carbon standards should provide regulatory "uniformity across states," as opposed to "a patchwork where there could be real conflicts between the pieces of it."
"So for example, if state A says we're going to count all of these things as emissions reductions and state B says we're not going to count any of those things as emissions reductions, then you'd have a different cost of compliance in state A than in state B, maybe even for plants that are identical," he said.
"And that would be both unfair and inefficient from a value perspective and a policy perspective, because it would affect the value of equivalent assets in different ways."
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