New Analysis Examines Clean Power Plan Costs

The EPA’s Clean Power Plan is likely to intensify the electricity industry’s already-underway shift from coal-fired generation to natural gas and renewables generation. A new working paper uses the Nicholas Institute for Environmental Policy Solutions’ Dynamic Integrated Economy/Energy/Emissions Model to evaluate Clean Power Plan impacts on the U.S. generation mix, emissions, and industry costs. Lead author Martin Ross, a senior research economist with the Nicholas Institute’s Environmental Economics Program, says that Clean Power Plan compliance costs, although relatively inexpensive from a national perspective, are highly variable from state to state. Those cost differentials could mean that rather than pursuing a coordinated national approach to the Clean Power Plan, some states may adopt a patchwork of policies that serve their own best interests but potentially impose additional costs on neighboring states. When it comes to estimating state-level Clean Power Plan costs, says Ross, the devil is in the details or rather in how many states choose the same details for their Clean Power Plan compliance.

Before we get to your findings, can you tell us about the Clean Power Plan compliance options that you modeled?

The Clean Power Plan rule regulates emissions from existing fossil generators and allows states to choose among four EPA-defined compliance approaches. The “dual-rate” option has subcategorized emissions rate goals for existing fossil steam units and natural gas combined cycle units. The “blended-rate” option uses each state’s 2012 historical generation to combine the separate fossil steam (largely coal) and existing natural gas combined cycle emissions rate targets from the dual-rate approach. And there are two “mass-based cap” options: one over (most) existing fossil units and one over existing and new fossil units—what the EPA calls the New Source Complement. But states can also adopt their own plans to achieve mass emissions limits, or they can set carbon dioxide emissions rate targets for individual existing units to achieve comparable reductions.

These state measures could take many different forms, and the options appeared too open-ended to include them in our analysis. We also didn’t examine the blended-rate approach because it appears to be the most expensive, and least likely, option.

How did you use DIEM to analyze the dual-rate and two mass cap options?

DIEM includes a detailed electricity dispatch model of U.S. wholesale electricity markets. The model represents intermediate- to long-run decisions within the industry regarding generation, transmission, capacity planning, and dispatch of units. To estimate policy impacts, it minimizes electricity generation costs while meeting electricity demand and environmental policy goals under different policy scenarios.

Your modeling indicated that increases in electricity generation costs due to Clean Power Plan compliance are relatively low nationwide.

Regardless of the policy options chosen by states, total policy costs are fairly low. For a coordinated national approach, they are most probably in the 0.1%–1.0% range, given most assumptions about future trends in the electricity industry. The reason is that decreased natural gas prices and renewables costs, plus environmental regulations such as the Cross-State Air Pollution Rule and the Mercury and Air Toxics Standards, have been shifting the industry away from its traditional base of coal-fired generation and into lower-emitting sources. In fact, low gas or renewables prices can achieve many Clean Power Plan goals without additional adjustments by the industry. High gas prices have the greatest potential to increase Clean Power Plan compliance costs. Energy efficiency measures play a significant role in containing those costs.

How do emissions reductions and costs compare across the three compliance options you modeled?

If you are talking about national approaches to the Clean Power Plan, the modeling shows that, at least until 2030, the dual-rate approach and the mass cap with New Source Complement are very comparable with regard to emissions reductions and costs. But after 2030, a dual-rate approach leads to additional emissions as electricity demand grows and as renewables increasingly enter the grid, creating more and more emission rate credits, which allows coal plants to run more. The mass cap over existing units has the lowest costs. But that’s because it achieves significantly fewer emissions reductions than the other approaches over its first decade.

Beyond emissions and costs, there’s an important difference between the mass-based options and the rate-based options. The mass-based options have a narrower (and lower) range of costs across many possible futures, so they create greater cost certainty for the industry as compliance options.

What distinguishes analysis of state-level policy costs from that of national-level costs?

In the context of national-level policy costs, interstate trade in emissions reduction credits or mass allowances are just transfers among economic parties, and that trade nets out across the country as a whole. But some states are net buyers and other states are net sellers of both electric power and credits or allowances. So purchases and sales of such compliance instruments must be included in a state’s net policy costs, as are estimated costs or benefits of any net electricity flows into or out of an area. That’s in part why we say that caution should be used when interpreting state-level cost estimates, especially when the states in question are part of an integrated, multi-state electricity market.

Does the analysis point to the benefits of any particular states pursuing any particular approaches?

Yes. Some states—or regions—are clearly better off with one approach instead of another. One example—West Virginia’s costs are much lower under a mass-based approach than under a rate-based one. But for other states, the most cost-effective approach is hard to pin down, and it can vary depending on the actions that other states take and with future market conditions.

You say that variability in state-to-state costs could lead states to adopt policies different from those of their neighbors. Why do these patchwork policy approaches raise costs?

Although these approaches can allow states to achieve local benefits, they may increase the total costs of supplying electricity to the grid. Here’s an example: states with under-construction nuclear units will have access to relatively cheap supplies of ERCs, potentially giving them a competitive advantage in a region if they choose a rate-based approach. But as states choose an approach that minimizes their own cost, generation patterns may change in neighboring states in ways that will distort markets’ current structure and increase inefficiency overall.

Neighboring states’ policy choices are particularly influential in the context of interlinked electricity markets. These markets allow for generation shifting across state borders, which changes the distribution of policy impacts. As a general rule, choices that lead to high compliance costs in neighboring states can lower net policy costs within a state as that state becomes a comparatively low-cost electricity provider and thus benefits by being able to sell more power into the interstate market.

What is the biggest determinant of the outcomes of patchwork approaches?

Those outcomes depend largely on the size of emission rate credits/allowance trading markets. States with expensive intra-state emissions reduction options will benefit from broad markets. States in a position to sell emission rate credits and allowances will have to evaluate market breadth. One possible outcome is that only those states capable of producing cheap emission rate credits choose a rate-based Clean Power Plan policy. In that case, the market price of emission rate credits could be quite low or even zero, providing few benefits and no incentivizes for additional low- or zero-carbon sources. On the other hand, low emission rate credit prices—or low allowance prices—may encourage additional states to enter into trading groups to take advantage of those prices.

One concern with allowing different forms of emissions trading (rate- or mass-based), such as that offered as a Clean Power Plan compliance method, is emissions leakage from one state or region to another. Is that problem worsened by patchwork policy approaches?

When states choose Clean Power Plan responses that segment the emissions trading markets, emissions leakage across state lines can increase as generation shifts to states with comparatively favorable policy environments. Patchwork policies that lead to low emission rate credit prices in a few rate-based states can also shift fossil generation into these states and increase leakage over the national New Source Complement cap. More broadly, emissions can shift from rate-based states or states that cap all emissions sources to states that cover only existing sources. Our analysis suggests that the leakage provisions in the final rule are insufficient to remove incentives to engage in this type of emissions shifting.

The analysis was supported financially by a grant from The Energy Foundation. To read this study, visit our website. Martin Ross and his other Nicholas Institute co-authors, David Hoppock and Brian Murray, are available for comment by contacting Erin McKenzie, or 919.613.3652.