The Federal Energy Regulatory Commission (FERC) recently announced plans to hold a technical conference on carbon pricing in wholesale electric power markets in late September. This decision comes after a diverse coalition of private energy interests petitioned FERC to carefully examine carbon pricing as a means to accelerate the adoption of low- and zero-carbon power generation technologies and hasten the retirement of older carbon-emitting fossil plants. These actions are needed to meet targets set by a growing list of states and corporations to significantly cut greenhouse gas emissions from electric power generation by mid-century.
Why Carbon Pricing?
Putting a price on carbon dioxide (CO2) emissions from electric power means that electricity generated with fuels like coal and natural gas that emit this greenhouse gas in the combustion process incur a cost for those emissions that power generation from zero-carbon sources like wind, solar, and nuclear do not. Placing this pollution cost on emitters favors the low- and zero-carbon sources, raising their share of total generation and increasing returns to new investment. The higher the carbon price, the greater the advantage to these sources.
First, it’s important to know that electric power sector emissions in the U.S. have declined substantially in recent years – about one-third since 2005. During this time, 11 states – California and ten northeastern states in the Regional Greenhouse Gas Initiative (RGGI) – introduced a price on carbon emissions from electric power. Though I have co-authored work showing that carbon pricing has had some effect on emission reductions in RGGI, the carbon prices seen are rather modest and there have been other critical factors in play, including other environmental policies and technology change that has produce cheap natural gas and renewables.
Though emission reduction progress over the last 10-15 years was both unexpected and remarkable, rapidly moving to the very deep cuts called for by mid-century will require a more ambitious approach. States are responding with a mix of strategies; some include carbon pricing through emission “cap and trade” policies, while others are offering aggressive economic incentives for the use of renewables.
Wholesale Power Markets, RTOs, And FERC Jurisdiction
Duke University’s Nicholas Institute for Environmental Policy Solutions and New York University’s Law School recently released a report identifying the key legal and economic issues underlying the incorporation of carbon pricing in competitive wholesale markets, which I highly recommend to those looking to explore these issues more deeply.
Approximately two-thirds of electricity in the U.S. is delivered via competitive wholesale power markets operated by Regional Transmission Organizations (RTOs). RTOs typically operate across state lines, which triggers FERC jurisdiction as the federal regulator of interstate energy markets. FERC requires RTOs to operate in a manner that yields wholesale prices that are “just and reasonable.” Mostly this means they are expected to set market rules that keep prices as low as possible to meet customer demand and that treat different groups of producers and consumers equitably.
But RTOs do not operate in a vacuum. Instead, the market overlays states and, as such, must contend with state-driven policies. As carbon reduction rules and clean energy targets proliferate, these policies necessarily affect the nature and cost of power generation or delivery within the RTO’s borders. States are legally entitled to establish such policies, but it can complicate matters for the RTOs running the interstate system. RTOs operate via time-specific auctions for delivered electricity. When a state subsidizes a form of zero-carbon generation like renewables or, more recently, nuclear, those subsidized electricity producers can bid less into the auction and still break even. But there may be other producers in the market that are not receiving subsidies from their state. Those producers will be at a competitive disadvantage and will be adversely affected by not clearing the market at their bid price or by receiving a market price that is lower because some bidders are subsidized.
Is it just and reasonable to modify market rules to counteract these subsidies? That sparks a vivid debate. If you put aside the reason for the subsidies to begin with, some argue the adjustments are warranted – states may be simply conferring advantage on their own producers by making it cheaper for them to operate in the market. With no other rationale for the subsidy, this can be viewed as an unfair practice and one that the RTO should remedy to create a level playing field across state lines. But of course there is an underlying rationale for the subsidy – namely, to address the fact that fossil fuel generators do not pay a price for the social cost caused by their emissions (climate change). Thus, one can argue it is only just and reasonable that renewables and nuclear generators be credited for not creating these social costs, rather than confer an unfair advantage to fossil generators who are effectively being “subsidized” by not being charged for them.
Some RTOs Are Already Dealing With Carbon Pricing
Three RTOs wrestle with this situation every day. California has had a carbon price in place for nearly a decade and its system operator (CAISO) has incorporated it into normal operations. New York is a RGGI state, so its producers face a carbon price, but its system operator (NYISO) is exploring ways to ensure that the price is effective in reducing emissions on net. But things have hit a crescendo in PJM, the country’s largest RTO operating across 13 states and the District of Columbia.
Several PJM subsidize zero-carbon resources, face a carbon price as part of RGGI, or both. PJM has a task force now studying the carbon pricing issue within its borders. Preliminary results from that work show that carbon pricing can be accommodated in competitive wholesale markets if border adjustments are used to mitigate emissions leakage from states that price carbon to those that do not.
In lieu of addressing the heterogeneity within its boundaries with a systemwide carbon price, PJM has modified the minimum price offer rule (MOPR) used in its capacity market (the market in which PJM procures enough capacity to meet future demand). The modified MOPR imposes a technology-specific minimum allowable bid for all bidders, in part to block state-subsidized resources from undercutting the bids of unsubsidized competitors. Despite howling protests in some corners that the MOPR seriously undermines efforts by states to decarbonize electricity, PJM has made this modification at the direction of FERC.
What A FERC Conference Does and Doesn’t Mean
FERC holds technical conferences to inform their deliberations on issues it deems important enough to warrant deeper inquiry. It need not indicate that FERC will issue a regulation in response, but it is a recognition of enough stakeholder interest to be taken seriously. Toward this end, FERC Chair Neil Chatterjee said of the decision to hold the conference, “When such a broad group of voices asked the commission to convene an exchange of ideas, I think it’s important that we do so.”
The Carbon Price Coalition, is the group of diverse energy interests from large merchant power generators to clean energy advocates to a natural gas trade group that petitioned FERC to consider ways RTOs can harmonize carbon pricing in wholesale markets. Chatterjee says he expects a lively exchange of ideas.
Tom Rumsey, Senior Vice President of External and Regulatory Affairs for Competitive Power Ventures (CPV), a member if the Carbon Price Coalition said by email, “CPV is extremely pleased FERC has agreed to begin a formal discussion on how best to incorporate environmental attributes into competitive energy markets. This will be an important discussion exploring how competitive markets can facilitate national and state decarbonization goals.”
One of the issues that FERC will likely address is whether they have legal authority to implement carbon pricing in wholesale markets. The issue would seem to revolve around whether FERC is essentially requiring carbon pricing in wholesale markets or whether it is merely accommodating states desire to do so and ensuring it is done without distorting the market. As an independent agency, some argue, FERC does not have the authority to impose a federal carbon price on energy transactions – only Congress and possibly the Executive Branch can do that. And if a federal carbon price is so authorized – through a carbon tax or cap-and-trade system – FERC’s job would be straightforward because all wholesale participants would face the same carbon price, leaving little room for market distortion. This is true, for instance in its treatment of federal tax credits for renewable energy and permit prices for Sulphur dioxide, a federally regulated pollutant.
So the importance of the technical conference is not that it marks a significant change in federal energy policy from the top down. Rather it reveals a surge in momentum by subnational entities toward greater accommodation of carbon pricing as a way to achieve the deep power sector emission cuts called for by many constituencies.
[This article benefitted from the comments of Kate Konschnik of Duke’ Nicholas Institute and editorial suggestions of Will Niver of the Duke University Energy Initiative.]
