There’s a good chance that Virginia will participate in the Regional Greenhouse Gas Initiative (RGGI) to cut utility CO2 emissions. The impact of the cap-and-trade system would be mostly symbolic.
Barring litigation, Virginia could start participating later this year in the Regional Greenhouse Gas Initiative (RGGI, pronounced Reggie), a cap-and-trade program designed to reduce CO2 emissions of electric utilities and large industrial customers by 30% over a 10-year period. All it will take is for the State Air Pollution Control Board to approve regulations, now undergoing public comment, that have been drafted by the Department of Environmental Quality (DEQ).
Cap-and-trade programs have proven highly cost effective at bringing down emissions in sulfur dioxide and nitrous oxide, and proponents say that a similar approach could work just as well for carbon-dioxide, widely held to be the primary driver of global warming. Cap-and-trade, they say, avoids the inefficiencies of bureaucratic command-and-control regulations. Instead, the auction arrangement steers power output to entities that can reduce CO2 emissions the most cost effectively. Not only will RGGI cut emissions, they contend, it will flatten electric rate increases, lower electric bills, and stimulate economic growth.
There’s just one problem. Virginia’s largest electric utility, Dominion Energy Virginia, doesn’t believe it. In fact, in its 2018 Integrated Resource Plan, the utility fired a broadside against the regulatory initiative. The company maintains the following:
- The program could impose $530 million in additional costs on Virginia customers between 2020 and 2030.
- In effect, Virginia will subsidize other RGGI states through lower compliance costs to the tune of $876 million over the decade.
- Virginia’s linkage to RGGI will not reduce CO2 emissions. To the contrary, the auctions will increase CO2 output by 5.7% more than it would have been otherwise.
A big reason RGGI proponent’s optimistic forecasts won’t pan out, Dominion says, is that there is a geographic mismatch between the RGGI states and PJM Interconnection, the wholesale market of which Virginia is a part. The nine RGGI states are concentrated in the Northeast; the 14 states of PJM are located in the Mid-Atlantic and the Midwest. The only overlap between the two are Virginia, Maryland, and Delaware. Because Dominion, Appalachian Power Co., and other electricity producers don’t control which power sources are dispatched to meet electric demand — PJM does — generators in Virginia would suffer a cost disadvantage compared to competitors in neighboring states not subject to RGGI, such as North Carolina and West Virginia.
“The effect of RGGI-equivalent reduction requirements in Virginia is likely to limit the dispatch of highly-efficient and lower-emitting [natural gas combined-cycle] facilities in Virginia and to encourage the dispatch of higher-emitting resources and increased emissions in neighboring states outside of the RGGI region,” states the IRP.
But environmentalists insist the cap-and-trade program will be beneficial. “Carbon pollution is a big contributor to climate change. Cap-and-trade is a market-based way of dealing with that environmental problem,” says Will Cleveland, an attorney with the Southern Environmental Law Center.
“We think this is a really good opportunity,” says Harry Godfrey, Virginia director of Advanced Energy Economy. “To the extent that there are still older, coal-fired plants online, we foresee … less utilization of those assets in the future. But we see less utilization anyway. All of our analysis shows a coal-to-gas shift. … Our analysis shows that you can limit cost impacts, and even reduce rates in the process.”
How RGGI works
In 2009 ten Northeastern and Mid-Atlantic states accounting for one-eighth of the U.S. population and one-seventh of its economic activity created the Regional Greenhouse Gas Initiative as an interstate cap-and-trade program. Broadening the geographic scope of the trading system beyond the boundaries of a single state, it was thought, would create a bigger pool of CO2-cutting opportunities.
Under RGGI’s “direct” auction trading system, RGGI sets a regional limit on the total amount of CO2 that power plants in member states are allowed to emit. Owners of fossil fuel power plants with capacity greater than 25 megawatts are assigned an allowance to release a certain amount of CO2. Then they are required to purchase pollution permits at quarterly auctions sufficient to meet that output. The plan is for RGGI to ratchet the CO2 allowances by 3% each year over a decade. Utilities and big industrial producers who can’t find ways internally to cut their CO2 emissions can go to the auctions to buy extra allowances. Power generators who can find ways to cut emissions economically can sell their excess allowances to those who need them.
In the first auctions between 2009 and 2011, RGGI sold 395 million tons worth of CO2 allowances. The cap was a generous one, so the auction price for allowances was low — ranging between $1.86 and $3.35 per ton — according to the Center for Climate and Energy Solutions. As the CO2 allowances tightened, prices increased, reaching a high of $7.50 per ton in 2015. Prices fell after the Trump administration nixed the Clean Power Plan but the next round of CO2 emissions cuts — 30% by 2030 — likely will push the price back up.
Auction proceeds are divvied up between the states, which have used the funds to invest in initiatives such as weatherizing homes, upgrading HVAC systems, promoting wind and solar, or helping low-income citizens with their energy bills.
Because of restrictions of state law, Virginia will not be a full-fledged RGGI member. But the commonwealth still will have a say in how RGGI operates, says Michael Dowd, director of the air division at the Department of Environmental Quality (DEQ). “We’ll be at the table when RGGI states get together and discuss how the auction should be run, how the accounting mechanisms work.”
The biggest difference between Virginia and other RGGI states is that Virginia’s “consignment” auction revenues will not flow into state coffers. Money will go back to the power companies that paid for them; in turn, regulated utilities will be required to rebate the funds to rate payers. The downside: Virginia loses the ability to fund its own energy-efficiency programs as other states do..
The auctions for CO2 allowances have cost owners of fossil fuel plants in the RGGI region nearly $2.8 billion over nine years, says the Analysis Group consulting firm in an April 2018 report, “Economic Impacts of the Regional Greenhouse Gas Initiative on Nine Northeast and Mid-Atlantic State.”
But the Analysis Group argues that RGGI states have enjoyed significant benefits over and above the CO2 reductions. States the report: “These investments keep more of the RGGI states’ energy dollars in their region, and reduce the amount of that leave the region to pay for fossil fuel resources produced outside the RGGI states.”
Energy customers benefited to the tune of $220 million between 2015 and 2017 as their overall energy bills dropped, the study says. The savings breaks down to $99 million for electricity customers and $121 for retail oil and natural gas customers. Small increases in electric rates were more than offset by reduced electricity consumption.
Most important of all from an environmental perspective, CO2 emissions in member states have declined 50% since the formation of RGGI (although the Analysis Group acknowledges that factors other than the cap-and-trade scheme contributed to the decline). The gains were achieved mainly through a shift to low CO2-emitting power sources like nuclear, wind and solar at the expense of coal and oil.
Crucially, according to the Analysis Group report, “RGGI’s implementation has not adversely affected power system reliability in New England, New York, or PJM.” The report provided no documentation for the statement.
While the Northeast region survived the extended deep freeze known as the Bomb Cyclone for eleven days in January, it did so just barely, according to an analysis conducted by the National Energy Technology Laboratory (NETL), “Reliability, Resilience and the Oncoming Wave of Retiring Baseload Units.”
Average daily electric load increased 23% during the Bomb Cyclone. The New England ISO (independent system operator) was hobbled by natural gas delivery constraints. As a consequence, “fuel oil provided almost all the surge capacity in the Northeast, barely enabling ISO-NE, in particular, to meet demand, as it experienced rapid depletion of its fuel oil storage reserves.” The spot price of natural gas in New York shot from around $6 per million BTU to $175.
Said the NETL study:
Having enough fuel oil was, in part, a testament to ISO-NE’s Winter Reliability Program of storing fuel oil at dual-fuel facilities. However, the stores of fuel oil were 51 percent depleted by this event, with some plants nearly or fully exhausting their on-site supplies. Additionally, refueling these depleted fuel supplies is a complex and logistically intense operation; ISO-NE is serviced by a single 50,000 barrel per day oil pipeline to which only two of the region’s 83 dual-fuel capable units are connected, which also services home heating oil and other petroleum product demands in the region, necessitating the delivery of fuel oil for power via truck and/or rail, creating supply issues should a similar event last for a longer period.
The PJM system, which drew upon extensive coal-fired generating capacity held in reserve, fared better than New England. Even there, despite access to abundant gas supplies, the spot gas price surged so high that PJM had to dispatch coal- and oil-fired units that twice as much CO2 per unit of heating value.
However, NETL’s immediate concern is not the immediate future. Rather, the study asks what will happen as coal- and nuclear-fueled power plants continue to shut down and are replaced by wind and solar, which have zero surge capability, and natural gas, which has pipeline capacity constraints, especially in RGGI states in New York and New England. The NETL report did not address how a 30% reduction in CO2 emissions in the RGGI states might impact the availability of coal and oil reserve capacity in the future. Neither did the RGGI-friendly Analysis Group study.
Dominion’s 2018 Integrated Resource Plan does not address the reliability issue either. But it does argue that RGGI will not have the desired effect in Virginia. The reason is that Virginia is part of the PJM wholesale electricity market, and PJM, not the utilities, control which power plants feed into the system.
“PJM is a multi-state region. Units are dispatched economically to meet load demands on a regional basis,” explains Bob Thomas, Dominion director of energy market analysis and integrated resource planning. “To the extent that generators have an extra RGGI ‘tax,’ by definition, they will be at a disadvantage to generators outside the state [that do not participate in RGGI].” As a consequence, out-of-state power sources (which are higher carbon) will generate incrementally more, and Virginia power sources (which are lower carbon) will generate incrementally less.
RGGI acknowledges that such “leakage” can be an issue, Thomas says. RGGI’s most recent monitoring report, dated August 2016, found that imported electricity increased 34% between a 2006-2008 baseline and 2012-2014. The leakage did not lead to increased CO2 emissions mainly because much of the imported electricity came from Quebec hydropower. There is no comparable source of hydropower accessible by Virginia. While there is substantial zero-carbon wind power in the PJM system, the electricity would have to be wheeled in from Midwestern states and be subject to transmission-related congestion charges.
Thomas acknowledges that RGGI states have reduced CO2 emissions, but he argues that the cuts might have occurred without the CO2 auctions. The Obama administration enacted the Mercury Air Toxics Standards in 2011, cracking down on the emission of mercury and other heavy metals from utility smokestacks. Those rules imposed significant new burdens on coal plants. Around the same time, the fracking revolution pushed the price of natural gas far lower. The result was a massive shift nationally from carbon-heavy coal to carbon-light gas generation. Likewise, working independently of one another, RGGI states have been pushing renewable energy sources.
Dominion ran several scenarios to see what impact RGGI regulations would have on Dominion’s fuel mix. The scenario most closely resembling the regulations being drafted by DEQ appear in the IRP as “Plan B”: participation in RGGI allowing unlimited electricity imports. The gap between projected energy capacity and the “energy requirement” line (representing forecast demand) is marked as “market purchases” — essentially purchases of electricity from the PJM wholesale market. Dominion would engage in some market purchases in the absence of RGGI, as seen in the Plan A scenario, but not nearly as much. The carbon intensity of the purchased power would exceed that of Dominion’s own power. The net effect would be to transfer lower-carbon electric generation from inside the state to higher-carbon generation outside the state, thus defeating the purpose of RGGI. Adding insult to injury, by Dominion’s calculation, the auctions would cost Virginia rate payers an average of $50 million extra per year over ten years.
Disputing Dominion’s forecast
William Shobe, director of the Center for Economic and Policy Studies at the University of Virginia’s Weldon Cooper Center, disagrees with Dominion’s analysis. The utility’s forecast inflates future electricity demand in its Virginia service territory, which throws off the rest of its RGGI-impact calculations, he says. Industrial demand for electricity is falling due to a change in Virginia’s industrial mix. Building shells sand appliances are steadily becoming more efficient. When property owners retrofit older buildings with LED lights and more efficient heat pumps, there is tremendous room for reductions.
“Actual electricity demand growth over the next several years will not come close to Dominion’s inflated 1.3% growth. Something like 0.5% to 0.7% is much more likely,” Shobe writes Bacon’s Rebellion. And that includes growing demand from data centers, which Dominion cites as a driver of demand. “Without growth in demand, Dominion fossil fuel capacity is over-built.”
With or without RGGI, says Shobe, Dominion will either try to export power into PJM wholesale markets, which are awash in new capacity, or cut back utilization of existing plants. Because their variable costs are zero, new solar and wind always will be dispatched. “That leaves existing coal and all that bright shiny new NGCC (natural gas combined-cycle) capacity Dom has just built. Which plants will be cut back? Coal, of course.”
If there’s a problem with RGGI, suggest Shobe, it’s that the cap will be set too low. The Department of Environmental Quality, which is guilty of its own forecasting errors, is proposing a cap of either 33 or 34 million tons. “That is actually quite high,” Shope says. “If the cap is greater than about 30 million tons, Virginia will likely be a net exporter of allowances into RGGI at least for the first few years and the cap, and maybe for quite some time. … This delays compliance costs until well into the future.”
Shobe calls Dominion’s demand forecast “a work of fiction.” Dominion’s econometric model is “shockingly poor.” “If an undergraduate handed this in as a final project for a class, they would be retaking the class.” A more realistic forecast, he contends, would show “much lower levels of leakage, much lower rate impacts, and lower costs of compliance generally.”
Dominion’s Thomas is familiar with Shobe’s criticisms, but he sticks with his methodology. “Our load forecasting process is well documented. It’s been reviewed by [State Corporation Commission] staff on numerous occasions, and reviewed by an independent source, Itron,” a technology consulting firm that serves the utility industry.
Market forces are propelling the switch from coal to solar, wind and natural gas, which means CO2 emissions will continue to decline whether Virginia participates in RGGI or not. Observers with perspectives as divergent as Bob Thomas and Bill Shobe agree about this. The question is whether RGGI’s caps will accelerate or retard cuts to CO2 emissions. One way or the other, CO2 output will decline substantially.
Meanwhile, DEQ is structuring Virginia’s participation so that rate payers will not bear any direct costs from the auctions, although a less efficient energy mix could in theory boost their fuel costs. Dominion provides a high-side estimate, about $50 million a year for ten years. Environmentalists think the number is inflated. In either case, $500 million is a modest number compared to the anticipated multibillion-dollar cost of modernizing the electric grid, disposing of coal ash, re-licensing four nuclear power units, installing millions of solar panels, and building a fleet of offshore wind turbines over the next couple of decades. Amid all the other forces at work, the cap-and-trade auctions will be background noise.
Perhaps the biggest impact of RGGI participation will be political. Governor Ralph Northam will be able to cite a tangible action he took to combat climate change. Environmentalists will notch a victory in their global warming crusade. Dominion will be able to blame the auctions for rising electric rates. Most Virginians won’t notice a difference.