Category Archives: Energy

PJM to Analyze Long-Term Grid Resilience

PJM Interconnection, operator of the regional transmission grid of which Virginia is a part, says the electric grid handled the 12-day bout of extreme cold weather in January with plenty of margin to spare. But given the evolving energy mix in the multi-state region serving 65 million Americans — more gas, wind and solar, less coal and nuclear — PJM has embarked upon an analysis to assess future fuel security.

“The PJM grid remains reliable even with the resource retirements analyzed to date and investment in new, increasingly more efficient gas-powered generation sources,” said the grid operator in a press release yesterday. “While the grid also remains fuel secure given these changes, the potential for continued evolution of the fuel mix underscores concerns … about the need to examine the long-term resilience of the grid.”

PJM’s initiative follows findings by the National Energy Technology Laboratory (NETL) last month that a surge in coal-generated electricity helped the Mid-Atlantic and Northeastern regions get through the Bomb Cyclone deep freeze, while nuclear, gas, wind and solar output remained largely static. NTEL argued that gas-fired electricity output was somewhat constrained by pipeline capacity and the necessity of competing with natural gas as a home heating fuel. PJM responded that demand for gas pushed up the price to the point where coal became cost competitive to burn, but there never was a shortage of gas.

That’s this year. What about the future as the energy mix continues to evolve? Virginia appears poised to participate in the Regional Greenhouse Gas Initiative (RGGI), a cap-and-trade market designed to ratchet down utility carbon emissions by 30% over 10 years. For participating states, that will require the phasing out of power plants reliant upon the most carbon-intensive energy sources, coal and oil. Furthermore, increasing production of wind and solar power continue to undermine the economics of nuclear power. Here in Virginia, environmental and left-wing activist groups have signaled their opposition to re-licensing the Surry and North Anna nuclear plants over the next decade or two. Bottom line: the long-range energy mix could be far more dependent upon gas and renewables than it is today.

PJM places a premium on fuel diversity as a way to mitigate risk. “No generation resource is free from risks that can negatively impact the electric power sector,” states a 2017 report, “PJM‘s Evolving Resource Mix and System Reliability.” “These risks are global and can affect any geography or political construction.”

However, in an analysis of a wide variety of power-source portfolios with different mixes of coal, nuclear, gas, wind, solar and “other,” the study found that “natural gas and, to a lesser degree, coal” contributed more to system flexibility and reliability than the competing power sources. The study drew no conclusions regarding an ideal power-generating portfolio. In other reports, PJM has said that the existing transmission system can accommodate up to 30% contribution from wind and solar.

PJM’s new analysis will involve three phases:

  • Identify system vulnerabilities and determine attributes such as dual-fuel capability that can ensure that peak demands can be met during extreme scenarios.
  • Model those vulnerabilities as constraints in PJM’s wholesale market for guaranteed capacity.
  • Work with federal agencies to ensure that PJM is meeting security needs for military installations.

Stated the press release: “The intent of the vulnerability assessment is to stress-test the system under various fuel supply disruption scenarios to better understand potential future reliability concerns.”

(Hat tip: Allen Barringer)

Emerging Lines of Conflict in Virginia Energy Policy

The General Assembly may have ushered Virginia’s energy sector into a new era with its passage of the Grid Transformation and Security Act of 2018, but the battle over energy policy is far from finished. It’s just entering a new phase under new ground rules.

New battlefronts are emerging over energy efficiency and onshore wind power, and the potential exists for controversy to erupt over the necessity (or non-necessity) of preserving coal and nuclear generating capacity.

The grid-modernization legislation declared it a matter of public benefit to promote clean solar and wind power, to invest in energy efficiency, and to upgrade the electric grid so it will be more secure and better able to handle intermittent power sources like wind and solar. To pay for these priorities, the General Assembly agreed to let Dominion Energy and Appalachian Power Co., reinvest earnings over and above allowable rates of return instead of returning the money to rate payers.

The ink has hardly died on the governor’s signature on the legislation before new conflict points became painfully clear.

Energy efficiency. The new law commits Dominion to spend $870 million on regulated efficiency programs over the next 10 years and contribute $6 million annually to a state weatherization fund — and that doesn’t include money spent by Apco. Advocates of a low-carbon energy future envision funds flowing to programs that allow customers to buy smart thermostats, add insulation, and replace inefficient lighting and appliances.

“Unfortunately, all of that potential could easily slip away,” Chelsea Harnish, executive director of the Virginia Energy Efficiency Council, told Energy News Network. Likewise, Harrison Godfrey, executive director of Virginia Advanced Energy Economy, said he is “not convinced utilities will invest in technologies that are real game-changers.”

It seems to have dawned upon energy-efficiency advocates that the real obstacle is not the electric utilities but the State Corporation Commission, which takes a hard-nosed view on the value of energy-efficiency programs. Last month, SCC staff rejected a lighting program, appliance recycling program, and three other proposals submitted by Apco on the grounds that they did not pass cost-effectiveness tests.

“I think there is a concern that the SCC will continue to ov­­erly scrutinize these programs in a way that they’ll continuing being rejected,” Harnish said.

Energy efficiency advocates say the conservation programs will reduce electricity demand, thus delaying the need to add new generating capacity at great expense to rate payers. But the SCC likes to see solid evidence that the programs actually deliver the promised benefits at reasonable cost to rate payers. The big question: Now that the General Assembly has declared energy efficiency to be in the public interest, will the SCC modify its cost-benefit methodology and become more receptive to utility submissions?

Photo credit: Kent Mason

Onshore wind power. In an effort to create a lower-carbon electric generating portfolio, Apco announced plans last July to buy the Beach Ridge II Wind Facility in West Virginia and the Hardin Wind Facility in Ohio. The company proposed to finance the development of the two projects with an $84.6 million construction surcharge spread out over 10 years to ratepayers.

According to the Charleston Gazette-Mail, in early April the SCC denied Apco’s request to recover its costs from Virginia ratepayers. The commission said the company doesn’t need the additional power generation.

Apco argued that its electricity-demand forecast expects CO2/greenhouse gas regulation to be implemented by 2024. Indeed, Virginia appears to be poised to participate in the Regional Greenhouse Gas Initiative (RGGI), a regional cap-and-trade program that would shave Virginia utility CO2 emissions by 30% over 10 years. Final regulations are being drafted for approval by the State Air Pollution Control Board.

“The Companies would be justly faulted if, in their planning, they ignored likely and expected developments simply because they hadn’t yet occurred,” Apco said. “There are many influential elements in American society today that favor such regulation.”

Still, the SCC appears to be acting as a guardian of the rate payer’s interests, and it needs to be persuaded that the acquisition or construction of new power sources can be economically justified. Whether the Grid Transformation and Security Act changes the commission’s calculus remains to be seen. Continue reading

Gas Pipelines in Virginia’s Reconfigured Energy Future

The furor over construction of the Atlantic Coast Pipeline (ACP) and the Mountain Valley Pipeline (MVP) continues unabated this week. News reports have highlighted legislators in Richmond joining pipeline protesters outside the state Capitol and, more colorfully, the antics of a dissident known as “Red” who has ensconced herself in a tree to block clearance of the pipeline route. But the combatants and the media are overlooking the biggest story of all — how the pipelines fit into Virginia’s energy future defined by electric grid modernization and carbon cap-and-trade.

The immediate issue revolves around state regulation of pipeline crossings over mountain streams in the pipeline paths. Foes worry that construction on steep, erosion-prone mountain slopes in karst terrain marked by sinkholes and underground streams will cause sediment runoff to harm wells and other water supplies. State Sen. John Edwards, D-Roanoke, expressed the apocalyptic views of many when he said that the proposed 303-mile Mountain Valley Pipeline “could ruin our way of life.”

ACP spokesman Aaron Ruby reiterated the pipeline’s assertion that the 600-mile pipeline had received “the most thorough regulatory review of any infrastructure project in Virginia history.” In its 25-year history as an agency, confirmed a Department of Environmental Quality spokesperson earlier this month, DEQ has never conducted a project review on the scale of either pipeline.

But pipeline foes say that the regulatory views still aren’t rigorous enough and that DEQ should issue permits for hundreds of individual stream crossings to address the unique conditions at each site.

That line of argumentation led to what may be the best rhetorical flourish of the entire controversy (sympathize with him or not) by Dennis Martire, mid-Atlantic vice president of the Laborers International Union of North America. Martire termed the call for more intensive review of water crossings an attempt to “distort and politicize” the regulatory process. “No doubt,” he said, “the next thing they’ll demand is a pebble-by-pebble analysis.”

The battle over the pipelines has become a stand-in for the larger fight over national energy policy, sucking in the emotional energy of the global warming controversy. Foes say that there is no public necessity for either pipeline. Instead of building infrastructure that transgresses landowner rights and cuts ugly swaths through pristine mountain vistas, Virginia should be pushing measures to improve energy efficiency and install more wind and solar.

Proponents stand by their assertion that natural gas, while not a zero-carbon source of electricity, is a low-carbon source of electricity, a complement to wind and solar power, and a necessary part of Virginia’s energy future. Opposition to the ACP pipeline, says spokesman Ruby, “will slow down our region’s transition from coal to cleaner energy sources, delaying improvements to our environment.”

The ACP and MVP were launched in 2014 under very different political, regulatory, and market conditions than today. The Obama administration, which took global warming very seriously, looked favorably upon natural gas as a lower-carbon alternative to coal and upon nuclear power as a zero-carbon energy source. At the time, it seemed eminently reasonable for electric utilities to plan to further shift their generating portfolios from coal to gas and to increase pipeline capacity to serve their service territories.

But the environmental movement leapfrogged ahead of the Obama administration. The leading edge of the green movement ceased regarding natural gas as a benign fuel, arguing that if one included methane leakage from gas wells and pipelines, not just the combustion of gas in power plants, the fuel contributed as much to global warming as coal. They contended that Virginia lagged other states in embracing energy-efficiency and that the potential existed to bend the demand curve much lower, obviating the need to add new gas-fired generating capacity. Some environmental groups, but not all, went so far as to advocate that Virginia phase out its nuclear units as well.

The ideas expounded by green progressives, which once seemed radical in the Old Dominion, have gone mainstream. Virginia is in the process now of adopting carbon cap-and-trade regulations designed to reduce utility CO2 emissions 30% by 2030. Meanwhile, the Grid Transformation and Security Act enacted this year has declared it to be in the public interest for Dominion Energy Virginia to build 5,200 megawatts of solar energy, or roughly one quarter of its electricity generating capacity, and to invest heavily in energy efficiency. These regulatory developments have been amplified by the increasingly competitive economics of wind and solar.

Both the ACP and the MVP have gone so far down the regulatory path that there’s almost no chance that the projects won’t be built, so the point may be moot now. But I think it would be a useful exercise to take a fresh look at the pipelines in the light of current regulatory realities to see how they might contribute to the optimal balance of cost to rate payers, environmental sustainability, and electric grid reliability.

The least discussed of this triad is reliability. But reliability, arguably, is the most important — cost and environmental considerations fast become secondary when the lights go out. The East Coast successfully rode out an extreme cold weather event this January, but the so-called bomb cyclone did put enormous stress upon PJM electric transmission system of which Virginia is a part. PJM handled the challenge just fine, but only by calling heavily upon the surge capacity of fossil fuels such as coal and gas, while continuing to rely on the steady input of nuclear. The problem in the future is that coal and nuclear plants in many parts of the country are shutting down.

I have seen no analysis that tells us what reliability looks like under Virginia’s new regulatory regime of 25% or more of intermittent wind and solar, 30% fewer carbon emissions and a commensurate reduction in coal and/or gas, bigger investments in energy efficiency with a resulting bending of the demand curve, and a possible phase-out, desired by some, of nuclear power. Will Virginia burn more natural gas or less in its energy future? And looking back in that light, will Virginians be happy or unhappy that the MVP and ACP were built?

Beats a Poke in the Eye with a Sharp Stick

Critics are furious that Dominion Energy Virginia and Appalachian Power Co. won’t be returning all of their excess profits to rate payers, but this year Virginians will enjoy modest rate reductions nonetheless.

First, the two power companies will return savings made possible by the federal 2017 Tax Cuts and Jobs Act tax reductions — $125 million from Dominion and $50 million from Apco, the State Corporation Commission (SCC) announced yesterday. The rate cut will be effective July 1.

Second, Dominion will issue a one-time $133 million refund to customers, also effective July 1, in accordance with the state’s Grid Transformation and Security Act of 2018. Dominion will issue a one-time, $67 million refund next year.

Although no authoritative accounting has been done, the refunds are likely to fall considerably short of what Dominion earned in excess of normally allowable earnings during the three years of the 2015 rate freeze. Instead, under the new law, Dominion will reinvest its over-earnings in renewable energy projects and upgrades to the electric grid.

Bacon’s bottom line: The Grid Transformation Act was highly controversial and hotly contested. I hope it’s somebody’s job to track the costs and benefits of the legislation. Here at a minimum is what the public needs to know: (1) What are the over-earnings each year, and how will Dominion invest them? (2) What is the expected payback of those projects, either in lower costs, greener energy, or improved reliability? and (3) what is the actual payback of those investments?

Mighty Morphing Power Turbines

If Virginia ever develops a large fleet of offshore wind turbines, we may have a team of researchers led by the University of Virginia to thank.

Funded by the Advanced Research Projects Agency-Energy, the research team expects to build prototypes this summer for a 50-megawatt offshore wind turbine that is nearly six times more powerful than the record-setting turbine deployed off the coast of Scotland in April, reports Greentech Media.

The massive turbine takes a radically different approach to wind turbine design. Conventional turbine blades face the incoming wind. By contrast, blades for the Segmented Ultralight Morphing Rotor (SUMR) would face downwind and fold together as the wind force increases. The design was inspired by palm trees, which have evolved to survive hurricane-force winds. And surviving hurricane-force winds is exactly what the SUMR is supposed to do.

One of the major barriers to developing a wind farm off the south Atlantic coast is the uncertainty of whether conventional turbines, which can withstand North Sea gales, would hold up to extreme hurricane winds. Before Dominion Energy Virginia is willing to build scores of turbines off the coast of Virginia Beach, it wants to erect two turbines in the so-called Virginia Offshore Wind Technology Advancement Project (VOWTAP) to test a hurricane-resistant design. But the utility was unable to get the project cost, last estimated at $300 million, low enough to win approval by the State Corporation Commission. The project has been effectively shelved.

The ultralight SUMR blades will be 200 meters long, almost twice as long as conventional blades, but will be possible to assemble in pieces, thus avoiding problems shipping them from the factory site to the project site. Because the blades would be constructed of more malleable materials, they also would be capable of morphing downwind.

“We’re trying to have the turbine blades be more aligned along the load path, so we can get away with lower structural mass and have less fatigue and less damage,” said Eric Loth, chair of the department of mechanical and aerospace engineering at UVa and project leader.

The UVa-led consortium plans to test its turbine this summer at the National Wind Technology Center in Colorado and complete the design within a year.

Loth, the design leader, hopes that the new turbine will be transformative. The innovative design could reduce the levelized cost of offshore wind energy by as much as 50% by 2025, he says. “We need to come up with turbines that are not necessarily more efficient but will cost less to build and maintain.”

Bacon’s bottom line: If this research pans out, Virginians should thank their lucky stars that Dominion didn’t commit to spending billions of dollars on what in retrospect can be viewed as risky and outmoded wind technologies. Hopefully, this project will spark renewed interest in offshore wind. It would be doubly cool if Virginia could not only participate in the creation of the SUMR blades but be the first to deploy it on a commercial scale and the first to reap its benefits.

As we think about Virginia’s long-term energy mix (see previous post), we should factor the potential of this new wind technology into the equation.

Correction: Al Christopher, director of the state Department of Mines, Minerals and Energy, informs me that the VOWTAP project has not been shelved. Rather it morphed last July into Virginia Coastal Offshore Wind. “Dominion has said publicly several times recently that it plans to file for cost recovery with the SCC very soon.”

No, Coal Did Not Save the Grid in January


Contrary to a recent report that coal-generated electricity prevented a system collapse during January’s “bomb cyclone” deep freeze, PJM Interconnection, the regional transmission organization of which Virginia is a part, says it had plenty of reserve capacity. The reason PJM dispatched so much electricity from coal-fired units was that it was cheaper than electricity generated by natural gas, the price of which surged during the cold spell — not because there were inadequate supplies of gas.

“Natural gas and nuclear units were not unreliable or otherwise unavailable to serve increased customer demand, nor would PJM have faced ‘interconnected-wide blacksouts’ without the particular generating units dispatched, states PJM in a response forwarded to U.S. Energy Secretary Rick Perry. (Hat tip: Albert C. Pollard, Jr.)

Last week Bacon’s Rebellion summarized key findings of a report by the National Energy Technology Laboratory (see “How Coal Saved the Electric Grid,”) which noted that coal-fired generation increased dramatically during the extreme, 12-day chill. Nuclear energy output didn’t change (nukes run flat-out all the time, regardless), wind/solar output declined slightly, and gas output was constrained by pipeline constraints and other factors. The NETL report argued that without the backup coal capacity, “a 9-18 GW shortfall would have developed, depending on assumed imports and generation outages, leading to system collapse.”

But PJM says that the regional electricity transmission system maintained significant reserves during the bomb cyclone. “PJM reserves were over 23 percent of peak load demand, and there were few units that were unable to obtain natural gas transportation.” The reason coal-fired output leaped was that it was cheaper than gas — not that the gas was unavailable.

During the cold snap, the region experienced an increase in the price of natural gas, which made coal resources (which often did not run under periods of lower natural gas prices) the more economic choice during times of high gas prices. But one cannot extrapolate from these economic facts a conclusion as to future reliability within PJM. …

The fact that additional coal resources were dispatched due to economics is not a basis to conclude that natural gas resources were not available to meet PJM system demands or that without the coal resources during this period the PJM grid would have faced “shortfalls leading to interconnect-wide blackouts.”

The PJM report did confirm other parts of the NETL analysis. Electricity from nuclear power plants stayed constant through the 12-day weather event. Wind and solar output declined ever-so-slightly. And natural gas did suffer minor supply-related outages… but they accounted for less than 2% of the total load requirement at the time.

Bacon’s bottom line: Coal-fired units kicked in 13,000 megawatts of additional output during the deep freeze. That was roughly one-third of the system’s 32,600 megawatts in reserve capacity. In the absence of the coal surge, customers in Virginia and across the multi-state PJM system would have paid more for their natural gas, but they would not have faced blackouts in January. It seems safe to say that the impression created by the NETL analysis was wrong.

But PJM did not address the longer-term outlook in its report. The political reality is that in the U.S. and in Virginia, powerful interest groups seek to curtail coal production. There is a strong likelihood that Virginia will enter the Regional Greenhouse Gas Initiative, a cap-and-trade arrangement designed to cut carbon emissions, most likely through the closure of additional coal plants. Looking out a decade or more, some environmental and consumer groups oppose the plans of Dominion Energy Virginia to re-license its four nuclear power units that currently produce 30% of the company’s electric power. Furthermore, the same groups, worried by the contribution of natural gas to CO2 emissions, want to slam the door on construction of any more gas-fired power plants.

As can be seen in the chart above, which details the breakdown of electricity by fuel type in the PJM system before and during the deep freeze, coal and nuclear accounted for 65% of the interstate region’s electricity production before the event and 66% during the cold snap.

Put another way, coal accounted for 45,900 megawatts of system-wide output during the freeze, and nuclear contributed another 35,400. Compare that to the system’s 32,6oo megawatts in reserve capacity.

While PJM has plenty of reserve capacity today, we have to ask ourselves, will the system have plenty of reserve capacity 10 or 15 years from now if coal- and nuclear-powered units continue to shut down? While the pipeline capacity exists today to supply today’s natural gas demand, will it be sufficient to meet demand when gas picks up much of the load for shuttered coal and nukes? While we can always purchase out-of-state electricity through PJM, will there be sufficient transmission-line capacity to get that electricity to Virginia load centers?

I don’t know the answers to these questions. Perhaps everything will turn out fine. But we can’t assume that it will just because PJM has ample reserve capacity today. As Virginians calibrate the balance between coal, nuclear, gas, hydro, solar, wind and battery storage, we need to consider the long-term outlook. The future will be upon us before we know it.

Leveraging Offshore Gas Drilling to Build Offshore Wind

Can allowing this…

The Trump administration is opening up the East Coast of the United States to oil and gas drilling, but it’s not clear how much enthusiasm there is. A recent sale of drilling rights in the Gulf of Mexico has attracted only “moderate” interest, reports the Financial Times, an indication that the oil & gas industry is more focused on expanding production in the country’s vast shale basins.

… help us get to this?

Last year the Department of the Interior cut the royalty rate it had been charged on production from leases in shallow water (less than 200 meters deep) from 18.75% to 12.5% in the hope of stimulating greater interest. But drillers submitted bids for only 148 of 14,000 tracts offered.

If the Trump administration can’t gin up much excitement in the Gulf of Mexico, where a mature oil & gas exploration and drilling infrastructure exists, it’s unlikely to do any better in the southern Atlantic states where no such infrastructure is to be found. Also discouraging interest is the reality than any effort to start drilling would ignite a firestorm of opposition. Why bother when shale can be fracked elsewhere with minimal fuss and muss?

But that’s today. Who can say what economic conditions and public opinion will look like in three or four years? What if public opinion could be swayed to look upon offshore drilling as a pathway to developing a viable offshore wind industry?

Environmental groups and Virginia Beach civic interests oppose offshore drilling, raising the specter of another Deepwater Horizon disaster — even though (a) any drilling off the Virginia coast would be in shallow water, while Deepwater Horizon occurred in… you guessed it… deep water, and (b) most, if not all, of the drilling would be for natural gas. I’ve never heard of a natural gas spill, and neither have you.

Indeed, the Commonwealth’s official energy policy supports offshore oil and gas drilling, with the caveat that no drilling occur within 50 miles of the shore. A 2005 study by the Virginia Secretary of Commerce and Trade found that natural gas exploration was safe, although if oil is discovered that the Commonwealth must “carefully consider the risk of spills.”

Is it not possible to work out a compromise that could allow drilling to move forward when market conditions permit while providing tough environmental safeguards? Here’s how we can do it.

First, let’s just take oil drilling off the table. Let’s make it official Virginia policy to permit no oil drilling because we want zero risk of oil spills. Drilling and production should be limited to natural gas only. (Do some wells produce both oil and gas? Can the gas in such wells be extracted while the oil is kept in the ground? I concede that some technical questions may need to be answered.) The vast majority of the energy wealth off the Atlantic coast is natural gas, so imposing an anti-oil restriction should not cripple the economics of offshore energy production.

Second, Virginia should get the first-mover advantage of establishing an East Coast offshore drilling industry. As the largest metropolitan area on the Atlantic coast between Miami/Fort Lauderdale and New York — and one with a large ship repair industry, at that — Hampton Roads would be the logical location for offshore companies to set up and do business. Thus, Virginia could get a significant economic-development bonus from the opening up of offshore drilling.

Third, an offshore drilling industry was the precursor in Europe to developing an offshore wind industry, and it could be the precursor in Virginia, too. The two sectors share many skills, competencies, services and specialized equipment. If Hampton Roads can develop an offshore drilling industry, it can lower the costs and risks of getting offshore wind companies to locate here. The lack of an existing industry is perhaps the biggest barrier to developing Virginia’s offshore wind resources — a desiderata of environmentalists and economic developers alike.

The immediate hold-up to large-scale development of wind resources is the need to test the performance of wind turbines in the Atlantic Ocean, which has different seabed conditions and is subject to hurricanes. That won’t happen until the State Corporation Commission approves Dominion Energy’s proposed VOWTAP project, two costly test turbines that could never be justified on the basis of their electricity production alone.

But if the SCC approved VOWTAP, and if the turbines proved their efficacy in Virginia offshore conditions, and if a gas drilling business ecosystem had a toehold in Virginia, then the chances would improve immeasurably to persuade European wind companies to invest in Virginia for the purposes of building and maintaining a fleet of offshore wind turbines at an economical price. Virginia then could become the hub of offshore wind production for much of the entire Atlantic coast.

If we play our cards right, it should be possible to fulfill former Governor Bob McDonnell’s dream of making Hampton Roads the energy capital of the East Coast while not only protecting the environment but improving it.

Pushing Forward Virginia’s Solar Future

Dominion solar facility in Buckingham County.

A couple of years ago, the rap against Dominion Energy Virginia was that it was hostile to solar power. That line of thought is harder to maintain now that Dominion is committed to build at least 5,200 megawatts of solar power — roughly a quarter of its generating capacity — by 2042. Dave Mayfield at the Virginian-Pilot has taken notice:

After many years as a laggard, Virginia has lately been emerging as a leader in the field.

Last year, it placed 10th among the states in new solar capacity installed, up from 17th the year before, according to a report compiled for the Solar Energy Industries Association. North Carolina ranked second, behind California.

The association projects that Virginia’s total solar generating capacity will more than triple over the next five years to roughly 2,000 megawatts – enough to power upwards of 200,000 homes.

Some industry officials and clean-energy advocates expect even-sharper growth during that time frame, and say the solar expansion almost certainly will accelerate across Virginia in the decades beyond.

I nearly fell out of my chair when I read this: “I think you’re going to see a lot more discussion about Virginia being a hot state for solar,” said Ivy Main, affiliated with the Sierra Club’s Virginia chapter who writes the “Power for the People VA” blog. Main has been relentlessly critical of Dominion’s approach to solar over the years.

So the rap against Dominion has changed. Now the criticism is that, yeah, 5,200 megawatts is pretty good, but 25 years takes too long to reach that goal. And, yeah, Dominion is building more solar, but it’s not opening up the grid fast enough enough to homeowners, small businesses and independent solar producers.

Regarding the first criticism: I expect Dominion’s enthusiasm for solar will increase in direct proportion to the falling cost of solar generation, smart grid technology, and battery storage. Just as the utility has gone from a minimal commitment to solar two years ago to a large-scale commitment today in response to changing economics and market forces — especially growing demand by data centers and large corporations for renewable energy — this “problem” will take care of itself. The main brake on solar adoption will be Dominion’s comfort level with integrating a huge solar fleet into its transmission and distribution systems while maintaining grid reliability during periods of peak demand.

The second criticism, opening up solar production to outside competition, is a thornier issue. Many companies would like a piece of Dominion’s electricity market (as well as that of Appalachian Power’s and that of the electric co-ops). These interlopers are nimble and innovative, and, given current price trends, they likely would be able to sell solar for less than the cost of generating electricity from coal, nuclear or even gas — if not now, then five years from now. If competition opened up as critics would like, Virginia’s incumbent utilities stand to lose significant market share.

But here’s the rub: Electric utilities are monopolies, and they are monopolies for a reason. They have the responsibility for maintaining the integrity and reliability of the electric grid. If the lights go out, the North American Electric Reliability Council, PJM Interconnection, the State Corporation Commission, and millions of customers will look to the likes of Dominion, Appalachian Power, and the electric co-ops to get them back on again. They won’t look to homeowners. They won’t look to the independent solar producers. They won’t look to the Sierra Club. The utilities are the ones with skin in the game.

Society and the utilities have struck a bargain: In exchange for ensuring the reliability of the system, society will grant them monopoly service territories and regulate them to provide an assured rate of return on their capital (absent incompetence on the utilities’ part). Reneging on that bargain and opening up the system to wide-open competition would undermine the utilities’ revenues and profits, exposing them to potentially massive write-offs. It should surprise no one that the utilities resist such an eventuality.

Ironically, Dominion led the charge for opening up the utility industry to competition some twenty years ago. The experience was widely judged to be a failure; little competition materialized. Then in recognition of that failure a decade ago, Dominion led the charge to re-regulate the industry in Virginia. We can debate the success or failure of the experience since then, but it does seem apparent that if the industry were deregulated in 2018, there would be plenty of competition on the power-generation side of the business — from merchant producers selling into the wholesale market, from entrepreneurs partnering with big corporations, from intermediaries buying wholesale electricity off the grid and re-selling it to retail customers, and from energy- and eco-conscious homeowners installing their own solar.

One approach to opening up the market for competition is to demonize the utilities. That’s a favorite trope of the Left, which is hostile to corporate power and profits to begin with. Another approach is to give thought to how to realign the incentives for Dominion, Apco and the electric co-ops to do the kinds of things society wants them to do — generate more renewables, allow more competition, invest in energy efficiency, etc. — and to realign them in such a way as to not trigger massive write-offs for power plants made obsolete by the changes. Virginia can choose an ideological route or it can choose a pragmatic path forward.

Under any scenario, building and maintaining the electric transmission and distribution remains a “natural monopoly” and would be subject to continued regulation. But deciding how to restructure electricity generation will be really complicated. In an ideal world, all power generators would sell into PJM’s wholesale market and the winners would be bidders who offer the best combination of price and sustainability. But if the incumbent utilities lose market share and revenues, who pays for cleaning up the coal ash ponds of coal-burning power plants? Who eats the cost of write-offs from obsolete generating units? Who pays to keep aging coal- or nuclear-power plants in reserve for back-up power? What are the implications of Virginia joining the Global Greenhouse Gas Initiative?

We haven’t begun to answer these questions. Indeed, only a handful of people are even asking them. After the exhaustive debate over the Grid Transformation and Security Act this year, there may be little appetite for any such conversations. But allowing for an appropriate respite from the recently concluded General Assembly session, perhaps we should begin the discussion.

Nukes and Renewal

Surry Nuclear Power Station

Should Dominion Energy re-license its four Virginia nuclear power units? The answer depends on your appraisal of solar power, energy efficiency and other alternatives.

Is there a future for nuclear power in Virginia’s long-term energy outlook?

Dominion Energy Virginia believes there is. Nuclear power currently contributes about 30% of the company’s electricity sales, and the company plans to continue generating power from its Surry and North Anna nuclear power stations for decades to come. Nuclear power, the company says, is reliable, provides fuel diversity, and does not emit carbon dioxide — a major plus as Virginia aims to reduce greenhouse gas emissions.

The utility’s 2018 Integrated Resource Plan, which peers 15 years into the future, assumes that the company will renew the licenses to operate the two nuclear-generating units at Surry and the two at North Anna. At the time of the license renewals, the units would be 60 years old. The nukes would continue to operate until they were 80 years old.

But many people think that renewing the licenses is a bad idea. While Dominion expects that refurbishing the four generating units would cost $3 billion to $4 billion, environmentalists and other skeptics suggest that the actual cost could run significantly higher. It doesn’t make sense to spend billions on nuclear power, they say, when solar energy costs less and is getting cheaper every year. While it is true that solar power is intermittent — it generates electricity only when the sun shines — the advent of low-cost batteries and the spread of electric vehicles, they claim, will make it possible to economically store surplus solar power for when it is needed.

Expect the debate to heat up when the Nuclear Regulatory Commission (NRC) begins processing Dominion’s re-licensing request for the Surry 1 plant. Dominion has filed notice of its intent to submit an application for a license renewal by the first quarter of 2019 — less than a year away. The review could take up to three years, and construction several years more.

License renewal for existing nuclear units is distinct from a proposal, also explored in the 2018 Integrated Resource Plan (IRP), to build a new nuclear unit at North Anna known as North Anna 3. Dominion has spent hundreds of millions of dollars in planning and engineering costs to keep that option alive. Estimates of the cost for building the third unit have ranged as high as $19 billion, and the IRP suggests that it would not make economic sense except in the strictest CO2-reduction regulatory scenario that would compel the shutdown of coal-generating capacity. The cost of building a third nuclear unit would be so high and fraught with so much uncertainty that opposition would be formidable no matter what the circumstances.

The re-licensing proposals are a different story. The up-front capital cost, though considerable, would be in the same ballpark as building new gas- or solar-powered generating capacity. Moreover, fuel costs would be more stable and lower over the long run than for the gas-fired facilities. Although there are no hard figures on what the impact on rate payers would be, no one disputes the fact that re-licensing Surry and North Anna would cost a fraction of building a new generating unit.

Flagships of the fleet

The two Surry units became operational in 1972 and 1973, capable of generating a total of 1,600 megawatts of electric power. In the early years the power station had some major operational issues. In 1972, two workers were fatally scalded by steam after a routine valve adjustment. And in 1986, a steam explosion due to internal erosion and over-pressurization injured eight workers, four fatally. But performance has been steady since then. Other than an incident in which a tornado touched down in the switching station, disabling power to the plant’s cooling pumps, Surry has operated largely without incident.

The two North Anna units went online in 1978 and 1980 with a combined capacity of almost 1,800 megawatts of power. The station has operated without major incident, except in 2011 when an earthquake centered nearby caused light damage and triggered an automatic shut-down of the nuclear operations.

The four nuclear units have formed the backbone of Dominion’s electric-generation portfolio. In recent years, North Anna has operated with top measures of efficiency and safety, garnering the highest ratings in inspections by the Nuclear Regulatory Commission every year but two. Surry and North Anna are consistently ranked as among “the lowest-cost producers of nuclear-generated electricity in the nation,” as reported periodically by Platts Nucleonics Week, a nuclear industry newsletter and database, says Richard Zuercher, manager-nuclear fleet communications.

While the nuclear units account for only 16% of Dominion’s nameplate capacity, they generate more than 30% of its total electricity output. That’s because they operate non-stop, twenty-four hours per day, seven days a week, almost 52 weeks a year, going offline only for planned refueling outages every 18 months or the the rare tornado, earthquake or other mishap. The 2018 IRP, as shown in the table above, assumes a capacity factor for the nukes of 96%, which compares favorably to 70% for combined-cycle gas plants, 42% for off-shore wind (assuming the company manages to build a wind farm off Virginia Beach), and 25% for solar. Thus a nuclear facility with a nameplate capacity of 1,000 megawatts generates 8.4 million megawatt hours annually compared to 6.1 million for natural gas, and 2.2 million megawatts for photovoltaic solar. Continue reading

Ruling Opens Electric Competition for Big Virginia Customers

Direct Energy Services Inc., a Houston-based retailer of electricity and energy-related services, is allowed to sell 100% renewable energy to large customers in Virginia without a restriction that would forbid customers from returning to their incumbent utility without a five-years’ advance written notice, under a Virginia Supreme Court ruling issued this morning.

The Supreme Court decision upheld a previous ruling issued by the State Corporation Commission against Dominion Energy Virginia.

“This appeal is about the intersection of these two subsections: What happens when a mega-consumer wants to buy from a green-energy company? Does that switch trigger the five-years-notice requirement, or not?” writes  Steve Emmert in his blog, “Virginia Appellate News & Analysis.” 

The bottom line: No, it doesn’t trigger the requirement.

The decision follows an SCC ruling two weeks ago that allowed Reynolds Group Holdings to aggregate demand from multiple properties to meet the 5-megawatt threshold required to purchase electricity from non-utility suppliers. Together, the SCC and Supreme Court rulings expand the options for large electric customers at a time when cloud providers and other major corporations are making big commitments to solar power.

The 5-year restriction, writes Emmert, “was likely designed to prevent bargain shopping on an annual basis, something that can play havoc with VEPCO’s planning.” The proviso also acted as a deterrent for companies thinking about purchasing renewable power from a non-utility. If a company wanted to preserve the safeguard of being able to switch back to Dominion, Appalachian Power, or an electric co-op, the inability to do so for five years added an element of risk.

Says Emmert: “This is clearly a win for those who seek greater competition in this field.”