Tag Archives: Solar energy

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.

The Biggest Corporate Purchase of Solar Power in the U.S… Ever

Microsoft Corp. plans to buy about 60% of the energy production from a massive solar power project in Spotsylvania County to power its data centers in Virginia. The proposed 500-megawatt solar development, called Pleinmont, would include more than 750,000 solar panels on a 3,500-acre site, which, when completed, would be the fifth-largest solar site in the country.

“This is really important to Microsoft, and we think it is really important to Virginia for several reasons,” said Michelle Patron, director of sustainability for Microsoft. “This is going to be the largest corporate purchase of solar power ever in the United States. … We think this puts Virginia on the map for clean energy.”

The Pleinmont solar farm is being planned by Sustainable Power Group LLC, or sPower, which is a joint venture of Arlington-based AES Corp. and Canada-based investment fund AIMCo, according to the Richmond Times-Dispatch.

The project still requires approval by the State Corporation Commission. The commission has scheduled a public hearing in May and is soliciting public comments.

Microsoft has said that it has met its target to power at least 50% of its data centers with clean energy by 2018, and the company wants to achieve 60% clean energy by early 2020, says the Times-Dispatch. In 2016 the company had agreed to buy power from a 20-megawatt solar farm in Fauquier County.

Bacon’s bottom line: In all the excitement over grid modernization and the rollback of the electric rate freeze in recent months, I totally missed this story. But if Virginia is on track to build the fifth-largest solar facility in the country, and if the deal represents the biggest corporate purchase of solar power ever in the U.S., that’s a big deal!

Previous reporting by the Times-Dispatch noted that Pleinmont would sell its electricity into the PJM interstate wholesale power market to companies that want to offset their electricity consumption with power produced by renewable sources of energy.

Does this deal cut Dominion Energy Virginia out of the picture as an electric power generator? Does this represent a new strategic direction for Microsoft and other data-center companies, which are driving the growth in electricity demand in Virginia? In other words, is Dominion’s electric power-generating monopoly being eroded? Five hundred megawatts is a lot of electricity — roughly half the capacity of a new, state-of-the-art natural gas-fired power plant.

Or will Dominion swoop in later, as it has in several other solar deals, acquire the Pleinmont property, and count it towards its commitment to build 5,000 megawatts of solar power, as codified in the recently passed Grid Modernization and Security Act?

One more question: What does this mean for natural gas demand in Virginia?Data centers consume electricity 24/7, but solar power generates power only 12 hours per day (with output varying by the time of year). Where will the electricity come from in off hours? Do deals like this bolster or obviate the need to build any new gas-fired plants?

The Great Grid Grab

Who gets what from a Dominion-backed legislative package overhauling Virginia’s electric grid? At this point, there are more questions than answers.

Last week lawmakers friendly to Dominion Energy Virginia introduced sweeping legislation, The Grid Transformation and Security Act of 2018, which would increase investment in Virginia’s electric grid with the goals of increasing renewable energy, reducing power outages, and guarding against cyber-sabotage. Backers say the three-bill package also would restore rate-setting oversight by the State Corporation Commission after three years of a rate freeze, and return a cumulative $1 billion in refunds and rate reductions to customers over eight years.

The response from some of Dominion’s traditional foes was negative. Critics suggested that the legislation would neuter the SCC’s oversight powers even while nominally restoring them, thus allowing the utility to keep hundreds of millions of dollars due the rate payers.

“This bill is bad policy and dangerous, giving Dominion even more power over our lives and our future,” responded Tom Cormons, executive director of Appalachian Voices, a group that has helped lead the fight against Dominion’s Atlantic Coast Pipeline project, in a press release. “For far too long, the legislature has gone along with the monopoly’s plans, and it’s high time for our elected representatives to finally say ‘no’ to Dominion.”

In a Washington Post op-ed, Stephen D. Haner, a lobbyist representing the Virginia Poverty Law Center (and a frequent contributor to this blog), described the proposals as a “preemptive attack” on the SCC’s independence. “The outcome Virginia consumers should be hoping for is a return to full SCC authority and an almost immediate rate case to review the earnings during the recent regulatory holiday.”

However, environmental groups such as the Virginia Chapter of the Sierra Club, the Southern Environmental Law Center, and the Chesapeake Climate Action Network, which have combated Dominion over the pipeline, solar power, and coal ash disposal, have refrained so far from blasting the bill — at least in official statements. By packing environmental desiderata such as renewable power, energy conservation, electric vehicles, energy storage systems and microgrids into the bill, Dominion may have disarmed some of its critics.

The most comprehensive description of the package comes from Dominion. The summary that follows comes from an “overview” prepared by the company’s communications team.

Refunds and rate reductions. Refunds and rate reductions for rate payers  totaling more than $1 billion over the next eight years include:

  • $133 million in one-time credits.
  • $740 million in rate reductions achieved through elimination of the biomass rider and other riders.
  • $100 million annually from lower taxes resulting from the recently enacted federal tax reform.

State Corporation Commission oversight. The legislation restores SCC review of Dominion base rates but reviews base rates every three years instead of every two years, as it did before the freeze. The bill also adds SCC reviews before and after grid transformation investments are undertaken.

The legislation will reduce future riders (also called RACs, or Rate Adjustment Clauses), which are surcharges for new projects. States the Dominion summary: Before future riders can be added for new investments, the SCC will determine if there were overearnings. If there are overearnings, SCC will use them to offset the cost of future riders.

Grid transformation investments

The package allows for investments to build a more sustainable and resilient grid. These investments, summarizes the Dominion outline, aim to “reduce outages or restoration times, secure energy assets, enhance tools available to customers, and increase investments in renewable generation.” The investments can be grouped as follows:

Reliability investments

  • Automatically reporting of outages when they occur.
  • Prediction of certain outages before they occur so crews can be dispatched to equipment nearing failure.
  • Isolation of outages so fewer customers are impacted.
  • Reduction of voltage fluctuations to improve power quality for industrial and other customers.
  • Dispatch of crews more precisely to restore power more quickly.
  • Automated routing and restoration of service.
  • Better integration of renewable generation.
  • Installation of energy storage systems and microgrids
  • Strategic undergrounding of outage-prone lines.

Security investments Continue reading

Solar Projects Progress in Orange, Campbell

Speaking of Dominion Energy Virginia’s commitment to solar (see previous post)…

Apco commits to solar… Appalachian Power Co., Virginia’s second largest electric utility, has signed an agreement to purchase electricity from the 15-megawatt Depot Solar Center in Campbell County as part its shift from coal to renewables. The deal represents the utility’s first commitment to utility-scale solar.

“Appalachian Power is excited to announce the Depot Solar Center as we move forward with the diversification of our generation portfolio,” said President Chris Beam in a press release. “We are pleased that the facility will be built and operated within our service area and provide other benefits that new construction will bring to surrounding communities.”

Depot Solar was developed by Pasadena California-based Coronal Energy, which has a office in Charlottesville. The company will sell the electricity to Apco through a 20-year renewable energy purchase agreement.

Apco selected the project after issuing an RFP in January 2017. The company received 37 proposals. Depot Solar, which will connect to Apco’s grid at the company’s Rustburg substation, is expected to be operational by September 2019.

And Orange County, too… The Orange County board of supervisors approved the county’s first large-scale solar farm, voting unanimously for a special-use permit that will allow a 400-acre, 60-megawatt solar farm to be build along Route 20.

The project, which will produce enough energy to power the equivalent of 10,000 homes, is being developed by Reston-based SolUnesco, according to the Orange County Review. Among the 20 provisions attached to the permit was a requirement to obscure visibility of the facility from Route 20.

The project is expected to bring in $2.2 million to the county in machinery and tools tax revenue over the course of its 30-year life, and bring in an additional $10,000 per year in property tax revenue. Depending on the environmental permitting process, construction is expected to begin by the end of 2018 or early 2019.

Another Arcane Obstacle to Solar Power

Virginia Comptroller David Von Moll

Some of the barriers to solar energy in Virginia are tucked away in the bowels of state government and the byzantine rules by which it operates.

One obstacle, since resolved, was a state rule granting solar projects an 80% tax exemption from property taxes under the guise of pollution control equipment. One would think the tax break would improve the economics of solar projects, but through a circuitous set of linkages involving the calculation of the Composite Index used in distributing state education dollars (described here) local governments would lose tax revenue from solar deals, which discouraged them from granting the necessary zoning and permitting approvals.

Jim Pierobon, writing in Southeast Energy News, has identified another obscure regulation: “An accounting rule, as interpreted by the Virginia Comptroller, effectively prevents Virginia from using a financing option used by many local governments: contracting through long-term power-purchase agreements (PPAs) with third parties to buy electricity.”

In a solar PPA, a third party project developer owns the solar farm and contracts to sell electricity to buyers such as universities or state agencies that are unable to take advantage of solar tax credits. Without the credits, many solar projects do not pencil out, and will be never be built. Writes Pierobon:

The Comptroller currently interprets a PPA to be a lease of capital equipment, and thus a debt owed by the state. Under that scenario, solar developers don’t own the electricity that they supply. That means a developer cannot claim the existing 30% federal Investment Tax Credit.

Why the state Comptroller, David Von Moll, interprets PPAs to be capital leases is a unclear to many solar developers. Neither he nor his office responded to requests for comment.

The McAuliffe administration had planned to do 25% of the installed solar capacity in state facilities as third-party PPAs, but were told by the Department of Accounts that the state could not enter into long-term PPAs.

“We’ve been trying to educate [Von Moll and his staff] as much as possible. We’re just not there yet. It’s incredibly frustrating,” said Hayes Framme, Deputy Secretary of Commerce and Trade. “State governments work certain ways to make their decisions. It’s our job to try to convince them otherwise.”

To be fair to Von Moll, there is a thin and tenuous line between solar PPAs and solar leases. Here’s how Energy Sage describes the difference:

While the terms “solar lease” and “solar PPA” are used interchangeably on this page, and are very similar in practice, there is a key difference between the two. With a solar lease, you agree to pay a fixed monthly “rent” or lease payment, which is calculated using the estimated amount of electricity the system will produce, in exchange for the right to use the solar energy system. With a solar PPA, instead of paying to “rent” the solar panel system, you agree to purchase the power generated by the system at a set per-kWh price.

Von Moll, who has worked in various positions in the Department of Public Accounts for 22 years, oversees the state’s financial management and internal control policies. He may be part of the executive branch, but it appears that he doesn’t knuckle under to pressure from the governor’s office. Whether that’s a sign of rock-ribbed integrity or pure bull-headedness, I’ll let readers render judgment.

Inside the Facebook Solar Deal

As part of the $1 billion Facebook data-center deal, Dominion Energy Virginia will file a request with the State Corporation Commission to create a new kind of solar tariff called Schedule RF. (The RF stands for Renewable Facility.) The tariff, if approved, could be used by other big customers seeking renewable energy.

“We came together with Dominion Energy Virginia to create a new tariff that ensures renewable energy solutions are accessible not just to Facebook, but other companies as well,” said Bobby Hollis, director of Global Energy at Facebook in a press release issued last week. The tariff “opens the door to attracting more businesses and more jobs for the communities we serve,” said Robert M. Blue, president of Dominion’s Power Delivery Group.

Virginia is well positioned to win more data-center projects and, as major players in cloud services are committed to reducing their carbon footprints, there likely will be more Facebook-like deals in the future. Given the magnitude of data-center energy consumption — the Facebook facility is expected to consume as much electricity as 32,500 homes and the solar investment will run roughly $250 million — these deals could well influence Virginia’s energy mix and cost of electricity. Curious to know more about how the project is structured, I talked to Dianne Corsello, director of Dominion’s business development group.

At full build-out, Facebook will require 130 megawatts of electricity. Power consumption at data centers is fairly constant, but the output of solar farms varies with weather and time of day. Assuming the panels are equipped with trackers, which rotate to follow the sun and generate more power, the solar farms will generate electricity only 25% of the time. Consequently, Dominion will need to build about 300 megawatts total solar capacity. (By way of comparison, the utility’s state-of-the-art gas-fired power station in Greensville is rated at 1,588 megawatts capacity and generates electricity approximately 85% of the time.)

Dominion soon will issue an RFP to solar developers with the expectation of bringing the solar capacity online in 2019 and 2020, Corsello says. The utility will draw from multiple facilities, none larger than 150 megawatts in size.

The SCC must approve the Schedule RF tariff, just as it will have to approve the rates charged by each proposed solar facilities using Schedule RF. Facebook will pay the full retail rate plus an add-on for the purchase of renewable. Under the tariff Facebook will receive Renewable Energy Certificates certifying that the company has paid for renewable energy equal to the volume of electricity it consumed. Facebook’s payments for these certificates will help offset the higher cost of solar power paid by all Dominion ratepayers.

The 300 megawatts of solar capacity arising from the Facebook project will be over and above Dominion’s commitment to derive 15% of its electricity from renewable power sources by 2025.

Electric Coops Vet Community Solar Plan

Subscribers to a community solar program in the works by five Virginia electrical cooperatives would pay a rate premium of 42% to 45% to use clean, renewable energy, according to data released by the electric coops.

The five rural cooperatives, who may be joined by others in a State Corporation Commission (SCC) filing late October or November, have developed the plan for customers unable to install their own solar capacity to purchase solar through the coops. The rates primarily reflect the cost of building the solar capacity. They do not include any cost for administering the program, but they do cover transmission and line losses to the cooperatives.

The five electric coops include A&N Electric Cooperative, Central Virginia Electric Cooperative, Mecklenburg Electric Cooperative, Northern Neck Electric Cooperative, and Rappahannock Electric Cooperative.

Unlike like investor-owned utilities, such as Dominion Energy and Appalachian Power, Virginia’s electrical cooperatives are owned by their customers. Because they pay no dividends to shareholders and don’t answer to Wall Street analysts, they have more flexibility in the programs they offer, said Sam Brumberg, association counsel for the Virginia, Maryland & Delaware Association of Electric Cooperatives, in a conference call Thursday to solicit feedback from solar developers and other stakeholders.

Legislation enacted in the 2017 General Assembly session allows electric companies to create “community solar” programs in which power companies market and re-sell solar power built by independent solar developers. The programs must be approved by the SCC.

Numerous electric coop customers have expressed an interest in purchasing solar energy through the cooperatives, said Brumberg, and the community solar program will provide them with a choice they don’t have now. The voluntary program will provide customers “easy on, easy off,” one-year subscriptions, which will allow them to avoid the long-term financial commitment of installing their own solar.  However, the voluntary program is designed to recover its costs from its subscribers.

The program will guaranteed flat rates for at least three years. While the solar portion of the rate will remain fixed for longer periods, the distribution charge may rise. 

A major sticking point addressed in the conference call was affordability of the program for low- and middle-income (LMI) customers. Brumberg discussed the potential for subsidizing the rates for certain customers, perhaps through government grants, foundation grants, or involvement of a large commercial “anchor tenant” who could absorb a disproportionate share of the cost.

Bacon’s bottom line: These are the first figures I’ve found that indicate the  cost of community solar in the current economic environment. The 40% to 45% premium represents a significant hurdle to widespread market penetration. In effect, community solar represents a luxury good in the energy marketplace, a fact that the electric cooperatives indirectly acknowledge by their concern that LMI customers may be difficult to recruit.

Admittedly, the economics of solar are changing. The per-kW cost of solar is steadily declining. So is the cost of battery storage, which makes it feasible to store surplus solar-generated electricity and release it when needed. Moreover, the “fuel” cost of solar — essentially zero — will not increase, while the cost of fossil fuel alternatives, especially natural gas, most likely will rise over time. But as long as programs are voluntary, and as long as most customers value money in their hand today more than savings years from now, it will be a challenge to persuade them to pay the premium.

Buried Lines and Microgrids

Downed power lines in Puerto Rico. Photo credit: ABC News.

Virginia has enjoyed a welcome respite from meteorological history, having dodged full-fledged hurricanes since Hurricane Isabel struck the Old Dominion in 2003 and Hurricane Gaston in 2004. But sooner or later, we’ll get hammered again. After surveying the devastation of Puerto Rico by Hurricane Maria, made worse by the total collapse of the territory’s electric grid, we Virginians should be asking ourselves how well our electric grid would stand up to a Category 4 hurricane — and what can we do to make it more resilient.

Two potential actions come immediately to mind: burying distribution lines and decentralizing the grid.

Last year Dominion Virginia Power advanced a $2 billion plan to bury the utility’s most outage-prone and difficult-to-repair electric distribution lines to limit the loss of electricity during severe weather events and speed the restoration of electric power. The company said the improvements would cut disruption of service to customers in half after a major hurricane. While the State Corporation Commission approved a small-scale version of the plan, it rejected the full-scale proposal as not worth the cost to rate payers.

There are alternatives to burying electric lines, such as hardening sub-stations, installing sensors that provide early-warning detection of damage, and aggressively pruning trees along right of way. But with the example of a prostrate Puerto Rico before our eyes, one might be more inclined to err on the side of caution. The wisdom of the line-burial policy depends upon the numbers — the cost of burying the lines, the cost of the alternatives, the number of people affected, the likelihood of a major hurricane or other natural disaster, and the economic value lost due to disrupted electric service. I don’t know if anyone has assembled all those numbers, but the topic is serious enough that someone — Dominion, perhaps, or state government — should pull them together for the public to digest.

Others have suggested that Virginia should move toward a distributed electrical grid, less dependent upon central power stations and endless miles of transmission and distribution lines. A distributed grid would rely instead upon wind and solar, batteries, and microgrid technology that allows local circuits to operate independently of the larger system. In theory, local islands of electric power would function even if the larger system were thrown into disarray.

Slate magazine describes Higashi Matsushima, Japan, in the aftermath of the earthquake that knocked out the Fukushima nuclear power plant:

After losing three-quarters of its homes and 1,100 people in the March 2011 tremblor and tsunami … The city of 40,000 chose to construct micro-grids and de-centralized renewable power generation to create a self-sustaining system capable of producing an average of 25 percent of its electricity without the need of the region’s local power utility.

The city’s steps illustrate a massive yet little known effort to take dozens of Japan’s towns and communities off the power grid and make them partly self-sufficient in generating electricity.

Sounds great. But questions arise. How well would Americans function with only 25% of their electricity supply? Also, how well do solar panels hold up in 120 mile-per-hour winds? Some pro-solar sources on the Web say that panels are designed to withstand up to 140 m.p.h. Do those claims withstand scrutiny?

Another issue is what happens when a massive weather system blots out the sun for days at a time. Batteries might be able to store power for a day, but solar + batteries could leave leave owners of rooftop solar bereft of electricity until the storm front passes and the sun reappears. On the other hand, Inside Climate News reports that, while Hurricane Irma cut power to 6.7 million Floridians, homeowners with rooftop solar arrays did just fine.

If unbiased reporting and analysis backs up such claims, perhaps Virginia needs to discuss how to move more expeditiously towards a distributed grid. That would mean solving tricky issues like net metering — whether to charge rooftop solar owners for access to backup power from the larger grid. A mediation initiative is trying to work through that question now. Perhaps Puerto Rico’s plight will provide the stakeholders with a heightened sense of urgency.

Dominion Touts Economic Benefits of Pumped-Storage Project

“Technology Risks and Maturity Level of Energy Storage Technologies.” Graphic credit: Dominion 2017 Integrated Resource Plan.

A proposed pumped hydroelectric storage power station in Southwest Virginia would bring more than $576 million in economic benefits to the Commonwealth, including $320 million in economic impact for Southwest Virginia, according to a study prepared by Richmond-based Chmura Economics & Analytics and commissioned by Dominion Energy.

The hydroelectric project, proposed by Dominion Energy, would support 3,000 Virginia jobs during development and construction, including 2,000 in the coalfield region. Once in operation, the facility would produce about $37 million annually in economic impact for Southwest Virginia including $12 million annually in tax revenues for local governments in Southwest Virginia, states Dominion in a press release.

“We are very excited about the prospect of bringing another major capital investment to the coalfield region of Southwest Virginia,” said Mark Mitchell, vice president of generation construction. (Dominion already operates a hybrid coal-biomass generating plant in Wise County.) “The entire grid system will benefit from having this new generation once it comes online, and the local area will benefit from the jobs and economic benefits that will come from it.”

The Dominion press release did not address the potential impact of the pumped-storage project on Virginia rate payers. While the facility would entail a hefty up-front capital cost, it could generate electricity during periods of peak demand or, potentially, offset fluctuations in output by Dominion’s increasing fleet of utility-scale solar farms. In its 2017 Integrated Resource Plan, Dominion describes pumped storage as the most mature and economically feasible form of energy storage, adding that the “proven dispatchable technology … would complement the ongoing development of renewable solar and wind resources.”

While Dominion operates the nation’s largest pumped storage dam in Bath County, it had not indicated much interest in second major facility until this year when the General Assembly enacted a bill that encourages a Virginia utility to build a pumped-storage facility in the coalfields. The law would allow the utility to petition the State Corporation Commission to recover project costs as they are incurred rather than waiting until the project is complete. Legislators made no secret of the fact that they saw the project as a boon for the economically depressed coalfield region, and some speculated that the pumped-storage facility might be accompanied by extensive local investment in solar power.

A pumped storage facility uses gravity-fed water from an upper-level basin to a lower-level basin to power the generators during periods of peak demand, when electricity is most expensive, and uses electric power to pump the water back to the upper basin when electricity is cheap.

After examining more than 150 potential sites in far Southwest Virginia for suitable geology and topography, availability of water, proximity to electric transmission lines, impact on landowners and other factors, Dominion has selected a site in Tazewell County “for further study.” Should its in-depth, on-the-ground studies show the site to be not suitable, it has identified other candidate locations for the facility.

Another option, touted by coalfield legislators, was to use a mine cavity as a lower reservoir. Dominion has engaged Dr. Michael Karmis at Virginia Tech to evaluate the idea. “Based on information provided to Dominion Energy Virginia,” says the Dominion website, “the former Bullitt mine near the town of Appalachia was identified as a top site for evaluation and will be evaluated in the Virginia Tech study.”

The company website says that the project is “in its very early stages and the project’s final size and scope have not yet been determined.” After scrapping with landowners along the route of the proposed Atlantic Coast Pipeline, of which it is the managing partner, Dominion is “sensitive to the needs and concerns” of homeowners who might be impacted by a pumped storage facility, the website says. The company “will make every effort to keep them informed and work with them throughout the process.”

Bacon’s bottom line: While Dominion is careful to say that it has not committed to a pumped-storage project, the fact that it has commissioned a positive economic impact report suggests that it is laying the political/PR groundwork for one. Could this be a harbinger of a greater commitment by Dominion to solar and wind power in the future? Or does Dominion plan to sell electricity into wholesale markets to for purchase by other utilities with big plans for renewables? That’s another economic analysis I’d like to see.

The Long, Painful Slog to Resolving the Net Metering Debate

Graphic credit: SolaireGen

After a two-hour telephone discussion Thursday, participants in a “net metering” sub-group of the Solar Policy Collaborative Workgroup didn’t seem to agree on much other than which issues need to be resolved. But that represented progress of a sort toward promoting small-scale, distributed solar energy in Virginia by businesses, homeowners and nonprofits.

“These are very difficult and complex problems. We made a run at it last  year, and didn’t get there,” Mark Rubin, the Virginia Commonwealth University professor and mediator behind the policy collaborative, said at the beginning of the session. “From a process perspective,” he said at the end, “this has been a helpful, productive call.”

The solar policy group, which worked out compromise legislation enabling “community” solar in the 2017 session, tackled the net metering issue without success last year. Two-thirds of the way through the current year, the group still seems far from formulating a consensus on net metering. But the conference-call discussion Thursday, which included a diverse set of participants ranging from electric utilities to smaller solar developers and environmental groups, did at least illuminate the main fault lines of debate.

“Net metering” refers to the regulatory system governing how small solar power producers, usually businesses and households putting solar panels on their roofs, connect with power companies. Solar panels often produce more electricity than property owners can absorb during peak periods, and a policy question arises as to the terms and conditions under which they sell their surplus to the electric companies. Solar advocates say utilities should pay small producers the full retail rate. Utilities respond that (a) the full retail rate is higher than the wholesale price of electricity they can purchase on the open market, and (b) they should be compensated for maintaining the electric transmission and distribution grid that solar producers periodically draw upon.

Long a laggard in solar energy, Virginia now has a big pipeline of solar deals in the works, and environmentally conscious consumers soon will be able to purchase renewable energy developed by community groups and marketed and sold through the utilities. But most solar production is large scale generation in vast tracts farms owned and operated by the state’s electric utilities, Dominion Energy and Appalachian Power. Progress has been much slower for small-scale, rooftop solar for the masses.

The most intractable issue facing the net-metering workgroup centered on standby charges. While the impact of rooftop solar on Virginia’s electric grid is minimal now — less than 1% of the power supply — participants are looking 20 to 30 years down the road to when it could become a major contributor. If hundreds of thousands of customers generated most of their own electricity, cutting into utility revenues, other customers would be stuck with the cost of building and maintaining the distribution and transmission lines that even those with rooftop solar rely upon from time to time. To offset this erosion of market share, utilities want to charge solar businesses and households a stand-by charge amounting to several dollars per month.

Katherine Bond, Dominion’s senior policy adviser, noted that a minimum bill of $7 monthly would not cover the company’s costs.

Solar advocates and environmental groups counter that solar is cost positive — that solar has a value that benefits utilities. For example, solar panels emit no carbon dioxide emissions, thereby making it easier for states to attain regulatory goals. Also, peak solar production overlaps with peak electricity demand, reducing the need for utilities to purchase expensive, peak-load electricity on wholesale electricity markets.

These issues are all well known, as they have been hashed out in many other states. What’s not known are the particulars here in Virginia. Because each state has unique geography, solar exposure, and regulatory systems, cost-benefit numbers that might apply to California or North Carolina may not necessarily apply to Virginia.

Aaron Sutch, program director of VA SUN, expressed the view of many that he wants to see more data. “We really do appreciate a respectful dialogue,” he said. But he added, “We haven’t seen any data from the utility side on the issue of cost recovery. … This should be a data-driven process.”

Will Cleveland, a staff attorney with the Southern Environmental Law Center, agreed. “If you want stakeholder buy-in, present the data so we can see [that cost recovery] is a legitimate problem. It’s hard from an optics perspective to hear that you can’t share the data. It makes it hard for [solar] advocates to agree to any solution if the data isn’t provided.”

“I understand your point that you’d like it to be disseminated more broadly,” said Rubin, the lead mediator of the workgroup. Core members of the net metering sub-group have been exchanging detailed data. But due to the proprietary nature of the data, participants have been held to strict confidentiality. Perhaps, once a particular path forward has been chosen, it might be possible to share more detailed data, he added.

A related issue is the necessity of attributing a monetary value to the positive impact of rooftop solar.  It wasn’t clear from the discussion whether the electric utilities had any data to formulate an estimate.

The sub-group discussed other, seemingly less contentious, issues. No one voiced opposition to the proposition that anyone investing in solar energy today should be grandfathered, or protected, from changes in the law that would harm the financial return on their investment. Rubin said Virginia needs to create a “glide path” to a new system. “How do you go forward without hurting those people who have already committed to solar?”