Tag Archives: Wind power

Dominion Long-Range Plan: More Solar, More Gas

Dominion’s 15-year plan affirms more solar in Virginia’s energy future.

Dominion Virginia Energy filed this afternoon its 2018 Integrated Resource Plan (IRP), an updated 15-year strategic plan. The IRP reiterates the utility’s commitment to more natural gas and more solar power as a path to a lower carbon future. There’s a lot to cover here, so I will just hit the highlights today, and I’ll dig deeper into the report tomorrow.

The key assumption behind the plan is that “carbon emissions regulation is virtually assured in the future, either through new federal initiatives or through measures adopted at the state level.”

A proposed regulation from the Department of Environmental Quality, if adopted by the State Air Pollution Control Board, would make Virginia a participant in the Regional Greenhouse Gas Initiative, which would ratchet down carbon dioxide emissions by 30% over 10 years. “Compliance with carbon regulation could, unless mitigated by other public policies, lead to an increase of between $2.23 and $5.81 in 2018 dollars in the typical residential customer’s monthly electric bills by 2030,” stated the company in a press release.

The IRP also incorporates legislation enacted by the General Assembly this year, the Grid Transformation and Security Act of 2018,” under which earnings above the allowed return on investment would be plowed back into investments in renewable energy, energy efficiency, and smart grid upgrades. The plan contemplates construction of the 12-megawatt Coastal Virginia Offshore Wind project to demonstrate the viability of wind turbines off the Virginia coast, license renewal for the Surry and North Anna nuclear units, the roll-out of new energy-efficiency programs, and the possible retirement of older, less-efficient coal, oil and gas power plants.

Dominion’s press release highlighted the growing role for solar energy. Depending on Virginia’s regulatory path, the company could add 4,720 megawatts of solar capacity over the next 15 years — enough to power 1.18 million homes at peak sunlight, and a nearly 50% increase over last year’s 3,200 forecast.

To back up the solar farms when the sun isn’t shining, Dominion forecasts the need to build eight new gas-fired combustion-turbine (CT) units capable of producing up to 3,664 megawatts of electricity, enough to supply the needs of more than 900,000 homes. Unlike combined-cycle gas plants, which ramp output up and down slowly, the CT units provide surge capacity that can nimbly adjust to fluctuating solar and wind output.

The exact details vary with five scenarios reflecting different federal and state regulatory approaches. The scenarios include:

  • No CO2 tax — no new regulations, the least-cost baseline.
  • RGGI participation — compliance achieved by importing “more carbon intensive out-of-state energy and generating capacity;” $1.5 billion more expensive than the baseline plan.
  • RGGI (unlimited imports) — Virginia becomes a full RGGI member, CO2 allowances cost more; costs $3.71 billion more than the base-line plan.
  • RGGI (limited imports) — Virginia becomes full RGGI member, but builds low-carbon capacity rather than imports it; costs $4.04 billion more than the base-line plan.
  • Federal CO2 program — assumes federal CO2 legislation beginning in 2026; costs $3.09 billion more than the base-line plan.

Predictable flashpoints. Inevitably, there will be pushback in the environmental community to Dominion’s plan. First, skeptics likely will dispute the utility’s forecast for increases in peak electricity demand and the need for more generating capacity; Virginia, they will say, needs to deploy energy-efficiency measures more aggressively. Second, they will argue that the re-licensing of the four nuclear units is unneeded. Third, they might contend that battery storage will be more cost effective than gas-fired CT units in offsetting fluctuations in solar production. Fourth, they will say that Dominion is exaggerating the cost of CO2 regulation; indeed, they will argue that the RGGI carbon trading regime will have little impact on costs to rate-payers, and might even reduce their monthly bills.

I’ll dig into each of these issues in the days and weeks ahead.

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

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.

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

Rocky Forge Wind Project Stalled: No Buyer for Its Electricity

Simulated view of Rocky Forge wind project.

The developer of what could be Virginia’s first commercial wind farm has lined up all the regulatory permits it needs, but it hasn’t started site work yet because it can’t find a buyer for the electricity. Apex Energy will not start construction by the end of this year, as planned, on the Rocky Forge project in Botetourt County, reports the Roanoke Times.

“We’re working to find the right partner to commercialize Rocky Forge,” said Apex spokeswoman Brooke Beaver wrote. “We do not yet have a specific date for the start of construction, but are working steadfastly toward that goal.”

On the positive side, Beaver said a later start date would allow Apex to take advantage of “even newer technology that will make the project even more competitive.”

Project critic Steve Neas told the Roanoke Times that he believes the wind farm’s 75-megawatt capacity is not enough to make it attractive to either a power company shopping for renewable energy or investors willing to commit to the project. “My guess is that they’re having a hard time lining up people to buy their power.”

Continues the Roanoke Times:

Apex contended in its statement that with the latest delay, the company has “the opportunity to utilize newer turbine technology, making Rocky Forge even more competitive in the market and further decreasing the cost of the energy it can produce.”

“Virginia has experienced tremendous growth in solar energy in the past year, and we look forward to adding wind energy to the generation mix.”

Dominion, DONG Seal Deal on Two Offshore Wind Turbines

The yellow square in this Dominion graphic shows the location of the two wind turbines on the edge of the bloc that Dominion has leased for a large offshore wind farm.

Dominion Energy Virginia has signed a Memorandum of Understanding (MOU) with DONG Energy, the world’s largest offshore wind-power company, to build two 6-megawatt turbines off the Virginia Beach coast — a critical step toward opening up 2,000 megawatts of off-shore wind to development.

Dominion will own the $300 million project, while Dong has committed to delivering the project at a fixed price. A Dominion solicitation in 2015 yielded a low bid of $375 million, way higher than the company’s internal estimates. When a federal grant expired, creating even more exposure for the company, many observers gave up the project for dead.

But the Denmark-based DONG, which claims to have built 27% of the total offshore wind capacity in the world, is eyeing the U.S. East Coast. Besides working with Dominion, the company has formed a partnership with Eversource, a Massachusetts utility, and has committed to develop a major lease off the New Jersey coast. The MOU with Dominion gives the company “exclusive rights to discuss a strategic partnership” with Dominion Energy to develop the commercial site based on successful deployment of the initial test turbines.

“Virginia is now positioned to be a leader in developing more renewable energy thanks to the Commonwealth’s committed leadership and DONG’s unrivaled expertise in building offshore wind farms,” said Thomas F. Farrell, II, Dominion Energy CEO, in making the announcement earlier today at a Port of Virginia facility in Portsmouth.

“Today marks the first step in what I expect to be the deployment of hundreds of wind turbines off Virginia’s coast that will further diversify our energy production portfolio, create thousands of jobs, and reduce carbon emissions in the Commonwealth,” said Governor Terry McAuliffe, who also spoke at the waterside announcement. McAuliffe had pushed hard for the project behind the scenes.

So far, the only offshore wind turbines operating off the U.S. coast are a five-unit farm located off Block Island, Rhode Island. While that heavily subsidized project does have the distinction of being the first offshore wind power, no one expects it to provide an economic model for U.S. offshore development. The Dominion-Dong project could provide that model. 

The significance of the new Coastal Virginia Offshore Wind project is not in energy the turbines produce — only 12 megawatts — but in demonstrating how well they hold up under hurricane conditions off the East Coast.

DONG has extensive experience operating in the North Sea, which is known for its harsh weather, but wave and wind conditions off the Mid-Atlantic coast are different. “From a technical perspective, we’re very keen to learn about Mid-Atlantic weather patterns,” Francis Slingsby, in charge of DONG’s strategic partnerships, told Bacon’s Rebellion. Experience with the two demonstration turbines will guide design and construction of the estimated 2,000 turbines to come later. “When we put steel in the water,” he says, “we want to do it right.”

“We are excited to bring our expertise to America,” said Samuel Leupold, CEO of Wind Power at Dong Energy, in a prepared statement. (Leupold was unable to attend the announcement.) “This project will provide us vital experience in constructing an offshore project in the United States and serve as a stepping stone to a larger commercial-scale project between our companies in the future.”

Work on the project will begin immediately, and the two turbines are expected to go into operation by the end of 2020. The pace of construction will vary, depending upon factors such as weather and the migratory patterns of whales and other animals. The tips of the blades will reach higher than the Washington Monument, Dominion says, but simulations indicate that the turbines, located 26 miles from the shore, will not be visible to Virginia Beach beach goers.

A primary motive of building offshore wind is to provide an additional source of clean energy. While solar is taking off in Virginia, wind inside state borders has been relegated to small ridge-line projects in the western part of the state. The only way wind can be a major contributor to Virginia’s energy future is through development of off-shore wind.

Two thousand megawatts, if built, would be the rough equivalent to two state-of-the-art gas-burning power plants. The difference is that wind is not “dispatchable” — it generates power when the wind blows, not necessarily when Dominion needs it. Despite that drawback, the cost of offshore wind power is increasingly competitive with other sources, and utilities are increasingly confident they can handle the fluctuations in electricity output.

Assuming the two-turbine demonstration project turns out well, Dominion expects to phase in large-scale wind production in increments, Mark Mitchell, vice president-generation construction, told reporters. As turbines are added, the company would assess the ability of the Hampton Roads electric grid to accommodate the added volume of intermittent capacity. Dominion would make grid upgrades as needed.

McAuliffe has been a vocal proponent of renewable energy in Virginia. He also sees offshore wind as a potential economic boon for Hampton Roads. Over and above the potential for large-scale construction work, the Coastal Virginia Offshore Wind project would support hundreds of jobs in ongoing operations & maintenance.

Economic developers have touted the advantages of Hampton Roads, with its mid-Atlantic location, ports, and shipbuilding as a logical center for the U.S. off-shore wind industry.

“We’re optimistic, Virginia has what it takes” to attract companies in the wind-power supply chain, Slingsby said. However, he noted that the European wind-power industry has multiple industry clusters, so there was no reason to think that companies necessarily would concentrate in a single U.S. location like Hampton Roads. Factors that states can control are the ability to ramp up for a large-scale installation of wind turbines and to make skilled labor labor available. Wind farm technicians are one of the most exciting and fastest-growing blue collar occupations in the U.S. right now, he said.

Appalachian Power Nails Down 225 MW in Wind Power

Appalachian Power Co. is asking state regulators in Virginia and West Virginia to approve 225 MW of new wind generation from facilities located in Ohio and West Virginia.

The Roanoke-based electric utility, which serves roughly 1 million customers in Virginia, West Virginia, and Tennessee, already has 375 MW of wind generation, with another 120 MW coming on line in 2018. With the approval of the two new projects, the company would have a total of 1,000 megawatts of renewable energy (wind and hydro).

“We are continuing to transition to an energy company of the future and further diversifying our power generation portfolio. These acquisitions move us in that direction,” said CEO Chris Beam. “Direct ownership and operation of these facilities will give our employees new experiences in the planning, production and delivery of power from diverse generating assets as Appalachian continues to add renewable resources in the years ahead.”

The 175 MW Hardin Wind Facility will be located in Hardin County, Ohio, and the 50 MW Beech Ridge II Wind Facility will be in Greenbrier County, W.Va. Both wind projects are under development by Invenergy, LLC.

Bacon’s bottom line: I wondered why Appalachian, the bulk of whose service territory resides in Virginia, would acquire wind properties based in far-away Ohio. Spokesman John Shelpwich gave the following response:

Appalachian Power operates in both Virginia and West Virginia. Our customers share in plants in both states… hydro and natural gas plants here, coal plants in W.Va. Historically, we have also owned or partly owned plants in other states (generally coal) too. In this case, these two facilities were proposals that came out of the RFP we issued in 2016 for wind generation with a primary requirement being that the new plant had to be interconnected with PJM. Both of these are.

We had a number of proposals in response; these two — and one other that was also approved will be in Indiana that we will not own, but will purchase its output by long-term contract — provide our customers the best deals. (I will note that it has been hard to get a sizable wind facility constructed in Va. so far).

If you recall, the RFP for utility scale solar we issued earlier this year calls specifically for construction to be within our service territory in Va. or W.Va. We received numerous proposals for that RFP too and are reviewing the best opportunities.

The key sentence: “It has been hard to get a sizable wind facility constructed in Va. so far.”

The problem here is not obstruction or foot-dragging by Virginia’s electric utilities. Appalachian wants to own Virginia-based wind power. A big part of the challenge, I suspect, is the paucity of viable utility-scale wind sites. Also, wind farms in the mountains are strung along ridge tops, almost invariably stimulating resistance from locals who don’t want their views marred. If Virginians want more wind power, we may need to take a look at how local zoning codes empower NIMBYs and hamper wind development.

Another lesson: If you like wind power, you’d better like the transmission lines that enable electrons in Ohio and Indiana to flow to Virginia. As renewable wind and solar make gain an increasing share of Virginia’s electric power mix, Virginia needs to build out a highly flexible grid that can handle the intermittent power generation from those sources. That means investing in “smart” grid technologies. And it could well require building more transmission lines.

Electric Reliability and Energy Mix

 Portfolios with high mixes of coal, nuclear and natural gas have the greatest electric reliability.

The purple line shows the Composite Reliability Index (CRI) of different energy-mix portfolios. Portfolios with high mixes of coal, nuclear and natural gas have the greatest electric reliability. Portfolios with large wind components tend to be more reliable than those with solar.

Electric utilities in the 13-state PJM Interconnection regional transmission territory have a balanced resource mix — coal, nuclear, gas and renewables — that is “well equipped” to support reliable operation of the regional grid, PJM has found in a new report, “PJM’s Evolving Resource Mix and System Reliability.”

But continued evolution of the resource mix — particularly the decommissioning of coal and nuclear plants and increasing reliance upon natural gas and renewables — could create reliability issues in the future.

PJM is in charge of maintaining the integrity of the electric grid within its territory, which includes all of Virginia. The study analyzed a spectrum of “portfolios” with different fuel mixes to see how they would affect a variety of electric reliability attributes such as voltage control, frequency response, and the ability to ramp production up and down as needed.

Of particular relevance to the ongoing energy debate in Virginia, PJM found that portfolios with 20% or greater of solar energy in the fuel mix would be “infeasible” because they would be unable to reliably meet night-time requirements. There don’t appear to be any upper bounds for natural gas, but excessive dependence upon gas could create vulnerabilities under a “polar vortex” scenario of sustained, bitterly cold temperatures.

In Virginia, Dominion Virginia Power has emphasized the importance of fuel source diversity, including coal and nuclear. Dominion’s plans for nuclear, which include extending the longevity of its Surry and North Anna nuclear units by an extra 20 years and possibly building a third nuclear unit at tremendous expense at North Anna, have proven particularly contentious. Solar constitutes a small percentage of Virginia’s fuel mix but is fast growing, and environmentalists are pushing for a much bigger role.

Across the PJM region, notes the study, the fuel mix has become more evenly balanced over time. In 2005, coal and nuclear generated 91% of the energy on the PJM system. But between 2010 and 2016, extensive coal capacity was retired and replaced mainly with gas and renewables. PJM’s installed capacity in 2016 consisted of 33% coal, 33% natural gas, 18% nuclear and 6% renewables and hydro. PJM has said in the past that the transmission grid was flexible enough that it could accommodate up to 30% renewables.

Each fuel source has advantages and disadvantages in helping electric utilities balance electricity supply and demand while sticking to tight parameters for frequency and voltage. Coal and nuclear are less responsive to changes in demand, taking far longer to ramp production up and down. Wind and solar are easy to turn off but, due to the variability of the wind and sun, cannot be turned on at will. Natural gas tends to be the most flexible, and PJM’s most reliable portfolios include large contributions from gas. Electric batteries also would provide considerable flexibility, but PJM does not foresee them being deployed on a large scale within the time-frame of the study.

States the study:

  • Portfolios with the lowest unforced capacity shares of wind and solar tend to have the lowest composite reliability indices. (Note: “unforced capacity” refers to capacity in normal operating conditions as opposed to maximum “nameplate” capacity.)
  • Composite reliability indices generally improve as capacity shares of nuclear, coal and natural gas increase.
  • When coal and nuclear units are retired and replaced, portfolios with the highest composite reliability indices tend to be ones in which natural gas is the predominant replacement resource.

Bacon’s bottom line: PJM makes no judgment about the “best” fuel source mix, and it does not say that the most reliable fuel mixes are necessarily more desirable. If the goal is to increase renewables for reasons of reducing CO2 emissions, it is possible that some fuel mixes are reliable enough to accomplish both reliability and sustainability objectives.

Still, the PJM analysis suggests that high-renewable fuel mixes are “at risk for underperformance” and likely will need “additional technology requirements and/or new market rules” to ensure electric reliability.”