How One Gas Plant Can Save Billions

Dominion Virginia Power's gas-burning plant in Brunswick County opened this year. The Greensville power station, scheduled to open in 2018, will be even more cost efficient.

Shown here: Dominion Virginia Power’s state-of-the-art, gas-fired generating plant in Brunswick County. The company’s Greensville facility will be even more cost efficient.

There’s more to the natural gas boom than fracking. Technology deployed at Dominion’s Greensville power plant will squeeze more electricity out of a BTU of gas than ever before. 

by James A. Bacon

Last month Dominion Virginia Power commenced construction of the $1.3 billion Greensville County Power Station. When it opens in late 2018, the facility could well be the most efficient gas-burning electrical power plant in the world. That one facility will save Dominion customers $2.1 billion over its 36-year lifetime, the company says, even as it emits less carbon dioxide per kilowatt hour than other gas power plants and only 40% of that of a coal-fired plant.

Even if stretched out over 36 years, $2 billion represents a significant savings from a single power station. The average savings of $59 million a year compares to $7 billion annually paid by Dominion’s Virginia and North Carolina rate payers.

Rate payers might wonder: How does Dominion calculate that $2 billion in savings. The station will save $2 billion compared to what? Those questions seem all the more germane in light of commonly heard arguments that investing in massive natural gas-fired power plants instead solar panels and wind turbines is a bad idea when the price of gas will only rise in the future and the cost of renewable energy will steadily decline.

“We see the potential for a lot of stranded costs to be put on consumers as emissions of carbon pollution and greenhouse gas emissions continue to be ratcheted down,” says Kate Addleson, director of the Sierra Club-Virginia chapter. Solar is not just non-polluting but in many parts of the country it’s the lowest-cost energy source. As solar technology improves and the cost per kilowatt hour continues to decline, solar could become the low-cost option in Virginia, too. While natural gas might look like an attractive option today, it may not be as gas reserves are depleted and prices rise. Says Addleson: “Dominion is pointing to the benefits of gas because that’s what they see as the best outcome for their profit margin.”

Dominion defends its commitment to natural gas as the best deal for rate payers. The Greensville County Power Station will save money two ways: (1) by extracting more energy value from each BTU of gas, and (2) by using its access to two pipelines to purchase cheaper gas.

Greensville will be the third “three on one” Combined Cycle plant in Dominion’s generating fleet, using waste heat from three gas-burning turbines to power a traditional steam generator. Incorporating the most advanced Mitsubishi Hitachi Power Systems turbines, Greensville will squeeze more electricity from 1,000 BTUs of natural gas than ever before.

Combustion at higher temperatures also releases less carbon-dioxide into the atmosphere. The Greensville plant will emit 780 pounds of CO2 per megawatt hour (MWh), an incremental improvement over the 790 pounds for the Brunswick plant and 2,100 pounds for a typical coal-burning plant. Mike Dowd, director of air quality for the Department of Environmental Quality (DEQ), noted that the air permit sets the limit at 813 pounds per MWh, the toughest ever set on a combined cycle, natural gas power station. Environmental groups claimed credit for the “stronger pollution protection” they lobbied for. But the real enabler of the stricter environmental standards was the same combustion technology that makes the facility so economical to run.

Glenn Kelly, director of Generation System Planning, walked me through Dominion’s methodology for calculating the cost savings. If Dominion did not build the Greensville plant, he said, the company would have to purchase the megawatts from wholesale electricity markets maintained by PJM, the regional transmission organization of which Dominion is a part. “PJM market is always an option. We can always buy energy and capacity there  – that’s our benchmark. ”

In the PJM wholesale market, utilities purchase capacity (the right to draw electricity, if needed) and energy (the actual electricity consumed) in day-before and same-day auctions. Prices vary by season, time of day, weather conditions, and other factors such as the volume of electricity being bought and sold at any given point of time and the ability of transmission lines to deliver the electricity to the consumer in different parts of the country. In all likelihood, Greensville’s replacement electric power would come from a mix of gas-fired, solar, wind, and other energy sources — whatever other utilities and merchant providers are willing to put on the market.

How does Dominion know what PJM will charge Dominion years in the future? It doesn’t. It relies upon its economic consulting company, ICF, to make realistic assumptions. ICF assumes that prices will fluctuate around the long-term cost (including a reasonable corporate profit) of generating the electricity, and that the cost of burning gas or building a solar panel can be estimated with some degree of reliability. “Gas prices are very volatile short-term,” says Kelly. Right now prices are depressed, running between $2 and $3 per million BTUs. ICF projects gas prices will likely climb to about $5.11 per million BTU by 2025. “We have it going up pretty fast.”

Many people are familiar with the fact that the cost per KWh of solar energy has gone down as solar panels get more efficient at converting sunlight into electricity, but few are aware how the cost of generating electricity from gas has gone down — and not just because of the fracking revolution that has flooded the market with gas. State-of-the-art power stations extract more electricity from the same amount of gas.

The G Class turbines installed in Dominion’s Brunswick County power station, which opened this year, are more efficient than the previous generation, says Bill Newsom, executive vice president-new generation systems with Mitsubishi Hitachi Power Systems Americas. They are about 59% efficient; that is, they extract about 59% of the energy value from the natural gas. The rest goes up the smokestack or is lost as waste heat.

Brunswick’s G Class turbines are an improvement from the old F Class machines, which are about 55% to 56%. But the Greensville power station, which will install Mitsubishi Hitachi’s new J Class turbines, should approach about 62% efficiency.

The key to achieving greater efficiency is burning the gas at ferocious temperatures, which now reach as high as 1,600° Centigrade. The company has been developing high-alloy materials, thermal coatings for the blades, and more sophisticated blade geometries that determine how injections of cooler air insulate the blades from the super-heated air. Mitsubishi Hitachi has set a goal of reaching 65% efficiency, a point beyond which it becomes counter-productive to raise the combustion temperatures because it starts creating higher levels of nitrogen oxide, a pollutant.

An old “one on one” gas plant could be built for a capital cost of about $1,000 to $1,200 per kilowatt hour of capacity. A “two on one” gets the cost down to $900 per kilowatt (kW). Greensville’s “three on one” with J Class turbines should drive down the cost to around $700 per kW, says Newsom. “Greensville will be the most cost-effective plant that Dominion has built in its history. That’s really exciting.”

For purposes of comparison, the up-front capital cost for solar and wind runs about $2,000 to $3,000 per kW, says Newsom. Of course, solar and wind save on fuel. But Dominion contends that the lower cost of capital for gas will outweigh the lower cost of fuel for wind and solar.

There is a bonus on the operating side as well. Newsom says the J Class turbines have the best reliability in the industry. Their EFOR (Equivalent Forced Outage Rate) is eight-tenths of one percent, meaning that the turbines run 99.2% of the time they’re supposed to. Curtailing down-time is crucial in power plant economics; negligible downtime enables gas plants to operate about 70% of the time, as compared to solar or wind, which operate only when the sun shines and the wind blows, about 30% of the time.

The Greensville power station will save money for rate payers in another way, which is not included in the $2.1 billion savings estimate. By drawing gas from two pipelines, Dominion will be able to exploit seasonal fluctuations in gas prices in northern and southern markets.

When Greensville opens, it will receive gas from the Transco pipeline, which draws mainly from the Gulf of Mexico region and limited access from Marcellus. Should the Atlantic Coast Pipeline (ACP) project receive federal approval, as Dominion expects it to, its route will run close to Greensville, giving the utility’s gas buyers a new array of purchasing options.

Dominion, like other utilities, obtains much of its gas supply through long-term contracts with gas producers. But the company maintains flexibility by putting 25% to 50% of its expected demand out for bids by issuing Requests for Proposals (RFPs). Virginia’s existing gas pipelines have little capacity to spare, so Dominion’s options are limited. When the ACP opens up access to the Marcellus/Utica shale fields for southeastern markets, Dominion can draw from a deeper pool of supply and competitors, says Kelly. Prices for gas originating in the Gulf of Mexico tend to peak in the hot, humid summer, when demand for air conditioning is highest, while prices in the north peak in the winter, when homes use it for heating. With two pipelines serving Greensville and its other gas plants, Dominion can purchase gas from areas where pricing is off-peak. Also, having multiple pipelines to serve its generating fleet also adds fuel reliability, minimizing exposure to disruption to a single pipeline for supply, as when Hurricane Katrina shut down the Gulf gas industry for several days.

The savings are potentially immense. Dominion currently spends about $1.8 billion annually on natural gas, which now comprises one of the biggest costs to rate payers.

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13 responses to “How One Gas Plant Can Save Billions

  1. If FERC approves the ACP Dominion will make 14% return on its investment for 30 years. Rate payers will have to pay. They will also have to pay for the 20 year contract on gas from the existing line. It’s hard to imagine a competitive gas cost along with the pipeline cost giving customers lower cost and the redundant cost must be considered.

    Meanwhile, the SCC will only award a return of around 10% for building solar and it won’t be for 30 years. Besides that state law has been stymied from offering solar benefits due to company lobbying.

    It’s easy to see why the company would go for gas instead of solar. Ratepayers don’t have a way to effectively weigh in to protect their best interests. The company has control.

  2. There has been a bonus return on equity (ROE) amount for solar since the 2007 statute was adopted, so almost ten years. The ROE on a solar plant by law is higher than the ROE on a natural gas plant. And Dominion is going to build a fair amount of solar over the next few years. There is a heavy economic thumb on the scale in favor of solar. That’s not the issue.

    This is not the Mojave Desert or even sunny Spain and I for one do not want to depend on the sun for base load in Virginia.

  3. Steve – if you could install a Tesla Powerwall or one of it’s increasing numbers of competitors home storage batteries coupled with a solar grid – with a ROI payback of less than 10 years – would you consider it ?

    Would you consider it even if it would not 100% power your house, still needed grid backup but still would cost you less than if you just stuck with the grid 100%?

    that’s what I see as the risk for DVP’s 30-year ROI “plan”.

    It may not matter what DVP itself does about solar 0r even gas in terms of what the market is going see in terms of disruptive changes in that 30 years.

    So who is going to pay if DVP gets it wrong?

  4. Thank you Jim, you answered my question from the prior post – and the answer is: 780 lbs CO2/MWhr. That’s pretty darn low CO2, very good efficiency. Our EPA-proposed CPP target is to get down to 934 lbs CO2/MWhr by 2030, thus these plants would help us to accomplish that.

    I believe even greater energy efficiency is possible by going the co-gen route, e.g.: like the Linden Energy plant on the NJ Turnpike by Exit 9. So the bragging rights are probably somewhat limited. The potential issue with the Greensville plant is huge size designed to fit the utility preference of extremely large centralized power plants. Nonetheless, chances are the new plant will be a terrific clean, tax-paying neighbor for the community.

    Currently Virginia imports about 40% of its power. Furthermore a good chunk of in-state generation is coal-based and slated to shut down. Thus there is still quite a large in-state energy deficit, so there should be plenty of need for additional renewable generation.

  5. I’m not necessarily advocating that DVP do utility-scale solar but I do wonder if they are seriously taking into account in their planning the likelihood that residential and commercial scale solar are likely to expand and DVP will end up with the load-balancing consequences despite their efforts to evade it now.

    It’s ironic that PJM and other members of PJM have actually done that – and DVP and the SCC and the VA GA have not.

    I still don’t understand if we can buy natural-gas generate power from PJM when we need it – why we site plants in places where there is not ample supplies of natural gas OR existing infrastructure to provide it.

    Why must we site gas plants in places where we must build pipelines to fee them when we don’t have to? How does that benefit anyone?

    Jim says they save piles of money by doing gas – but who is going to pay for the new pipelines (that are not needed)?

  6. I applaud Dominion’s effort to utilize the most efficient technology available. However, there are a few issues to keep in mind:

    The quoted efficiencies in the article are likely the manufacturer’s nameplate ratings which are usually several percent higher than what is actually experienced in operation. However, that should not diminish the importance of striving for higher efficiency. Utilizing waste heat is an important concept. Distributed gas-fired combustion turbines can achieve 85% efficiency when the waste heat is used for heating and cooling or other uses.

    The capital cost comparison between combined-cycle units and solar appears exaggerated. The $700 per installed kilowatt for the combined-cycle is on the very low end for a NGCC unit, which you would expect from a state-of-the art plant. Lazard’s Levelized Cost of Energy Analysis for 2015 shows a current cost of $1400 per installed kW for a solar unit rather than the $2000-3000 that you quoted. This cost is also expected to go down significantly. The capital cost of solar has declined 82% in the last six years. It is expected to be at least 50-60% cheaper within the next 5 to 6 years; that would make the capital cost of solar almost the same as the new combined-cycle unit when it first begins operating, with no fuel costs.

    Lazard’s Levelized Cost of Energy (LCOE) takes all of the costs of a power plant into consideration, including fuel. The current LCOE for utility solar is $0.05 – 0.06 per kWh (and will continue to go down in the years ahead). The current LCOE for an advanced combined cycle unit is $0.053 – 0.078 per kWh. Considering a higher gas price scenario the combined cycle unit’s wholesale energy charge could go as high as $0.085 /kWh.

    That is why using today’s PJM replacement energy cost as a basis to calculate the cost savings to consumers from the new plant is mathematically correct, but very misleading (I doubt that they included renewable sources in the price estimate since they are non-dispatchable). It would be far cheaper for the customers of Virginia to create 1600 MW of energy efficiency at $0.02-0.03 /kWh than it would be to invest in the Greensville plant at $0.05 – 0.07 /kWh. Dominion is drawing from a pool of options that are acceptable to them and ignoring others that might be better for their customers. I understand their business model and why they are doing it, but consumers rely on trusted sources of information such as Bacons Rebellion and other media and they are misled by the analysis.
    The higher reliability of the new J Class turbines is helpful in allowing PJM to lower reserve requirements as a greater number of high reliability units come into the mix.

    There are several quotes regarding the pipeline that must be addressed:

    “When Greensville opens, it will receive gas from the Transco pipeline, which draws mainly from the Gulf of Mexico region and limited access from Marcellus.”

    “Also, having multiple pipelines to serve its generating fleet also adds fuel reliability, minimizing exposure to disruption to a single pipeline for supply.”

    Dominion has been using this statement in the application for the ACP and in their many public announcements. It is patently incorrect. The Transco pipeline has historically moved gas from the Gulf Coast productions zones to the load centers along the Eastern Seaboard to the Northeast. As part of the Southside Expansion Projects to build a spur from the main Transco corridor to the Brunswick and Greensville plants, Dominion paid Transco to adjust the piping and compressor stations in New Jersey to allow gas to flow from the Marcellus southward to serve these two plants. These plants do not have “limited access” to the Marcellus. They have “full” access. Because the existing pipeline can also receive supply from the Gulf they already have two sources of supply which Dominion claims is only fulfilled by the ACP.

    “Virginia’s existing gas pipelines have little capacity to spare, so Dominion’s options are limited.”

    Much of the load in the northeast will be directly supplied from the Marcellus as sufficient takeaway capacity comes online in 2017. This frees up two of the four main pipelines in the Transco corridor to move gas from the Marcellus to the Southeast. In their 2015 survey of nationwide natural gas infrastructure requirements, the DOE stated that the reversal of flow in existing pipelines is sufficient to provide for the projected needs in Virginia and the Carolinas through at least 2040. The available capacity in the Southbound Transco system to serve loads in the Southeast is equal to the capacity of the Atlantic Coast Pipeline, the Mountain Valley Pipeline and the Appalachian Connector combined. How this could be interpreted as having “little capacity to spare” or “limited options” is beyond imagining, but this is all the public and politicians have heard.

    “The savings are potentially immense.”

    This has been the main argument both for the pipeline and the natural gas plants since the beginning. I have already shown that energy efficiency and renewables are cheaper than the new super efficient gas combined cycle plant in terms of the cost of generated energy. When the new plant is compared to a mix of existing generating plants in PJM it is cheaper, because it is more efficient. Dominion’s statement is accurate but self-serving and misleading. It is cheaper only to what Dominion has chosen to compare it to.

    In a similar false comparison, Dominion has claimed that by accessing gas from the Dominion South Hub via the ACP, its customers will gain an energy cost savings of $377 million per year. They calculated this value by comparing the current cost of gas at Dominion South with the national price at Henry Hub in Louisiana. The Dominion South price is lower because of the surplus of gas stranded in the Marcellus.

    But Dominion South is not the only supply hub in the Marcellus. To calculate savings for Virginia customers Dominion should compare their actual alternatives. The Transco spur to the Greensville and Brunswick plants takes its supply from the northeastern Marcellus, where wells in just 3 of the 72 counties supply over 50% of the Marcellus production. The price in this region (in June 2016) was 26% cheaper than Dominion South and has been for some time. Purchasing gas for the two new Southside plants from the supply zone that Dominion plans to use for the ACP would actually cost Virginia ratepayers $91 million per year more than using the existing Transco pipeline.

    The pipeline transport charges are based on the cost of the pipeline, plus the approved rate of return. New pipelines have higher transport fees than existing pipelines that have been mostly paid for by previous customers. Virginia ratepayers will pay $218 million more in the first year to transport gas to these two power plants using the Atlantic Coast Pipeline compared to using the newly built Transco spur. This is just for two power plants. Can you imagine how much more ratepayers will have to pay when six or more new power plants are attached to the ACP?

    It has been said that if a lie is repeated often enough, people will believe it. The information regarding the numbers I have just reported come from Dominion documents filed with FERC. I know Jim is earnest in his desire to get these issues out for public discussion. But to make good decisions we need good information. It is natural for everyone to put their choices in the best light, but in this case, despite Dominion’s pronouncements, Virginia ratepayers will experience a far different reality. The SCC or the AG needs to look into this and be certain that decisions are made with appropriate information. Not PR releases.

  7. Sounds like TomH has provided a pretty cogent counter argument to Jim’s post which does sound a little like a DVP PR release to be honest.

    I think Dominion is choosing to get itself involved in pipelines when it should be strategically addressing the likely future of widespread solar adoption by both Commercial and residential and, in turn how that would affect the existing grid and that they will, at some point, be going to the General Assembly for “relief” from consumers installing solar on their own.

    I also think a real analysis of “savings’ would acknowledge and also address what those costs would be if natural gas increases in cost.

    DVP is counting chickens and eggs here.. best case scenario….for them.

  8. Larry, you observe, “I’m not necessarily advocating that DVP do utility-scale solar but I do wonder if they are seriously taking into account in their planning the likelihood that residential and commercial scale solar are likely to expand and DVP will end up with the load-balancing consequences despite their efforts to evade it now.”

    Let’s put that into perspective: “load balancing” is the central fact of life for an electric utility. The load must be served, whatever it is, whenever it shows up or drops off, with the lowest-cost generation available at that time. Being part of a large regional pool like PJM helps by averaging the variations over a larger amount of generation and load — but even that can’t eliminate the fact that loads vary daily at roughly the same time and also are sometimes affected by large-scale weather events over a wide area at the same time.

    What residential solar and residential battery storage does is put the homeowner into that mix as an active participant. PJM will buy that power today at wholesale prices (most homeowners prefer to be “paid” by offsetting their retail electricity purchases, which in effect pays them the retail price of electricity plus the retail price of the distribution system — the “net metering” debate — but that’s a whole ‘nother discussion). In any event, what PJM needs is plenty of generators or batteries to take over when solar isn’t available but load is higher — after dark in the winter, for example.

    For the foreseeable future, say the next 20 years, there is very little chance (or risk to the utility) that batteries are going to become cheap enough to take on the bulk of the winter residential load from sundown through the long winter night. Lithium-ion technology is good, but far from cheap or trouble-free (sorry, Mr. Musk). Even if battery technology makes a breakthrough in 10 years as predicted — for the last 40 years the promised battery breakthrough has always been “just 10 more years” — it would take another 10-20 years to scale up production and develop the degree of market penetration and the massive distributed investment by millions of consumers necessary to make a big difference. The likelihood is that a really widespread battery presence on the grid will be 30-40 years or more in developing. That leaves DVP plenty of time to recover its investment in new gas generation and in the new pipelines to supply that generation (and other customers). I think this part of the picture makes good sense.

    Dominion does not make that decision alone in a vacuum; it must also persuade the VSCC that its forecasts make sense. That is what the annual IRP review is all about.

    That said, we should remain skeptical of Dominion’s insistence on ratebasing this entire investment. Ratebasing means the retail customer pays to amortize the investment over its lifetime and also gets all the benefit of the operating savings through future rates. The other way to go is to build the plant entirely “on spec” — as an investment by Dominion’s shareholders, and at an operating profit (or loss) entirely to Dominion’s bottom line. Dominion will always be able to sell its gas-generated power into the PJM wholesale markets — but at what price? Will the run-times diminish, will the operating profits decrease, over time? If Dominion really thinks efficient NGCC generation is such a good way to make electricity for the next 40 years, why doesn’t it put its own money where its mouth is (and potentially reap even greater rewards for shareholders)? Plenty of other utilities spun off their generation in the 1990s into unregulated subsidiaries, and unregulated new construction is commonplace today — but not in Dominion’s territory.

    I also agree with Larry and TomH that Dominion hasn’t made the economic case for locating those new gas generating plants in southeastern Virginia as opposed to, say, somewhere in West Virginia. You can transport power to consumers either as gas fuel or as bulk electricity; the decision which way to go should depend on what is the overall lowest cost to get power delivered to the consumer. Yes, there are political benefits to boosting employment in Southside to run the generating plants; yes, there are shareholder benefits to building a gas pipeline with a guaranteed (affiliated) customer base; yes, the presence of multiple pipelines gives Dominion some competitive bargaining leverage over gas transportation costs; yes, the additional pipeline capacity may bring more employment to the area. But is this enough to justify the cost of the pipeline? And again, Dominion has set this up as a rate-based venture, at ratepayer risk in case its forecasts are optimistic.

  9. we continue to have truly informative dialogue on this issue for which I do thank those like Acbar for sharing their knowledge and perspective.

    I guess I was thinking in terms of load balancing – what happens DIFFERENT from now – if a whole bunch of folks start installing residential and commercial solar – and use it when solar is available rather than DVP grid power then tap that grid power at night and other times – adding much more variability to demand side in ways way different than conventional grid variabilities.

    all those folks do that even without getting paid for their excess solar – the ROI payback is good even without getting paid for that surplus OR they can store it themselves.

    The point I (think) I’m making is that even as detractors and skeptics of solar’s “variability” – to include DVP make their point for DVP not wanting to do solar – because of the load variations …. isn’t DVP going to end up with that situation anyhow because ratepayers will do it and the same problem will fall into DVP’s hands – anyhow.

    What exactly is DVPs “plan” to deal with this? Is there “plan” essentially to go to the GA and ask for a law prohibiting ratepayer adoption of solar because of it’s impact on the DVP grid never planned nor modified to deal with solar load issues?

    In other words – the conventional wisdom seems to be that because DVP is controlling the rate and pace of utility solar that in doing that – they also control what changes will happen to the grid in response -but can DVP also control the rate and pace of ratepayer adoption of solar?

    or am I just barking up a wrong tree all together?

  10. As Acbar says, grid variability has always been an issue for utilities. Greater adoption of solar is accelerating that, but distributed generation also has benefits that can be used to stabilize local grids.

    That is why many encourage a “value of solar” tariff that properly accounts for the costs and benefits of distributed solar much better than does the more blunt instrument called net-metering.

    I don’t think Dominion is opposed to distributed solar because of its potential to add variability to the grid (totally ignoring its benefit). Although that is often the cover story. I believe they are concerned about the loss of revenues third-party generation creates.

    Dominion has a very skilled subsidiary that specializes in bringing the grid into the digital age, which allows much more rapid control of potential variations.

    They also know about the cost advantages of solar. That is why they plan to install hundreds of megawatts of solar capacity over the next 5-10 years. But they want to do it all as utility owned central station solar that they can earn a rate of return from, including a return from building the necessary transmission lines. Unfortunately, this approach keeps the variability of solar but misses out on the benefits of distributed generation. It also forecloses the additional jobs, innovation, and other benefits of third-party participation. In NY they are asking the utilities to identify the grid locations that can most benefit from distributed generation, to encourage third-party development. In Virginia, we just want to shut that down and we miss the potential benefits.

  11. is there concurrence that we WILL SEE more and more ratepayer-installed solar – or not?

    If we believe that is true – then doesn’t that mean that distributed generation is not an optional path but instead a core part of any strategic endeavor?

    that’s what seems to be missing from DVP’s planning – at least the part that is in the public realm.

    If not distributed generation then what – to deal with massive adoption of solar – and really – increased efficiency on the demand side in general.

    DVP’s planning just ignores this whole issue – it doesn’t even seem to acknowledge it even as a potential.

    For ANY planning – risk analysis for issues like the price of gas, the adoption of solar, increased efficiency – you’d not only address it but you’d do a high side and low side scenario and then the planning process would address the high and low potentials.

    Just a for instance – what does DVP project the price of natural gas to be over the next 30 years and how does that affect their planning?

    if 10% of people adopt solar over that 30 years – what happens to grid reliability and how does planning address that?

    If heat pump technology gains 20% in efficiency – how does that affect average summer use and peaks?

    Unless I misunderstand DVP seems to have decided how they’d LIKE the future to be – more so than a cogent analysis of the range of possibilities.

    that’s not really a legitimate forward-looking process.

  12. “For the foreseeable future, say the next 20 years, there is very little chance (or risk to the utility) that batteries are going to become cheap enough to take on the bulk of the winter residential load from sundown through the long winter night. ”

    Sorry ACBAR, but storage is here. Granted Hawaii has the highest rates in the US because the island’s electricity has depended on imported diesel fuel. That has made rooftop solar so popular HECO keep people waiting in line to be grid connected for years. Finally their PUC stepped in and told HECO to do better with distributed generation. Now with storage added to the picture, Hawaii is a place to watch. Inverters have been invented that aid wiih grid integration, so now distributed energy has an additional value for the grid itself.

    https://www.morningstar.com/news/pr-news-wire/PRNews_20160426SF81219/energy-storage-leader-sunverge-energy-meets-hecos-new-solar-technology-standards.html

    “HECO’s plans for reaching a 100 percent renewable energy portfolio by 2045 include increasing rooftop solar installations by more than 250 percent from current levels,” said Ken Munson, co-founder and CEO of Sunverge Energy. “Intelligent energy storage systems in a virtual power plant model will play a critical role in efficiently and cost-effectively managing this distributed generation. We estimate solar customers can recoup their energy storage investment within seven years through significantly lower monthly energy bills.”

    That is behind the meter. Here is some storage in front …
    http://www.greentechmedia.com/articles/read/HECO-and-SolarCity-to-Put-Smart-Solar-Inverters-Through-Real-World-Testing

    “HECO is dealing with the challenges of reaching 100% renewable energy by 2045, and energy storage is playing a key role in that transition.
    Hawaii’s largest solar array, a 12-MW facility by REC Solar on Kauai, is paired with a 6-MW battery storage system. And last October SolarCity won the bidding to build what has been called Kauai’s first fully dispatchable solar farm, a 13-MW array that will charge a 13-MW, 52-MWh battery system.”

    I share the above commenters concerns with Dominion’s choices. They are based on the old monopoly rate based framework and like it or not, as a new report from NERC states, change is coming, Relying totally on central generation will cost customers more, not less. The question I will put up later is … Why is Dominion passing up the offshore opportunity in order to remain dependent on questionable gas prices and supplies, and which will actually drive up our CO2 emission levels, when additional plants on the drawing board at Dominion are added?

  13. Some reaction:

    LarryG, you say, “All those folks do that even without getting paid for their excess solar – the ROI payback is good even without getting paid for that surplus OR they can store it themselves.”

    It really doesn’t help to distinguish between a home investor in solar who sells his solar electric output to the grid market, versus the guy who merely reduces what he would have bought at that moment from the grid, versus the guy who charges a battery-pack and later reduces what he would have bought at the time of his choosing. Each of them receives a payback — in one case cash, in the other two an avoided retail purchase cost — which as you say has to be a “good ROI” (relative to the alternative, buying from a retail supplier) or they won’t bother. For each payback variation, the return on investment has to be positive or that investment is going to dry up.

    Now, for “what happens DIFFERENT from now – if a whole bunch of folks start installing residential and commercial solar – and use it when solar is available rather than DVP grid power then tap that grid power at night and other times – adding much more variability to demand side in ways way different than conventional grid variabilities.”

    Yes, this would add significantly to the variability the grid operator has to deal with. Solar output doesn’t just vary with the position of the sun; output at a given location can plummet from 100% to zero in seconds when a thunderstorm hits, or even a thick patch of clouds rolls in; generation can resume just as abruptly. Solar cells under a blanket of snow don’t work at all until cleared. And there are other variables: for example, solar generation from cells at a fixed angle to the horizon are less efficient than cells whose angle can be adjusted (or adjusts automatically) to track the sun (but the tracking mechanisms are expensive).

    But grid operators already deal routinely with such variations. A thunderstorm affects localized grid loads directly by cooling hot heat pumps and roofs and the ambient air, dramatically reducing air conditioning loads. Adding variable solar DG outputs to the grid is a complicating factor, not a game-changer. PJM has studied its ability to control the system despite a high degree of penetration of distributed solar generation on its grid and says it doesn’t foresee a problem.

    This assumes, of course, that the grid has time to adapt. There is a finite mix of generation out there. At a given time, PJM pays the generation owner whatever it takes to get someone out there to operate whenever more generation is needed. In other words, the marginal grid energy market price rises as necessary to attract more generation. Competition usually keeps the marginal energy price in the grid energy market reasonably low, but it can spike high on occasion, sufficiently high that someone somewhere will offer to sell more generation (or load reduction). But PJM also requires its members to come up with sufficient generation resources under contract each year to cover their forecast grid loads (including a reserve component to deal with equipment outages and other emergencies). Those forecasts will include, of course, the effects of DG solar on forecast generation and load levels. PJM doesn’t care particularly how efficient that generation is, as long as there is enough of it; but of course the generator owner cares, because he is going to be paid the energy market price, not a cost-based price with a guaranteed profit. His profit margin will go up when the marginal market price goes up, but most of the time he has to make his return on investment and his profit from normal market prices. He had better have generation that will run (and cycle on-and-off) cheaply enough under the circumstances (including the circumstances of a grid with lots of solar DG on it) or he will lose money.

    DVP does not have to build new generation; but it MUST show PJM each year that it has enough of its own generation PLUS generation under contract to meet its PJM forecast of DVP’s load plus reserves. “Generation under contract” can include load-management resources under contract — where the customer agrees to curtail load when you call on him to. If DVP doesn’t agree with PJM’s forecast, it can appeal to the Federal Energy Regulatory Commission; otherwise PJM’s decision is final.

    Where do batteries enter into this? Well, they allow more flexible matching of generation and load; they allow electricity to be stored and time-shifted. Time-shifted to when? Well, when will it offer the greatest savings to the customer not to consume retail power? Today, that’s in the middle of a hot summer day, which is when the solar power is most likely to be available anyway without the added cost of a battery. But a customer willing to curtail load upon request can earn a lot more than the retail price; batteries can be used to provide the equivalent of “curtailable load”; so, load management is one likely market for batteries in the short run. In the longer run, if batteries ever become cheap enough, they could be used to shift electricity routinely from daytime generation to nighttime consumption — but nighttime loads are lower, nighttime grid energy market prices are lower, so there is no economic incentive to do that shift today. What about the solar DG customer who simply wants to go off the grid and use his own stored solar power at night? Well, there’s the romantic notion of “cutting the cord,” but that really doesn’t make much economic sense today unless the retail supplier of grid power has levelized rates for the solar DG owner, which isn’t cost-justified — the PJM market price at night is usually quite low. It makes more economic sense for the solar customer to go petition the VSCC for time-of-day rates than to go out and buy a bunch of batteries. Not incidentally, time-of-day retail rates also make the economics of solar generation during the day that much better.

    It is conceivable that solar DG could become so widespread that grid generation at night could become higher than in the day, and the price of grid electricity at night could become higher than in daytime. But even then, the only reason to use batteries to store excess solar power until nighttime would be if the difference between the price for selling it to the grid in the middle of the day (when generated) was exceeded by the price for selling it at night (from batteries) by enough to amortize the cost of the batteries. This is simply not likely to happen within the lifetime of most grid generation. Moreover the NGCC units being built today are more efficient and flexible than older ones; even if the grid’s role diminishes relative to DG, they will remain useful long after other units are retired.

    So, “Is there [a DVP] “plan” essentially to go to the GA and ask for a law prohibiting ratepayer adoption of solar because of it’s impact on the DVP grid”? No, for multiple reasons. First, it would be unprecedented nationwide (and probably illegal under current State law) to forbid a homeowner to own and operate DG for his own use or deliver it to the transmission grid. Second, it would definitely be illegal under federal law to forbid a homeowner to sell the output of DG to the wholesale electric marketplace (e.g., PJM). Moreover, DVP hasn’t tried to do these things! The ONLY thing that DVP has been accused of is (1) opposing “net metering” (crediting the full retail electric rate for the homeowner’s solar DG output), and (2) opposing “retail sales” of electricity by solar equipment manufacturers who do not sell their equipment to a homeowner but contract to install and maintain their solar equipment at the home and sell him its output at a contract rate; this of course constitutes a “retail sale” of electricity. Not that DVP is indifferent to the competitive threat from DG, but they seem to me to be trying to deal with that threat competitively — that is, by keeping their own costs and prices down, not by throwing up artificial roadblocks to DG. In general, I agree with TomH: “I don’t think Dominion is opposed to distributed solar because of its potential to add variability to the grid (totally ignoring its benefit). Although that is often the cover story. I believe they are concerned about the loss of revenues third-party generation creates.” And I also agree with his observation, “That is why many encourage a “value of solar” tariff that properly accounts for the costs and benefits of distributed solar much better than does the more blunt instrument called net-metering.”

    Finally, you say, “In other words – the conventional wisdom seems to be that because DVP is controlling the rate and pace of utility solar that in doing that – they also control what changes will happen to the grid in response -but can DVP also control the rate and pace of ratepayer adoption of solar? or am I just barking up a wrong tree all together?”

    No, no, no — (1) DVP isn’t controlling the rate and pace of utility-scale solar; in fact they are latecomers to solar. Most utility-scale solar in DVP’s territory has been developed by third parties; but DVP has got up to speed fast by buying some of that. (2) DVP has no control whatsoever over what changes will happen to the grid in response to increased solar. That is PJM’s exclusive responsibility as the federal-regulated grid planner and system operator and wholesale market manager. In those changed grid and grid-market circumstances, DVP may learn that it had best change how it goes about making money as a generation owner; but that is an economic gamble for DVP, not a question of “control.” (3) DVP cannot control the rate and pace of ratepayer (homeowner) adoption of DG solar. In fact DVP’s own retail tariff on file with the VSCC recognizes that. And numerous decisions, including one at the US Supreme Court just this year, affirm that DVP cannot block a homeowner’s sales of his own solar power into the PJM wholesale marketplace. No, the ONLY thing DVP can do is defend its right under State law to be the exclusive seller of retail electricity within its service territory, and oppose “net metering” as bad public policy (even though it’s quite legal in many States).

    In short, I don’t know if that’s “barking up the wrong tree” but it sure sounds like you think DVP is to blame for stifling homeowner solar in Virginia, and I don’t think the facts support that. DVP may be stodgy and unimaginative and overly “traditional-utility-operations” oriented, but I just don’t agree they are hostile to solar. The single biggest reason solar DG hasn’t taken off in Virginia is the absence of State tax credits for homeowners. And solar IS taking off in parts of North Carolina served by Dominion, where the only real difference is those tax credits.

    Finally, Larry, you conclude, “If we believe [more and more ratepayer solar] is [coming] – then doesn’t that mean that distributed generation is not an optional path but instead a core part of any strategic endeavor? that’s what seems to be missing from DVP’s planning – at least the part that is in the public realm. If not distributed generation then what – to deal with massive adoption of solar – and really – increased efficiency on the demand side in general. DVP’s planning just ignores this whole issue – it doesn’t even seem to acknowledge it even as a potential.”

    “Strategic endeavor” by whom? Solar DG is very much a part of PJM’s planning for the reliability and efficiency of the future grid. It’s a central factor in energy forecasts issued in the past two years by the Department of Energy, by the International Energy Agency, by the Lawrence Berkeley Energy Laboratory, by the National Renewable Energy Laboratory, and the International Renewable Energy Agency. I don’t agree that DVP “just ignores this whole issue”: significant solar penetration in the Mid-Atlantic U.S. is openly acknowledged as likely in Dominion’s own latest IRP.

    But does DVP jump on board the homeowner solar movement and tout its advantages for consumers and its benefits for Dominion ratepayers and shareholders? Hah! There’s some truth in what you say next, “Unless I misunderstand, DVP seems to have decided how they’d LIKE the future to be – more so than a cogent analysis of the range of possibilities.” Yes, Dominion’s latest IRP isn’t so much a set of recommendations as an expression of wishful thinking and a request for advice, a ‘Hail Mary’ toss to the VSCC asking implicitly for guidance what to do about North Anna 3 and CPP compliance and other pivotal issues, including solar. That’s the same VSCC, by the way, that blocked DVP’s plan in the ’90s to spin off its generation and become more focused on the grid for its future supply of power to Virginians. Given that history, I just can’t blame Dominion for seeking renewed guidance before turning away from its strong preference for utility ownership and ratebasing of Virginia’s generation.

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