Doubling Down on Natural Gas

Dawn Garber, a Dominion environmental engineer, stands by a strut supporting the immense steam cooling fans used to recycle water at the Brunswick plant.

Dawn Garber, a Dominion environmental engineer, stands by a strut supporting the 72 immense fans used to cool steam to water at the Brunswick plant.

Dominion says its new Brunswick County Power Station is clean, super-efficient, and a good deal for rate payers. Environmentalists question whether the natural gas-fired facility is a wise investment over the long run.

by James A. Bacon

Dominion Virginia Power’s new $1.2 billion gas-fired power plant in Brunswick County is state-of-the-art. Three of the most efficient gas turbines in the world combined with the recycling of exhaust heat to power a steam-powered boiler “makes this one of the most efficient plants in the world,” said Paul Koonce, CEO of the Dominion Generation Group, at a ribbon-cutting ceremony Thursday.

The Brunswick County Power Station will generate electricity more efficiently than the coal-fired units at the Chesapeake Energy Center it is replacing — converting 55% of the energy produced by combustion into electricity, compared to 35% for the typical coal-fired power plant — and it will emit significantly fewer pollutants and less carbon-dioxide.

The facility is a showcase for Dominion’s multibillion-dollar pivot away from coal to natural gas. The company is seeking regulatory approval for a slightly larger gas-fired power plant five miles away in Greenville County, and the utility’s parent company, Dominion Resources, hopes to build the Atlantic Coast Pipeline to deliver gas to both Brunswick and Greensville among other locations.

While Dominion officials say Brunswick will yield $1 billion in fuel savings over the 40- to 50-year life of the plant, the company’s critics argue that it is unwise to invest such a massive sums in natural gas when renewable power sources like solar and wind represent the energy future.

“The core concern we have is that Dominion is building and planning plants that will lock in natural gas for years to come,” says Kate Addleson, director of the Sierra Club-Virginia Chapter. “Dominion’s customers could get stuck with stranded costs” as the Clean Power Plan and foreseeable follow-up climate-change initiatives clamp down on carbon-dioxide emissions. Dominion, she says, should be moving more aggressively to zero-carbon options such as wind and solar.

“I’m sure it’s a pretty awesome plant. I’m sure it’s state of the art,” says Walton Shepherd, a staff attorney with the Natural Resources Defense Council. “But it’s a textbook case of economic inefficiency.” Dominion is building its own facilities rather than purchasing electricity from wholesale markets organized by PJM Interconnection where competition thrives.

Dominion is assured a return on its $1.2 billion investment, while rate payers absorb the risk of price swings in natural gas. The price of gas is low now, but will it be in ten or twenty years? If prices rise, as many expect, the cost of gas is passed through through fuel adjustment clauses to rate payers. Meanwhile, the cost of solar and on-shore wind electricity continues to drop. Dominion could make just as much money building solar, Shepherd says, but then its parent company, Dominion Resources, would have less rationale to build the Atlantic Coast Pipeline.

“I don’t hold any grudge against Dominion,” says Shepherd. “Dominion’s behaving rationally in a regulated marketplace. That’s the system we have chosen in Virginia.”

From Dominion’s perspective, the challenge is reducing its reliance upon coal while also preserving the reliability and integrity of the electric grid. Off-shore wind is not an economical option at the moment, and mountain-top wind can deliver only small volumes of electricity. The company has solicited solar proposals but not enough projects are forthcoming to replace coal and meet anticipated growth in demand, and solar supply does not always match demand in any case. As for purchasing wholesale electricity through PJM, the volume of electricity purchased is constrained by the finite capacity of transmission lines. Natural gas, argue Dominion officials, provides the optimum balance of cost, grid reliability and pollution reduction.

The Brunswick power station has three combustion turbines fired by natural gas. Each turbine is attached to a generator rated for 266 megawatts of production. Exhaust heat from the turbines is used to boil water used in a conventional steam turbine, which generates an additional 575 megawatts. The total electricity output is sufficient to supply 347,000 homes and businesses.

Sensors atop the three exhaust towers closely monitor the emissions for carbon monoxide, volatile organic compounds and carbon dioxide. Dawn Garber, supervisor-regulatory compliance, says the air permit restrictions are the toughest she has ever seen. If sensors indicate a problem, control room operators often can fix it quickly from their desks. If not, they are under orders to shut down the offending generator until the problem can be resolved. It is strict Dominion policy, she said, to stay in compliance with its permits at all times.

The plant, which is set up to run 24/7, is highly automated, requiring only 40 employees. Astonishingly, the billion-dollar facility can operate during nights and weekends with as few as two employees in the control room, although a team of specialists is on call all the time. It’s similar to being a physician on call, says Garber — except that even physicians get to rotate off duty.

While the ribbon-cutting ceremony was held yesterday, the plant has been operating more or less full blast since April as operators have been tweaking the controls to achieve optimal efficiency.

Critical to the plant is a 100-mile spur running from the massive Transco intercontinental pipeline to Brunswick County to supply up to 250 decatherms of natural gas daily. The Dominion officials I talked to yesterday did not know whether the cost of that project was public information. But published reports indicated that the pipeline cost $300 million, partly offset by a $30 million grant from the Virginia Tobacco Community Revitalization Commission for the purpose of increasing capacity beyond Dominion’s needs to make supply available to industry.

Dominion also plans to deliver gas to Brunswick and a proposed sister plant in Greensville County via the Atlantic Coast Pipeline. That pipeline, estimated to cost about $5 billion, will serve markets in Hampton Roads and North Carolina as well. However, supplying the Brunswick and Greensville facilities with natural gas forms part of the justification for asserting a “public need” for the ACP, and a finding of “public need” is required in order to acquire easements in the face of public opposition by eminent domain.

If the Brunswick plant is already being supplied natural gas by Transco, how can Dominion argue that there is a public need for a second pipeline? It’s all about fuel diversity, says Jim Eck, Dominion vice president of business development. The Atlantic Coast Pipeline will deliver gas from different suppliers than Transco, providing Dominion more alternatives to purchase gas at lower prices. Ideally, savings from lower prices will more than offset the cost of reserving capacity on a second pipeline.

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53 responses to “Doubling Down on Natural Gas

  1. maybe to give some contemporary context and perspective on the value of 5 billion dollars that the ACP will cost.

    ” Nine years of construction work, at a cost of more than $5 billion, have equipped the Panama Canal with a third set of locks and deeper navigation channels, improvements that will double its capacity. When the new locks slide open for the first time in late June……….” …. “….
    Panama should start to benefit from the expansion in 2017, when the government foresees getting an extra $1.4 billion in revenue, a jump of 30 percent compared with this fiscal year.”

    So how much is Dominion expecting to increase revenues?

    😉

  2. Here is Johnnie-One Note again …
    Dominio has signed a 20 year contract to furnish Brunswick and Greensville with gas and still wants to build the ACP. Here is again what all are missing about the need for all that gas …

    The view of future grid based electricity demand by CitiGroup…. “Combining the declining size of the electricity market in terms of volumes with the declining market share for conventional generation, we could see utilities in their current form suffer a 50%+ decline in their addressable market.”

    – 30-40% – Distributed resources (solar, CHP, wind) both for households and industry

    – 20-40% – Renewables (onshore wind, offshore wind, biomass, hydro) to constitute a big portion of centralized energy that could cover 30-40% of demand.

    – 20-40% – Conventional generation (nuclear, CCGTs, coal) to cover some of the base-load demand as well as provide back up to the system.”

    The recent PJM capacity auction for 2019 backs up this direction and studies about Virginia’s policy toward efficient buildings and blocking on-site generation reinforce the idea.

    Here is the solar policy comparison with other states. Remember, on-site solar reduces central generation demand …
    Together, 10 states hold ~35% of the total solar potential in the United States, but only produce 6% of the nation’s capacity. Virginia is one of those 10 “worst states” that have solar potential but are blocking solar development.

    The legislature, the administration and our utility haven’t stepped up to the energy revolution.

  3. I don’t understand the fuel diversity claim. When Dominion owns one pipeline and the need for that pipeline is justified based upon supplying Dominion facilities, it seems that Dominion will force use of that pipeline, even if the total cost of transmission and gas by the other pipeline is lower, because it wants to recoup its costs on its own pipeline.

    Monopoly utilities were developed because we realized that it was too expensive to install and operate redundant infrastructure and doing so was keeping streets in constant construction status as it was installed. The pipelines that are currently proposed say they have firm 20year contracts for the gas that will be transported. In order for Dominion to do that, it will need to get out of the firm 20year contract with Transco.

    It is likely that the excess gas will be sold internationally. Since world gas prices are higher than US prices, US prices will increase to keep providers from exporting all the gas. Multiple efforts are already underway to develop export facilities. That means that in addition to paying for two sets of infrastructure, rate payers will be socked with higher gas prices. It also means US gas reserves will be used more quickly, reducing the time of energy self-sufficiency the US has been striving for over so many years.

    Will the SCC make ratepayers pay for two sets of infrastructure? Will it find a way to force the company to charge rate payers a US gas price or will it be forced to allow pass through of the global one?

    Clearly, this is a win for the company. It’s not a win for the rate payers or for the landowners and neighborhoods who will have to tolerate a dangerous pipeline and LNG export facilities that are not needed.

    The Virginia system currently allows monopoly providers to control these decision making processes and gives little opportunity for influence by rate payers or their representatives. The SCC has been reorganized and whipped into form so that it mostly delivers decisions desired by utilities. When it doesn’t, utilities get the General Assembly to change the rules again. Some peaker facilities were installed by non-Virginia utilities during the late 1900’s but soon after quasi-regulatory legislation was passed in 2007, Dominion purchased them and potential competitors left. Every roadblock possible has been thrown at distributed renewable energy in Virginia, especially consumer owned infrastructure. Everyone talks about the competitive market but that is not what is operating here. Virginia has an unfair utility controlled market. Things will not improve until we either find a way to make fair competition work or provide a regulatory framework that actually substitutes for competition.

    • Consumers need to participate in the SCC’s proceedings involving Dominion. If a pipeline will not be used to provide gas to the retail market, it is not used and useful in the provision of utility service. Ergo, its investment should not be permitted in the rate base and associated expenses allowed for ratemaking purposes. The facts must be put into evidence and the arguments made.

  4. I don’t think consumers have a clue how any of this works and couldn’t make an intelligent comment if their lives depended on it.

    And the only folks who have actually spent the time and effort and do have a clue have been routinely marginalized and demonized as “enviros” and “opponents”, etc.

    and these are the folks that some folks would prohibit from lobbying…

    right TMT?

    • Larry, you are twisting my comments. I have never suggested any entity, for profit or nonprofit, should be prohibited from lobbying. What I have said is lobbying expenses should not be tax deductible (many already are not) and no non-profit that uses paid lobbyists (in-house or third-party) should be permitted to lobby. An organization using volunteer lobbyists should certainly be permitted to lobby. A non-profit wishing to use paid lobbyists need only cancel its tax free status and suck up its lobbying costs like any for profit business should do.

      • Interesting concept. How will we get a level playing field for consumers if only for profits can use paid lobbyists? Most nonprofits have very limited budgets and even if they have a paid lobbyist, the resources put toward that are far fewer than those of the other side. Already, the playing field is so tilted toward business that it seems your idea would just make a bad situation impossible.

  5. The SCC will not have any hearings related to the ACP. This is a FERC-regulated and permitted project. The ACP will not be owned by Dominion Virginia Power and will not be “ratebased” into DVP rates. The SCC will not permit, nor can it stop, the construction of the ACP. I’m sorry, that’s just the way it is. Some aspects of energy regulation belong to the states and some to the federal government.

    • You are exactly right about FERC superseding any state agency. However, I think that the SCC might have the right to say that Dominion could not recover through fuel cost adjustments any charges for transportation or higher fuel costs for gas transported by the ACP compared to using existing pipelines.

      This would stop the ACP, since it is completely reliant on the ability to have the ratepayers subsidize its higher cost. Not only could the SCC do that under its authority to protect ratepayers against unnecessary charges, I think they would be completely negligent if they did not.

      At least the North Carolina Utility Commission has intervened with FERC to complain that FERC’s inordinately high rate of return will harm North Carolina ratepayers.

      • I believe that you are right that the SCC could decide that the choice of the ACP to deliver the gas instead of the currently active line, especially if the ACP and the gas from it are more expensive, is not acceptable. No, the SCC won’t have hearings on the pipeline and yes FERC sets the rate of return. However, the SCC has to decide whether expenditures in Virginia rates are prudent, etc. and I also would say they’d be negligent to not assure that ratepayers get the best deal. I guess we’ll find out.

      • The SCC also could intervene in any FERC proceeding involving the pipeline and expenses that would be recovered indirectly from local ratepayers. That includes a proceeding that decides the appropriate rate of return on investment.

        But a state agency has no authority over interstate investments, expenses and revenues. Nor should it under our federal system of government.

        • TMT, I agree that FERC has authority in interstate projects. State agencies can only make comments as any other intervener.

          My point was that the SCC does have rate-making authority in Virginia. If they were to rule that Dominion could not recover fuel or fuel transportation charges, related to using the ACP, that are higher than those offered by existing alternatives it might dramatically alter Dominion’s choice of moving forward with the ACP or at least whether they would take their gas supplies from it.

          Dominion is a 48% owner of the ACP but expects to use just 20% of its supply (at least as presently configured). This makes it appear to be more of a business proposition for Dominion Resource rather than a necessary source of supply for DVP. They would do just fine with such a ruling since using existing pipelines would be cheaper for their customers.

          It would then still be up to FERC to determine if it makes sense to build more than 300 miles of pipeline on new right-of-way through West Virginia and Virginia just to provide a gas supply to North Carolina. Especially since those two states would derive no value from the pipeline and North Carolina has much easier and cheaper access to greater supplies from the Transco corridor running through the state. This might be a reasonable argument, but FERC has a history of permitting pipelines whether they are necessary or not.

          • TooManyTaxes

            TomH – you raise important and interesting points. There is an argument that, once FERC has determined what are reasonable interstate rates, the SCC (or any similar state regulatory agency) cannot challenge those rates further or prevent a utility from recovering them from consumers. Hence, I think there are good reasons why the VSCC needs to participate in FERC proceedings that will affect rates paid by Virginia consumers.

      • Virginia law gives the SCC the right to reject any imprudent costs proposed to it for recovery by any utility. However, I know of no provision of law that authorizes the SCC to pre-announce that it will not permit recovery of costs that have not yet been incurred or proposed for recovery.

        Tom, what is the FERC proceeding in which the NCUC has intervened?

        • Rowinguy, I suspect you are correct about not being able to “pre-announce” a specific ruling. Although, I think they could provide some “guidance” regarding what their policy might be. It is unfortunate that many of our legal remedies exist only have the harm has already been done. What I am advocating is that we should all put our heads together and create a better system that is good for the utilities, their shareholders, and the ratepayers.

          The North Carolina Utility Commission has intervened in the FERC proceeding for the Atlantic Coast Pipeline, saying that the 14-15% rate of return provided by FERC is far higher than the 11% authorized for intrastate projects and as such creates an undue hardship for North Carolina ratepayers and an unnecessary windfall for North Carolina utilities. I don’t think they will make much headway changing FERC’s mind about the rate of return.

          • TooManyTaxes

            Interestingly, the FCC has adopted a new RoR for smaller telcos (that are still RoR regulated) that lowers the allowed return on investment from 11.25% to 9.75% on a six-year phase down. While I’m not sure the 14-15% FERC RoR is on total investment and not just equity, if it is the former, it seems too high, at least based on the FCC decision of 2016.

  6. “The Atlantic Coast Pipeline will deliver gas from different suppliers than Transco, providing Dominion more alternatives to purchase gas at lower prices. Ideally, savings from lower prices will more than offset the cost of reserving capacity on a second pipeline.”

    This is a more honest statement of how the developers intend to use the ACP. Saying that “without the ACP, Virginia would not have adequate supplies of natural gas” and linking the pipeline to the two new power plants (making it appear that the ACP is necessary for their use) has always been a bit of a subterfuge.

    Dominion, Duke and Southern Co. (owners of AGL) want to build a pipeline in order to arbitrage natural gas throughout the southeast. They have used their captive utility subsidiaries in order meet FERC’s need threshold. This is simply a business proposition. Nothing wrong with that. But by dressing it up as a project that meets the “public convenience and necessity” strikes many as an abuse of the right of eminent domain.

    The developers of the ACP intend to have their supply header in the western Marcellus, in West Virginia. About 85-90% of the production in the Marcellus comes from Pennsylvania. About half of the production is provided by just 3 counties in northeastern Pennsylvania. This is the source of much of the supply for the Transco southbound strategy, a portion of which will be contributed by the 1.7by Bcf/d Atlantic Sunrise project.

    The comment about hoping to “purchase gas at lower prices” relates to the below national market prices that have been experienced at the Dominion South hub over the past few years. Although the Dominion South hub is located in a much lower production region of the Marcellus, thousands of miles of gathering pipelines built by Dominion Transmission also bring gas from wells in Pennsylvania into the region. The Dominion South hub is also near the “wet gas” region of the Utica shale. Various light liquid hydrocarbons are associated with the methane in this zone. Dominion owns several plants that strip the liquids and create “dry gas” for shipping in pipelines. The liquids are marketed throughout the U.S. and overseas. Dominion has also developed the nation’s largest natural gas storage reserve spread throughout underground zones formerly used for brine production in Pennsylvania and West Virginia.

    These are all useful resources and should find value in today’s market. I believe it would be better to direct their output to markets in the Midwest and avoid the ecologically sensitive and unsuitable terrain in the Alleghenies and the Shenandoah Valley. But Dominion has chosen otherwise.

    Part of their incentive is to make use of gas priced below the national market rate at the Dominion South hub. This might make sense, but one has to understand the reason for the lower price. This area is removed from the more active zones in the Marcellus and from major markets. Early development of takeaway pipelines that are used to move gas from the wells to the national gas transmission system occurred first in the more productive regions. In more remote areas, such as the Dominion South hub, the “stranded” gas could only find a market if it sold at a discount to the national price, established at Henry Hub in Louisianna. Because of a surplus of supply, other hubs in the Marcellus also sell gas at a discount to the national price.

    Obviously, producers and suppliers in the Dominion South zone are eager to get better prices for their supplies of gas. Adequate pipelines will exist to get this gas into the national gas transmission system by 2017, which will allow the gas supplies from this region to sell at prices much closer to the national price, as long as the substantial surplus of Marcellus production begins to be resolved.

    Dominion has attributed several hundred millions of dollars of benefits to the ACP as a result of this price differential. When the ACP might be available in 2019, any price advantage for gas in this region will likely to have largely disappeared. If some advantage remains, the 1.3 Bcf/d expansion of the Columbia Gas system (requiring just 3 miles of new pipeline) appears to take its supply from this region also. So this gas could be made available to Virginia and the Southeast without needing the ACP or MVP.

    Even though Dominion’s hopes might be dashed for gaining any gas price advantage using the ACP, how much might ratepayers have to pay for the possibility of this happening? I am not an expert on natural gas pipeline rates, but I can read what has been filed in the FERC documents. The Firm Reservation Rate identified in the FERC filing for the ACP is $1.7249 per dekatherm per day. This was based on the original price of about $5 billion. The pipeline is now about 100 miles longer than originally proposed, so it is probably closer to $6 billion. The actual rates would be higher, but let’s stick to what is in the filing.

    The Certificate of Public Convenience and Necessity issued for the Transco Southside Expansion Project by FERC identifies a Firm Reservation Rate of $0.60423. Dominion has agreed to a negotiated rate with Transco which is not part of the public record, but we can use the published rate for this example.

    For the 500,000 dekatherms per day for the two plants, the price premium for the ACP is $560,335 per day (over $204 million per year). There is also a charge for the actual transport of the gas of $0.0041 per dekatherm for the ACP, but I could not find a corresponding rate for Transco.

    The June 2016 rate at Dominion South hub is $1.65 per dekatherm, while the price at the Leidy hub (a likely source for the Transco gas) is $1.50.

    If the gas were to be supplied today to the two plants via the ACP, Dominion ratepayers would be asked to pay a premium of at least $560,335 per day for the shipping the gas via the ACP, plus an extra $75,000 per day for the more expensive natural gas compared to the present arrangement with the Transco pipeline. This amounts to an annual expense to the ratepayers of almost $232 million dollars!

    Why would Dominion tout the ACP as a method for saving ratepayers money? Why would they compare the Dominion South price to Henry Hub rather than the true alternative of the existing gas supply from the cheaper source from the Leidy hub? Because there is a huge amount of money at stake.

    The developers have been given the opportunity by FERC to earn a 15% pretax return on the total cost of the pipeline, assuming a capital structure of 50% debt and 50% equity. The identified debt rate is 6.8%. The FERC authorized return on equity is 14% and assumes a 40 year depreciation schedule (2.5% per year). The developers of the pipeline will earn nearly $135 million after taxes in the first year, with an additional $50 million in revenue protected from taxes by depreciation for a total first year cash income of nearly $185 million.

    All that is required for this income stream to accrue to Dominion and Duke for the life of the pipeline is to get a rubber stamp approval from FERC to allow the substantial disruption of nearly 600 miles of new right-of-way and the taking of property from unwilling landowners. Sticking the ratepayers with an extra bill for $232 million will happen automatically, since no Virginia agency is willing to speak on their behalf. The costs to ratepayers escalate for every new plant served by the ACP rather by existing pipelines.

    You are welcome to check my logic and my math. I want to be very certain that this properly represents the situation, because it is so far different from what we have been told by the pipeline developers, the politicians and the media. If anyone has additional insights, I would appreciate hearing from you.

  7. excellent narrative .. an unfortunately I feel dumber by the minute !!

    so dumb question. If Pennsylvania is in PJM – why transport gas such long distances rather than build gas plants nearer to the fuel?

    excellent analysis – and thanks for providing it.

    • Transmission lines suffer from line losses due to resistance that doesn’t occur in the same way in a pipeline. Pipelines are not affected by storms in the same way wires can be. If all of the generation was concentrated in a small area, transmission congestion could become an issue.

      Reliability is improved when generation is dispersed around the service area. That is why lots of small sources such as with distributed generation contribute to a more reliable grid compared to just a few large generating stations.

      Pennsylvania is already being shredded by all of the development for fracking drilling pads dotting the countryside and pipelines by the score moving gas in every direction.

  8. I was under the impression that the 500kv and 750kv COULD move electricity longer distances AND that there are already EXISTING pipelines much closer to Pennsylvania and PJM.

    Since gas pollutes far less than coal – it would seem that a string of gas plants located along existing pipelines would get the job done.

    500K and 750K powerlines are built above the trees and to mega hurricane standards as far as I know.

    https://encrypted-tbn3.gstatic.com/images?q=tbn:ANd9GcTNwERJMG7dTMPajjZtY6r3JeC5A4iWgYh5bFupv3XtOHCaEIZZ

    gas plant sites could be hybrids – combined-cycle plus peakers with nearby co-located solar. the combined-cycle would provide baseload – the peakers would ramp up and down in concert with how much solar was available.

    the net result from each complex would be reliable power without variances feeding into 500 and 750kv lines.

    the gas – it’s availability over the longer term would be conserved and extended – which is critical for renewables because without gas the variability of the wind/solar makes them much less usable.

    We need a plan that supports sustainable electricity for the long term MORE than we need Dominion and other companies maximizing profits for their investors at the expense depleting and exhausting the fuel stocks that critical to the future.

    it appears they want to insert as many big straws as they can to use up the gas as fast as they can – for maximum profits…

    What the SCC should be doing is requiring Dominion to show how they plan to provide sustainable electricity 50-100 years into the future – that ought to be a mandate to any utility.

    • I see what you are saying. My concern is that this, to use a computer metaphor, extends the “mainframe” centric character of the old utility system and concentrates the pollution. There are many benefits, including greater reliability, lower costs, less environmental damage, etc. to moving towards a distributed “network” model for our energy system just as we have moved dramatically forward by adopting the network model for our information systems.

      • well, not advocating that they be “centralized” but located lineally along existing corridors.

        I’m just not understanding why we have to extend pipelines and extend powerlines when we already have a fairly extensive existing network of both.

        The plants in Brunswick and Greenville have both extensions of pipelines AND powerlines… so why? what drives that?

        and if Dominion can buy power from PJM and move it throughout Va – again – why can it not site new plants that are on the existing powerline corridors to feed directly into them?

        We have all this upheaval with the current ongoing process for new location pipelines and new powerplants and new location powerlines.. and the clear justification for why – is not provided.

        I’m not saying it should be denied outright – but it should be justified because of impacts to rate-payers and property-owners. There needs to be compelling reasons why we cannot use existing locations – not just because that’s what Dominion wants.

        • I agree wholeheartedly with “use what you have before you build something new”. That has been my point all along regarding the pipeline.

          I also agree with putting the generation near the load or at least near existing transmission lines.

          Although. I would strongly encourage us to save energy first before we look to build more capacity.

          But every one of those principles is negated by the way we incentivize our utilities. Under our current regulatory design, they make money only when they build something. So they want to build a pipeline, not use the cheaper one that is owned by someone else. They want to build a power plant far away from the load centers (it is easier to find a site) so they can earn money by building more transmission lines. They need to convince us that we will need more energy so that they can earn money from new power plants. None of these choices are necessary or in the public’s interest. But the utilities are playing by the rules that we have given them.

          But there are some old rules that they do have to follow. NEPA and the threshold for eminent domain say that a project’s benefits must outweigh its costs. In the case of the ACP, they claim that it is crucial to providing an adequate supply of energy to our region and will improve our economy. If a supply greater than that proposed by the ACP already exists and costs ratepayers far less to use than the ACP, there is no justification for the project according to long-standing regulations.

  9. there are 500 and 750kv lines to the places in Va where new plants are planned.

    Clearly if we can currently purchase power from PJM existing plans we could for new gas plants also, right?

    • Larry, I think you are right; the power plants Dominion wants to build COULD be concentrated in WV near the fuel sources or existing pipelines and still satisfy PJM criteria and still make Dominion the same return on DVP’s (generation) investment. But I also agree very much with TomH’s conclusion, “Dominion, Duke and Southern Co. (owners of AGL) want to build a pipeline in order to arbitrage natural gas throughout the southeast. They have used their captive utility subsidiaries in order meet FERC’s need threshold. This is simply a business proposition.” That’s probably the main reason for it. Incidentally, the pipeline competition also can be expected to help DVP ratepayers a bit, through lower gas transportation rates to the new gas generation plants.

      But in addition, there is widespread political support for the notion that development of any kind in areas of Virginia like Brunswick and Greensville Counties as well as down to Hampton Roads and into eastern NC would be a good thing, and it not only helps Dominion politically to promote economic growth, but also the growth eventually helps Dominion grow with it. Not only the construction and employment activity associated with these new plants, but also the excess capacity in that new gas pipeline, will be attractive to new businesses.

      There is some advantage to system operations from having your generation scattered around the grid rather than concentrated in one place, but that’s not a significant factor in most instances including, I suspect, this one.

      So why build the new gas plant in Brunswick? Why build more gas generation at all? Obviously there are a lot of factors, not all of them concerning electric utility efficiency or cost.

      • Acbar, One other site-location factor that Dominion mentioned was access to potable water. Dominion signed a contract with the Town of Lawrenceville to supply its water. Despite a massive apparatus for recycling water, the Brunswick plant still will draw 300 gallons per minute from the Lawrenceville system. How that compares to proximity to gas pipelines and 500 kV lines, I can’t tell you. But Dominion officials did say it was a significant consideration.

        • a cubic foot of water is about 8 gals (7.48) . one cubic foot of water per minute is 60×7.5 = 450 gal in a minute… to give perspective – a small creek 5-8 foot across would generate 20-50 cfs … or 5000 gals per minute or more. The North Fork of the Shenandoah at Strasburg is currently running 800 cfs.

          Appalachia is chock full of water… but I’m curious why Dominion needs water treated to drinking water standards… as feedstock for their turbines.

          with regard to Acbars and TomH view that the utilities are seeking to
          “arbitrage” as a “business proposition” – Dominion is using eminent domain to take people’s property – ostensibly to satisfy a public need.

          You know – in BR – we spend a lot of time talking about how govt regulation harms economic progress and productivity and how this administration is the worst example of it but in this case – it appears that FERC and the other regulators are basically the fox in charge of the henhouse.. they are lackeys using the power of govt to force private property owners to give up their property rights and give them to other property owners so they can make a profit …

          Virtually none of this is a bona fide public need that cannot be satisfied without siting these plants near existing pipelines and powerlines – without a legitimate need to use eminent domain.

          essentially – this stuff is being built on the backs of private property owners and rate payers.. to enrich investors… and the same guys who turn down Medicaid because of it’s “cost” have no problem using the tobacco money for this instead of Medicaid for the folks of Brunswick and Greenville.

          pretty disgusting if you ask me.

        • Access to water is one of the primary site selection issues for power plants. Water is used to cool the exhaust from the steam turbine. The giant cooling towers (shown in the picture in the article) allow this water to be recirculated, like a radiator for your car. The potable water might be used as “make-up water” (replacing water lost to evaporation) in the steam cycle since it would be free of contaminants that could cause problems in this crucial aspect of plant operations. It also could have been used to initially charge the entire condenser system. This water has to be to be treated to reduce scale and corrosion in the system.

          • 300 gallons a minute is a small number – something that could be met easily just about anywhere in the state – and the Meherrin RIver is within a couple of miles of the plant – is generating 2600 gallons a minute right now and the mean is 1500 but if you really wanted to be near a lot more water – you’d be on the James or the Shenandoah or Lake Gaston.

            to this point – I have yet to hear the justification for this site from Dominion – just speculation from observers.

            My suspects are that they will replace the power that Surry used to provide to this area – before it was re-routed to replace Yorktown but I doubt seriously we’d ever hear that.

            RTD quoted Dominion: ” The company said the plant would cost about $1 billion and that it could power 400,000 homes when operating at peak capacity. ”

            still – it would be interesting to hear Dominion’s statement.

            The plants can also be put up fairly quickly – looks like 2-3 years -so it’s not like they need a long lead time to anticipate projected demand in 2030.

            and if Dominion can pay 300 million to extend a gas pipeline 100 miles to Brunswick County – why can’t they do that same thing with Hampton and then add gas plants on the Peninsula as needed instead of powerlines over the James?

          • The several years required for construction is just a portion of the time required for the planning of a new power plant. Years in advance, load forecasting and system planning must be done to identify the need for a new plant, then planning for transmission and fuel supplies is required, then the laborious and time consuming activities of site selection, environmental and engineering studies, permit applications, regulatory review and hearings, before approval is granted for construction. I would guess that the lead time for a new gas-fired plant is at least 8-10 years today. We used a 15 year lead time for nuclear plants, but Dominion has already used nearly that much time for preliminary work on North Anna 3, with at least 15 more years to go.

          • I won’t get into it with you, Larry, about proper use versus abuse of the power of condemnation. Suffice it to say that the average Joe at Dominion is committed to the concept of “public service” and sincerely believes that what they are doing in Brunswick County is going to be in the public interest. Here on BR we can dissect the corporate business and political motives that may also lie behind Dominion Resource’s choices in how to meet future electric load growth, some of which undoubtedly satisfied multiple goals, some of which may have reached beyond the scope of Dominion Virginia Power’s electricity business; but gee, that’s legal. I do not think that makes FERC “the fox in charge of the hen house.” The initial question before these regulatory agencies is, is this project as described in the application “in the public interest” as presented to us, not, is there some alternative configuration that we could possibly think of that might be MORE in the public interest. If no intervenor or staff makes an alternative configuration argument, then the agency judges the application on the facts before it. If you disagree in a particular case, then get in there and be (or help someone else be) the intervenor that presents that alternative configuration argument.

            On the matter of “potable water” I’m surprised it matters that much, that’s all. Yes, you need cooling water, but that doesn’t have to be potable or distilled so it can be untreated river water. Perhaps you need pure (“distilled”) water sometimes, but in a power plant that is easy to come by, simply by tapping the steam condensate from any one of several stages, and most uses of distilled water are closed-cycle and don’t require much replenishment. This, moreover, is a “combined cycle” plant which may have some other need for water I’m not familiar with. And of course you’ve got a little consumption of drinkable water in the plant for personnel on the premises. All told, it adds up, but drawing a sufficient amount of water from the ground or a surface source for an NGCC power plant shouldn’t be a big deal — unless of course there is profound water table depletion in the Brunswick area because some other local industry is sucking the ground dry.

            As for why not build this power plant on the Peninsula in lieu of more transmission into the Peninsula to replace the Yorktown retirements — perhaps you could. But then you’d also be committing to must-run this generation whenever needed for local power adequacy and stability on the Peninsula, which might destroy the unit’s potential efficiency as an NGCC plant and end up costing more incrementally than the new transmission line. I just don’t know the details but it’s likely that someone has looked into that tradeoff and rejected it.

  10. The goal should be two-fold:

    1. – extend and conserve supplies of gas for as long as it will be needed as a backup co-fuel to wind/solar

    2.- pollute no more than is required – only when solar and wind are insufficient for load – and you must burn fossil fuels.

    these ought to be the goals for people – for society – and trump goals for investors in public utilities.

    this is an example of where left and right politics – diverge and a certain irony with the word “Conservative” which came from “Conserve” and “Conservation”.

  11. I am not convinced that Brunswick will be one of the most efficient natural gas plants in the world.

    Let’s talk numbers:
    Virginia’s proposed EPA Clean Power Plan 2030 target is 934 lbs CO2/MWhr.

    Brunswick at 55% efficiency comes in at, I calculate, 700 lbs CO2/MWhr. Somebody check my numbers…but 700 lbs CO2/MWhr is not bad at all.

    Keep in mind some states with 100% coal burning are emitting up to 2400 lbs Co2/MWhr. So 700 lbs Co2/MWhr is not bad (assuming I got my math correct – which is questionable).

    • This seems too low. I made a quick check of a calculation on the Scientific American site. They show a typical CO2 emission rate from new gas combined-cycle plants of 890 lbs CO2/MWh. This corresponds to numbers in the low 900’s that I had seen elsewhere.

      This is for CO2 release from the power plant itself and does not take into account greenhouse gas equivalents produced in its supply chain.

      Studies have shown the actual efficiencies of combined-cycle plants can reach about 54%. Manufacturers estimate efficiencies using a slightly different method allowing them to claim efficiencies of up to 60%, but this is not realized in actual operation.

      Small distributed natural gas combined heat and power units obtained fuel to useful energy (electricity and heat) output conversion of over 85%. These units have a higher per kW cost than the huge utility-scale units because labor is a higher percentage of the installed cost. However, they offer many advantages for reliability, lowering demand charges for peak heating and cooling needs, and for using underutilized resources such as landfill or sewage gas.

      • Wow; 85% sounds extraordinary! What’s the stand-alone conversion efficiency (fuel to electricity) of the small electric generation unit embedded in that package? I’m just curious how much of the ‘waste’ heat must be captured and how it is typically used in a d.g. setting.

        • I don’t know for certain, but it is a simple combustion turbine so the electrical efficiency is probably just 35% or so as with combustion turbine peakers. The real advantage is that for an industrial, commercial or office building application you can capture the waste heat that normally gets thrown away in a utility application (although the combined-cycle plants are now capturing some of it). This heat is typically used for space heating, water heating and cooling applications (using absorptive air conditioners). Low to moderate temperature process heat can be produced, but it is not hot enough to produce process steam, I don’t think. But demand charges are the largest portion of the utility bill for this class of customers, so substantial savings might be available.

          I have always thought it would be great to use them in a business in a baseload capacity. Two or more units are often used to provide some load following capability, idling one at night and to allow for maintenance. They can be managed remotely by computer. The excess thermal energy is easier and cheaper to store than electrical energy. Imagine complementing these units with solar PV or maybe solar thermal. You could almost be self-sufficient. Cost considerations are important. I don’t know current pricing. The units have been great for remote applications such as oil and gas operations or remote use by utility co-ops that have a widely dispersed service territory. But higher demand is bringing the price point down. The huge drop in gas prices has probably slowed down their adoption a bit, people are less concerned about wasting most of the energy in the gas.

          Paul Allen (a Microsoft co-founder) bankrolled the company a number of years ago (Capstone). They have numerous successful installations worldwide.

          I thought a number of their larger units could be used to replace a good portion of the generating capacity lost at Yorktown and along with the CHP contribution lowering the load, it would avoid the need for the transmission line across the James. This would be foreign territory for Dominion although better for the region, so it probably won’t be considered as an option.

          • Thanks. Very interesting. As you know such a setup probably would qualify as cogeneration under PURPA, not that that would necessarily make any difference in the way either DVP or PJM treated it (for interconnection or purchases/sales).

  12. Could Dominion kindly give us carbon intensity in Lbs CO2/MWhr for these new natural gas plants in Brunswick and Greensville?

    We could then compare this to EPA’s target of 934 lbs CO2/MWhr for Virginia in 2030.

    I calculate from US DoE that natural gas (at 100% efficiency) is 400 lbs CO2 per MWhr. So for 55% efficiency , that is 400/55% efficiency = 725 lbs CO2/MWhr for the Brunswick plant. But I am not sure if this is the official EPA CPP equation, because depending upon how one handles the heat of water vaporization, it could be closer to 500/0.55 = 925 lbs CO2/MWhr.

  13. One thing I notice on the CO2 is that the peaker turbines are not as efficient as the combined cycle plants.

    that’s a real issue – because the peaker plants are the only ones that really can mesh with solar because they’re the only plants that can quickly vary in it’s output – in concert with solar that would be varying.

    Of course – the other approach with solar could be to employ the same approach used with baseload coal and gas when demand drops below what the plant is producing – you can’t bring the plant down quickly – so you just disconnect the turbines and essentially just burn fuel without generating electricity.

  14. In addition to carbon, don’t we also need to be paying attention to methane?

  15. re: methane

    we do and I’m curious how the CPP deals with that issue. Do they calculate it’s impacts not only at the power plant but in the supply chain?

    that’s yet another reason why we should be using wind/solar when we can and only use Gas when wind/solar are not sufficient.

    or we can just pretend that all this stuff about CO2 and methane are really just conspiracies…to screw up society.

  16. This has been a great discussion with an enormous amount of information exchanged and this environmentalist would like to support what TomH has said … “we should all put our heads together and create a better system that is good for the utilities, their shareholders, and the ratepayers.”

    To do that Virginia must change the rules to allow a network model for a new electricity system develop as other states are already attempting. The new system, as Tom says using the computer industry as reference, will not have the old “’mainframe’ centric character of the old utility system and concentrates the pollution. There are many benefits, including greater reliability, lower costs, less environmental damage, etc. to moving towards a distributed ‘network’ model for our energy system just as we have moved dramatically forward by adopting the network model for our information systems.”

    So here is my problem …I am coming to view ‘conservative’ not just as supporting business interests because that happens on both sides … I have come to view conservative as unable to change. Can someone explain why Virginia is so resistant to even starting to develop that change, a change that could be better for everyone … and how sdo we change that?

    • I suspect you’ll find that any state (a) with below-average electric rates and (b) legislative bodies dominated by Republicans, who tend not to feel any urgency in dealing with climate change will be less motivated to overhaul its regulatory system.

  17. Good points. I have been struggling with the questions you raise for decades. Those who are in control of our system have a stranglehold on it and seem to believe that they cannot share any of that control with any party. They have conditioned decision makers to only believe their truth and to be so dependent upon their support (financial and other) that they dare not challenge the companies. The energy area is the worst, but the same thing is true to lesser degrees in others. Instead of discussing the real needs of everyone and finding ways to set up a system to meet those, the controllers belittle new ideas and others’ perspectives and seek more and more control. I would love to be in an environment where everyone seeks win/win instead of I win/ you lose. So far, I’ve found that to be totally elusive and seeming farther and farther away as our political environment has become so strident and compromise has become a dirty word.

  18. re: distributed vs centric

    it’s not only where you generate geographically – it’s where you get the fuel to generate.

    I’m not in favor of “centric” for centric-sake but I do ask if you have to transport the fuel to a different geographic site- …. why? what’s the advantage of doing that because transporting the fuel is not free so what’s the reason to do that?

    the “fuel” for wind/solar do not need to be “transported” – it’s by definition “on site’ – …

    but the fly in the ointment is that “on-site’ wind/solar is not “dependable” without a back-up source that can compensate for a reduction in output – at least until we have a much more capable “load-balancing” grid.

    finally – we can do the very same thing with wind/solar that we do right now with nukes, coal and gas – and that is – if they are “online” but there is no demand for their power – you just don’t use it.

    for example -if we insisted on putting power from a coal plant into the grid when there is no demand – we’d just destabilize the grid of require other generating plants to go offline.

    so what we do instead – is either sell it to PJM OR just don’t put the electricity into the grid.

    Yes – we run baseload plants – burning fuel – with their turbines idle rather than shut the plant down and then within a few hours having to fire it back up – we just continue to burn fuel but not put that electricity into the grid.

    If we can do that with coal – or even combined-cycle gas – why not wind/solar also rather than claiming that wind/solar are not “reliable” ?

    so – for instance if you had a baseload plant operating and solar operating but you did not need both – what would be better? to take the gas turbines off line or to not feed the solar into the grid?

    the thing we are missing – is understanding what Dominion does with a baseload plant when demand falls below what it is feeding into the grid.

    what happens? do they shut the plant down or just disconnect the turbines and keep on burning fuel in “standby” mode – ready to engage the turbines as soon as demand ramps back up?

  19. Climate change was the basic motivation for changing the electricity system, but we are finding that replacing fossil fuels with a large share of renewables and distributed energy generation actually makes the system better, more reliable, cheaper and best of all … non-toxic. no mercury in the air and in the fish, no particulant damaged lungs in Richmond, no more coal ash to store … etc.

    How much gas is enough gas? Virginia has hydro too … which, like gas peaker plants, is very good at balancing wind and solar. And then there is the PJM framework that really does take over a lot of the functions that Dominion worried about before the wholesale market was so interconnected and available. Maybe someone else can talk to that.

    Rocky Mountain Institute continues to bring together all stakeholders to explore finding the way to the future. NY and CA and other states are bringing everyone to the table too, and they are finding that the usual baseload curve is inverting as more renewables are integrated into the system. Here in Virginia we evidently will have to wait until Dominion has stranded assets before they will release their grip on remaining a centralized monopoly regulated utility, or until efficient buildings and grid defection become their greatest fears.

  20. Larry,

    The figure below shows a typical daily load curve at the summer and winter peaks for a typical utility. The amounts and relative size of each type of demand do not necessarily correspond to what occurs with Dominion.

    The “base load” is the darkest portion at the base of each diagram. It is the load that exists 24 hours a day. Plants that fulfill this load do not cycle as you suggest. They run all day long. The plants with the lowest cost of energy usually are assigned to provide this load. Typically, plants that suit this need cannot vary their output easily or very quickly.

    As people wake up and get ready for work, the load picks up. Because this load exists for much of the day (but not all day) it is considered “intermediate load”. Units that can vary their output at some moderate rate are used to fulfill this “cycling” need. Often, as you describe, the turbines are kept spinning but not connected to the generators when their output is not needed. This is referred to as “spinning reserve” and is also used to meet the utility’s backup reserve in case one of the baseload units goes offline unexpectedly.

    As the work day gets underway and the day heats up, the “peak” load occurs. This usually occurs during the hottest part of the day (late afternoon) in summer. Most of the lower cost generating sources are already engaged so this short-term variable load period is met by “peaking” units that don’t run many hours per year (hence their higher cost) but that can rapidly change their output in response to changes in load.

    In the winter, the peak occurs in the evening. Industries, office buildings and commercial enterprises are still functioning at close to their daytime levels and people are coming home to turn on the lights, warm up their house, prepare dinner, wash the dishes, do laundry, etc.

    Solar is especially well adapted to meet intermediate and peak loads because they occur mostly when the sun shines. PJM always accepts solar or wind generation whenever it is available because it is “free”. There is no cost to generate an extra unit of energy. The cost for solar is all wrapped up in the capital cost. The “cost” of solar energy is the capital cost divided into the projected energy produced over the lifetime of the unit. That is why solar is cheaper in New Mexico than it is in Massachusetts. The same capital cost invested in a solar unit in New Mexico will yield more kWh’s than an identical unit in Massachusetts because there are more hours of sunshine in New Mexico.

    Wind is usually cheaper than conventional sources of baseload generation. But often it is most available at night, or the morning and evening hours when most of the easily variable generation is already turned off. This can result in wind energy displacing conventional baseload generation. Having to “throttle down” these units complicates their operation and reduces their return on investment. This is one reason operators of nuclear units are not too fond of wind energy.

    Energy efficiency is also not embraced by many utilities because it shifts the entire load curve down, also displacing the need for more baseload capacity. Baseload plants are a utility’s money makers, especially with the assistance of pumped storage or an unfilled demand elsewhere in PJM.

    Although solar will be cheaper than conventional sources of intermediate and peak generation, the sun doesn’t always shine so there must be enough variable capacity to fill in the shortfalls in solar output.

    • GOOD chart but it’s “generic” … I wonder what that chart for Virginia looks like?

      also: ” The “base load” is the darkest portion at the base of each diagram. It is the load that exists 24 hours a day. Plants that fulfill this load do not cycle as you suggest. ”

      might be confusion here. I do not think baseload plants “cycle” – I think they run 24/7 and do not ramp up or down but I ask what happens to a baseline plant when it’s output exceeds demand. do they shut it down or just idle the turbines and continue to burn fuel?

      question – what kind of plants provide “intermediate” ? baseload or peakers or other?

      in terms of hydro – that’s a limited resources with no future for expansion.

      it’s good what we got -but it won’t add anything for the future.
      we’ve pretty much exhausted new sites for hydro.

  21. Climate change was the basic motivation for changing the electricity system, but we are finding that replacing fossil fuels with a large share of renewables and distributed energy generation actually makes the system better, more reliable, cheaper and best of all … non-toxic. no mercury in the air and in the fish, no particulant damaged lungs in Richmond, no more coal ash to store … etc.

    How much gas is enough gas? Virginia has hydro too … which, like gas peaker plants, is very good at balancing wind and solar. And then there is the PJM framework that really does take over a lot of the functions that Dominion worried about before the wholesale market was so interconnected and available. Maybe someone else can talk to that.

    Rocky Mountain Institute continues to bring together all stakeholders to explore finding the way to the future. NY and CA and other states are doing the same and they are finding that the usual baseload curve is inverting. Here in Virginia we evidently will have to wait until Dominion has stranded assets before they will release their grip on remaining a centralized monopoly regulated utility, or until efficient buildings and grid defection become their greatest fears.

  22. Here’s an interesting news story:

    State OKs addition of two turbines at Hanover site

    ” The State Corporation Commission has approved the construction of two additional generating units capable of producing 340 megawatts of electricity at the Doswell Energy Center in Hanover County.
    The units, capable of firing both natural gas and ultra-low sulfur diesel fuel, will join five similar turbines on the 155-acre site near the Kings Dominion theme park.
    The owner of the energy center, Doswell Limited Partnership, did not disclose the cost of the turbines in its application, but they will be able to produce twice the electricity of the most recent expansion on the site, which in 2000 was said to cost about $50 million. The center currently includes four combined cycle natural gas units that together can produce up to 665 megawatts of electricity and an additional turbine that can generate 171 megawatts.”

    http://www.richmond.com/business/local/article_56d985d2-bf4f-58b1-840a-8bd218725e93.html

    so a couple of questions. Why is this a non-Dominon plant and who are they selling the power to ?

    why can’t this kind of thing be done all across Va using these smaller turbine plants to buffer local demand?

    • Regarding types of plants meeting various types of load (someone who has been a resident longer might have a better idea, but I can generalize):

      The nuclear plants at Surry and North Anna are probably the first baseload plants to go online for Dominion. These plants were built in the 1970’s so they are fully depreciated and have a lower fuel cost than coal or natural gas units. They usually are offline only for refueling or unexpected maintenance issues. Next, I would guess that the new combined cycle plants in Warren County and Brunswick might be up next. Although Dominion is assuming about a 75-82% capacity factor for these units, so another unit might be coming on before them.

      The most efficient coal plants here or in West Virginia probably come up to complete the baseload and begin the intermediate load. Other coal plants and the biomass plant and the old coal plants converted to natural gas might come on next. I am not sure how the hydro is dispatched; probably in the intermediate load band. The pumped storage is probably saved for peak loads. Then the gas and oil-fired combustion turbines would be used to meet peak loads, with the least efficient and most expensive units just used around the seasonal peaks.

      The Doswell unit you refer to appears to be a series of simple combustion turbines with some waste heat recovery going to a 171 MW steam turbine. The two new units appear to be natural gas or oil-fired combustion turbines. This facility might operate in an intermediate and peak load capacity. It is in Hanover County, so it might be contracted to the Rappahannock utility, although I don’t know the details.

      Dominion currently has more than a dozen different gas and oil-fired combustion turbines around the state and intends to build more as they increase their development of solar facilities.

  23. Denver Post – 6-9-16 “Western Colorado has 40 times more natural gas than previously thought[.] … The U.S. Geological Survey said the Mancos Shale formation in Colorado’s Piceance Basin holds about 66.3 trillion cubic feet of gas, up from 1.6 trillion estimated in 2003. … The new estimate could mean the Piceance Basin has the second-largest natural gas reserves in the country, after the Marcellus Shale formation in Pennsylvania and neighboring states[.]”

    http://www.denverpost.com/2016/06/08/colorado-more-natural-gas-than-thought/

  24. Dominion’s choice for gas-fired electric plants is based on supporting the other 75% of Dominion’s business. Excel Energy’s Public Service of Colorado utility just signed a 25-year agreement to purchase power from a 56-megawatt solar farm. The Comanche farm solar power beat out all other power sources including gas, and there is no future risk of fuel price escalation. Dominion’s choice for gas may be a risky one.

    The ‘shale gas revolution’ Dominion is counting on to meet Virginia’s electricity needs may not be durable.
    • Researchers at the University of Texas and the Post Carbon Institute analyzed extensive well production data and concluded that most shale gas fields will have reached peak gas production in three – five years. Some believe the Marcellus may peak next year. Range Resources, a drilling company, thinks peak production will occur in 2020.
    • The drilling process requires excessive amounts of fresh water and can cause ground water contamination. The water used is removed from the water cycle. Toxic wastewater that cannot be processed by water facilities is re-injected into old wells and has caused earthquakes.
    • New York State banned fracking after an intensive evaluation by the State Board of Health.
    • The supposed 50% reduction in Green House Gas emissions is not a complete or accurate comparison when pipeline and wellhead leaks are included. A new Massachusetts survey found 20,000 potentially dangerous leaks that have cost ratepayers more than $1billion over the years.
    • While in the atmosphere methane is 75 times more potent than CO2. The measurement comparisons are confused by “time in the atmosphere” vs the standard time frame of CO2 disapation – 100 years – as measurement.

    Why can’t VA join the world and leave some fossil fuels in the ground?

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