The Ascendancy of Gas and Wind

A front-page article in the Wall Street Journal today highlights how the rapid rise of wind and natural gas is forcing electric utilities to close older coal- and nuclear-powered generating units. Last year natural gas surpassed coal as the leading source of electricity, and wind provides energy at the lowest price of any source.

Last year the wholesale price of electric power averaged less than $25 per megawatt hour in Texas, which has the most deregulated electricity market in the country. The wholesale price has fallen as low as $29 in the PJM Interconnection grid (of which Virginia is a part), which arguably operates the most sophisticated interstate grid in the country. PJM benefits from the construction of gas-fired plants tapping cheap Marcellus shale gas and extensive wind farms in the Midwest.

Citing a study by investment bank Lazard, the WSJ gave the following average unsubsidized cost of generating power from different electricity sources:

  • Natural gas — $60
  • Coal — $102
  • Nuclear — $150
  • Solar — $49.50
  • Wind — $45

But the WSJ provides one very big caveat: Those numbers don’t factor in the intermittent production of wind and solar. A megawatt of electricity that is “dispatchable” — that is, it can be produced when called upon to meet demand — has greater economic value than a megawatt of electricity from a source that produces output when the sun is out and the wind is blowing.

I’m still trying to figure out the economics of this. As I understand it, the marginal cost of operating a wind or solar facility is essentially zero. The energy source is free, and the manpower requirements are negligible. Thus, wind and solar producers dump all of their production into wholesale markets, undercutting coal, gas and nuclear generating units that actually have operating costs. As a consequence, coal and nuclear are losing market share and, increasingly, many units are unable to operate profitably. Even less efficient gas-fired units may be in trouble.

Question: If the wholesale price for electricity is below the unsubsidized cost of generating electricity in the PJM system, how can anyone justify building new capacity of any kind?

Another question: What happens if dozens of coal and nuclear plants in the PJM system shut down? Will there be sufficient capacity to meet base-load demands for electricity, especially at night when solar isn’t producing? There is plenty of wind power at night, but not in Virginia. There is only so much power the electric grid can transmit from Midwestern wind farms to Virginia.

I have seen no indication that PJM’s experts are worried about these problems, so maybe I’m raising a non-issue. All I can say is that the electrical industry works according to laws of economics like no other.

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29 responses to “The Ascendancy of Gas and Wind

  1. What’s not clear is if you’re talking about onshore or offshore wind.

    Additionally – there is some kind of a mega-disconnect here because in this blog we have repeated “news” that wind in the Middle Atlantic states is mostly a “no go” from both NIMBYs and reliably wind patterns that keep turbines spinning.

    Also .. when we say “marginal” or “operating” costs are we including the up-front capital costs? For instance Offshore wind has huge up-front costs and those costs do have to be recovered as it “operates”. One would think that a huge part of any charged price for wind power – goes to pay for the capital costs which are probably loans or investments.

    All things being equal – if wind IS a good investment than where are those units?

    and once again – the intermittent nature of wind and solar is not a significant issue now that we do have plentiful supplies of gas and the ability to build gas plants that can and will run complementary to wind/solar.

    We just don’t use wind/solar as a primary fuel .. it’s a “use when it is available” fuel… which can offset using other fuels when it is available.

    I suspect Jim gets this thinking from Dominion… but if you take what they say with a grain of salt and listen to other utilities – that ARE using wind/solar – they have it figured out and it’s not considered a disadvantage at all but rather a way to burn cheaper fuel when that cheaper fuel is available.

    This is what most islands are doing now that use diesel fuel as their primary source but they can save on how much diesel they burn – if they can “harvest” wind/solar at the times it is available … and when it’s not, drop back to the diesel.

  2. PJM’s experts are not worried about the issues that are described in the article because they currently have 75% more surplus capacity than they need to assure grid reliability, with more new generation on deck that is not supported by an increase in demand.

    The greater economic value of dispatchable units is recognized by PJM. They have a separate auction for capacity. Gas, coal, oil, and nuclear units can participate in this auction that pays a certain amount per MW for capacity than can be reliably available to the grid whenever it is needed. Renewable sources cannot participate in this auction and do not have any type of “free ride”with PJM. As a higher percentage of renewables exist on the grid the value of dispatachable generation will increase. The market mechanism will actually assist with grid reliability.

    The difficulty is that coal and nuclear units are dispatchable, but are very inflexible in their operation, which does not have as much value to the grid. The current administration wants to distort the current market mechanism by adding subsidies for coal and nuclear units because of the unsubstantiated idea that they add to grid reliability. They are trying to have power plants that have at least 90 days of fuel on-hand receive a subsidy (coal and nuclear). Independent studies have not confirmed that paying for coal and nuclear units to operate uneconomically adds to grid reliability. But it does add to customers’ bills.

    During the Polar Vortex coals piles froze, causing many more curtailments than did shortages of natural gas or pipeline capacity (less than 5%).

    The cost to generate the next unit of electricity (the marginal cost) for renewables is essentially zero. It is common for the small maintenance costs for solar to be built into the capital cost of the project. Once the capital costs have been spent, the cost to generate another unit of electricity by a solar panel is zero, because there are no fuel costs.

    The marginal costs for conventional generation are basically the costs of fuel (plus O&M). Nuclear fuel costs are going up, natural gas costs are going up. PJM is considering adding a carbon price into their wholesale power cost so gas and coal ‘s prices will go up.

    The cost of new wind and solar is continuing to decline at a rapid pace (15-20% per year). The challenge is how to provide adequate power when the renewables are not generating, at a price that properly compensates the dispatchable units. PJM and others are looking at this.

    The wholesale price of $29 reflects the low price when a good percentage of renewables are contributing without a great need for peakers. This is not the average wholesale price for PJM, so it is still possible for the better conventional units to make a profit.

    Much of the fear of renewables that has been stirred up has been done by special interests in search of corporate welfare. The subsidies proposed by DOE and and being considered by FERC will predominately (over 80%) benefit just five companies that own nuclear plants and five companies that own coal plants.

    PJM is trying to operate a free market, but is considering setting up its own coal and nuclear subsidy that won’t distort things as much as the DOE proposal will.

    There is a lot of attention to reliability by NERC, FERC, the ISOs (like PJM), and state regulators. No one will jump off the deep end with renewables in a way that will threaten reliability. This is about whose ox is being gored by technological advances. Old technologies that are no longer a good fit for the modern grid want the rest of us to pay extra to keep them afloat. It is interesting to see those who do not support that concept when it applies to people, have no qualms supporting it when it comes to their favorite corporations.

  3. I endorse TomH’s comment above. It is easy to see changes as dramatic as those happening today in bulk electricity as threatening, if not apocalyptic; and there are plenty of folks out there today who don’t understand the forces in play and are dead-set against change. It would be less admirable if corporate interests which did know what is happening misrepresented the consequences to a confused public. But worst would be, if those corporate interests themselves were confused.

    The short answer to your questions, Jim, is that the market structures and reliability and operating and regulatory requirements we have in place seem to be holding up very well under this stress of change. I continue to believe that solar and wind power are wonderful new tools in the electricity toolbox; and we have a lot to look forward to, particularly with regard to distributed solar (“rooftop solar”).

    If you’ll allow me, I’d like to expand on just one aspect of this, which is what I think is your key question, “What happens if dozens of coal and nuclear plants in the PJM system shut down? Will there be sufficient capacity to meet base-load demands for electricity, especially at night when solar isn’t producing?”

    Electricity, as you know, today must be created essentially at the same moment it is consumed. Let’s start here even though there is a whole ‘nother discussion we could get into about time shifting through storage in the form of pumped hydro, batteries, flywheels etc. For purposes of this discussion, supply must equal demand at any given moment in time. That means, when solar and wind aren’t available, some other kind of generation must be, else the grid will collapse. This is not optional. If there simply isn’t any more generation available, the grid operator will shed load in order to balance the supply with the demand again. The likelihood of this is measured by the “loss of load expectation” (LOLE) calculation which has to be within extremely low limits set by the reliability standards-setter, NERC, and its regional reliability councils.

    Here is how PJM currently goes about preventing loss of load due to insufficient generation.

    First, individual investor-owned utilities take their long term planning seriously. Financing and building new generation is a long lead time item; and it’s expensive to build the wrong new equipment for the job and be stuck with its inefficiencies. Shareholders will not be amused if this is done sloppily. Regulators require planning updates from the utilities (e.g., the SCC’s IRP) designed to allow the regulators to sound the alarm if the public is at risk.

    Second, with the advent of competitive independent generation selling into wholesale energy markets, the FERC established a series of independent system operators (ISOs) across the country, whose primary concern is to sustain grid reliability and to blow the whistle to regulators if they foresee a threat to grid reliability, either on the resource or the delivery side. Secondarily, they are concerned about maintaining that reliability in an economic manner and about operating markets in which the participants can make the most economically efficient use of available resources on the grid. PJM is one of these independent system operators today; it is built on a pre-existing voluntary group of utilities who “pooled” their resources for mutual benefit, for greater reliability and for voluntary economic power exchanges that evolved into today’s wholesale energy market. PJM started in two states but has expanded dramatically in recent years.

    When integrated utilities that both own generation and serve retail customers operate on the same grid as independent generators, and independent load servers (for example, coops that don’t own generation), the grid operator also has to assure that the arrangements between buyers and sellers are at arms length, with maximum transparency. PJM does this by requiring, among other things, that all load-serving entities (LSEs) within PJM contract publicly with enough deliverable, reliable generation or generation-equivalent demand-side resources to allow PJM to supply their forecast peak load. Dominion is an LSE; Rappahannock Electric Coop is an LSE; Staunton Municipal Electric is an LSE; any entity that has undertaken a commitment to provide electricity to an end user (a retail customer) off the PJM portion of the grid is an LSE. For example, for 2018, if the LSE’s peak load is forecast to be 3000 MW and PJM has established a reserve requirement of 13%, PJM will require that the LSE give PJM operational control over 3,390 MW of generation (3000×1.13); the reserve requirement is to cover equipment failures (“forced outages”). How the LSE obtains the operational control that it turns over to PJM — whether it’s through ownership or by contract — doesn’t matter to PJM; neither does the price. All PJM requires is that the LSE turn over control over enough generation to meet the LSE’s load.

    Of course, on most days, at most times of day, each LSE’s load (and the load of all other LSEs) will not come close to the annual maximum. PJM’s job on those days is to run the cheapest generation made available to it first. We can save a discussion of the grid energy market and how its clearing price is calculated for another day. The important thing here is, at the beginning of the operating year beginning June 1, every LSE must own or have under contract enough generating capacity to meet its forecast load. Moreover, these arrangements must be made intially 3 years in advance, with adjustments thereafter to substitute resources, or if the LSE’s load forecast changes. PJM operates a “capacity market” to facilitate the exchanges that result in all these contracts.

    So what if, three years out, an LSE says it cannot find sufficient deliverable, reliable capacity to meet its PJM obligation? Three years is about the minimum time it would take for emergency construction of new generation such as “combustion turbine” units that are diesel powered, high-operating-cost, but get the job done and can be built quickly.

    All of this presumes the existence of a competitive generation market in which independent generators, sensing a coming shortfall, would build new generation in order to satisfy the demand for it. Nationwide, there is money to be made in electricity generation and the industry follows the trends and responds, particularly in regions with efficient wholesale markets like those in PJM, well in advance of extreme conditions like an absolute shortage of capacity grid-wide. So far, the independent generation sector has been very active in the PJM region, and some utilities such as Dominion have also continued to build aggressively.

    It is highly unlikely that PJM’s utilities and their planners, or their regulatory commissions, would be caught unawares and only have three years notice of a regional capacity shortfall. First of all, every one of those retirements you mention would have attracted a great deal of attention. Any LSE in PJM (including Dominion) that included a unit among its committted capacity resources three years out, then chose to retire the unit, would either have to wait out the three years or replace the unit with a substitute resource. If this was pursuant to a contract with another generation owner, that owner would be liable for breach of contract and damages. The PJM regulatory commissions all have long range integrated resource planning requirements and exchange information among themselves about these; PJM itself also performs long range capacity adequacy studies and participates in the State’s regulatory reviews of all of these.

    Now, all this said, we are talking about having enough generation at the time of maximum load. PJM also runs studies of “loss of load expectation” (LOLE) which take into account the impact of solar and wind generation that are not always available; LOLE standards are set by the reliability organizations under NERC. Obviously, the more solar and wind power in the diverse mix of generation that LSEs are using to meet their capacity requirements, the greater the risk of LOLE. PJM currently believes the LOLE is low enough if solar and wind generation is less than 20% of the total. The annual peak demand is statistically likely to be on a hot, clear day with some wind; the remaining generating resources are not limited to day only or windy conditions or clear skies, etc., and given the lower grid demands at night and other times, PJM believes the LOLE criterion is met with less than 20% solar/wind. But above that, it appears that LOLE would rise. Moreover there is concern about the ability of older generation to perform when needed if, although not retired, a unit is run so infrequently due to economic displacement by cheap solar and wind power that it becomes unreliable on short notice. PJM is phasing in a weighting of performance criteria in its evaluation of capacity resources claimed by an LSE for capacity credit.

    So, your question was, “”What happens if dozens of coal and nuclear plants in the PJM system shut down? Will there be sufficient capacity to meet base-load demands for electricity, especially at night when solar isn’t producing?” Yes — assuming the PJM ISO continues to require all its LSEs to meet their capacity and LOLE obligations under NERC reliability requirements and the PJM agreements.

  4. I endorse TomH’s comment above. There is no imminent shortage of generation in PJM. Longer term, it is easy to see changes as dramatic as those happening today in bulk electricity as threatening, if not apocalyptic; and there are plenty of folks out there today who don’t understand the forces in play and are dead-set against change. It would be less admirable if corporate interests which did know what is happening misrepresented the consequences to a confused public in order to push their own agenda. But worst would be, if those corporate interests themselves were confused.

    The short answer to your questions, Jim, is that the market structures and reliability and operating and regulatory requirements we have in place seem to be holding up very well under this stress of change. I continue to believe that solar and wind power are wonderful new tools in the electricity toolbox; and we have a lot to look forward to, particularly with regard to distributed solar (“rooftop solar”).

  5. A further comment: If you’ll allow me, I’d like to expand on what I think is your key question, “What happens if dozens of coal and nuclear plants in the PJM system shut down? Will there be sufficient capacity to meet base-load demands for electricity, especially at night when solar isn’t producing?”

    Electricity, as you know, today must be created essentially at the same moment it is consumed. Let’s start here even though there is a whole ‘nother discussion we could get into about time shifting through storage in the form of pumped hydro, batteries, flywheels etc. For purposes of this discussion, supply must equal demand at any given moment in time. That means, when solar and wind aren’t available, some other kind of generation must be, else the grid will collapse. This is not optional. If there simply isn’t any more generation available, the grid operator will shed load in order to balance the supply with the demand again. The likelihood of this is measured by the “loss of load expectation” (LOLE) calculation which has to be within extremely low limits set by the reliability standards-setter, NERC, and its regional reliability councils.

    Here is how PJM currently goes about preventing loss of load due to insufficient generation.

    First, individual investor-owned utilities take their long term planning seriously. Financing and building new generation is a long lead time item; and it’s expensive to build the wrong new equipment for the job and be stuck with its inefficiencies. Shareholders will not be amused if this is done sloppily. Regulators require planning updates from the utilities (e.g., the SCC’s IRP) designed to allow the regulators to sound the alarm if the public is at risk.

    Second, with the advent of competitive independent generation selling into wholesale energy markets, the FERC established a series of independent system operators (ISOs) across the country, whose primary concern is to sustain grid reliability and to blow the whistle to regulators if they foresee a threat to grid reliability, either on the resource or the delivery side. Secondarily, they are concerned about maintaining that reliability in an economic manner and about operating markets in which the participants can make the most economically efficient use of available resources on the grid. PJM is one of these independent system operators today; it is built on a pre-existing voluntary group of utilities who “pooled” their resources for mutual benefit, for greater reliability and for voluntary economic power exchanges that evolved into today’s wholesale energy market. PJM started in two states but has expanded dramatically in recent years.

    When integrated utilities that both own generation and serve retail customers operate on the same grid as independent generators, and independent load servers (for example, coops that don’t own generation), the grid operator also has to assure that the arrangements between buyers and sellers are at arms length, with maximum transparency. PJM does this by requiring, among other things, that all load-serving entities (LSEs) within PJM contract publicly with enough deliverable, reliable generation or generation-equivalent demand-side resources to allow PJM to supply their forecast peak load. Dominion is an LSE; Rappahannock Electric Coop is an LSE; Staunton Municipal Electric is an LSE; any entity that has undertaken a commitment to provide electricity to an end user (a retail customer) off the PJM portion of the grid is an LSE. For example, for 2018, if the LSE’s peak load is forecast to be 3000 MW and PJM has established a reserve requirement of 13%, PJM will require that the LSE give PJM operational control over 3,390 MW of generation (3000×1.13); the reserve requirement is to cover equipment failures (“forced outages”). How the LSE obtains the operational control that it turns over to PJM — whether it’s through ownership or by contract — doesn’t matter to PJM; neither does the price. All PJM requires is that the LSE turn over operational control over enough generation to meet the LSE’s load.

    Of course, on most days, at most times of day, each LSE’s load (and the load of all other LSEs) will not come close to the annual maximum. PJM’s job on those days is to run the cheapest generation made available to it first. We can save a discussion of the grid energy market and how its clearing price is calculated for another day. The important thing here is, at the beginning of the operating year beginning June 1, every LSE must own or have under contract enough generating capacity to meet its forecast load. Moreover, these arrangements must be made intially 3 years in advance, with adjustments thereafter to substitute resources, or if the LSE’s load forecast changes. PJM operates a “capacity market” to facilitate the exchanges that result in all these contracts.

    So what if, three years out, an LSE says it cannot find sufficient deliverable, reliable capacity to meet its PJM obligation? Three years is about the minimum time it would take for emergency construction of new generation such as “combustion turbine” units that are diesel powered, high-operating-cost, but get the job done and can be built quickly.

    All of this presumes the existence of a competitive generation market in which independent generators, sensing a coming shortfall, would build new generation in order to satisfy the demand for it. Nationwide, there is money to be made in electricity generation and the industry follows the trends and responds, particularly in regions with efficient wholesale markets like those in PJM, well in advance of extreme conditions like an absolute shortage of capacity grid-wide. So far, the independent generation sector has been very active in the PJM region, and some utilities such as Dominion have also continued to build aggressively.

    It is highly unlikely that PJM’s utilities and their planners, or their regulatory commissions, would be caught unawares and only have three years notice of a regional capacity shortfall. First of all, every one of those retirements you mention would have attracted a great deal of attention. Any LSE in PJM (including Dominion) that included a unit among its committted capacity resources three years out, then chose to retire the unit, would either have to wait out the three years or replace the unit with a substitute resource. If this was pursuant to a contract with another generation owner, that owner would be liable for breach of contract and damages. The PJM regulatory commissions all have long range integrated resource planning requirements and exchange information among themselves about these; PJM itself also performs long range capacity adequacy studies and participates in the State’s regulatory reviews of all of these.

    Now, all this said, we are talking about having enough generation at the time of maximum load. PJM also runs studies of “loss of load expectation” (LOLE) which take into account the impact of solar and wind generation that are not always available; LOLE standards are set by the reliability organizations under NERC. Obviously, the more solar and wind power in the diverse mix of generation that LSEs are using to meet their capacity requirements, the greater the risk of LOLE. PJM currently believes the LOLE is low enough if solar and wind generation is less than 20% of the total. The annual peak demand is statistically likely to be on a hot, clear day with some wind; the remaining generating resources are not limited to day only or windy conditions or clear skies, etc., and given the lower grid demands at night and other times, PJM believes the LOLE criterion is met with less than 20% solar/wind. But above that, it appears that LOLE would rise. Moreover there is concern about the ability of older generation to perform when needed if, although not retired, a unit is run so infrequently due to economic displacement by cheap solar and wind power that it becomes unreliable on short notice. PJM is phasing in a weighting of performance criteria in its evaluation of capacity resources claimed by an LSE for capacity credit.

    So, your question was, “”What happens if dozens of coal and nuclear plants in the PJM system shut down? Will there be sufficient capacity to meet base-load demands for electricity, especially at night when solar isn’t producing?” Yes — assuming the PJM ISO continues to require all its LSEs to meet their capacity and LOLE obligations under NERC reliability requirements and the PJM agreements.

  6. Much appreciative of TomH and Acbars comments.. !

    re: definition of “dispatchable”.

    much ado over the fact that you cannot necessarily call up wind/solar when you need it.

    but that is ALSO TRUE of nukes and coal if you think about it and as Tom pointed out.

    who knew electricity and the grid was this complicated! 😉

    if nothing else, Tom and Acbar and some others have brought that message home at least to this ignorant guy!

    One of the problems that I have with Dom and some others is that they seem to inject fear and loathing into the renewable issue by continuing to point out that they are “not dispatchable and not reliable”. And if they were wholly independent voices with no dogs of their own in the hunt – that might put some strong credence into that concern. But the fact that they are heavily invested in conventional fuels and the status quo for their business models .. for their monopolies… undermines , at least for me, those “concerns”.

    There seems to be a basic conflict and how “reliable” or “dependable” renewables are or are not – seems to be colored by who is saying it.

    I’m a continuing skeptic of the more optimist voices from the environmental side especially when it comes to batteries or other “emerging” technologies… I don’t see them as never happening but it’s the here and now we have to deal with – especially at night and times when even when we are all asleep – there is sufficient power to keep our homes warm and the lights on and all those electronic gizmos not blinking or beeping…etc.

    So – no – I’m no believer in solar nor batteries at 2 am when I am snoring.

    however, just as we have “adapted” to the “limitations” of coals and nukes in their inability to quickly come online – even when we desperately need that power or will “shed load” otherwise – we can also adapt renewables.. harvesting from them what is valuable and useful – when it is available and so it is with skepticism when I keep hearing Dom and others accentuate the negatives about renewables and not embracing the “deliverables” – in a similar way that they have managed to minimize and overcome the deficiencies of coal/nuke/baseload .

    The question ” what if we close too many coal or nukes” … why you’d think that – THAT question would evoke a super-quick response from the utilities – “HEY .. do you think we are stupid or irresponsible about our core duty of grid reliability? ” .

    I EXPECT the utilities to maximize their use of a valuable fuel resource – renewables WHILE chewing gum at the same time – i.e. not screwing up the grid by closing plants that are needed.

    Why do we actually have conversations like this to start with – other than I guess for the amusement of folks at Dominion to churn the Hoi Polloi like would happen when a critter shows up at a poultry building to spook the 10,000 chickens.

    Bottom Line: ” Oh woe is us ..how can we use renewables when they are not reliable and if they force us to ..we might close too many coal and nuke plants and disaster will surely follow us the rest of us wretched lives”.

    that dog won’t hunt not now, not ever , no matter how many times it howls.

  7. Basically I am happy…after fighting coal plants in a prior life, I never thought we’d see this day in my lifetime. I do not pretend to be a utility planner or grid management forecaster, so that is between Va., PJM, and Dominion and others involved.

    The three opportunity areas where Virginia could take a more of a lead (assuming we wanted to) are probably:
    (1) natural gas,
    (2) nuclear
    (3) off-shore wind

    Those options are all politically controversial here. It’s looking more and more like our hands are tied. Presumably the major power export states in our region (OH, PA, WV) will continue their lead role by replacing old coal/nuke plants with natural gas/wind when/if needed.

  8. A few observations that appear to be missing in this discussion … the fact that DR and efficient buildings have lagged in Virginia because of rules and the availability of easily financed capital … Virginia’s large potential for offshore wind … and the timing of solar and wind production …. as well as the fact that storage will be available in the not too distant future.

    While Virginia is one of the most improved states this year for efficiency measures we only moved up to rank 29th among the states in 2017, scoring 15.5 points out of a possible 50. Not good. Closing those coal plants will be easier when our need for electricity is curbed by efficiency.

    Then our DER lag … allows Virginia to continue with the old system because DER means conventional generation will see declining revenues as Tom has highlighted frequently.
    DER requires flexibility and a redesigned gird. Onsite PV can meet a piece of summer peak requirements and allow for cheaper power overall. Behind the meter storage will become cost effective for the customer in the next decade.

    Then offshore wind … I have written about the synergy of offshore wind and solar at meeting peak demand, the most expensive power to generate on the grid. “Called the sea breeze effect …as the land heats up during the day the air mass above it rises, pulling in the cooler air over the water and creating steady offshore winds. An offshore wind farm … will tend to be very productive during hot summer afternoon conditions, when electric demand is at its highest due to increased use of air conditioning.”

    Then there is proximity. Since most of the world’s largest cities are near coastlines, offshore wind power installations have the potential to produce power close to high-demand areas, meaning the transmission of mid-western wind in VA won’t be a factor.

    Finally, costs are coming down fast. Lawrence Berkeley National Lab estimates offshore wind prices will drop by 30%, by 2030. BNEF expects the levelized cost of offshore wind to decline 71% by 2040, In addition, many European offshore projects are now reaching wholesale cost parity without subsidies. As US projects, now on the boards, get built the price will drop here too.

    Other coastal states are planning for large offshore farms … NY, MA, and in NJ Gov.-elect Phil Murphy wants New Jersey to get all its energy from “clean” sources by the middle of the century … and he set what his campaign calls “the most ambitious offshore wind target in the country” by promising to bring 3,500 megawatts of offshore wind power online by 2030.

    In MA, storage is combining with offshore wind. “Deepwater Wind announced a partnership with Tesla this week to pair a 144 MW offshore wind farm with a 40 MWh battery storage system. The project will be located off the coast of New Bedford Mass. and is in response to a joint request from the state’s utilities and Department of Energy Resources for proposals (RFP) to obtain 9,450,000 MWh of clean energy.

    I just don’t understand why Virginia is willing to be last.

  9. “The three opportunity areas where Virginia could take a more of a lead (assuming we wanted to) are probably:
    (1) natural gas,
    (2) nuclear
    (3) off-shore wind”

    Virginia utilities have really taken a lead in the first area. DVP has built thousands of MW of new, very high efficiency gas combined cycle generation. Even coal-dependent Apco bought and finished a natural gas plant in Dresden, OH that serves its customers in Virginia and WV also.

    DVP has extended the operating licenses of its 4 nukes and intends (at this point) to seek a further extension. Plants originally thought to operate for 40 years will operate for 80 years, if the extensions are granted. New nuclear construction remains punishingly expensive and likely will not be attempted, although DVP keeps its North Anna 3 unit as a conceptual possibility, mainly to use to manipulate its earnings under the odd regulatory scheme in Virginia, assuming the General Assembly eventually relents and lets the SCC regulate again. That seems more likely with the election results from this past November.

    DVP is also installing an off-shore wind mini-project (12 MW) that may or may not lead to a larger set of facilities 22 miles off Virginia Beach. The economics of that remain insane also, with gas prices so low.

    Couple of other observations about PJM and reliability. There is not enough intermittent, renewable, zer0-cost power available across PJM to meet totally meet demand at any hour of the year (yet). In PJM, every supplier of energy receives the price of the market-clearing unit. So, the price of power in PJM for all suppliers is always a positive number. I believe this is not the case in Texas at certain times of year at night when there is so much wind that the price of power drops to zero or even below, when the inflexible units have to pay customers to take their power.

    Also, PJM uses something called Locational Marginal Pricing (LMP) which is designed to incent the construction of generation in the areas where, due to transmission constraints, the local price is highest. Whether LMP has worked as designed is sort of open to debate. So, if unexpected unit retirements occur, and pricing reflects shortage, there is a kind of built in incentive to replace that generation. But, PJM is awash in capacity at the moment.

  10. It looks to me as if renewable energy sources will continue to provide more and more of the electric power consumed in Virginia. It either has or will in the foreseeable future reach a tipping point. If so, how much regulation will be needed to protect consumers while the transition completes? And what happens if we have more regulation? Will it protect competitors or competition?

    Virtually every federal agency senior official I’ve spoken to over the last 33 years, be they a political appointee or professional staff, Republican or Democrat, has clearly stated the federal government makes poor economic decisions. These basic decisions should be left to the market.

    So why should presidents, governors, members of Congress or state legislators make decisions about sources of electric power? Why should the NJ Governor-elect make a decision that all electric power must be from renewable sources? What if a 90/10 mix provides more benefit to consumers? Odds are those decisions will be bad ones. Create and enforce a framework that requires reliable service, protection against excessive and discriminatory prices, and transactions between affiliates.

  11. Jumping on board the shale gas revolution may not end up being a great idea in the 40-50 year long run. We have hydro which is a form of storage, and we do need gas to be a flexible source of generation as we build up renewables and gather the political will to change the old monopoly rules to free the growth of distributed resources and efficiency measures. But how much gas is too much? In CA a planned gas plant for peaker use is being withdrawn because there are better, cheaper ways to meet that peak demand. And MIT just issued a report stating that the projections for Marcellus shale are overblown, confirming a UT report from 4-5 years ago.

    As for those 2 windmills on the coast … Dominion lost funds from the federal government to help pay for those ‘trial balloons’ because they delayed doing the project. In the meantime Dominion has been sitting on the 113,000 acres of Virginia offshore leases they won by out bidding several wind companies. Dominion pays an annual fee of $350,000 to hold the space, but building on those leases does have a time limit attached to it.

    The state holds some responsibility for this offshore wind debacle because they did not provide onshore support for the development of the offshore wind industry, the kind of development that is now taking place in Baltimore and MA.

    The future requires new regs, a different structure for the grid, as well as expansion of the sources and owners of power generation.

  12. Jumping onboard the shale gas revolution may not end up being a great idea in the 40-50 year long run. We have hydro which is a form of storage and we do need gas to be a flexible source of generation as we build up renewables, and gather the political will to change the old monopoly rules that hinder the growth of distributed resources and efficiency measures. But how much gas is too much? In CA a planned gas plant for peaker use is being withdrawn because there are better, cheaper ways to meet that peak demand. And MIT just issued a report stating that the projections for Marcellus shale are overblown, confirming a UT report from 4-5 years ago.

    As for those 2 windmills on the coast … Dominion lost funds from the federal government to help pay for those ‘trial balloons’ because they delayed doing the project. In the meantime Dominion has been sitting on the 113,000 acres of Virginia offshore leases they won by out bidding several wind companies. Dominion pays an annual fee of $350,000 to hold the space, but building on those leases does have a time limit attached to it.

    The state holds some responsibility for this offshore wind debacle because they did not provide onshore support for the development of the offshore wind industry, the kind of development that is now taking place in Baltimore and MA.

    The future requires new regs, a different structure for the grid, as well as expanded sources and owners of power generation.

  13. Re …why is the government involved?

    We have that reliability framework and it served us well over the past century … regulated natural monopolies. Thing is we now have 2 additional things to consider … a century’s worth of pollution in a variety of forms to clean up and new technology that doesn’t pollute, is more efficient and allows for a different market because generation is no longer required to only come from central sources.

    Those added parameters are leading us to attempt to create a more market-oriented solution to providing reliable power, but energy remains a market still restricted by generation methods that create pollution we no longer need to endure, and reliability issues which are also seen as the purview of governments.

    Developing markets, seen to be in society’s interest, have always required ‘help’ developing.

    • I’m not disputing a need for regulation of monopoly services – such as power distribution and even some controls where there are only a few sizable sources of generation. We also need safety and environmental regulations.

      But why should we trust government to make decisions about what energy sources are to be used an in what proportion or number? Look what government did to ethanol and gasoline. What is to prevent our legislators from mandating X amount of wind or Y amount of solar when the market conditions might, over time, dictate just the opposite? Dominion’s monopoly power over distribution must be monitored along with its interactions with its generating operations, but with that in mind, why would anyone think that Ralph Northam or any other governor for that matter can be expected to make even a good decision about energy sources and the like?

      The big question is: Do we, including experts, believe that the march to renewable energy sources is simply unstoppable? Do we believe that there costs will simply undercut those of fossil fuel generation? If so, we should allow the market to work and regulate against bad conduct, etc.

      • TMT,

        As usual, you raise some important questions. First we need to clear up what we mean by government. The primary organization in our region that determines what new type of generation comes on line is PJM. This Independent System Operator (ISO) is a non-profit organization that has set up market-based auctions to establish wholesale prices for conventional and renewable generation, as well as a capacity auction to assure long-term reliability. A new unit cannot be attached to the grid without receiving PJM’s permission to attach to the transmission system.

        The SCC is also involved in that they approve the construction of a large new plant within the state, both for utilities and independent power producers, and deal with rate issues, etc.

        This market-based mechanism is being distorted by policies passed by both the national and state governments. For example, several state governments and the federal government are trying to subsidize uneconomic coal and nuclear plants (they do not receive enough from the market prices to be profitable). In Connecticut, Dominion is asking the state legislature to pay them a subsidy for their Millstone nuclear plant even though that plant is considered the most profitable nuclear plant in the U.S. These subsidies will allow more expensive units to displace lower cost facilities from the market place.

        In this way, governments will pick the winners and losers (just a handful of companies) rather than an objective market structure. PJM has added the capacity prices to value what dispatchable conventional units add to grid reliability. CO2 pricing is also under consideration to give recognition to the zero CO2 emissions from nuclear plants.

        Renewable portfolio standards also distorted the pure market mechanism, not by adding a subsidy, but by having a policy that required a certain amount of generation from renewables. Many would argue that this was a good policy because it established a new industry (more jobs) and resulted in cleaner, lower cost sources of generation, but it was a government created distortion of the market mechanism. Some states, such as North Carolina, added a state tax credit for renewables that helped those technologies be price competitive before they would have been without the subsidy.

        Our state government also directs the development of our energy system in less obvious ways. We pay our utilities more when they build more, which encourages them to build new power plants instead of finding ways to use less energy. Our governor has thrown his support behind and allowed the DEQ to take regulatory short-cuts in approving a pipeline that will add billions to our energy costs in Virginia. This won’t help the utility, just their parent company, but it will skew our energy use more towards natural gas because we will want to use something that we must pay for whether we use it or not.

        If the SCC determines that these costs should not be passed through to ratepayers, because they are far higher than market alternatives, it would be good for the ratepayers but bad for the pipeline developers. The GA could interfere with this decision by saying it is in the “public interest”, even though it is not because it will cost Virginia families and businesses perhaps $3 billion more (over 20 years) and is not necessary for us to have all of the gas we need.

        Natural gas-fired generation will be the primary source of electricity in Virginia for decades to come. But this does not mean we need to build more of it. Each time we build a new gas-fired plant our rates go up. Dominion projects that gas prices will increase 3-4 times over the next 10-15 years, also raising customers’ bills. Dominion’s plans for natural gas development will increase CO2 emissions within the state over the next 25 years.

        The primary source load growth in Virginia is from new data centers and they want only renewables. No case had been made for the need for new gas-fired generation. Dominion says they might need a new unit in 2025, but this is based on an overoptimistic load forecast. PJM projects that load growth will be essentially flat in Virginia for the next 15 years.

        Extending the licenses of our existing nuclear plants for another 20 years would cost at least $4 billion, according to Dominion. It would probably cost significantly more by the time it would occur 15-20 years from now. This is several times higher than the cost of other options that would last for twice as long. Even Dominion does not believe that building North Anna 3 is practical.

        Renewables are decreasing in price by 15-20% per year, as is the cost of storage, a trend that is expected to continue for some time. But their incorporation into the grid will be subject to the needs for reliability, which will not be an issue in our region for quite a while. Low-cost methods such as energy efficiency, demand side management, and other methods are helping to create a more resilient and responsive modern energy system.

        We will have an increasingly diverse energy system and we should let market forces and objective regulators sort this out. The SCC’s evidentiary process is a good way to evaluate alternatives. It reveals the truth far better than does the legislative process, which is less transparent and more influenced by special interests.

        The legislature should consider the best way to adapt the energy regulatory system to meet the needs of the future. We should examine the best options to realign the interests of utility shareholders with the interests of the customers. Virginia would be far better served by win-win alternatives, rather than our current win-lose approach.

        • Tom – I’m not troubled by PJM per se. It looks like a response to changes in markets and technology. However, I do worry about the antitrust implications of power producers and distributors working through PJM. Price fixing and a refusal to deal sure look easy to implement.

        • Tom, I think you may have inadvertently overstated PJM’s influence on generation. While it is true that a new generator cannot interconnect to the regional grid without PJM’s assent, PJM neither sites plants, nor makes resource choices (gas, wind, solar coal, etc.) All it does when a generator wants to interconnect is establish conditions, if necessary, to ensure that generator does not adversely impact grid reliability and that the generator pays for any grid-related upgrades needed to ensure such continued reliability. I believe DVP had to pay for some upgrades up in New Jersey a few years ago when it added one of its big gas plants down in Southside, for instance.

          PJM’s power market mechanisms are designed to incentivize generation construction where additional capacity is needed, but PJM doesn’t award contracts to build. States do that.

  14. one way of thinking about renewables – and I’m sure there might be critics..but here goes.

    no matter how many renewables you have – you will never be able to use any more than the power needs that are above the baseload.

    In other words – baseload provides the minimum basic demand…. like what you’d see at night.

    Since those units coal-nukes cannot ramp up and down quickly they are occupying the baseload niche and renewables will never provide that power because coal/nukes cannot respond dynamically to the varying nature of renewables.

    So that leaves renewables to serve the demand that is above the base.

    And renewables will compete against – and complement gas because gas CAN ramp up and down quickly in response to the dynamic nature of renewables.

    That really takes baseload – nukes/coal out of any discussion about renewables since one is inflexible and cannot vary – and the other – renewables – it’s signature characteristic is that it DOES vary … so renewables ONLY work with other fuels that can also vary and that basically means only gas – a minor amount of hydro – that will never be much more than minor and perhaps some day -batteries.

    but for right now – it’s simply not a contest between renewables and baseload/coal/nukes.. they are basically incompatible with each other.

    okay.. .. so folks tell me where I’m wrong on this…

    • Google “duck curve,” Larry. Sometimes in some areas, notably California and in Texas, renewable and intermittent power drives baseload off the dispatch curve.

      I don’t think we’ll see that in Virginia in the foreseeable future, we just don’t have the Texas or California wind or solar capacity.

  15. Incombatabllity? …. looks like there are good reasons for that view.

    Looking through my online library the best and most thorough description of why ‘baseload’ is loosing its position in the generation market comes from Amory Lovins at RMI in his argument against the energy department’s assist for coal and nuclear…. “Do Coal and Nuclear Generation Deserve Above-Market Prices?”

    Overall, the report explains that the use of the term “baseload” generation is no longer helpful for purposes of planning and operating today’s electricity system. Indeed, inflexible baseload generators are becoming an impediment to further grid integration. The weight of expert opinion clearly concurs. As Bloomberg New Energy Finance’s founder wrote, Super-low-cost renewable power—what we are now calling “base-cost renewables”—is going to force a revolution in the way power grids are designed, and the way they are regulated.

    “The old rules were all about locking in cheap base-load power, generally from coal or hydro plants, then supplementing it with more expensive capacity, generally gas, to meet the peaks. The new way of doing things will be about locking in as much locally-available base-cost renewable power as possible, and then supplementing it with more expensive flexible capacity from demand response, storage and gas, and then importing the remaining needs from neighboring grids.” There’s your incombatability.

    The other thing that the paper discusses is the fact that in addition to loosing their former advantages in operating costs, other necessary requirements of large, inflexible generation are not included in any cost comparisons. “integration of such large baseload plants into the electricity system typically required significant system upgrades, including investments in hydroelectric storage facilities, investments in large transmission infrastructure to spread generation over a larger region, and “contingency” management processes to avoid blackouts.”

    Facts coming to light … “Variable renewables may need less backup (or storage) than utilities have already bought to manage the intermittence of their big thermal plants. For example: utilities have found that high wind fractions can be firmed by fueled generators ≤5% of wind capacity—several fold below classical ~15–20% reserve margins for thermal dominated systems.”

    Finally, the grid structure must change as distributed generation becomes more ubiquitous with community solar, microgrids small and large, and the dropping costs of rooftop solar. Lovins looks to regional coordination and natural geographic resource diversity to help to address wind and solar variability, much like the Atlantic Wind group wants to do with our offshore farms.

    For this English major, giving up on ‘baseload’ means seeing a very different grid structure in addition to different generation.

    • LG, Don’t confuse baseload generation types with the “base load.” The “base load” — that load which is there 24/7, at least in some months of the year — can be served by whatever generation is available and, of that, PJM will dispatch the cheapest to run. What you CANNOT do is run baseload generation types (nuclear and coal, mainly) in excess of the base load. Their amount IS capped by the amount of 24/7 load because they can’t be cycled off line. But you can always have less baseload generation than base load. Moreover, some of the newer NGCC gas cycling units are so efficient they are competitive with older baseload generators, yet in a pinch they can be cycled off (with some temporary loss of efficiency). So as coal units and maybe some nukes get retired, and given the efficiency of solar and wind generation when powered, you can expect a lot of renewables will be built — but, as discussed above, when the grid operator has to deal with more than 20% or so of renewables, there is going to be a need to keep quick start cycling units ready to fill in for every cloud bank that blows over, let alone big storms covering the entire midwest and mid Atlantic. The energy market clearing price will rise until somebody starts building units that satisfy that need. These will be cycling units that won’t run as much as gas cycling today because solar will beat their price whenever the sun shines. But at some price, they will be built, and used, and the price will end up embedded in your retail bill. Maybe some of those baseload units that have to run 24/7 will survive too, if in fact they are more efficient. That’s how markets work.

  16. “Re …why is the government involved?”

    When I lived in NJ in the 1990’s, the legislature adopted official state policy that all future power plants would be coal-fired. The stated reason was to develop a balanced mix of power sources. The real reason was probably because industry was installing natural gas co-gen. That was taking business away from the utilities (who wanted to be in charge of generating the electrons). NJ was also viewing utilities as a economic-stimulation opportunity that the state could manage. The state tried to stop or downsize any non-utility power plants.

    I am curious to know if that NJ coal policy is still on the books. But the point is politics is huge in the utility structure we and NJ have. I thought it was worse in NJ, actually.

  17. TMT, I’m with you on leaving it up to the market what kind of generation to build. The only rationale for a mandate that makes any sense to me is the notion of helping a new technology gain a foothold — either to help achieve efficiencies of scale in manufacturing or to develop/ pay for some sort of needed support infrastructure (like a pipeline to deliver fuel or shore facilities and boats for offshore wind maintenance). Rather than a percentage mandate, which is a meat-axe approach to the problem and totally inflexible, tax incentives (such as those in NC for installing distributed, rooftop solar) can help induce the behavior you want for as long as you want without becoming impossible politically to repeal. Even these decisions may be better left to the market despite their political popularity.

    • I would oppose subsidies for business entry into the generation market. It quickly becomes crony capitalism. Installation of renewable generation capacity for residential customers might be appropriate for a tax credit to encourage use could be reasonable. But if the costs are dropping very fast and payback can be had within 5 years, for example, there may be no need for even tax credits. Once businesses are addicted to the credit as part of their financial operations we soon have crony capitalism.

  18. Tax credits and subsidies have both done their job .. subsidies being a bit ‘on again – off again’ so maybe not as effective as tax credits to help get new industry up and running ie .. able to compete …

    BUT … We did that for the oil industry 100 tears ago and now we loose $2Billion annually continuing to support fossils! Some of those tax breaks have actually been on the books for 100 years. Evidently it gets too hard to remove them, and after all they aren’t the same as ‘spent money’. Tax expenditures are just monies we don’t collect. (See the report from Oil Change International that details all these giveaways)

    I think another way is the ‘end run’ created by an expansion of the playing field that removes constricting regulations and assures that sources of investment monies can be found. PACE is soon to happen in Arlington and other jurisdictions can copy the work they did. CT’s commercial Green Bank is another good example. A small amount of seed capital was put together with funds from banks that do business in CT, and the success of the Green Bank has allowed it to securitize the loans and expand the program.

    Come on Virginia …I still don’t understand why you are willing to be a laggard!

    • Given the fact Connecticut is a fiscal basket case due in large part to the policies adopted by government officials, why would Virginia want to follow Connecticut energy policy? I get your arguments on the fossil fuel subsidies and crony capitalism, but like other states, including Illinois, Connecticut’s public policies have led to financial ruin. That gives me reason to look at other state policies with a jaundiced eye.

      It’s not much different than a job seeker with bad credit. Many businesses just won’t hire a person who doesn’t pay his/her bills. And probably few of the person’s friends would want to emulate her/his behavior.

      Let’s look at policies that come from states that are not in financial crisis. If a state can manage its finances without tax increase after tax increase and big cuts after big cuts, the other policies adopted by those states are deserving a look see.

      • I agree with your instinct for skepticism. This is precisely the time to slow down. I smell the usual rat. We are being manipulated. The Wind / Solar people, and their allies, are putting on a bum’s rush, trying to force out nukes and coal before the risks of reliability and stable costs are assured.

        This is not the time to over rely on experts projections as to future risks. This will be a test of character and principle, staying the prudent course instead of jumping too early on a train of ideology, short term gain, grabbing market share, crony capitalism, and false claims of low cost for profit.

  19. Here are the stats from PACENATION.org. Since 2009, PACE has provided $340 million in financing for energy upgrades to 1020 commercial buildings. Commercial PACE is in a period of growth: States continue to pass enabling legislation and launch new programs while PACE programs and lenders close ever-larger deals. Over the past year, Colorado, Rhode Island, New Hampshire, Ohio, Maryland, Florida, and Wisconsin launched new C-PACE programs. The market for C-PACE is expected to expand into new municipalities in California, Colorado, Florida, Michigan, Texas, Wisconsin, and other states throughout 2017.

    In September 2016, Renew Financial and CleanFund Commercial PACE Capital completed the largest-ever PACE project: a $10 million solar installation at Pacific Ethanol, a bio-refinery company in California.

    So take your pick of states … CA is the leader and their economy out shines just about everybody. The state was also the first, before the program was halted in a variety of places and ways. Conservative states like TX are getting on board with excellent programs.

    and since the graph fom the PACE market overview doesn’t print… the rest of the states with funded programs are: CA, CT, FL, OH, MN, CO, MO, MI, NY, WI, DC, TX

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