Dominion Doubles Down on Natural Gas

Questar pipeline operations

Questar pipeline operations

by James A. Bacon

With the acquisition of Questar Corporation, a Salt Lake City-based natural gas distribution and pipeline company, Dominion Resources is making a $4.4 billion bet that natural gas represents the energy future.

“Dominion expects the value of the Questar pipeline system to rise over time as Utah and other Western states seek to comply with the requirements of the U.S. Environmental Protection Agency’s Clean Power Plan and meet state-mandated renewable standards, with increasing reliance on low-carbon, gas-fired electric generation,” stated Dominion, parent company of Dominion Virginia Power (DVP), in a press release announcing the deal.

In the same statement, the company noted that it has committed $1 billion for three solar-generating facilities located in Beaver, Iron and Millard counties in Utah. “These solar facilities are backed by long-term power purchase agreements with local electric utilities,” the company said.

The announcements come at a time when the McAuliffe administration is wrestling with which strategy Virginia should pursue in meeting the requirements of the Clean Power Plan. The EPA gives states some flexibility in meeting its tough goals for reducing CO2 emissions from electric-generating plants. DVP has been leaning toward natural gas as the dominant fuel to replace coal, while keeping open the expensive nuclear option. The Sierra Club and other environmental groups are pushing for much more aggressive use of wind and solar, which emit zero CO2 but create grid-reliability issues when operated on a large scale.

Dominion and DVP contend that the giant Marcellus and Utica shale basins in West Virginia, Ohio and neighboring states will provide years, perhaps decades, of inexpensive natural gas. Although gas combustion does emit CO2, it creates far less than coal. The cost is lower than that of wind and solar, and the fuel source provides more flexibility. Critics counter that the price of gas is volatile and not necessarily the optimum long-term choice. Dominion prefers its DVP subsidiary to burn gas, however, in the expectation that DVP will purchase gas transported on the proposed Atlantic Coast Pipeline, of which Dominion is the managing partner, and utilize its gas storage assets in the Marcellus basin. Keeping the business all in the family, so to speak, will create more profit for the parent company.

The Questar acquisition suggests that Dominion’s top brass really does see natural gas as the energy future. Serving markets in Western states, Questar gains no benefit from its association with Dominion Virginia Power. Rather, as the company explained in its press release, “Questar would provide enhanced geographic diversity to Dominion’s natural gas operations. Dominion’s existing operations lie in the heart of the mid-Atlantic, whereas Questar’s system is the ‘hub of the Rockies’ and a principal source of gas supply to Western states.”

At the same time, Questar fits Dominion’s broad corporate strategy. “This addition is well-aligned with Dominion’s existing strategic focus on core regulated energy infrastructure operations,” said Thomas F. Farrell II. “Questar boasts best-in-sector customer growth in states with strong pro-business credentials and constructive regulatory environments. These high-performing regulated assets will improve Dominion’s balance between electric and gas operations.”

Market commentators had little light to shed upon the merger, noting mainly that stagnant demand for electric power due to energy efficiency has spurred a number of deals between utilities and natural gas distributors, which enjoy stable prices thanks to the supply glut from shale fields.

“Top-line growth in electricity is basically nil,” Kit Konolige, an analyst for Bloomberg Intelligence, said Monday. “They’re looking for a business on the gas side that’s similar to what they’re doing but, as they see it, would have better growth prospects.”

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23 responses to “Dominion Doubles Down on Natural Gas

  1. “Dominion and DVP contend that the giant Marcellus and Utica shale basins in West Virginia, Ohio and neighboring states will provide years, perhaps decades, of inexpensive natural gas.”

    Yes, this has certainly been the idea that has been aggressively promoted by the by the energy companies and the politicians. However, the U.S. Energy Information Administration (EIA) has reported this month that Marcellus production has peaked and begun to decline by 225 million cubic feet per day. Higher gas prices might reverse this trend as numerous gas producers have recently gone bankrupt.

    “Although gas combustion does emit CO2, it creates far less than coal.”

    Based on the amount of CO2 released per million Btu’s of fuel burned, natural gas fired units produce 43% less CO2 than bituminous coal according to the EIA, about 42% less on a tons per MWh basis.

    “The cost is lower than that of wind and solar, and the fuel source provides more flexibility.”

    In November 2015, Lazard, an investment analysis firm, produced a report comparing the current cost of various generating methods. They used the Levelized Cost of Energy comparison which includes the cost of construction, operations, maintenance and the cost of fuel among other factors. This is the best type of apples to apples comparison we have except that it uses only current fuel costs. This report shows that energy efficiency is $0 – $50 /MWh; solar is currently $50-$60 /MWh; Natural Gas Combined Cycle is $52-$78 /MWh; combustion turbines (peakers) are in excess of $140 /MWh. By 2022 when the next gas plant is proposed (other than the Brunswick and Greensville plants) solar is expected to be at least 50% cheaper. By 2022 natural gas will be at least $4 mcf, which twice its current price of about $2 mcf. The LCOE of an NGCC is about 50% fuel costs. If fuel doubles in price by 2022 the LCOE goes up by 25% which would yield $65-$98 /MWh for gas plants compared to $25-$30 /MWh for solar. Within 10 years if we export appreciable amounts of LNG, many expect the U.S. gas price will begin to approach the world price, so we could easily see U.S. natural gas prices of $8-$12 mcf after 2025. This would make the gas plants even more expensive than solar.

    What is missing from this comparison is that solar does not fill the same role as do the combined cycle units. NGCC’s are dispatchable for baseload and intermediate (cycling) duty. However, with the cost differential increasingly favoring solar as time goes on and the cost of storage coming down, some of the dispatchable load could be provided by a solar/storage combination. The remainder of the baseload component would be replaced most cheaply by energy efficiency which performs 24/7/365 – far better than any power plant.

    New York State has set a goal of having 50% of their electricity provided by renewables (not including nuclear) by 2030. Much analysis has been done on the economics and the capability of the grid before making this commitment. So this is not a pie in the sky option, it should be carefully evaluated in Virginia.

    “Critics counter that the price of gas is volatile and not necessarily the optimum long-term choice. ”

    We have shown the effect of price volatility above. But other factors might also affect this choice. With the Paris Protocols and the CPP – greenhouse gases are getting more attention. As the Sierra Club study (and others) show, the supply chain to gas-fired power plants contributes greatly to GHG’s. Methane is slowly broken down to CO2 over time, but initially it is an about 100 times more potent greenhouse gas than CO2, declining to about 84 times more potent after 20 years and is about 25-28 times more potent after 100 years. We have fairly good techniques now to measure the leaks from drilling, transmission and distribution of natural gas and this issue will gain increasing attention.

    New Natural Gas Combined Cycle units release about 1,000 – 1,200 tons of CO2 per MWh (1000 tons is the CPP limit for new gas plants). Although less than equivalent coal plants, this is still higher than the statewide mass or emission rate CO2 standards in the 800+ tons/MWh range in the CPP. It is misleading to portray natural gas as the solution to the CPP or greenhouse gas issues. They could be a near term part of the solution but other components are necessary too. Although the existing nuclear plants contribute to lowering the CO2 contribution from the state, they can only be counted on for another 18-20 years. There is no assurance that their license can be renewed for a second 20 years and we cannot yet know what investment would be required to do so. The proposal for North Anna 3 is so far out of the realm of a reasonable cost, that we should stop even discussing it the IRP’s and search for better options.

    Natural gas-fired power generation only slows down the increase in GHG’s, some (as we have seen) might argue it doesn’t even do that. A longer term solution must use non-CO2 emitting and much cheaper options such as energy efficiency and renewables (with appropriate storage and demand shifting). We have the new Warrenton NGCC, and soon the new Brunswick NGCC and probably the Greensville NGCC. We must have a very serious discussion, perhaps as part of the CPP plan, about what comes next.

    “Dominion prefers its DVP subsidiary to burn gas, however, in the expectation that DVP will purchase gas transported on the proposed Atlantic Coast Pipeline, of which Dominion is the managing partner, and utilize its gas storage assets in the Marcellus basin.”

    I heard someone say recently that Dominion is a gas company that sells electricity. It feels that their desire to chase new revenues rather than reorienting their business model to prosper in a time of declining load growth is exposing the ratepayers and the state economy to perilous times.

    The Senior V.P. of Dominion Transmission gave a talk at the Marcellus-Utica Midstream (MUM) Conference last week. He said that between 2015 and 2018, 21 billion cubic feet per day of new takeaway capacity from the Marcellus was planned. Moody’s tallied this with existing pipelines and identified a total of 10 trillion cubic feet per year of takeaway pipelines to access the 122 trillion cubic feet of technologically extractable gas in the Marcellus. Developing all of these projects could create enough capacity to drain the Marcellus resource in less than 15 years. Each developer believes that their project makes sense, even if they all don’t in aggregate.

    Mark Eisenhower, V.P. of Strategic Planning for Aspire Energy said “What if the Marcellus/Utica region is overpiped?” He went on to say that the scaling back of production would reduce or eliminate the value of new pipeline projects.

    Elie G. Atme, V.P. of Range Resources said “We believe the Appalachian Basins’ takeaway capacity will be largely overbuilt by the 2016-2017 timeframe.”

    These comments are coming from people in the industry not from groups opposed to development. Dominion is making heavy bets on a short term situation lasting for decades and it could cost us all dearly. It was only seven or eight years ago when natural gas was $13.50 mcf. The era of cheap money in the early 2000’s severely distorted the market and caused this current glut of oil and gas resources. U.S. developers are so deeply in debt that they cannot afford to voluntarily cut back to bring supply into alignment with demand and stabilize the price. Much of the resource is being sold at bargain basement prices and when we really need it – it will no longer be cheap. Executives and policy makers who make choices based on wishful thinking will create the need for huge corrections at a later date.

    • Sorry, my brain went on vacation. If the fuel price for natural gas goes up by 100% and that is 50% of the LCOE for NGCC’s the LCOE will increase by 50% not 25%. So gas-fired plants are at an even greater price disadvantage to solar as fuel prices rise.

    • TomH – excellent post. You give us lots to think about and make a fair case about risk associated with natural gas used for generation of electricity. And there is no reason to give blind trust to DVP.

      At the same time, I don’t trust the “salesmen” for wind and solar. Just as DVP is seeking ratepayer money through the regulatory and legislative processes, so too are the wind and solar industries seeking both ratepayer and taxpayer money through the same processes. I recall the billions of dollars borrowed from the Chinese wasted on energy projects as part of the Obama administration’s Stimulus. And GOP office holders can be mined as well.

      Who is representing and advocating for the average Virginian?

      • TMT,

        The wasted money that you refer to had more to do with a bad vetting process that had more to do with politics than with solar. Solar hardware prices are now about the same throughout the world so that part is pretty well established. In Germany the soft costs of permitting, site approvals and installation are cheaper than in the U.S. so we still have more work to do here.

        Part of me wanted the the tax credits to expire so purer price signals could be used to make choices, but in reality they help close the gap a bit for the much larger subsidies that have long existed for fossil fuels and nuclear. I think the politicians (and probably the solar lobbyists) felt we couldn’t afford a big drop in solar installations in 2017 and still make headway on the CPP, because as I mentioned above, natural gas is still a large emitter of CO2 and more non-carbon sources of generation are needed to meet the EPA limits.

        I am not trying to “sell” solar – only to remove the barriers to its adoption where it makes sense. I don’t see anyone advocating for the Virginia ratepayer or citizen whose money and jobs are being risked by our present policies.

        • TomH – My starting premises are: 1) we need inexpensive and reliable sources of power, especially electricity; 2) there is a finite (albeit huge) store of fossil fuel – such that, long-term, a sensible, measured movement to renewable and non-fossil fuels is in the public interest; 3) anybody who is seeking access to public money, be it taxpayer or ratepayer contributed, must be vetted carefully; 4) there are ideologues on every issue, including energy; 5) the government makes crappy choices in picking economic winners and losers; 5) there is a role for the government to protect consumer interests and ensure laws and regulations are followed, including full and accurate disclosure; and 6) decisions made by the federal government are more than likely inefficient and ineffective.

          Having said this, I think an open and informed discussion of these issues by both interest groups and the public is important. But I worry who is representing the public.

    • Tell me more about New York 50% renewables. I suspect we may be talking about low cost imports of hydro power from Canada that allow that kind of statistic. I personally do not consider NY to be a model state, rather kind of an import/export state. Import power/export trash etc. I call it a NIMBY state but that could be unfair. Heck I was born in NY.

      • TBill,

        The New York policies are being driven by the Governor. In 2013, he appointed Audrey Zibelman, the former COO of PJM, to be the Chairman of the state Public Service Commission. A process called Renewing our Energy Vision (REV) was begun and is a very open discussion about how to create a 21st century energy economy in New York State. The process has been wide ranging and has sometimes moved in fits and starts, a few times hitting a dead end and then backtracking to a better solution. But it has been open to input from all over the world and is serving as a source of information for policymakers throughout the U.S.

        The Governor is concerned about climate change and has established a goal to phase out all coal plants in the state by this date as well. But he is Governor of an old rust-belt state that saw much of its industry leave for the the Southeast and Southwest in the 80’s and 90’s. The NY energy research agency is funding many different pilot projects, some done by utilities others by third-parties, to demonstrate the feasibility of many of the new technologies. They want to go beyond theory and get some practical experience with what works and what doesn’t. This has attracted many of the most innovative new businesses to the state and NY has the air of a “happening” place for new energy companies.

        The utilities are excited about it too. They were skeptical at first, but they were given a forum to express their concerns and as tentative policies were proposed the utilities have been active in shaping their own future. They recognize that the PSC is not trying to put them out of business, but rather give them a central role in it as Distribution System Platform providers (DSP’s). They will be the one’s to build the modern grid that makes all of the rest possible and will fairly paid to do it. Certain rates will go up but overall customer bills will likely go down. Third-parties will use the upgraded grid as an equal access platform to sell their products and services, as will the utilities.

        NY has its own ISO and the utility generation must compete separately from the “wires” side of the company. The hydro imports from Canada mostly were developed decades ago and NY is intending to be mostly self-sufficient in new energy development, which includes their own considerable hydro resources from Niagara Falls and a big pumped storage plant.

        ConEd in NYC was faced wit the prospect of having to build a new substation for $1 billion. Instead, with the help of the PSC they are finding a way to add solar and energy efficiency to provide a higher level of service and reliability without the need for a new substation. Everybody wins.

        Virginia has a different history and disposition than NY, but a similar process appropriate to our situation could attract many new businesses, jobs and lower our utility bills. Somehow Dominion must be guided to see that this is in their interest too. Investors are becoming more wary about utilities that are dragging their feet on moving into the modern age. All of Dominion’s recent moves are right out of the 20th century playbook.

  2. let me ask – does wind and solar “work” without natural gas peaker plants??

    • Gas-fired peakers are necessary to complement solar, especially in the early days. Fortunately, there is a good deal of peaking capacity currently in the PJM system. You can see how expensive it is. As batteries and affordable demand reduction (or displacement) strategies develop they will probably assume some of the “peaking” role, as they will be cheaper than combustion turbines.

  3. For many years I have advocated for natural gas vs. coal. Part of my ethic derives from a canoe trip to the Adirondacks as a young adult, seeing the effects of acid rain on that vulnerable eco-system. For almost 30 years natural gas has been cheaper or competitive with coal, but yet state after state has preferred to stick with coal.

    I also welcome wind and solar because I don’t prefer coal and nukes at this juncture.

    I do feel the highest standards of safety, efficiency, and environmental stewardship are warranted in all cases. Of course management rarely wants to give us those things. I hope they get the message.

    As far as wind/solar in Virginia, keep in mind we apparently and sadly do not have much wind on-shore. Lucky in a way, it might be an economic hardship to harvest wind for Virginia, because we also already have a large amount of carbon-free nuclear energy. Bottom line if we are to increase renewables substantially over 15%, we will probably do it “on paper” means paying cap-and-trade credits to other states.

  4. so – for right now – wind/solar by itself without gas plants is what?

    is it viable?

    I AGREE about the acid rain – but I think that is a pre-existing issue that has no import in the current CPP wrestling match.. at least as far as I can see.

    • None of these generating sources (nuclear, coal, natgas) operate by themselves, including solar. When variations in load occur now, it is often the gas peakers which cover the variations because they can respond rapidly, but PJM has other tools in the shed to deal with this depending on the time of day, size of the variation, etc. Solar complicates this because the greater percentage of the load met by solar, the greater the potential variations. Rapid response (within minutes) gas combustion turbines do this well. Affordable batteries and demand response can do it even faster.

      You have to be more precise than just saying “gas plants” the new combined cycle plants are not designed to follow load variations rapidly in the same way that the less efficient combustion turbines do. The question in front of us is to develop the best mix of generation types (and energy efficiency) that yields the greatest reliability, the lowest environmental consequences at the least cost for ratepayers. Dominion has good people considering all of these issues and they are especially concerned about the reliability issue. They also seem to put more weight on shareholder returns than they do on ratepayer concerns, but their CEO gets rewarded for returns to shareholders not for lower customer bills. My position is to create solutions where both interests are properly served. Programs which set the interests of the shareholders against the ratepayers cannot be sustained in the long run.

      This takes a revision of the business model for utilities, and appropriate regulatory changes to keep utilities healthy in this new role. We have not yet embraced that task in Virginia. In the meantime, in order to protect their revenues Dominion has clamped a lid on third-party development in Virginia and progress in this area must wait for Dominion to initiate it.

  5. re: ” You have to be more precise than just saying “gas plants” the new combined cycle plants are not designed to follow load variations rapidly in the same way that the less efficient combustion turbines do.”

    so what is their role if not “peaker”?

  6. The “peaker” units are the combustion turbines. Basically they are jet engines which run on natural gas and turn a generator to produce electricity. They can be started and turned off within a few minutes so they are good match for rapid variations in load. Because they run only about 10% of the time, their capital cost must be repaid in those few hours that they run so they are expensive. They are also inefficient, turning only about 30% of the energy in the fuel into electricity. These are the units that are used to deal with the variations in solar power. Dominion plans to build 100 MW of new peaking units for every 300-400 MW of new solar capacity.

    The other type of gas plant is the combined cycle plant. They are called combined cycle because three combustion turbines are built in the same plant and energy from the heat of their exhaust is extracted to make steam which turns one additional steam turbine to produce electricity. By using two energy cycles to create electricity about 50% of the energy in the natural gas can be used to produce electricity. Because of the more complex operation, this type of gas plant takes much longer to ramp up to full power and is slower in reducing power compared to the single cycle combustion turbines (peakers). But they run for more hours and are more efficient so they produce electricity less expensively than do the combustion turbines. Dominion will use them as base load and intermediate load (cycling) units, which will run about 65-85% of the time. In the five year period 2014-2019 Dominion will bring into service three combined cycle plants totaling 4300 MW.

    Both types of gas units are important contributors to the Dominion and PJM systems. Think of the combined cycle units as providing 24 hour baseload generation and solar plus peakers as handling the intermediate and peak loads during the daytime.

    As solar plus storage becomes less expensive and increasing natural gas prices push combined cycle power higher, solar could displace some of the combined cycle units at certain times, causing them to run less often, resulting in a lower return on investment. If this happens, Dominion will still want to get paid for its investment in these plants (plus their profit) so our rates might have to go up if they build more of these plants than are truly needed over the next 40 years.

    This is why we need to deal with issues such as accurate load growth projections (not ones based on the past when conditions were different), and a true picture of how much energy efficiency and distributed solar could be economically built by third parties if they had the freedom to do so. Otherwise, we run the risk of having Dominion overbuild the number of combined cycle plants. We will then have to pay for investments which yield the ratepayers little value.

  7. very good explanation and much appreciated! thanks!

    if baseload runs constant on or off and peaks cycle rapidly

    what is the role of the combined cycle plants to “cycle”?

  8. Consider a warm Spring or Fall day. These are probably the lowest load conditions, little heat or A/C required. The night time loads might be such that only output from the old paid-for nukes would be required to meet the baseload requirements. Perhaps, there might still be surplus nuclear capacity and that would be sent to the pumped storage facility for later use during the peak. As the load begins to ramp up in the morning as people begin their day, the next cheapest sources of dispatchable generation would come online, these could include the combined cycle plants. In the old days we called these intermediate load plants, Acbar refers to them as cycling units. As soon as the sun is up enough to activate the solar units all of that capacity would flow into the grid (or be used in the buildings on which they are mounted) because solar or wind is always the cheapest marginal cost because there is no fuel cost. If enough solar input is available some intermediate load (cycling) units might be throttled back if the load is not great enough. Remember though that this is happening over the 13+ state region of PJM so the units already online probably don’t get turned back so much as it just slows down the need to bring on additional capacity.

    The wide geographic territory of PJM also dampens variations in solar output, but peakers could fill in gaps as necessary. In the late afternoon on warmer days or early evening on cooler days, the highest loads of the day usually occur, when the most heating or cooling is required. The next most economic sources of generation would be used, with peakers covering the rapid changes. As evening progresses and load declines, units would be taken offline in roughly the same order as they were brought on in the morning.

    In this scenario the combined cycle plants might be used just 50% of the day rather than in a 100% baseload capacity. This is a simplified explanation. I’m sure Acbar could provide a more accurate explanation.

  9. excellent explanation – I CLEARLY understood !!!!

    one more question.

    if we did not have gas – what fuel would be used to provide/serve/satisfy the intermediate loading?

  10. In the past several decades, this was the role filled by many of the coal plants. Back in the 1990’s and early 2000’s it was prohibited to build a new gas fired power plant because natural gas was in short supply and expensive. The price peaked around 2008 at $13.50, compared to $2+ today.

    The loads of cheap money that were dished out after the housing bubble burst and the high natural gas prices existing at the time prompted the development of the shale gas fields. Because all of the developers are deep in debt (an average of 83% of their revenues are used just to pay for debt service) they cannot afford to cut back production to bring supply back in line with demand. This has lead to a great surplus of supply in the U.S. and the natural gas prices have fallen by 50-70% in just the last few years years.

    This apparent surplus and low prices have caused another rush to build Liquefied Natural Gas export facilities to take advantage of the higher natural gas prices in Europe and Asia. We had this same rush to build LNG import facilities in the early 2000’s. FERC received 43 applications, and 11 import facilities were eventually built for a need that never materialized. Dominion’s Cove Point LNG plant is being converted to export LNG supplied from Marcellus gas.

    Oil and gas always seem to go through boom-bust cycles, but what is changing now is that we are building a huge number of natural gas-fired power plants nationwide which will last for 40-60 years. The U.S. Energy Information Administration has issued a report in early January 2016 that showed the production from the Marcellus (which is the nation’s largest shale gas field supplying about 20% of our gas) is beginning to decline. This is primarily due to lower drilling rig counts because some developers have gone bankrupt. As new takeaway pipelines come in to service in 2016 and 2017 more of the Marcellus production will have easy access to the gas transmission system and prices will increase and the output will pick back up. Experts who have studied the geology of the shale plays say that they are depleted much more rapidly than the conventional sources that we have used for the past 100 years.

    My concern is that as valuable as natural gas is for its flexibility (peakers) and its possible lower CO2 emissions (compared to coal), we could be overbuilding our capacity of pipelines and power plants beyond what can be economically sustained. In the next 5-10 years, solar will be a cheaper source of energy to fill in the intermediate and peak load needs. As affordable storage comes along solar will provide more of the peak load and perhaps more of the intermediate load requirements too. And energy efficiency will be cheaper than any of these alternatives.

    Once these gas-fired plants are built, Dominion will expect to be paid for them regardless of how much they are used. We should be very cautious about how quickly we rush to build all of this infrastructure before we have a clearer picture of the long-term situation. If we can’t see very far ahead, we should be selecting solutions that can be installed quickly in small increments instead of long-lead time units in big chunks of capacity.

  11. I never knew that coal could be used for intermediate cycling…

    so modern coal plants can ramp up and down more quickly than baseload coal plants?

    • The coal plants would not ramp up and down. They do that too slowly. In the scenario above, the coal plants would produce energy more expensively than the nuclear plants so they would not be used 24 hours per day (baseload). But before the new combined cycle plants became available they would be the ones that turned on in the morning and run continuously until late in the evening (intermediate load). In the summer and winter periods of higher demand the more efficient coal plants would have run 24 hours a day. Now that role is being assumed by the gas combined cycle plants and the coal plants will be retired or retrofitted to partially or completely burn natural gas.

      Because the gas-fired plants only help lower CO2 emissions but not to low enough levels, additional zero carbon sources of generation such as solar are still required to meet the CPP standards.

  12. okay. I had assumed that all coal plants were always baseload and no variant could ramp up or down quickly enough to be used to follow demand.

    My impression had been that the choice was either to run baseload but let the turbines idle – just burn the coal at minimum thresholds, but not drive turbines until the demand needed it then spin the turbines.

    pre-shale, gas was many times as expensive but it COULD ramp up and down quickly so the cost trade-offs were between the costs of idling the coal plant – i.e. burning coal but no power until needed OR burning gas but only when needed – the gas plant would be not operating at times of no demand.

    that’s where the idea of having a variable rate to charge higher rates when gas was being used. that concept is obsolete now for as long as gas is so cheap but that would change if gas gets scarce thus more expensive again in the future.

    NOW – gas is so cheap that they are building (I thought) essentially base-load gas plants and perhaps instead they are classed as intermediate – i.e. they burn for longer periods of time than gas “peaker” plants – perhaps all day long to supplement the coal/nuke base load but you’re telling me that peak plants are pretty wasteful compared to combined-cycle gas plants – that take longer to come online than peakers.

    the worry is that the gas is shale gas and as you have pointed out – has a finite supply that could be limited and run out quicker than projected.

    someone (investors and financiers) thinks there is enough gas to capitalize billion dollar gas plants through expected life though… and I assume the folks who finance those plants – do for the life of the loans or perhaps the duration of the financing is dependent on how long they think those plants can operate cost-effectively.

    if this is a reasonable perspective – then one would presume that if gas plants could complement wind/solar – that wind/solar would actually extend how long shale gas could be a cheaper fuel because every kwh of solar/wind used would go towards not burning gas.

  13. ” I had assumed that all coal plants were always baseload and no variant could ramp up or down quickly enough to be used to follow demand.”

    There is a difference between running 24 hours a day (baseload) and running continuously for a significant portion of the day (intermediate load).

    The other option, as you suggested, is to run the boilers but reduce the steam flow to the turbine which would reduce the amount of generation, but the generator would remain turning and synchronized to the grid. When more electricity is needed more steam would flow through the turbine to generate the requested amount of generation. Since the turbines are always spinning to generate some level of power, this is called spinning reserve, which can ramp up in about 10 minutes.

    Non-spinning reserve would include the gas combustion turbines which can be cold started quickly, coming up to full power in less than 10 minutes. Most of the energy cost from these plants are capital costs because they only run about 10% of the time. The baseload/intermediate load combined cycle plants will have an average annual capacity factor of 65-85%. About 50% of their cost is related to fuel, so their cost is more dependent on changes in the price of natural gas than are peakers.

    Investors are not looking at a particular type of power plant so much as the likely overall rate of return on their investment. Some will buy shares in the company while others will invest in bonds of various maturities. The financial life of a combined cycle plant is probably 30-36 years (I don’t know for certain the approved depreciation period), but the physical life is more in the range of 40-60 years. If the output cost of a unit becomes more expensive compared to other units it will be dispatched less often and will return less revenue. However, it also makes a difference whether the unit is run as a merchant generator or a rate base unit.

    As solar gets less expensive it could capture a larger share of the intermediate and peak load demands. Although, if affordable storage is not available more peakers might be needed to fill in variations in solar output.

  14. well… it’s always informative listening to you and I feel like I do understand more than before.

    thanks much!

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