GNE - Genesis Energy

[blackcap]

Intermittent wind and solar cannot stand on their own,” the brief concludes. “They must have some form of back-up power, from reliable coal, natural gas, nuclear units, storage capability from hydroelectric facilities, and/or batteries. Batteries of the size and scope needed for 100-percent renewables are unproven and not cost effective.

Researchers Say Renewable Energy Mandates Cause Large Electricity Price Increases
Anthony Watts / 1 hour ago May 2, 2019
By Tim Benson

A 1-4 Percent In Renewable Generation Raises Electricity Prices By 11-17 Percent

An April 2019 working paper from the Energy Policy Institute at the University of Chicago shows renewable energy mandates (REMs), also known as renewable portfolio standards, are dramatically increasing retail electricity prices and serve as a very expensive way to try to reduce carbon dioxide emissions.

The authors of Do Renewable Portfolio Standards Deliver? found that seven years after REMs are enacted, renewables’ share of electricity generation increases by only 1.8 percent. They also found REMs raise retail electricity prices by 11 percent. After 12 years and a 4.2 percent increase in renewables’ share of generation, these prices rise by 17 percent. Altogether, the total extra electricity costs of REMs to consumers in the states that have enacted an REM are $125.2 billion.

The study also reveals reducing carbon dioxide emissions through an REM costs between $130-$460 per ton of carbon dioxide abated. These increased costs are, at the low end, almost three times higher than the social cost of carbon estimated by the Interagency Working Group set up by the Obama administration, which is roughly $46 per ton for 2020. (It should be noted that whether there is a “social cost” to carbon dioxide emissions at all is debatable.)

Outside of these higher prices, REMs impose other costs. Since wind and solar are so intermittent (having respective capacity factors of just 34.6 and 25.7 percent) and must be backed up by conventional sources of electricity generation, most estimates “do not account for the additional costs necessary to supply electricity when they are not operating.”

The paper also notes “renewable power plants require ample physical space, are often geographically dispersed, and are frequently located away from population centers, all of which raises transmission costs above those of fossil fuel plants.” Further, “[REM-driven] increases in renewable energy penetration can also raise total energy system costs by prematurely displacing existing productive capacity, especially in a period of flat or declining electricity consumption. Adding new renewable installations, along with associated flexibly dispatchable capacity, to a mature grid infrastructure may create a glut of installed capacity that renders some existing baseload generation unnecessary. The costs of these ‘stranded assets’ do not disappear and are borne by some combination of distribution companies, generators, and ratepayers. Thus, the early retirement or decreased utilization of such plants can cause retail electricity rates to rise even while near zero marginal cost renewables are pushing down prices in the wholesale market.”

The findings of this study are not surprising and have been mirrored elsewhere. States with these mandates had electricity prices 26 percent higher than those without. The 29 states with renewable energy mandates (plus the District of Columbia) had average retail electricity prices of 11.93 cents per kilowatt hour (cents/kWh), according to the U.S. Energy Information Administration. On the other hand, the 21 states without renewable mandates had average retail electricity prices of only 9.38 cents/kWh.

In just 12 states, the total net cost of renewable mandates was $5.76 billion in 2016 and will rise to $8.8 billion in 2030, a 2016 study revealed. A 2014 study by the left-leaning Brookings Institution found replacing conventional power with wind power raises electricity prices 50 percent and replacing conventional power with solar power triples electricity costs. The American Action Forum estimates the costs of moving the entire country to 100 percent renewable sources would be around $5.7 trillion, and a 2019 brief from the Institute for Eenergy Research estimates that the idea of getting to 100 percent renewable generation is “nothing more than a myth,” and that attempting to do would be a “catastrophe” for our country.

“Intermittent wind and solar cannot stand on their own,” the brief concludes. “They must have some form of back-up power, from reliable coal, natural gas, nuclear units, storage capability from hydroelectric facilities, and/or batteries. Batteries of the size and scope needed for 100-percent renewables are unproven and not cost effective. Even if a 100 percent renewable future were feasible, the land requirements and costs of transitioning would be enormous and would require subsidies to ease the electricity price increases that would result.”

State legislators should not mandate the use of renewable sources in electricity generation. Such mandates raise energy costs and disproportionally harm low-income families. Instead of trying to increase renewable mandates, legislators should repeal them.

https://wattsupwiththat.com/2019/05/...ice-increases/

[bull....]

Intermittent wind and solar cannot stand on their own,” the brief concludes. “They must have some form of back-up power, from reliable coal, natural gas, nuclear units, storage capability from hydroelectric facilities, and/or batteries. Batteries of the size and scope needed for 100-percent renewables are unproven and not cost effective.

Researchers Say Renewable Energy Mandates Cause Large Electricity Price Increases
Anthony Watts / 1 hour ago May 2, 2019
By Tim Benson

A 1-4 Percent In Renewable Generation Raises Electricity Prices By 11-17 Percent

An April 2019 working paper from the Energy Policy Institute at the University of Chicago shows renewable energy mandates (REMs), also known as renewable portfolio standards, are dramatically increasing retail electricity prices and serve as a very expensive way to try to reduce carbon dioxide emissions.

The authors of Do Renewable Portfolio Standards Deliver? found that seven years after REMs are enacted, renewables’ share of electricity generation increases by only 1.8 percent. They also found REMs raise retail electricity prices by 11 percent. After 12 years and a 4.2 percent increase in renewables’ share of generation, these prices rise by 17 percent. Altogether, the total extra electricity costs of REMs to consumers in the states that have enacted an REM are $125.2 billion.

The study also reveals reducing carbon dioxide emissions through an REM costs between $130-$460 per ton of carbon dioxide abated. These increased costs are, at the low end, almost three times higher than the social cost of carbon estimated by the Interagency Working Group set up by the Obama administration, which is roughly $46 per ton for 2020. (It should be noted that whether there is a “social cost” to carbon dioxide emissions at all is debatable.)

Outside of these higher prices, REMs impose other costs. Since wind and solar are so intermittent (having respective capacity factors of just 34.6 and 25.7 percent) and must be backed up by conventional sources of electricity generation, most estimates “do not account for the additional costs necessary to supply electricity when they are not operating.”

The paper also notes “renewable power plants require ample physical space, are often geographically dispersed, and are frequently located away from population centers, all of which raises transmission costs above those of fossil fuel plants.” Further, “[REM-driven] increases in renewable energy penetration can also raise total energy system costs by prematurely displacing existing productive capacity, especially in a period of flat or declining electricity consumption. Adding new renewable installations, along with associated flexibly dispatchable capacity, to a mature grid infrastructure may create a glut of installed capacity that renders some existing baseload generation unnecessary. The costs of these ‘stranded assets’ do not disappear and are borne by some combination of distribution companies, generators, and ratepayers. Thus, the early retirement or decreased utilization of such plants can cause retail electricity rates to rise even while near zero marginal cost renewables are pushing down prices in the wholesale market.”

The findings of this study are not surprising and have been mirrored elsewhere. States with these mandates had electricity prices 26 percent higher than those without. The 29 states with renewable energy mandates (plus the District of Columbia) had average retail electricity prices of 11.93 cents per kilowatt hour (cents/kWh), according to the U.S. Energy Information Administration. On the other hand, the 21 states without renewable mandates had average retail electricity prices of only 9.38 cents/kWh.

In just 12 states, the total net cost of renewable mandates was $5.76 billion in 2016 and will rise to $8.8 billion in 2030, a 2016 study revealed. A 2014 study by the left-leaning Brookings Institution found replacing conventional power with wind power raises electricity prices 50 percent and replacing conventional power with solar power triples electricity costs. The American Action Forum estimates the costs of moving the entire country to 100 percent renewable sources would be around $5.7 trillion, and a 2019 brief from the Institute for Eenergy Research estimates that the idea of getting to 100 percent renewable generation is “nothing more than a myth,” and that attempting to do would be a “catastrophe” for our country.

“Intermittent wind and solar cannot stand on their own,” the brief concludes. “They must have some form of back-up power, from reliable coal, natural gas, nuclear units, storage capability from hydroelectric facilities, and/or batteries. Batteries of the size and scope needed for 100-percent renewables are unproven and not cost effective. Even if a 100 percent renewable future were feasible, the land requirements and costs of transitioning would be enormous and would require subsidies to ease the electricity price increases that would result.”

State legislators should not mandate the use of renewable sources in electricity generation. Such mandates raise energy costs and disproportionally harm low-income families. Instead of trying to increase renewable mandates, legislators should repeal them.

https://wattsupwiththat.com/2019/05/...ice-increases/

arh its a conspiracy then the labour govt renewable plan is nothing other than a plan for electricity companies to charge more so they can pay the govt bigger divs in the future

[Jantar]

Any thoughts on why the combined cycle gas powered stations lasted such short times in NZ? Sparky (15yr life) and Southdown (18yrs) are closed and Stratford (might get to 24yrs) and E3P (might get to 19yrs) are projected to close soon.....

There are two main reasons for the short life of CCGTs in NZ.

The first is simple: it is the shortage of confirmed gas. With the governments ban on further offshore exploration, the current gas reserves would not last very long if used for electricity generation. Already the cost of purchasing the gas that is available has skyrocketed making gas generation as expensive, and sometimes even more so than coal.

The second reason is a bit more complex, and is related to the way our electricity demand varies. CCGT plant are designed to run mainly as base load plant. While they can be ramped around a bit, they do not like it, and are most reliable when brought up to a steady load and left there. But here in NZ we are unable to share generation with other areas in different time zones. That means our daily demand is at a minimum at around 4:00 am, rises to a peak at 8:30 am drops off during the day to a trough at around 3:30 pm, rises again to a peak at 6:00 to 7:00 pm, then trails off till 4:00 the next morning. Both hydro and coal plant can follow this trend nicely. Geothermal just stays at full load right through, and CCGTs are forced to ramp through their operating range placing more stress on their blades and combustion chambers. If a CCGT is shutdown, it can take days to bring it back on line, and each start removes around 100 hours from its effective operating time to next overhaul. Running them in unstable modes also reduces the time left to next overhaul.

Intermittent generation like wind just exacerbates this situation. It is not uncommon to see wind generation very strong overnight when it is not needed, and non existent over the evening peaks. I have also seen swings in wind generation of 240 MW in a single hour. The way that our nodal pricing works means that when wind generation is higher than forecast the wholesale price drops to make CCGT operation completely uneconomical. Thus the uneconomic running happens at the very time that the low loads and ramping due to wind is increasing the maintenance costs.

[Jaa]

There are two main reasons for the short life of CCGTs in NZ.

The first is simple: it is the shortage of confirmed gas. With the governments ban on further offshore exploration, the current gas reserves would not last very long if used for electricity generation. Already the cost of purchasing the gas that is available has skyrocketed making gas generation as expensive, and sometimes even more so than coal.

The second reason is a bit more complex, and is related to the way our electricity demand varies. CCGT plant are designed to run mainly as base load plant. While they can be ramped around a bit, they do not like it, and are most reliable when brought up to a steady load and left there. But here in NZ we are unable to share generation with other areas in different time zones. That means our daily demand is at a minimum at around 4:00 am, rises to a peak at 8:30 am drops off during the day to a trough at around 3:30 pm, rises again to a peak at 6:00 to 7:00 pm, then trails off till 4:00 the next morning. Both hydro and coal plant can follow this trend nicely. Geothermal just stays at full load right through, and CCGTs are forced to ramp through their operating range placing more stress on their blades and combustion chambers. If a CCGT is shutdown, it can take days to bring it back on line, and each start removes around 100 hours from its effective operating time to next overhaul. Running them in unstable modes also reduces the time left to next overhaul.

Intermittent generation like wind just exacerbates this situation. It is not uncommon to see wind generation very strong overnight when it is not needed, and non existent over the evening peaks. I have also seen swings in wind generation of 240 MW in a single hour. The way that our nodal pricing works means that when wind generation is higher than forecast the wholesale price drops to make CCGT operation completely uneconomical. Thus the uneconomic running happens at the very time that the low loads and ramping due to wind is increasing the maintenance costs.

Thanks for the detailed reply.

The offshore gas exploration changes came after most of these decisions so don't think they can be blamed. It's more like, not much gas has been found in the last 10-15 years.

The preference for CCGT to be run as base load and subsequent maintenance costs when they are not, especially in the competitive NZ context seem more of an issue. That article I linked to stated new blades at Stratford cost $50m every 25,000 hours, which is less than 3yrs if run 24/7. Also explains the preference for fast starting peaker stations.

Every 25,000 hours you have to put new blades in the turbines," he said.

"It costs about $50 million to do that. Obviously before you do that you need to know that you will get value for that investment.

Hydro generally plays the fast start role in the NZ market and is well suited to it. CCGT plants should be able to run as baseload in winter and when other stations are unavailable. They also should be being dispatched in front of coal if the cost is the same due to the environmental benefits. Do the Rankine units not suffer the same fast start maintenance costs?

I remember Contact when it listed talking about how Sparky was the latest and greatest in the land (fuel efficient, modern tech, perfect location etc) and with an operating life of 20-25 years I think? Lasting only 15yr seems like a good illustration of the hidden risks Snoopy is talking about, Sparky must have cost Contact some serious money and be part of the reason the share price struggled until recently.

[Jantar]

Thanks for the detailed reply.

The offshore gas exploration changes came after most of these decisions so don't think they can be blamed. It's more like, not much gas has been found in the last 10-15 years.

The preference for CCGT to be run as base load and subsequent maintenance costs when they are not, especially in the competitive NZ context seem more of an issue. That article I linked to stated new blades at Stratford cost $50m every 25,000 hours, which is less than 3yrs if run 24/7. Also explains the preference for fast starting peaker stations.



Hydro generally plays the fast start role in the NZ market and is well suited to it. CCGT plants should be able to run as baseload in winter and when other stations are unavailable. They also should be being dispatched in front of coal if the cost is the same due to the environmental benefits. Do the Rankine units not suffer the same fast start maintenance costs?

I remember Contact when it listed talking about how Sparky was the latest and greatest in the land (fuel efficient, modern tech, perfect location etc) and with an operating life of 20-25 years I think? Lasting only 15yr seems like a good illustration of the hidden risks Snoopy is talking about, Sparky must have cost Contact some serious money and be part of the reason the share price struggled until recently.

The two Auckland stations that were shut down were partially due to gas transfer costs, and partially due to the way NZ's nodal pricing works. The idea of nodal pricing was to encourage power stations to build where the demand is and therefore not need any new power lines. Wholesale prices in the Auckland area were high and hence encouraged the construction of new stations. But once they were built and operating the wholesale price differential disappeared, and accompanied by expensive gas take or pay contracts they were never economical.

The Rankine units do not suffer quite the same start up maintenance costs and can be operated over a load range of 40 MW to 250 MW. In comparison EP3 has an operating range (not desirable) of around 180 to 380 MW. Percentage wise this is a much smaller range. With CCGT plant it is often the GT core that causes the most issues. Rankine units do not have this component.

The Rankine units are arguably the best non hydro plant that NZ has ever seen.

[Airw0lf]

Wholesale prices in the Auckland area were high and hence encouraged the construction of new stations. But once they were built and operating the wholesale price differential disappeared, and accompanied by expensive gas take or pay contracts they were never economical.

There's an additional factor at play too. Even with the operation of Otahuhu and Southdown in Auckland, there were times where relatively high pricing in Auckland occurred due to lack of transmission capacity between the Central NI and Auckland, and/or due to high losses in transmission between the CNI and Auckland. But once the North Island Grid Upgrade circuits were commissioned by Transpower in 2012, there was ample transmission capacity into Auckland (even under transmission outage situations) and the new circuits also significantly reduced transmission losses by several percentage points.

[Snoopy]

The two Auckland stations that were shut down were partially due to gas transfer costs, and partially due to the way NZ's nodal pricing works. The idea of nodal pricing was to encourage power stations to build where the demand is and therefore not need any new power lines. Wholesale prices in the Auckland area were high and hence encouraged the construction of new stations. But once they were built and operating the wholesale price differential disappeared,...

Is there a postscript to this story? By this, I mean when Southdown and Otahuhu gas fired station shut up shop, did the Auckland nodal power point price rise again?

... and accompanied by expensive gas take or pay contracts they were never economical.

Wasn't the purpose of the Ahuroa gas storage site to make the gas supply contract more 'take and pay' rather than 'pay and don't take'? IOW it was meant to drastically improve the 'take or pay' economics? Will Genesis take more advantage of this facility, now that it is independently owned?

SNOOPY

[Airw0lf]

Is there a postscript to this story? By this, I mean when Southdown and Otahuhu gas fired station shut up shop, did the Auckland nodal power point price rise again?SNOOPY

The power prices in Auckland didn't rise back up to anywhere near the pre-North Island Grid Upgrade prices or the pre-Southdown/Otahuhu prices. This is because the North Island Grid Upgrade circuits could transport loads of power from further south into Auckland. In other words, lots of cheap generation from say NI hydro, SI hydro, NI geothermal and so on could compete to meet demand in Auckland, and at relatively low transmission losses. Back in the heyday of Southdown and Otahuhu there was tighter transmission capacity into Auckland which supported their viability to a strong extent.

Wasn't the purpose of the Ahuroa gas storage site to make the gas supply contract more 'take and pay' rather than 'pay and don't take'? IOW it was meant to drastically improve the 'take or pay' economics? Will Genesis take more advantage of this facility, now that it is independently owned?SNOOPY

There is also a fairly liquid spot and futures gas market finally available in NZ (http://www.emstradepoint.co.nz/), taking the gas industry out of its dated model of bilateral gas contracts. This certainly should support flexibility for gas users, but probably more so as top-ups for big users rather than providing enough depth to heavily ride on spot...

[Snoopy]

The power prices in Auckland didn't rise back up to anywhere near the pre-North Island Grid Upgrade prices or the pre-Southdown/Otahuhu prices. This is because the North Island Grid Upgrade circuits could transport loads of power from further south into Auckland. In other words, lots of cheap generation from say NI hydro, SI hydro, NI geothermal and so on could compete to meet demand in Auckland, and at relatively low transmission losses. Back in the heyday of Southdown and Otahuhu there was tighter transmission capacity into Auckland which supported their viability to a strong extent. ..

So the government mandated Transpower grid upgrade was a key factor in the demise of Southdown and Otahuhu? The 'free market' in NZ for power received a political nudge to move power generation in a certain technological direction?

SNOOPY

[Airw0lf]

So the government mandated Transpower grid upgrade was a key factor in the demise of Southdown and Otahuhu? The 'free market' in NZ for power received a political nudge to move power generation in a certain technological direction?SNOOPY

No I definitely would not draw that conclusion. The way in which Transpower is regulated is actually pretty efficient. If Transpower wants to spend money (i.e., consumers' money) to make a major capital investment like the NIGU it must justify it as beneficial for NZ electricity consumers in one or both of two ways:

1. Show an economic cost benefit analysis that is positive for approval by the Commerce Commission. I.e., the benefits outweigh the capital and expected maintenance costs. This can happen if a transmission investment allows renewable generation such as hydro, wind or geothermal to flow more readily into other regions and displace more expensive sources such as gas or coal. A transmission investment also often reduces transmission losses and therefore saves consumers and NZ more money on top of this. An example of this sort of investment was the Wairakei-Whakamaru line built circa 2013 which enabled new geothermal generation from Mercury and Contact to get to market. Yes this would come as a disadvantage to more expensive generator competitors but there's no denying that if transmission allows cheaper generation options to be exploited in NZ then that is for the benefit of the consumer and NZ Inc. overall. This sort of logic is standard in just about every developed electricity market in the world, it's not about deliberately screwing with past investment decisions made by generators, it's about getting the most efficient electricity system in the long run for the country. All players in the generation game know this anyway whenever they are contemplating investment/divestment, it's just part of being an industry player.

2. Demonstrate that the transmission investment will be required to meet legally mandated grid reliability standards. Transpower must ensure a certain reliability standard in terms of transmission redundancy so that the lights stay on in NZ, so this is essentially about security of supply. Again, any such investment application is reviewed by the Commerce Commission to ensure that the investment is warranted.

In both cases the government isn't directing anyone to do anything, it's largely a Transpower-Commerce Commission process with various industry stakeholders such as generators, retailers, Electricity Authority watching closely and commenting.The North Island Grid Upgrade investment was largely justified on criterion #2 above.