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Large-scale transmission expansion: what’s the prognosis? (Pt. 1)
In this post, let’s explore renewables and large-scale transmission expansion. In Australia, significant large-scale, inter-state transmission expansion is underway to support renewables. But the question remains: is it cost-effective? In this first of two posts, I will focus on Australia. The second post will focus on the US.
I invited Professor Bruce Mountain, PhD, Director of the Victoria Energy Policy Centre at Victoria University in Melbourne, Australia, to help answer the question. First, I will explain the background on transmission expansion to support renewables, then bring Dr. Mountain into the conversation, and finally discuss transmission buildouts to support large-scale decarbonization.
The Electric Reliability Council of Texas (ERCOT) was perhaps the first jurisdiction to augment its grid at large-scale to allow for increased integration of multiple large-scale renewable generators across renewable zones. This “Competitive Renewable Energy Zone” (CREZ) transmission expansion, largely completed in 2014, cost around US$6.9 billion and intended to allow for the integration of approximately 11 GW of additional wind generation from West Texas for delivery to the main Texas demand centers of Dallas, Fort Worth, Austin, San Antonio, and Houston, with a typical distance from CREZ wind farm locations to the demand centers of very roughly 500 km.
Much of the CREZ transmission was built on new corridors. The landowners in West Texas were relatively sanguine about transmission construction. There were likely several reasons for this, including the level of compensation for accepting transmission easements and the understanding by the landowners that remuneration from additional wind farm leases could only occur if there was transmission to move wind power from West Texas.
We can do a simple (and simplistic) calculation to evaluate the cost-per-unit of incremental transmission capacity. In particular, dividing the incremental capacity into the cost yields a capital cost of around US$600/kW for delivering power across roughly 500 km. This is not the same as the cost of individual lines, which would be lower on average, but is instead an effective cost of what was required to uprate the transfer capacity. However, it should also be acknowledged that various issues have limited the transfer capacity increase to below the intended 11 GW, so the actual capital cost per unit capacity is, practically speaking, somewhat higher than US$600/kW.
Although CREZ was a big investment, it is likely one of the lowest cost per unit capacity transmission expansions in modern times anywhere in the world. (Click here for a fuller discussion of these costs and various transmission cost components.) Subsequent to the CREZ expansion, inflation in materials costs and increases in land costs point toward increases in new transmission construction costs both in real and nominal cost terms. That is, we should view US$600/kW as being below current and future costs of transmission.
In contrast to transmission, the real and nominal cost of building both wind and solar has decreased in the last decade. The US Energy Information Administration (EIA) provides historical data on renewable construction costs. EIA data reports that construction costs for large-scale solar fell from more than US$3,500/kW in 2013 to US$1,800/kW in 2019. Large-scale wind fell from around US$2,000/kW in 2013 to around US$1,400/kW in 2019. Although the construction costs of large-scale renewables have apparently risen in nominal terms during and post-COVID, the implications are clear: over the last decade, transmission costs are assuming a much larger fraction of the cost of renewable integration as transmission costs have increased somewhat while renewables costs have decreased markedly.
Recently, and partly inspired by the ERCOT CREZ, Australia has been developing transmission expansion to support renewable energy zones. One element of this expansion has involved a planned strengthening of the interconnections between the states of Victoria and New South Wales. This “VNI-West” Project is a double-circuit line spanning about 800 km, roughly 300km longer than the distance spanned by the ERCOT CREZ. It is justified in part on the basis of the benefits of diversity of renewable supply (see page 46 in the Transgrid Transmission Annual Planning Report 2023), although there are other stated benefits.
Professor Mountain has co-authored a report, “No Longer Lost in Transmission,” which proposes an alternative “Plan B” to VNI-West. He concluded that VNI-West should not be built because it is not cost-effective. I do not intend to cover the whole of Professor Mountain’s report, nor the reports that originally proposed and recommend VNI-West, nor evaluate the other benefits of VNI-West.
Instead, I will focus on how the relative change in costs of transmission and renewables has affected the cost-effectiveness. To do so, we need to consider the value of diversity of renewable supply, renewable cost trajectories, and transmission cost trajectories. I will argue that these issues are generically changing the relative costs and benefits of building a line such as VNI-West that spans large distances. (In the next post, I will argue that the impact on cost-effectiveness is also relevant to the US.)
First, what is the value of renewable diversity? In the context of ERCOT, wind across the whole of the West Texas region is highly correlated. To have significant diversity among wind production requires spanning different wind regimes, such as inland (West Texas) and coastal (Texas gulf coast) wind. For solar, spanning East-West distances on the order of 1000 km or more is necessary to diversify the effect of sundown on production. That is, diversifying wind production or diversifying solar production may require even longer distances of transmission than the 500 km of CREZ. Of course, locating wind and solar together can result in diversification, as in Texas where inland wind production is typically highest at night while solar peaks around solar noon. Statistical analysis of wind production in Victoria and New South Wales by Professor Mountain also suggests that there is limited value in diversity among inland wind production in these states.
Second, how do renewable and transmission cost trajectories interact with the issue of diversity? Professor Mountain’s report concluded that the trends of reduced renewable costs and increased transmission costs would together reduce the value of diversity of production that is provided by connecting the states of Victoria and New South Wales as compared to historical projections of the value of diversity. That is, the value of having transmission available to bring power from NSW to Victoria when it is cloudy and not windy in Victoria has decreased, because the cost of building solar and wind generation is now lower, while the cost of building transmission is now higher. The same applies for when it is cloudy and not windy in New South Wales. This reduces the benefits of building transmission between regions. It makes more sense according to Professor Mountain to build transmission and more renewables within each region.
Professor Mountain suggests that it will be more economical to build more solar and wind in both Victoria and New South Wales as compared to trying to take advantage of the (relatively low) diversity between Victoria and NSW by building VNI-West and transferring power between the states. His “Plan B,” in contrast to VNI-West, is aimed at strengthening connections within Victoria from renewable energy zones to load centers, which, he argues, involves much less transmission cost and has a much easier regulatory/social acceptance path, in part because of the use of existing transmission corridors. VNI-West, in contrast, mostly involves new transmission corridors and spans a state boundary.
I was intrigued by Professor Mountain’s recommendations and wanted to learn more. He graciously agreed to an email interview.
Question: Does the argument about diversity also suggest that we should be building more solar on rooftops and over parking lots — sites that are inherently closer to demand? While this might include residential solar, Australia already has a large amount of residential rooftop solar. So I am specifically including rooftops on big box retail and on other commercial and civic structures that have large expanses of flat rooftop. This is perhaps an extreme version of trading off transmission costs against diversity and access to the best solar resources.
Mountain: In short, in the Australian context, I think the unequivocal answer is yes. In Australia, the levelized cost of production from rooftop solar, particularly large scale rooftop solar, is not terribly much higher than large scale grid-connected ground-mounted solar. This is because Australia has a competitive and innovative rooftop solar industry, and one that is quite effectively regulated in respect of product standards, installation, and the administration of subsidies. Rooftop solar does not attract many of the additional costs that purpose-built ground mounted solar attracts. And now, large scale remote solar farms in most parts of Australia are struggling with grid access. It should be understood that transmission development in Australia is very much more expensive than we see in the US. I attribute this mainly to regulatory arrangements in Australia that tolerate extraordinarily profitable transmission monopolies.
So, in many ways the debate in Australia has not got stuck on somewhat academic arguments about the average cost of rooftop versus ground-mounted solar, which we see in some parts of the U.S., particularly in California. Solar adds great value to Australian customers, noting that Australia’s grid-supplied electricity is very expensive for retail customers, and so they are attracted to their own cheaper supplies. That is where the buck stops (or should I say starts?)
There are often concerns that rooftop solar will impose costs on local grids, but these concerns do not seem to persist under closer scrutiny in Australia. In many cases network providers will specify zero export limits and in some cases this might stifle rooftop solar uptake. But customers are responding with the installation of batteries and many are proceeding anyway, even if zero export is allowed.
Professor Mountain’s observations suggest that the relative cost of transmission in Australia is even higher as a fraction of renewable cost than implied by the ERCOT CREZ costs. The high retail prices in Australia have already resulted in a very large take-up of residential rooftop renewables. As mentioned before, the CREZ was uniquely low in cost per unit capacity even in the US context. Although I do not have detailed information about the capacity provided by VNI-West, it would not be surprising if the 800 km long VNI-West is several times more expensive in $/kW terms than the CREZ capacity, making it comparable in cost to, or even more expensive than, the capital cost of renewables.
However, the capital cost of a transmission line is not necessarily the biggest cost to society. Apart from West Texas, there is typically considerable opposition to building transmission in regions that do not already have existing transmission corridors. This suggests that there is actually a large, hidden social cost in building overhead transmission. That is, the opposition to new transmission construction is a flag that neighbors of proposed transmission are anticipating significant reduction in amenity and property values due to the construction of lines. There are several reasons for this including the effect on viewsheds of the lines themselves and the effect of required easements and access roads on rural land. I have often observed that this means that the capital costs we usually consider for transmission—easement and corridor acquisition and construction costs—neglect other externality costs that may indeed exceed the land and construction costs.
Undergrounding transmission is sometimes proposed as an alternative to mitigate the externality costs. However, unless the cost of excavating for the underground line can be shared with other infrastructure, the cost of undergrounding is itself significantly more than overhead transmission. Furthermore, undergrounding long lengths of conventional AC transmission presents technical challenges related to reactive power. In short, undergrounding does not generally solve the problem of high costs because it only swaps the avoidance of externality costs with increased construction costs.
So I asked Professor Mountain about these overhead transmission externality costs.
Question: Should we be considering those externalities and compensate landowners more fully for them? In other words, is transmission actually far more expensive than just the direct land and construction costs? Would paying additional compensation to landowners help us to get needed transmission built by aligning their incentives with the social need for transmission (as might have occurred with West Texas farmers who wanted to lease to wind farms), or would it just shut down all new construction?
Mountain: I agree with you that the costs that electricity production and distribution imposes on others have been greatly under-estimated. This seems to now be well understood in respect of greenhouse gases, but local environmental impacts have been greatly under-estimated in Australia, particularly in electricity transmission. In Australia the great transmission expansions occurred in most states from the 1940s to the 1970s. It was a much poorer and less developed country then, and communities had a different understanding of their rights and less ability to exercise them. That has changed now, but it seems to me that many in Australia’s electricity industry have not appreciated this fully yet.
Would paying landholders improve the prospect of transmission development? Perhaps, certainly in wind development this has been important. For solar, there is limited ability to also use the land for agricultural purposes and so outright purchase is the dominant model there. Transmission seems to extract a particular anger from the community as it can have quite a severe effect on farming – on agricultural operations and also fire control. Huge towers are also unsightly and so they impact the community more generally, not just directly affected landholders.
In Australia, governments have announced higher compensation to landholders affected by transmission. It has got to the point where this cost is now meaningful as a proportion of projects’ total costs, but I doubt it will kill transmission projects from developers’ perspectives. As I said, Australia’s regulatory arrangements easily accommodate high costs. Will it nonetheless make projects acceptable to the affected communities? We will have to see. I am not convinced that in many cases it will make a great deal of difference.
Regarding transmission, if we do recognize the cost of externalities, then the transmission costs would be a greater proportion of the renewable integration pricetag. If that is so, the changes in relative costs of transmission and renewables will significantly affect the overall desirability of the VNI-West development. In Professor Mountain’s opinion, VNI-West is not warranted.
Next time: we will explore these ideas in the context of proposals for greatly increased transmission expansion in the US.
Posted in commentary, research
Tagged Australia, diversity, ercot, grid, renewables, texas, transmission
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Resource adequacy: how much is enough?
“Can resource adequacy be attained without defining what is ‘enough’?” This is the astute question posed by Beth Garza, formerly Independent Market Monitor for ERCOT and now senior fellow at the R Street Institute think tank. In this blog, I would like to engage with her question.
Customary short-hand descriptions of resource adequacy focus on installed reserve margin, which is the amount by which the total power generation capacity exceeds a forecast peak consumption. I will argue that, in a high renewable world, the focus on power capacity over a short time interval at the time of a forecast peak is not a suitable short-hand, because adequacy will become more dependent on the availability of energy over an extended time. The “what” in Beth Garza’s question will increasingly need to be thought of as energy capacity rather than power capacity, and we will need to define how much energy capacity is needed to satisfy our requirements for adequacy.
To understand this change in the needed short-hand for adequacy, let’s first think about assessing resource adequacy in systems with mostly thermal generation. Typically, load is at peak levels for just a few hours in summer or winter. In thermal-dominated systems, resource adequacy is roughly tantamount to having enough thermal generation capacity available with high enough probability to meet a particular future peak load condition. Outside of these peak load hours, there is generally sufficient capacity to meet load, even considering failures and the need for annual maintenance.
There are various considerations in an assessment of adequacy in a thermal-dominated system that hinge on uncertainties and probabilistic assessments. On the demand side, probabilistic assessments arise because we must forecast future peak load conditions, including the extremity of associated weather conditions that drive both winter and summer peaks. In other words, there is an uncertain future peak load, so the definition of resource adequacy must consider how extreme the peak.
To put it another way: in order to define whether resources are adequate, we must specify the forecast load that the resources are supplying. Implicitly, there is a non-zero probability that the actual realized peak load exceeds the forecast peak load. For example, peak loads in the February 2021 event in ERCOT exceeded the ERCOT assessment of forecast peak loads for winter 2020-2021, because the extreme weather that actually occurred in February 2021 was a once-a-decade phenomenon. The forecast peak considered only more typical winter peaks.
It is not just load that has randomness. Generators, too, have random failures. The assessment of resource adequacy must therefore also consider the probabilities of failure of thermal generation. Historical statistics are typically used to estimate generator failure rates.
Putting the demand and supply together, a specification of resource adequacy must define the minimum acceptable probability for being able to supply all load. This could equivalently be described as deciding how far out to consider on the “tail” of unlikely events of peak load variation and generator failures. Given the minimum acceptable probability of being able to supply all load all the time, we can assess whether or not the resources are adequate. A typical minimum acceptable probability of supplying all the load might be 99.97% over a year.
To summarize, the question about thermal resource adequacy typically comes down to a question about the likelihood of power production capacity being available to meet peak power consumption conditions. This assessment primarily depends on a particular, relatively small, length of time during load peaks and considers the probability distribution of power capacity in relation to the probability distribution of peak load. This is appropriate for a predominantly thermal system with “peaky” demand, where failures of thermal generation are uncorrelated from generator to generator, and where the critical demand periods are particular hours sporadically occurring over a summer or winter, with the occurrence of these peaks uncorrelated with generator outages.
So how can we evaluate whether there are enough thermal generation resources to satisfy our specification of adequacy? One approach is to define the concept of “effective load carrying capacity” (ELCC) of each generation resource. For thermal resources, if their failures are not correlated with demand conditions and the failures are uncorrelated across generators, then the ELCC can be roughly evaluated as the installed capacity of the generator derated (reduced) by its failure or forced outage rate. The derated capacity can be viewed as the “expected” availability in a probabilistic sense.
Adding up the capabilities of a large number of generators, and assuming that failures across generators are uncorrelated and that failure rates do not change over time, the law of large numbers tells us that the sum of the actual available capacities of all the generators will be roughly equal to the sum of these derated capacities. To put it another way, we can roughly think of the derated capacity as representing the capacity of an equivalent perfectly reliable generator that is always available. Adequacy is tantamount to having enough equivalent perfectly reliable generation capacity.
How can we interpret this in terms of installed reserve margin? Adding up the total installed capacity in a system with adequate generation, we will find that it exceeds the peak load forecast. That is, there is a reserve margin. Historically, an installed reserve margin of around 12 to 15% above the peak load forecast provided adequate capacity in a thermal-dominated system.
A more refined calculation considers the distribution of failures more carefully to evaluate the derated capacities. Stanford Professor Frank Wolak provides some examples in his paper “Long-Term Resource Adequacy in Wholesale Electricity Markets with Significant Intermittent Renewables.” If the sum of the derated capacities is sufficient, then the assessment is that supply would be able to meet load with a probability that is at least the minimum acceptable level. If not, then significant involuntary curtailment of load would be required or new generation should be built. In a resource adequacy context, the potential for significant curtailment would point to the need to build new generation before the season of these forecast load peaks with a view to increasing the reserve margin sufficiently.
A complication with this analysis relates to generator failure rates. In fact, “common mode events,” such as extreme cold or heat, can increase the failure rates of generators, as experienced in the ERCOT February 2021 event and therefore mean that there is some correlation of thermal generation failures with weather and load. This issue is discussed at length in an EPRI report and in my blogpost on the ERCOT event. In principle, this effect can be included or approximated in the analysis.
How do renewables change this situation? Unlike thermal generators, the availabilities of renewable resources are correlated from one resource to another and also highly correlated with weather conditions and load. When it is windy at one wind farm in west Texas, it is likely to be windy at most West Texas wind farms, and when it is not windy at one wind farm, it is likely to be not windy at most wind farms. This correlation means that the law of large numbers cannot be used in the same way as for thermal generation. It invalidates the idea of “adding together” derated capacities of individual wind farms since the availabilities are not independent across farms.
To consider these correlations, one approach is to consider the net load, the demand minus total renewable production. This necessitates forecasting simultaneous renewable production and demand, including the extremity of the weather conditions. Adequacy comes down to whether the thermal generation and storage can meet the forecast net load, bearing in mind that the time of the net load peak will differ from the time of the load peak.
Modern ELCC software can evaluate these situations. However, interpretation of the results for renewables is different to the notion of capacity derating for thermal generation. For a thermal generator, we expect that its ELCC will be roughly, although not completely, independent of what other resources are built or retired and roughly independent of how other resources are operated. This is consistent with the “rule of thumb” of a 12 to 15% installed reserve margin being adequate in a thermal system.
In contrast, the ELCC for a particular wind farm calculated for, say, the case of 30GW of installed wind capacity will be significantly lower than the ELCC calculated for the case of 20GW of installed wind capacity and the ELCC can depend significantly on the other available resources such as storage and how they are operated. As renewable penetration increases, the correlation of production across renewables implies that the ELCC per MW of installed capacity will decrease. For example, in a 2019 study by Energy and Environmental Economics (E3) of deep decarbonization for California, E3 expects ELCC for solar farms to fall from about 50% of farm capacity to around 1% of farm capacity as the penetration of solar increases significantly. This means that a particular level of installed reserve margin will no longer be a suitable short-hand for adequacy in a renewable-dominated system because the reserve margin necessary to achieve an acceptable level of adequacy will be highly dependent on the assets in the system.
System operators recognize this issue and can consider it in their calculations. Again, Professor Wolak provides a detailed explanation of the process. ELCC assessments of resource adequacy could then, in principle, use derated capacities of individual thermal resources together with a derated total renewable capacity to assess whether there will be enough available capacity at the time of a forecasted future peak net load. Professor Wolak details some of the serious technical difficulties in trying to apply ELCC in high renewable contexts.
Professor Wolak’s critique of ELCC applied to renewables and the discussion in various reports, including the E3 California report and work by the Energy Systems Integration Group, point to why adequacy cannot be captured in high renewable systems by power capacity concepts such as static levels of installed reserve margins. Installed reserve margins implicitly reference a peak load or peak net load condition; however, under high renewable penetration, adequacy is increasingly determined by supply-demand balance during the extended periods of low renewable production that the Germans call a dunkelflaute. While sophisticated simulations can reflect these sorts of energy constraints, translating them into capacity terms such as an ELCC or a required installed reserve margin then obscures the underlying energy issues.
Correlation of renewable production over multiple hours or days brings into question the whole power capacity focus of reserve margin assessment. It is not simply that there might be low renewable production during the particular hour or few hours of peak load or peak net load in a summer or winter and that we might or might not have enough available capacity for that hour or few hours. The issue is more serious: there might be low renewable production for many hours, or even days, resulting in a significant mismatch between the desired energy consumption and the available energy production.
This was illustrated by the February 2021 event in ERCOT, which incidentally also involved correlated outages of generation and natural gas supply due to cold weather. While winterization will reduce the coincidence of future outages of thermal generation and gas supply under cold conditions, and more generally reduce the prevalence of other issues that can be mitigated by winterization, it will not change the correlation between lowered renewable production and increased consumption, since these are due to the “common mode” event of the extreme weather event itself.
Consider a future repeat of a similar weather event to February 2021 in ERCOT. Let’s assume winterization of the thermal generation, gas supply, water supply, and other components has been accomplished. And, suppose similar weather conditions occur in a future ERCOT with much higher penetration of renewables.
ELCC assessment that included this particular weather event would reveal whether or not the other generation and storage in the system could meet demand or whether significant curtailment was necessary. Although repetition of something like the February 2021 weather might be a low probability event, its severity would lead to significant hardship. That is, the most pressing question for future adequacy will increasingly be whether there is enough energy over multiple hours to days to cover an event similar to the February 2021 ERCOT event without significant curtailment. This energy would come from a combination of renewable production, available fuel at thermal generators, and from other storage such as batteries. From this perspective, the recent discussions in ERCOT around new mechanisms for ensuring adequate generation capacity seem beside the point: these discussions all build on an anlysis that did not consider the 2021 weather conditions.
The ERCOT market has recently added a “Firm Fuel Supply Service.” Requirements for onsite fuel storage for thermal generators is a tacit recognition that power capability is insufficient to evaluate resource adequacy when stressed conditions may extend over multiple contiguous hours or days. The issue of supplying energy over multiple contiguous hours or days will become increasingly significant at higher levels of renewables.
So what should be used to assess resource adequacy moving forward in ERCOT? I believe that we will need to move toward the sort of evaluations that have been used in hydro dominated systems such as Brazil, Chile, New Zealand, and Tasmania in Australia. Such studies do not focus on a particular hour or a few hours. Rather, they consider the various scenarios of renewable availability and storage over extended times. That is, they consider the probability distribution of energy capacity in fuels and storage to assess whether or not the load energy can be met at the required minimum acceptable probability.
Seasonal water inflow and water storage in Brazil, Chile, New Zealand, and Tasmania dictate that the timescales for assessment in these countries are on the order of months to years. ERCOT has very little hydro and no pumped storage hydro. Therefore, the timescales relevant to ERCOT are shorter due to the need to compensate for daily or weekly renewable fluctuations instead of seasonal water inflow. Nevertheless, ERCOT will need to consider scenarios of load and of generation that unfold over many hours to days.
This type of analysis is familiar to operators of hydro-dominated systems but full assessment may require further evolution of assessment tools for ERCOT, or at the very least require consideration of extreme weather events within existing ELCC tools. We need to make these informed assessments before we have another curtailment event like February 2021. The reforms of the ERCOT market that are being discussed currently should be thoroughly analyzed to determine if they result in appropriate levels of resource adequacy considering the emerging energy dimension of resource adequacy.
Large-scale transmission expansion: what’s the prognosis? (Pt. 2)
In the last post I discussed the cost-effectiveness of the VNI-West transmission project in Australia that is designed to facilitate renewable integration. Various transmission projects have also been proposed in the US to transport large amounts of renewable energy from renewable rich regions to demand centers, typically crossing several state boundaries. For example, the US National Renewable Energy Laboratory (NREL) discusses potentially nearly tripling the US transmission capacity to achieve full decarbonization. The Princeton Repeat Project finds that an expansion of around 40% is necessary to unlock the emissions potential of the US Inflation Reduction Act, while the benefits will be significantly lower if transmission expansion is constrained. A recent US Department of Energy report synthesizes these and other reports and concurs with the need for significant transmission buildout in the US.
In this post, I will consider the cost-effectiveness of large-scale inter-state transmission to support renewables in the US. Spoiler alert: I will argue that the greatly expanded large-scale interstate transmission being proposed is not cost-effective to support renewables in the US.
Similar to VNI-West in Australia that was discussed in my last post, much of the proposed transmission in the NREL, Princeton, and several other US studies would have to be on new corridors, or would involve large expansions of existing corridors and would cross state boundaries. In a weakly meshed system such as in Eastern Australia, there are potential system security benefits from more strongly connecting regions such as Victoria and New South Wales that might justify, for example, VNI-West even in the absence of compelling benefits regarding renewable access. In contrast, the proposed expansions in the US are to systems that are already highly meshed. That is, the proposed expansions in the US are presumably primarily providing benefits associated with transmitting renewable energy and not providing other system benefits. To an even greater degree than with VNI-West, the changes in relative costs of transmission and renewables will strongly affect the overall desirability of the US developments.
It is certainly true that both expanding existing transmission corridors and co-locating lines with existing highway and railway corridors can be more palatable to nearby communities and therefore lower cost than new greenfield corridor acquisition. Moreover, recent US DOE and FERC announcements suggest that US Federal permitting horizons may be shortened and the US DOE has just established a several billion dollar revolving fund to facilitate interstate projects.
However, the upper end of the scale of new transmission buildout proposed in the US by NREL is not credible to me, given the controversy and opposition that transmission proposals bring and the total investments in the hundreds of billions that all must be approved through various regulatory authorities. While the amount of buildout in the Princeton Repeat study is less than NREL proposes, it still involves a large amount of inter-regional transmission construction. This level of buildout of new transmission seems unlikely because its direct transmission construction costs will be such a large fraction of the renewable construction costs and because the true societal cost of the proposed transmission will be even larger.
Fortunately for decarbonization efforts, there are four other factors that mitigate the need to build so much new overhead transmission, both in the US and Australia.
First, the cost of renewables has decreased so significantly that there is now a much more feasible trade-off between renewable site quality and renewable overbuilding. Some recent US decarbonization proposals emphasize distributed as well as utility-scale renewables. Building some of the renewables closer to or within demand centers will reduce needed transmission buildout but result in less ability to utilize (possibly limited) diversity and will likely result in lower capacity factors.
Second, the electrical conductors in existing transmission lines can be replaced with higher capacity lines. This reconductoring results in an increase in capacity of existing lines that are thermally limited. This can allow more renewable generation to be built in regions of existing utility-scale renewables, albeit further reducing diversity of renewable production. A recent report suggests that this approach can be used to greatly enhance the existing transmission system and access renewables.
Both of these developments result in less renewable diversity than was presumably anticipated in the NREL and Princeton plans. However, a third development, the decreased costs of storage, will play a role in smoothing out local variations of renewable production and help to compensate for lower diversity in renewable production due to the reduced amount of transmission interconnection. For example, Green Mountain Power in Vermont is proposing to locate storage in all of its customer premises.
However, there are drawbacks. Greatly expanding the footprint of distributed renewables and storage will likely require at least some distribution system upgrades together with the telemetering and control infrastructure to provide visibility and control of these assets to system operators. Furthermore, challenges related to the interactions between the control of distributed resources will need to be addressed if such resources become the dominant generation sources in distribution systems.
Fourth, while undergrounding conventional AC transmission is typically impractical over long distances because of reactive power issues, technology for DC transmission is improving and is amenable to undergrounding even over long distances. While underground transmission is typically much more expensive than overhead, integrating with upgrades of civil infrastructure such as highway and railway corridors can potentially decrease the cost of excavation compared to dedicated excavation of a trench for buried transmission. Potentially, the cables could even be laid in concrete conduits at grade in highway and railway corridors without significant excavation. Judicious use of long distance DC transmission may provide for some new inter-regional capacity in cases where the renewable diversity benefits are high.
Certainly, existing transmission capacity and some upgrades, including reconductoring, and some new transmission capacity together with innovations such as dynamic line rating will enable increased transfers of renewable production between regions; however, I think it is time to stop pretending that huge amounts of new transmission buildout are viable in the coming one to two decades as part of decarbonization. Yes, there are cost-effective wind and solar resources such as West Texas, New Mexico, and elsewhere that will continue to be developed and connected to demand centers with long-distance transmission. But much of the new transmission buildout to support huge transfers over long distances will not be cost-effective. Instead, we need to expand utility-scale renewables within regions and also develop more resources closer to demand centers.