The following content was distributed by Energy Resources, Energy Efficiency, GHG Emissions  –  January 13, 2025

Federal Highway Administration Provides $635M in EV Grants

The U.S. Department of Transportation’s Federal Highway Administration (FHWA) announced $635 million in grants to continue building out electric vehicle (EV) charging and alternative fueling infrastructure.

The grants fund 49 projects that will deploy over 11,500 EV charging ports and hydrogen and natural gas fueling infrastructure along corridors and in communities across 27 states, four Federally Recognized Tribes and the District of Columbia.

The grants are funded by the Bipartisan Infrastructure Law’s signature zero-emission refueling infrastructure programs. President Joe Biden set a goal of building out 500,000 publicly available EV chargers by 2030, and the program is on track to achieve that goal early.

….

• The Port Authority of Houston will receive nearly $24.8 million to construct and operate a hydrogen fueling station for heavy-duty trucks in Bayport, Texas.
• The Maryland Department of Transportation, in partnership with the Pennsylvania Department of Transportation, the New Jersey Department of Environmental Protection, and the West Virginia Department of Transportation, will receive $18.6 million to deploy alternative fueling infrastructure along the I-81 and I-78 corridors in Maryland, Pennsylvania, and New Jersey. The project includes installation of six fast charging stations in locations that will serve local fleet needs and build out connections to a regional network of freight truck charging infrastructure.

The Iberian green industrial opportunity: Electrification and renewables

July 31, 2024 | Article

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Cooperation from all stakeholders can drive Iberian decarbonization through electrification and renewables deployment. Here we discuss the ambition, challenges, and potential unlocks for Spain.

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The European Union (EU) has set ambitious decarbonization targets—at least a 55 percent reduction in EU greenhouse gas (GHG) emissions by 2030 compared to 1990 levels.¹ Achieving these targets can help to deliver greater energy sustainability, security, affordability, and competitiveness as the EU accelerates its energy transition.

About the authors

However, this transition is not as simple as deploying more renewable energy sources (RES). It involves shifting to a diverse, more sustainable power mix while managing intermittent supply, revamping infrastructure, aligning technology innovations and policies, and engaging consumers. All of this requires massive capital deployment and collaboration from all stakeholders—both public and private.

Scaling the energy transition will also bring challenges across the value chain, from sourcing raw materials to manufacturing, infrastructure, and capital availability. Despite these challenges, Spain is well positioned to decarbonize and embrace the new opportunities from this journey. The country has the potential to become a leader in the energy transition, harnessing electrification and renewables to decarbonize energy end-uses and power supply, respectively.

In this article—the second in our series looking at the Iberian decarbonization opportunity—we highlight that, although natural endowments are necessary for Spain’s decarbonization, they are not sufficient alone. We further highlight that electrification is already a cost-competitive solution to decarbonize multiple processes, but slow adoption could hinder the ability to deploy further RES. Also, Spain has sufficient renewables capacity in the pipeline overall, but faces execution challenges and favors solar over wind. Enabling the transition requires grid expansion and modernization, as well as implementing updated power market design constructs.

The Iberian Industry and Energy Transition Initiative

We discuss how Spain could capture the potential value from the energy transition while decarbonizing, drawing insights from our Energy Initiative research (see sidebar, “The Iberian Industry and Energy Transition Initiative”). Despite clear advantages, Spain may need to act fast to attract industries and capture the opportunities—and value—at stake.

Spain has endowments to leverage and headwinds to overcome

Spain’s natural and technical endowments could make it a leader in the decarbonization journey and create an unprecedented opportunity of growth for the region.

The country has around 300 sunny days per year, resulting in a levelized cost of energy (LCOE) for solar that is approximately 45 percent lower than the EU average.² Spain also has favorable conditions for 24/7 renewables production, including pumped-hydro storage capacity of around 3 gigawatts (GW), which represents 3 percent of the total installed power capacity—more than most European countries.³ There is a larger share of unused and abandoned land in Spain, too—25 percent compared to the European average of 15 percent.⁴

These natural endowments exist alongside well-established infrastructure, including a robust capillary mesh grid infrastructure that can serve as the backbone for future upgrades, and seven regasification plants (representing the largest capacity in the EU).⁵ Spain is located in an area that has one of the heaviest maritime traffic volumes in the world and it has one of the largest power purchase agreement (PPA) markets in Europe, representing 40 percent of the total European PPA market in 2022.⁶

However, the energy system in Spain bears several legacy headwinds that may hamper progress, including uncertain regulatory frameworks, additional taxes for companies in the energy sector (for example, in 2022, Spain introduced a 1.2 percent additional tax on revenues for some companies in the sector), and lengthy permitting processes.⁷

Where transport is concerned, Spain has seen a slower pace of mobility electrification than other countries in the EU. Grid access can be slow and grid constraints have hampered the deployment of electric vehicle (EV) charging points, with around 30,000 public points in 2023 versus the government target of 100,000.⁸ This is likely impacting EV uptake, as only 10 percent of all vehicle sales in 2022 were EVs in Spain compared to 21 percent in the rest of the EU.⁹

The hazy long-term view on electricity prices poses another challenge. Here, the lack of liquidity of Spain’s futures market limits visibility on future cash flows, disincentivizing the large investments required for electrification. For instance, in 2022, the percentage of power exchange forward in Spain represented only about 2 percent of the total energy traded, compared with a European average for major markets of approximately 22 percent.¹⁰

Spain’s electrification and renewables ambition

Leveraging its natural and technical endowments, and in line with its commitments, Spain has the potential to become a leader in the energy transition journey and to continue leading in RES deployment and usage. This will require both decarbonizing energy end-uses through competitive and affordable electrification, and decarbonizing power supply through renewables deployment.

Harnessing cost-competitive electrification

In the majority of energy end-use sectors, electrification is currently the most cost-competitive lever to decarbonize. However, to be able to electrify affordably, a renewables uptake will be necessary.

Spain could be a frontrunner in electrification, leading to a potential market increase in power demand of 30 to 45 percent (around 70 to 100 terawatt hours [TWh]) by 2030 (Exhibit 1). This transition would require a major shift across energy end-use sectors, including the realization of announced hydrogen projects, a major switch in industrial equipment toward electric solutions, a rapid acceleration in EV adoption, and for buildings to adopt electric technologies.

Exhibit 1

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The following section details industrial decarbonization, EV adoption, and building electrification.

1. Industrial decarbonization

Industry can decarbonize by electrifying and increasing green hydrogen and derivatives production.

Green industries

Today, electrification is regarded as the most cost-efficient option for decarbonizing multiple industrial processes, in particular, for low- and medium-temperature processes.¹¹ In fact, low- and medium-temperature processes (for example, in food or textile industries) could increase their share of electricity in the final energy consumption by more than ten percentage points by 2030.¹²

European regulation is pushing for decreased industrial emissions by expanding the Emissions Trading System (ETS) and reducing the emissions’ cap every year, making fossil fuels increasingly less competitive.¹³ Following through, most industrial sectors could transition toward electrifying their assets as this shift becomes cost-competitive for a larger set of industrial processes.

Spain could be well positioned to become a leader in industry decarbonization by electrifying its existing industries and attracting new energy-intensive ones (Exhibit 2). New industries could represent an additional electricity demand, for example, in 2030, data centers alone could consume more than double the electricity they consumed in 2022.¹⁴

Exhibit 2

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However, this important shift needs to be accelerated, as industrial electricity demand has not shown significant signs of growth in the past decade, or even in recent months.¹⁵

Green hydrogen and derivatives production

Green hydrogen production is projected to account for the bulk of Spain’s increased industrial energy consumption due to the power intensity of the production process. Given the region’s low LCOE, Spain could be a European leader in hydrogen production, where demand will be driven by the Carbon Border Adjustment Mechanism (CBAM) regulation, green steel targets and premiums, sustainable aviation fuels (SAF) regulation, and decarbonization goals (such as ReFuelEU, RFNBO targets, and RED III).¹⁶

However, project deployment has slowed because of increases in cost estimates due to inflation, high interest rates, and slower advancements in electrolyzer deployment at scale. The levelized cost of green hydrogen (LCOH) estimates for Spain now fall between 4.0 and 5.5 euros per kilogram (€/kg) by 2030—above the expected grey hydrogen cost estimates of 1.0 to 3.0 €/kg.¹⁷

Our analysis shows that currently, more than 95 percent of the total announced green hydrogen projects that are expected to be operational by 2030, are still in feasibility and preliminary front-end engineering design (pre-FEED) stages.¹⁸ To foster their deployment, over €3.1 billion of incentives have been announced to finance the hydrogen industry, with only approximately €500 million already allocated to specific projects.¹⁹

1. Electric vehicle adoption

An increase in EV penetration would gradually increase power demand from the road transportation sector as internal combustion engine (ICE) vehicles are phased out. Sales of new ICE vehicles are set to be prohibited after 2035 and the EU is aiming to have 30 million passenger EVs on the road by 2030.²⁰ In Spain, this could increase the share of EVs among passenger cars from slightly above 1 percent to more than 12 percent by 2030, potentially reaching a total of around 3 million EVs on the road (Exhibit 3).

Exhibit 3

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Some commercial and heavy-duty vehicles could also switch to an electric powertrain, with approximately 10 percent of trucks and 30 percent of light commercial vehicles expected to be electric in Spain by 2030.²¹ The ramp-up of EVs will have to be supported by a significant deployment of charging infrastructure—Spain is currently lagging behind the European average in the number of public EV chargers per square meter and per capita (with 70 percent and 60 percent fewer public chargers per square meter and per capita, respectively).²²

The Iberian Industry and Energy Initiative scenarios

To reach this potential, however, the EV transition needs to be accelerated. To align with the Iberian Industry and Energy Transition Initiative’s aspirational, upper-bound scenario, Spain would need to increase from EVs comprising only 10 percent of all passenger vehicle sales today to approximately 50 to 70 percent by 2030 (see sidebar, “The Iberian Industry and Energy Initiative scenarios”).

1. Building electrification

Currently, Spain surpasses Europe’s average electricity consumption in buildings—50 percent of the total consumed energy in buildings is electricity compared to the EU’s average of about 30 percent.²³

A new EU emissions trading system—ETS2—was created to address the CO₂ emissions from fuel combustion in buildings, road transport, and additional sectors.²⁴ The ETS2 cap aims to drop emissions by 42 percent by 2030 compared to 2005 levels. The resulting increased carbon prices will further incentivize the adoption of lower-carbon alternatives in buildings, enabling electrification solutions to become cost-competitive relative to alternatives.

Building electrification can be highly impacted by changing the heating and cooling equipment in both new and retrofitted buildings. For example, Spain could improve its electrification by using heat pump technology, which not only contributes significantly to decarbonization efforts but also aligns with the ambitious European target of doubling the heat pump deployment rate, resulting in 10 million units by 2027 (REPowerEU).²⁵ This could lead to an additional 60 million heat pump installations between 2023 and 2030, according to the European Heat Pump Association.²⁶

However, as of 2022, heat pump sales in Spain accounted for about 30 percent of total building heating equipment. In contrast, countries like Austria, Denmark, France, and Portugal have already surpassed the 40 percent mark, with some even exceeding 70 percent in certain cases.²⁷ In Spain, electric heat pumps could contribute to more than 40 percent of buildings’ heat demand by 2030 compared to only 11 percent today (Exhibit 4).

Exhibit 4

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Despite the electrification of buildings being key to the country’s decarbonization, the corresponding growth in electricity demand will likely not materialize. In fact, the increased electricity demand from building electrification is expected to be counterbalanced by gains in energy efficiency in, for instance, electrical appliances—which will further contribute to emissions reduction.

Decarbonizing power supply through renewables deployment

To meet the increase in power demand from electrification while aligning with the energy transition, Spain’s overall installed power capacity would need to increase while emissions intensity is reduced significantly (potentially by up to 80 percent).

This shift would entail a major increase in renewable energy capacity (solar and wind) that can ensure a future decarbonized power system capable of meeting expected demand growth. The Spanish power system could be expanded to increase installed renewable capacity by between 60 and 70 percent, meaning between 50 and 60 GW (Exhibit 5). As our upper-bound scenario is balanced, with the power system optimized for lower generation costs, while ensuring system stability and preserving a minimum viable profitability of renewables projects (also minimizing overbuild for peak demand), the capture prices of renewables could remain above their respective LCOEs.

Exhibit 5

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However, given the intrinsic intermittent nature of these energy sources, other technologies would also be required to ensure the balance of the system, such as existing gas-fired powerplants in the short term and additional storage capacity (for example, pumped hydro and batteries) in the longer term.

Investors have strong appetite to meet renewables capacity needs, depending on the technology. The current solar energy capacity in the Spanish pipeline for grid access is estimated to be 2.6 to 3.4 times higher than that required to achieve the aspirational, upper-bound scenario.²⁸ On the other hand, the current capacity in the pipeline for wind energy is only 1.2 to 1.6 times the required amount to achieve the same ambitious scenario.²⁹

Key challenges and unlocks for decarbonizing energy end-uses through cost-competitive electrification

Spain could become a leader in electrification but there are significant challenges that need to be overcome. In this section, we focus on the key points to address and potential unlocks for the electrification of industry, road transport, and buildings.

1. Decarbonizing industry

Achieving decarbonization targets in Spain will require significant electrification across sectors, driving up power demand. In our upper-bound Energy Initiative scenario, electrification is expected to drive an additional 70 to 100 TWh of annual electricity consumption in Spain.

However, Spain faces challenges that are preventing this electrification wave from materializing. Electricity demand in Spain hasn’t grown since 2021, which could be due to increased energy efficiencies in the market, decreases in industrial output, or a shift to decentralized solar generation.

Lack of industrial and technological competitiveness: The electrification of certain industrial processes is challenging because solutions lack the technological maturity to make them viable and competitive at scale. According to our analysis, this is especially true for high-temperature heating processes—for example, 75 percent of technologies for decarbonizing processes with temperatures higher than 1,000ºC are not yet considered mature. However, for some lower-temperature processes, electric technologies can already be cost-competitive.

Even when technologies are mature and competitive, there is often a lack of awareness of these new electrification solutions and their benefits—especially among smaller organizations. And many do not know about the expected future cost increase for fossil-based fuels due to carbon penalties.

The long lifetime of existing fuel-based equipment (for example, 15 years, on average, for a gas boiler) is another barrier that deters industrial players from proactively exploring lower-carbon solutions.³⁰

Difficulties in financing initial capital expenditure: There are high upfront costs for switching to electric equipment, even for those technologies with an already competitive total cost of ownership (TCO). For example, capital expenditure (capex) represents approximately 25 percent of a heat pump’s TCO, compared with 2 percent for a natural gas boiler.³¹ Additionally, obtaining green financing at a competitive cost of capital is made more difficult by the lack of long-term visibility on electricity prices and their stability.

Challenges in implementing electrification solutions: Obtaining grid access is currently a hurdle, due to the lack of available capacity and long wait times for connections to be approved, even when there is available capacity (for example, there are cases that took more than five years to secure grid access). While industrial players could consider deploying on-site generation or thermal storage to overcome this hurdle, the firmness requirements of industrial activities constrain the ability of players to rely solely on direct connection to distributed RES.³² And deploying new equipment often requires the interruption of industrial processes, which can be costly. The scarcity of talent to deploy complex equipment can delay installation and operations, too.

Potential unlocks

Despite all of these challenges to electrification, Spain could foster public and private collaboration, improve power price visibility, refine electricity price incentives, and increase electrification awareness in various ways.

Promote public and private-sector collaboration to alleviate financing challenges: Private-sector financing schemes, such as green bonds, could allow players to access financing capacities to overcome initial capex. For smaller players, securitization instruments could be explored to improve their access. Financing schemes could promote the use of the most competitive decarbonization solutions for each individual case, since different industrial processes may leverage different technologies (including thermal storage that can enable broader electrification use cases).

Foster power price visibility to improve the business case: Financing such projects could be made easier by fostering longer-term visibility on power prices, for instance through easier access to PPAs. For example, the FERGEI/CESCE fund in Spain provides guarantees for PPAs to large electro-intensive players.³³

Improve electricity price incentives: Some electricity price incentives already exist for electricity-intensive players. These incentives compensate consumers for the charges levied to finance renewables and high-efficiency cogeneration, as stipulated in Real Decreto 444/2023 (Royal Decree 444/2023).³⁴ Electricity price incentives could be further refined by including energy service providers when they supply electricity-generated heat for industrial facilities or by promoting the use of residual heat and heat networks.

Increase electrification awareness: Public and private stakeholders could collaborate to create more awareness of electrification solutions and their benefits, carry out R&D in the sector, and explore Spain’s industry-specific initiatives (such as financing schemes or partnerships for pilot projects) to foster awareness.

2. Boosting EV adoption

The main factors hindering EV adoption involve switching costs, customer behavior, and charging infrastructure.

An expensive switch from ICE to EV: Our analysis shows that battery electric vehicles (BEVs) are still 15 to 75 percent more expensive than comparable ICE vehicles, even when considering existing financial incentives for their purchase (usually granted after vehicle acquisition). EVs also tend to depreciate differently than ICEs, imposing different financing terms and rates. The reluctance to switch to EVs in Spain is also influenced by the long duration of vehicle ownership. Passenger cars are, on average, 12 years old in the European Union, compared to the 13.5-year average of Spanish cars.³⁵

Lack of public EV charging infrastructure: Deployment of public EV charging infrastructure has rolled out slowly in Spain. The cumbersome administrative process has led to a lack of charging availability at affordable prices and at comfortable distances, which can deter customers from switching to EVs. In fact, Spain has 0.5 public chargers per square kilometer, in contrast with Europe’s average of 1.95.³⁶ And, with up to 70 percent of cars in Spain kept outdoors, public charging infrastructure is even more critical.³⁷

Constraints in deploying private charging: Private charging infrastructure is challenged by constraints in building power availability and grid capacity. EV charging requires significantly more power capacity than conventional residential loads, needing 90 percent of the average power contracted in Spanish buildings (4 kilowatts).³⁸ Requests for increased power can also lead to grid capacity constraints with slow grid upgrades and permitting becoming bottlenecks to deploying charging infrastructure.

Potential unlocks

To overcome these challenges, Spain could boost the business case for EVs and charging infrastructure.

Enhance the business case for EVs: Barriers posed by the high upfront costs of EVs could be addressed through financing programs for EV adoption, encouraging individual customers to switch to EVs and companies to renew their fleets with EVs. The business case could also be improved by enabling response mechanisms to increased demand—for example, allowing for direct load throttling from the network operator, while still guaranteeing a minimum of available power. This could decrease the pressure on the grid and address generation and demand mismatches, while providing a source of revenue (or discounts in the electricity bill) for EV owners.

Accelerate investment in public and private charging infrastructure: An acceleration of investment in public charging infrastructure would be needed, while guaranteeing competitive charging prices—this could be done through permitting and streamlining administrative processes. Private charging infrastructure could be boosted through the development of modular low-cost solutions for multifamily private charging.

3. Electrifying buildings

To help achieve decarbonization goals, Spain could electrify new buildings or retrofit existing buildings. This, however, comes with its own set of challenges, including high capex and labor and stakeholder incentive constraints.

High capex associated with electrification: Given the historical slower pace of construction in Spain, most of the building electrification potential by 2030 would likely come from building retrofits.³⁹ However, this transition is challenged by high upfront costs and TCO of electrification solutions. The lower operational costs of electric solutions often do not compensate for the additional upfront investment required (for instance, heat pumps can present a TCO more than 50 percent higher than that of a gas boiler).

Labor and stakeholder incentive constraints can hinder electrification: In the medium term, we expect that the economic case for electric solutions is likely to improve, given the expected decrease in electricity costs, the introduction of carbon pricing for residential emissions (set to start in 2027, according to Fit for 55 stipulations), and R&D developments, leading to lower equipment and installation costs.⁴⁰ Even so, building electrification will face challenges such as constraints of skilled labor for installation, and misaligned incentives between tenants and owners (as the former would get most of the opex savings while the latter would have to cover the capex).

Potential unlocks

However, by boosting financing programs, improving the business case for electrification, and reducing labor scarcity, Spain could reach its building electrification targets.

Boost financing programs: To overcome the challenges arising from high upfront costs, buildings electrification could be boosted by financing programs tailored for electric equipment and building retrofitting. Similarly, energy efficiency funding programs (such as the Spanish National Energy Efficiency Fund [Fondo Nacional De Eficiencia Energética]) and energy performance contracts—which could be incentivized through standardization—could further promote electrification.⁴¹

Improve the electrification business case: To improve the economics of electrification and protect consumers from potential future price volatility and investment risk, distributed photovoltaic (PV) power generation could be more widely incentivized. The build-out of solar distributed generation (DG) could see a more streamlined permitting process, removing administrative barriers. Additionally, consumers could participate in demand-side flexibility mechanisms (such as selling their own produced energy to the grid), improving the business case for electric technologies by creating a revenue stream for consumers.

Reduce labor scarcity: The labor scarcity challenge could be addressed by simplifying certification processes and investing in reskilling programs for installation workers, for example, by promoting public-private cooperation in upskilling heating, ventilation, and air conditioning (HVAC) technicians and installers to work with heat pumps.

Key challenges and unlocks in deploying additional renewables capacity

In our upper-bound scenario, 80 percent of all installed power capacity would comprise renewables by 2030, with the majority being wind and solar (45 to 49 GW and 59 to 63 GW, respectively). Currently, Spain’s pipeline of wind and solar projects already represents 2.0 to 2.6 times this capacity, mainly driven by solar. However, the materialization of this pipeline and the deployment of additional renewables capacity faces many barriers across business cases, supply chain, and procedural requirements.

Compared to past commissioning trends, this would imply a reduction in annual solar deployment from 4.3 to 3.1 GW per year, but an increase in onshore wind deployment from 1.0 to 2.7 GW per year.⁴²

Here, we explore Spain’s challenges in improving RES deployment, as well as the potential unlocks to overcome these hurdles.

4. Ensuring the renewables business case

Uncertainties over the future business case for different renewables technologies threaten the materialization of projects in the pipeline. The increasing penetration of renewables is expected to lower prices in the market in the long term, potentially decreasing capture prices and revenues for renewables projects (Exhibit 6).

Exhibit 6

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Developers could lose revenue through noncompensated energy curtailments, due to a mismatch between supply and demand. To some extent, this is already being felt from the slower-than-expected uptake of electrification. In fact, looking into the future, the materialization of demand projects (in particular, green hydrogen) could play a critical role in enabling the business case for additional renewables capacity overall.

Uncertainty over future revenues: Spain’s futures market has limited liquidity.⁴³ While the PPA market in Spain has the largest contracted capacity in Europe, it also presents some challenges such as the contractually heavy nature of PPA contracts, which, coupled with guarantees’ requirements, pose significant barriers to smaller players signing attractive PPAs. This is particularly important in a scenario where increasing penetration of renewables is expected to lower prices in the market in the long term.

Uncertainty on technology costs: Business case uncertainty is also technology specific. For instance, the deployment of distributed solar is hindered by the high initial investment required and high interest rates. On the other hand, storage technologies such as battery energy storage systems (BESS) and pumped hydro face uncertainty on future revenues, particularly in future capacity markets. Additionally, BESS technology is not fully mature in terms of its technological readiness, especially on a large scale. Developments in this technology are expected to increase its lifetime, share of capacity use, and recycling, and to lower costs.

Potential unlocks

Spain could improve revenue predictability and the business case for different renewables technologies, including solar DG, to help materialize projects in the pipeline.

Boost revenue predictability through market initiatives: Revenue predictability and the business case for renewables could be strengthened through market initiatives to boost long-term instruments such as PPAs. Access to PPAs could be further democratized (for example, by promoting awareness of aggregator PPA platforms to broaden their use), thus serving smaller-sized customers with different profiles, energy demand needs, and risk appetites. Facilitating access to guarantees could also enable smaller developers to participate in PPA markets, for instance, through partnerships with public financial institutions with core capabilities to offtake credit risk. To further increase revenue predictability, contracts for differences could be implemented as a last resort, in line with the latest European market design proposal, while guaranteeing these do not affect PPA market liquidity.

Improve the business case for specific technologies: Storage solutions such as battery storage and pumped hydro, for example, could see their revenue predictability improved through clarity on future capacity remuneration mechanisms. Solar DG could be leveraged through financing schemes and increased transparency on customer benefits. As another example, utility companies could provide financing solutions or partner with banks to reduce initial investment needs for solar DG for commercial and industrial players similar initiatives have already been widely implemented for residential customers.

5. Reducing uncertainties affecting renewables build-out in the supply chain

The supply chain for renewables projects faces significant challenges—spanning raw materials as well as capacity constraints among OEMs, engineering, procurement, and construction (EPC) firms, and operation and maintenance (O&M) providers.

Price increases and availability of raw materials: RES equipment—such as wind turbines—require rare earth elements and nickel, which were approximately 150 percent more expensive in 2023 than they were in 2019.⁴⁴ Similarly, steel and copper prices have increased by around 30 and 50 percent, respectively, over the same period.⁴⁵ In addition, there is a risk of shortage, or lack of access for geopolitical reasons, to key materials for solar PV (including copper, tin, silicon, and gallium) and wind (such as rare earth elements like dysprosium and terbium).

Challenges affecting equipment manufacturing: OEMs face financial challenges and are impacted by geopolitical tension. The scale-up in wind-equipment manufacturing capacity is not in line with the required pace of RES deployment, as increased costs of production (also due to the rushed development and deployment of new technologies leading to additional incurred costs) have reduced OEM margins and forced the closure of several wind manufacturing plants in Europe. For solar, geopolitical tensions and the decrease in OEMs’ financial performances pose risks to the supply chain.

Limited specialized service provider capacity: Renewables deployment is further hindered by limited EPC and O&Ms’ capacity in terms of both equipment and labor.

Constraints in permitting, grid access, and costs for RES: The recommended time for permitting RES projects is approximately two years, but the observed permitting time usually ranges between two and six years.⁴⁶ The permitting process is complex, involving several steps and stakeholders. The environmental permitting stage is a key bottleneck, with approximately 10 percent of projects not getting a response for four years. In addition, a lack of transparency around auctioning grid capacity creates public uncertainty. Also worth mentioning, the renewables build-out could lead to increased grid costs, mainly related to bottleneck management.

Potential unlocks

To improve renewables build-out, Spain could investigate strategic procurement levers, attract local and international talent, and ease grid access and permitting.

Explore strategic procurement levers: To address some of their supply chain constraints, RES developers could engage in co-investment agreements, joint ventures, or upstream vertical integrations with suppliers, and negotiate with OEMs to obtain priority or exclusivity of supply. They could design multiyear framework agreements with suppliers to secure volumes upfront by enabling suppliers to book capacity ahead of time or diversify the number of suppliers of solar PVs and wind turbines.

Collaborate to attract local and international talent: Developers and OEMs could source more talent by offering partnerships or scholarships for reskilling, upskilling, and the guaranteed employment of technicians. Considering the RES growth ambition in the Iberian Peninsula, local manufacturers could increase their capacity, or international manufacturers and developers might seek to establish themselves in Spain.

Ease grid access and permitting processes: Increased transparency in permitting could be promoted by making information accessible on timelines and responsibilities for each stakeholder, establishing separate and simpler permitting processes for projects (including retrofitting ones), and implementing unified permitting procedures. Developers could use a “positive silence” policy in which the authorization is considered accepted (not including the environmental impact assessments [EIA] or final procedure decisions) if the relevant authority does not provide an answer within a predefined timeline.

Key challenges and unlocks in ensuring a reliable and optimized power system

Harnessing the RES and electrification opportunity could raise two major challenges for the grid—network inadequacy and network instability.

Network inadequacy refers to the fact that there is not enough physical grid capacity to accommodate expected future supply and demand connections. Operators will also contend with network instability as increased penetration of intermittent power sources cause a higher volatility of utility frequency and voltage (for example, balancing services costs per MWh in Spain had already increased by 45 percent from 2022 to 2023).⁴⁷

As renewables penetration increases and it becomes more complex to match the daily profiles of electricity generation and demand, the system will need more firm capacity that can ensure 24/7 adequate supply (and that can replace the existing firm capacity that may be decommissioned or become too expensive for future needs). This could be provided by dispatchable technologies and storage. In our upper-bound scenario, combined cycle gas turbine power plants (CCGTs), pumped hydro, and BESS could represent approximately 28 GW, 7 GW, and 6 to 8 GW of installed capacity by 2030, respectively.

6. Scaling grid infrastructure capacity to meet future system requirements

Grid infrastructure needs to be scaled to meet future grid demand. However, to achieve this, Spain needs to overcome several challenges including the cumbersome grid permitting and planning process, higher investment requirements, execution hurdles, misaligned supply and demand profiles, and limited stakeholder collaboration (that is, public-private-sector collaboration).

Cumbersome grid planning process: The stability of power grids could be at risk due to the integration of renewables in combination with increasing electricity demand. The initial hurdle that needs to be overcome to ensure grids are fit for purpose is a grid planning process that does not anticipate grid investment-specific needs. Currently, the grid planning process is still mostly performed on a need-to-have basis, in which investments are planned based on the most immediate connection needs, and these are fixed across lengthy six-year periods.⁴⁸ This process doesn’t capture the speed and agility of the changing energy sector environment in which electricity supply and demand growth is expected to be high, even if uncertain.

Higher investment requirements and execution hurdles: Even after investments are regularly planned and adapted to planned needs, the investment amounts would have to grow substantially compared to historical values. Under the new paradigm of the increased use of RES and growing grid investment, the execution of grid expansion projects will face significant challenges as supply chains and permitting funnels become increasingly stressed. According to our analysis, supply chain constraints could lead to equipment shortages, delayed deliveries, and price volatility (for example, transmission and distribution equipment costs have increased 0.6 to 1.3 times in Europe over the past two years). Project execution can be hindered by tight EPC capacity, as the labor needs for grid capacity could increase by 60 percent until 2030 in a context where grids would be competing for talent with other sectors. Execution could also be hampered by a cumbersome project development and permitting process, such as the four to ten years’ permitting time for grid expansion projects in Spain.⁴⁹

Misaligned supply and demand profiles: Managing the future grid will be increasingly complex as supply and demand profiles become more disconnected. Ensuring grid reliability while more renewables are added—together with arising bidirectional flows—will require additional equipment and power management capabilities.

Stakeholder collaboration misalignment: Perhaps most important, limited alignment and collaboration among stakeholders (such as regulators, developers, consumers, and other involved authorities) creates multiple obstacles to a better process across all grid expansion stages. There is a misalignment of existing regulatory frameworks with investment needs, which limits the expansion and modernization of the grid, as is visible in the existing limits for grid investments linked to GDP (0.13 percent and 0.065 percent of GDP for distribution and transmission investments, respectively).⁵⁰

The lack of clarity on the future regulatory landscape—for example, ex-post regulation changes to project remuneration, together with a complex investment compensation model (such as late compensation of investments, with no correction for inflation)—could hamper efforts for new investments.

The limited visibility on future grid upgrades and the timelines for when renewables projects can connect to the grid also hinder project development. Currently, consumers face a long and difficult process to access the grid, as there are more requests to connect to the grid than there are supplied access points. For example, in Madrid, the current pipeline for data centers to access the grid is already more than four times larger than the actual guaranteed capacity.⁵¹

Current collaboration frameworks do not adequately incentivize investments in the modernization and digitalization of the grid, beyond its expansion alone. This could be a critical point to unlock, as optimizing grid capacity by leveraging flexibility and demand response becomes increasingly important.

Potential unlocks

Changing the grid infrastructure paradigm to meet the future system requirements would require a joint effort across grid planning, deployment, and operation, and, most important, closer collaboration and better alignment between stakeholders.

Enhance flexibility of grid planning: Grid planning could be improved through a more proactive approach to identifying and prioritizing investment needs, and a more agile planning and implementation process (for example, performing yearly updates within the six-year regulatory period). The planning of distribution networks would also benefit from increased clarity over grid operators’ remuneration frameworks. Beyond grid expansion, investment plans could also consider grid modernization and digitalization, preparing for increased flexibility needs and demand response mechanisms.

Also, considering the EU’s REPowerEU objectives and grid action plan, a compelling case could exist for early grid investments, particularly when new generation and demand could be reliably anticipated. Such investments could prioritize strategic network projects and adhere to European Commission guidelines.

Streamline grid deployment: As grid planning becomes more agile, infrastructure deployment processes could be streamlined, too. Grid access for RES developers could be improved by offering technically standardized connection modules and easing connection requirements by allowing conditional connections with a pre-agreed curtailment level. Permitting for grid deployment itself could be accelerated through solutions that streamline permitting steps (for example, by implementing a one-stop shop for transmission and distribution expansion permitting or creating electric corridors where permitting is eased under certain conditions).

Increase resilience of grid operations: Supply chain constraints could be mitigated by standardizing equipment procured to reduce costs and lead times and by establishing long-term framework agreements with OEMs, providing visibility on future demand. Upskilling and reskilling initiatives, in partnership with EPCs, could incentivize employees to learn skills for high-demand occupations—thus helping to address talent shortages.

Improve collaboration: Improving collaboration and alignment across stakeholders could be a key enabler across grid planning, deployment, and operation. Promoting closer alignment between operators and regulators could help to improve investments, bring clarity and predictability to the remuneration framework for investments, and establish a remuneration update process that is adjusted to different economic contexts (for instance, considering higher inflation and interest rates).

Increase visibility between stakeholders: Collaboration could also be improved by increasing the visibility over investment incentives, including potential access to EU funds. Tightening collaboration among market stakeholders can increase RES developers’ visibility over grid constraints and demand projects (for example, by publishing current and future available capacity of substations). It can also further promote projects of common national interest that can streamline grid deployment together with RES and electrification projects. Promoting the technological transformation of grids to unlock efficiency gains without incurring elevated expansion investments could also be a key enabler.

7. Guaranteeing 24/7 firm capacity in the system

The current power market structure does not ensure the sustainability of existing assets that can provide firm capacity, nor the addition of novel types of assets and solutions to the system.

Unsustainability of firm capacity assets: Existing assets that can provide firm capacity (such as CCGTs) are facing major challenges to remain profitable as electricity spot prices decrease and the assets are used for fewer hours throughout the year as lower-marginal-cost renewables cover most of the daily electricity needs. This means use of CCGTs could drop as low as 700 hours, compared with current levels of 3,000 hours and above, driving up prices and increasing volatility. The lack of mechanisms to incentivize reconfiguration of these assets exacerbates this situation (for example, according to our analysis, covering CCGTs’ fixed costs to keep these assets working could require capacity payments of approximately €20,000 per MW). On the other hand, batteries are not yet fully profitable through existing revenue streams (for instance, maximum daily spot prices today are still approximately 42 percent below BESS levelized cost of storage).⁵²

Alternative firm capacity solutions are not being deployed: Alternative solutions, such as pumped hydro or installing BESS, are not being deployed as needed due to a lack of visibility over future revenue streams (for example, current compensation for these assets is still tied to significant market volatility through both arbitrage and ancillary services). Moreover, uncertainty over the learning curve of some of these technologies, namely BESS, poses additional challenges to projects’ bankability (for example, NREL’s forecasts for four-hour, utility-scale Li-Ion BESS capex in 2030 range between $144 and $300 per MWh in different scenarios).⁵³

Potential unlocks

Guaranteeing 24/7 firm capacity could be met in three ways: leveraging existing firm capacity assets (such as CCGTs and pumped hydro), adding new green assets (including battery storage and new or retrofitted pumped hydro), and activating flexibility levers (for example, demand response).

Leverage existing firm capacity assets: This would require a timely implementation of adequate capacity remuneration mechanisms in line with the European Commission’s proposed market design already being explored in Spain. In the short term, this could enable a viable business case for CCGTs and new pumped hydro. In the medium term, it could enable the gradual deployment of BESS while the technology matures and becomes cost competitive. Pumped hydro can be a solution for long-duration storage with competitive costs and, if deployed through retrofitting existing reservoirs, would avoid complex environmental permitting and public reluctance. Improving ancillary service markets toward additional needed services and longer-term markets could also provide additional mechanisms to improve the firm capacity business case.

Add new green assets: 24/7 granular PPAs could be used to further incentivize the deployment of new technologies, increasing market liquidity. These products could offer a stable price for both electricity producers and consumers. Providing 24/7 green capacity would require the use of a diverse set of solutions (for example, storage and demand response), thus supplying additional and stable revenues for these technologies.

Activate flexibility levers: Finally, to mitigate the challenge in matching daily supply and demand profiles, the power generation mix could be diversified by deploying new wind projects already in the pipeline and through repowering assets approaching their end of life. Additional wind capacity could improve the overall generation profile and, despite having a higher LCOE than solar, wind can be a competitive solution to ensure future system adequacy and stability. In parallel, and to avoid excessive infrastructure investments, the engagement of flexibility assets for system stability could be unlocked by increasing the participation of different resources (such as industrial consumers and renewables). This participation can come in different forms, such as flexibility tenders—for example, through local energy trading platforms where excess power from congested grid nodes can be sold to demand users or storage developers—or other demand side management mechanisms.

The opportunity for Spain is clear but, in the end, coordination between stakeholders is essential to enable these unlocks. Public entities, renewables developers, financial institutions, suppliers, and consumers would need to work together to create a supportive regulatory environment, share experiences and best practices, and foster a culture of collaboration. By doing so, these stakeholders could create a more sustainable, resilient, competitive, and affordable energy system that benefits everyone in Spain.

About the author(s)

André Anacleto is a partner in McKinsey’s Lisbon office, where Maria João Ribeirinho is a senior partner, Diogo Amorim Santiago is a consultant, and Patrícia Ovídio is an associate partner; David González is a senior partner in the Madrid office, where Ignacio Martínez Giménez is a consultant.

The authors wish to thank Álvaro Bau, Álvaro González, Denitsa Georgieva, Diogo Cary, Fábio Neves, José Diogo Peres, Jose Luis Gonzalez, José Pimenta da Gama, Joseba Eceiza, Juan Antonio Bahillo, Tamara Gruenewald, Tomás Calleja, and Xavier Riba for their contributions to this article.

——————————————————————————————————————–Texas electricity demand could nearly double in six years, grid operator predicts

The state’s power grid operator says power demand in Texas could nearly double by
2030. (Eddie Gaspar/The Texas Tribune, Eddie Gaspar/The Texas Tribune)
storm
The Texas Tribune – June 20, 2024 6AM
The state’s main electric grid operator has sharply increased its prediction for how much
power demand will increase in coming years. If it’s accurate, the state would need to be
able to provide nearly double the amount of power within six years.
Two factors led to the higher forecast: A new law allows officials to count companies’
requests for grid connections before they are finalized. And there has been a significant
rise in requests from large users such as data centers, hydrogen production
facilities and oil and gas companies that are electrifying their operations.
On top of that, the state’s population continues growing, Electric Reliability Council of
Texas President and Chief Executive Officer Pablo Vegas told state lawmakers in a
Senate Business and Commerce Committee hearing last week, repeating information
he shared with the ERCOT board in April.
“All of that is putting together a picture of a very significant, different demand growth that is forcing us to really re-think how we’re looking at planning to make sure we can meet those needs and continue to deliver on the expectations of all Texans,” Vegas told
lawmakers.
Demand on the power grid hit a record of 85 gigawatts last year, which was the hottest
ever recorded in the state. ERCOT experts now say demand could reach around 150
gigawatts by 2030.
More than a third of the forecast growth is coming from the Permian Basin, where oil
and gas operators are converting operations to run on electricity instead of gas or
diesel. Much is also coming from large users such as data centers that are powering
artificial intelligence and crypto currency mining. Some are requesting several times
more power than what the city of Lubbock now uses, according to ERCOT.
The new estimates raise crucial questions, such as whether large power users that can
ramp up and down need greater state oversight, the committee’s chair, state Sen.
Charles Schwertner, R-Georgetown, said in an interview. One bitcoin mining
company last year reported making millions of dollars in the electricity market by
selling back pre-purchased power when grid conditions became tight, which provoked
the ire of some Texans who saw their power bills rise.
“I think we need to rise to the challenge of getting the needed generation onto the grid,”
Schwertner said. “But there is eventually a prioritization that could be discussed, and
obviously Texans — their families, their homes, their businesses — are the most
important individuals, the most important clients for electricity.”
In a post on X after the hearing, Lt. Gov. Dan Patrick said the Legislature needed to
“take a close look” at data centers and crypto operations. “We want data centers, but it
can’t be the Wild Wild West of data centers and crypto miners crashing our grid and
turning the lights off,” he wrote.

DOE US Transmission Needs Mar 2024 See the file here >>DOE US Transmission Needs Mar 2024