The Economics Of Renewable Energy

The Economics Of Renewable Energy – Renewable electricity accounted for a quarter of electricity consumption in 2020, up from just 8 percent in 2010 (

). More is on the way, with solar capacity set to quadruple by 2024 from today’s comparatively low levels. Because availability can be intermittent, renewable energy needs the support of other power plants to meet electricity demand.

The Economics Of Renewable Energy

Meanwhile, Texas’ aging coal, nuclear and gas-fired power plants (collectively known as “thermal plants”) in Texas are requiring more than expected maintenance and repairs, increasing the risk of generation shortfalls during periods of high demand. Additionally, Texas’ electricity use will only increase due to population migration, transportation electrification, and growing demand from industrial sources such as data centers and petrochemical plants.

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Given the low investment in new heat generation, does the design of the Texas electricity market provide sufficient incentives to develop capacity for future electricity needs? Increased use of battery storage and demand response programs—incentives that utility companies pay customers for voluntary, planned reductions in energy use—as well as new gas-fired power generation may require Texas consumers to enjoy reliable power in the future the

Because daily wind and solar power is variable due to weather and time of day, Texas’ grid operator — the Electric Reliability Council of Texas (ERCOT) — gets harder every year to match power supply with demand. That increases the need for “distributable” power — electricity on demand, mostly from natural gas plants — that can fill the gap when power generation from renewable sources falls.

This challenge will be greater as ERCOT expects utility-scale solar capacity to increase from 7,800 megawatts (MW) today to more than 28,000 MW by 2024. On a summer day, this amount of solar capacity can power nearly 4.5 million Texas homes.

ERCOT forecasts expected seasonal power generation capacity, demand (load) and reserve margin – the generation is exceeded above maximum load, typically the hours of highest demand on the hottest or coldest days of the season. To avoid power outages, ERCOT strives for a reserve margin of at least 13.75 percent to cover unexpected increases in demand or power plant failures.

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When forecasting available generation capacity, ERCOT takes into account renewable energy weather patterns and the downtime schedules provided by power plant operators. Based on these, ERCOT expects reserve margins of more than 30 percent between 2023 and 2026 (

While margins above these targets may seem reasonable, high temperatures, extended power plant outages and low renewable energy production can significantly reduce summer margins. If all of these events happened during the current summer season, according to ERCOT’s own forecast, the grid would be less than 14,000 MW, causing widespread outages.

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The February 2021 winter storm was one such scenario, with all the unlikely events happening at the same time. Electricity demand rose above forecasts, power plants and natural gas facilities were insufficient for winter, more facilities were out of service for maintenance than expected, and renewable generation was very low.

Looking ahead, the error rate will shrink due to weather and the changing power generation mix. If thermal plant downtime reaches June 2021 levels — 9,000 MW offline on the Texas grid — and renewable generation falls to 50 percent of its projected contribution, capacity would be tight on projected peak days and reserve margins would be just over below this ERCOT target. by 13.75 percent for the next five years, increasing the likelihood of blackouts (

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Texas is approaching, if not already, the limits of the current power generation mix. The grid is increasingly dependent on intermittent generation from renewable energy as the question arises of how much heat capacity is actually available to meet unexpected shortages – all as electricity demand increases.

An improvement would be the expansion of utility-scale battery storage for wind and solar systems. In Texas today there is only 853 MW of battery capacity. These storages are designed to help meet demand for just one to two hours, usually during peak periods when renewable resources are scarce. Although a capacity of 2,400 MW is planned by 2024 – equivalent to a quarter of ERCOT’s current reserve margin – more is needed. Installing battery storage costs an average of $1.5 million per megawatt.

Expanding demand response programs could also help prevent power outages. ERCOT already predicts that these programs will save 2,900 to 4,700 MW of peak demand over the next five years. Increased adoption, even on a limited scale, could make a big difference when every megawatt counts in a severe weather event.

Texas is the only US state with an “energy-only” electricity market, where generators pay only for the electricity they provide. This is based on the premise that higher electricity prices during periods of increased demand will encourage the development of power plants in the Texas grid. This is in contrast to the more common “market capacity” where producers are required to have certain reserve capacity.

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The growing presence of renewable energy generally lowers wholesale electricity prices on sunny and windy days, and causes thermal plants to be offline for longer hours. This has reduced the economic incentive to build and properly maintain thermal plants.

This trend will intensify as renewable capacity increases. It is now an open question whether this market structure will stimulate sufficient investment in on-demand capacity in the future, which will be crucial in times when solar and wind resources are unavailable.

In the face of policy makers: introduce a capacity market or strengthen energy market conditions-only for more power reserve capacity. In any case, it seems likely that more on-demand power will be needed in the near future than currently planned.

According to the U.S. According to the Energy Information Administration, the spread of renewable energy in Texas, increased natural gas consumption, and the closing of coal-fired power plants have reduced the power sector’s carbon emissions by 13 percent over the past decade, even as use has increased by 20 percent. Continuing this trend and providing reliable power is not an incompatible goal with careful planning and incentives.

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The opinions expressed are those of the authors and should not be attributed to the Federal Reserve Bank of Dallas or the Federal Reserve System. The US electricity system is one of the largest, most complex and most expensive machines in the world, but the basic infrastructure of the electricity grid is old and not aging gracefully. Almost 500 gigawatts (GW), or about half of the existing fleet of thermal generators (ie coal, nuclear and gas) are expected to be decommissioned by 2030, creating a capacity gap that needs to be addressed with new investment.

U.S. power producers could charge up to $1 trillion in future capital and gas costs to customers and investors by 2030 as they rush to build new power and gas plants. But advances in renewable energy and distributed energy resources (DER) offer lower tariffs and emission-free power while providing all the grid reliability services that new power plants can provide.

The analysis shows that due to recent innovations and rapid price declines in renewable energy and DER technology, clean energy portfolios can often be procured at significant net cost savings, with reduced risk and zero carbon and emissions when compared to building a new gas plant. . Even more dramatic

Fuel-efficient power plant costs over the next two decades – a risk for investors and customers in a market with already announced investments in new power plants of more than US$100 billion.

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The report analyzes four electric and natural gas plants currently proposed for construction in the United States and compares them to self-optimized, region-specific renewable energy portfolios and DERs that can provide the same services. The analysis includes two combined cycle gas turbine power plants announced for high capacity factor operation and two announced combustion turbine power plants scheduled for peak-time operation. In three of the four cases, an optimized clean energy portfolio would cost 8-60 percent less than the power plant announced. In one case the analysis showed that the net cost of optimizing the clean energy portfolio is slightly (~6 percent) higher than that of the proposed power plant. Considering further cost reductions are expected from distributed solar systems and/or a carbon price of $7.50/ton

Emissions, all four cases show that an optimized clean energy portfolio is cheaper and less risky than the proposed gas plant.

Examine a scenario where more than half of decommissioned thermal capacity is replaced by a portfolio of resources capable of providing the same energy, peak capacity and flexibility to the grid by 2030, using conservative assumptions for both renewable and DER assumptions. This path would unlock a $350 billion market for renewables and DERs by 2030 while avoiding 3.5 billion tons of CO.

If you subscribe, we will keep you up to date with the latest news and information through regular email communications. Global renewable energy capacity broke a record last year, and 2021 is expected to be even better. Renewable energy is already the fastest growing source of electricity generation, currently providing more than a quarter of global electricity generation and is on track to become the world’s largest source of electricity by 2025.

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Renewable energy has seen amazing growth that has consistently exceeded expectations. A recent report by Ember and Agora Energiewende shows that renewable energy and wind have almost doubled in Europe over the past five years. According to an IHS Markit report called “Top Clean

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