Navigant Research Blog

The Overlooked Renewable

— May 19, 2015

Hydropower may account for just 7% of U.S. electricity generating capacity, but this sometimes overlooked renewable energy source could play a more significant role. That’s one of the conclusions from a first of its kind study on hydropower that quantifies the size, scope, and variability of hydropower in the United States.

The new U.S. Department of Energy (DOE) study (2014 Hydropower Market Report) describes a diverse fleet of hydropower plants that collectively produce enough electricity to power more than 20 million homes. The report also notes that the size of the hydropower fleet has grown in the last decade, mainly as owners have upgraded existing hydro assets, with a net increase of nearly 1.5 GW from 2005 to 2013. Total investment in hydropower amounted to more than $6 billion for refurbishments, replacements, and upgrades during that timeframe.

 One Major Hurdle

On the plus side, the report indicates that the United States has more than 77 GW of potential hydropower capacity, and that the current development pipeline encompasses a mix of proposed projects at non-powered dams, conduits, and undeveloped rivers or streams. These projects, as well as large-scale pumped storage hydropower (PSH) projects, account for the bulk of current development plans. However, there is a major hurdle that clouds this picture. The widely available bond, grant, and tax-credit programs that helped drive development of hydropower projects in recent years have gone away, and new projects are likely to depend on alternative funding sources, which more than likely means a slower pace for upcoming projects.

Without a doubt, hydropower has it limits and cannot be thought of as a viable alternative in certain regions – drought areas of the Southwest come to mind. But given its potential for adding tens of gigawatts of untapped power, it should be part of the overall energy conversation because of its proven track record as a source of clean, reliable power, despite the potential funding hurdles.


Major Shifts Ahead for European Power Generation

— May 4, 2015

Across Europe, major changes in the power generation sector are driving the development, expansion, and deployment of new and reconfigured electric transmission and distribution systems. The forces driving these changes include the retirement of much of the existing coal and nuclear generation fleet, the European Union’s energy policy goals, concerns over security of supply, climate change mitigation efforts, and the ongoing integration of distributed energy resources (DER) across the region. Power peak load is expected to grow between 8% and 28% by 2030, according to the Ten-Year Network Development Plan produced by the European Network of Transmission System Operators for Electricity, or ENTSO-E.

The net generation capacity of the European power sector must grow from about 1,000 GW today to between 1,200 GW and 1,700 GW by 2030 in order to keep up with demand, according to the Plan. To accomplish this massive increase, the generation fleet must not only add new capacity, but also replace present units that will be retired in the next 15 years. This represents a 3%4.6%  expansion per year across all potential resources.

Age of Wind

Looking to 2030, the generation fleet in Europe will morph in a number of significant ways, including:

  • Major nuclear generation plant retirements will happen across the region, including those in Germany, Belgium, and Switzerland. All present nuclear units in the United Kingdom are scheduled to be shut down, and France plans to reduce the share of nuclear to 50% of the country’s power supply by 2025. This adds up to a net 30 GW and 45 GW of nuclear capacity being shut down. At the same time, 20–30 GW of new nuclear capacity is expected to be added. New plants may be added in the United Kingdom, Finland, and Central Europe.
  • New generation additions will occur in new locations. Wind farm development will be located where wind speeds are optimal; a significant share of the new generation fleet in Western Europe is being built on new sites, mostly in harbors.
  • The shutdown of nuclear and fossil-fired units across Germany will require additional grid investment necessary to transport remote power to population centers.
  • New generation capacity will primarily be made up of distributed wind and solar systems. The generation capacity of wind, solar, and biomass is expected to reach at least 405 GW and could triple, reaching more than 870 GW by 2030.
  • DER will be located in Germany and in countries with favorable wind conditions, such as the Iberian and Italian peninsulas and Nordic countries bordering the North Sea.
  • New hydropower capacity is expected to increase from 198 GW to between 220 GW and 240 GW, with most new development in the Alps, the Iberian Peninsula, and Norway.

These major generation shifts will be the primary drivers for investments in high-voltage transmission systems across the region. Navigant Research’s forthcoming report, Submarine Cable and High Voltage DC, will detail many of these changes and additions, which promise to transform Europe’s power sector.



U.S. Energy Mix Shifts toward Renewables, Natural Gas

— April 20, 2015

The U.S. Energy Information Administration (EIA) has released figures for scheduled additions and retirements of generation resources in the United States during 2015. According to the EIA, the United States is expected to add 9.8 GW of wind, 6.3 GW of natural gas power plants, and 2.2 GW of solar—all of which make up 91% of the total 20 GW that is expected to come online this year. No coal plants are scheduled to come online this year, and 12.9 GW of coal and 1.98 GW of natural gas will be retired. Not only does this signal a shift in the U.S. energy mix, but it also indicates that there is a great deal of investment in wind, gas, solar, and even nuclear in the U.S. market. That said, 12 GW of this capacity is variable and will require some type of firming or integration. Often, this balancing is executed by gas power plants, which are more flexible than nuclear plants, for example.

Sources: U.S. Energy Information Administration, Electric Power Monthly
Note: Other renewables include hydroelectric, biomass/wood, and geothermal.

Overall, a healthy amount of capacity is slated to come online in the United States, thanks to market signals such as the Production and Investment Tax Credits. That said, what can we expect to happen in response to the difference between generation and load if the market is not encouraging investment in generation assets?

Shrinking in Texas

I learned at the ERCOT Market Summit that Texas is in a tenuous position with a current reserve margin of 15.7% in 2015 that is expected to shrink to 7.3% by 2024. The reserve margin is a reflection of a grid’s ability to cope with unpredictable but foreseeable events—such as a generator tripping offline or a sudden spike in load. These are not uncommon occurrences, but forecasting them is impossible; hence, the margin.

In Texas, the shrinking reserve margin is a function of power plant retirements and an increase in overall load. In addition, Texas is one of the most deregulated energy markets in the world. This means that it is very unlikely that the state would employ any type of market intervention, such as a mandate or a subsidy, to encourage investment. Instead, it is up the market to adapt in order to embolden the right participant behavior. So far, as evidenced by the shrinking margin, the market is not sending the right signals to encourage investment in power plants.

Markets designers in deregulated markets already looking ahead. Texas has decided against a capacity market and is instead developing reserve products for short-, medium-, and long-term reserves. These products are unlikely to offer the lucrative and consistent returns natural gas power plant developers are looking for, but they should open the door for alternative technologies, including storage.


In Golden Age, Natural Gas Becomes Generation Workhorse

— March 9, 2015

The promised golden age of natural gas has begun to take hold globally. Fortunately, rising natural gas demand will not require a corresponding increase in infrastructure spending across the United States, according to a recent report from the U.S. Department of Energy. These findings hold even as the U.S. electric power sector—currently the largest consumer of natural gas in the country—saw generation from natural gas replace that of coal in recent months. This corresponds with a sharp increase in demand for natural gas from multiple end-use sectors.

With the Henry Hub reference price for natural gas in the United States lingering below $5 per million Btu (mmBtu) since the early part of 2014, a demand surge is expected to continue across the power generation sector.

Renewables and Gas

The United States, already the largest consumer of natural gas in the world, is expected to see a 33% increase in demand by 2040, according to the U.S. Energy Information Administration’s Annual Energy Outlook 2014 reference case. Growth is expected to be 42% for the electric power sector between 2012 and 2040 under the same scenario.

Living up to its promise as a bridge fuel to a low carbon future, natural gas is helping backfill baseload generation, especially in areas where coal plant retirements are highest. The combination of wind or solar power and gas-fired generation, meanwhile, has emerged as an option for states looking for more access to lower-carbon electricity. This hybrid approach is playing out across the expansive areas of the West, where electrical grid transmission bottlenecks have made it difficult to export renewable generation from areas of high productivity (e.g., Wyoming) to population centers on the West Coast, for example.

Not Laying Pipe

The increased use of natural gas in the electric power sector, however, is not without potential challenges. Unlike competing fuels, natural gas is delivered as it is consumed, and cannot be stored onsite like coal. Furthermore, adequate infrastructure is needed to maintain electric system reliability. The investment of $65 billion in new interstate pipeline construction over the past 18 years appears to be sufficient to deliver natural gas from producing regions to end users across the country without substantial new investment.

Unlike the U.S. electrical grid, natural gas power plants and natural gas production are both broadly distributed rather than geographically concentrated, reducing constraints on interstate pipeline capacity. What’s more, lower-cost investment options, such as improving the utilization of existing infrastructure and rerouting gas flows, are far cheaper than building new pipelines.

As the U.S. power sector faces several concurrent transitions—retirement of coal-fired generation, aging electrical transmission infrastructure, and a surge in the use of intermittent renewables—these findings suggest that natural gas will continue its emergence as the workhouse on the modern electrical grid.


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