Growing power consumption and the U.S. administration’s plan to rely more heavily on renewable generation sources will increase the demand on America’s already overloaded electricity grid and require major investment in transmission and distribution networks.
Upgrading power transmission and distribution systems is likely to cost as much as installing new generating capacity over the next 20 years.
While Congress provided an extra $4.5 billion of funding for grid improvements in the recent fiscal stimulus, federal loan guarantees and other support, far more investment will be needed if the administration’s targets for renewable generation are to be realized.
In its “Annual Energy Outlook 2009″ (AEO2009), the Energy Information Administration projects consumption will increase by 1,000 billion kilowatt hours (26 percent) between 2007 and 2030. The United States will need to install 259 gigawatts (GW) of new generating capacity to replace aging generators taken out of service (30 GW) and meet increased demand on the system (229 GW).
A report prepared for the Edison Foundation by consultants Brattle Group last year put the capital cost of capacity installation at between $500 billion and $1 trillion (depending on how much of the total is met by cheap sources such as coal and gas and how much by expensive sources such as nuclear, wind and solar). Click here for PDF.
AEO2009 projects that most of the added generating capacity will be from conventional sources such as natural gas (53 percent), coal (18 percent) and nuclear (5 percent). But a substantial proportion will come from renewables (22 percent), raising the share of renewable power in total generation from 8 percent in 2007 (much of it from hydro dams) to as much as 13 percent in 2030.
The biggest additional contribution will come from the combustion of biomass waste products left over from increased production of ethanol to meet the federal government’s ambitious targets. The other major contribution will come from wind. Solar is likely to make a marginal contribution in the timeframe owing to high cost.
Biomass generators can be used in the same way as conventional power sources like gas and oil since the technology is identical (combustion to raise steam). The amount of power can be scheduled (”despatched”) to meet demand in exactly the same way as a conventional power plant.
Wind and solar present greater challenges because they cannot be scheduled with precision. As the percentage of power drawn from these non-despatchable sources increases, it will pose unique challenges for grid managers and require a substantial reconfiguration of the system.
Reconfiguring the grid to handle increased demand and a greater share of renewables will impose substantial costs. The Brattle Group report estimated the industry would need to spend as much upgrading the high-voltage long-distance transmission system ($300 billion) and lower-voltage local distribution networks ($600 billion) as it will on increased generating capacity.
Electricity supply is a relatively simple system in which power is supplied from generators to household and industrial appliances (”loads”) via the transmission and distribution network. But unlike other commodities, storing electricity is impractical, and supply and demand must balance continuously.
In response to short-term supply and demand fluctuations, system controllers employ a variety of techniques to ensure continuous balance between generation and load. In response to an unexpected increase in demand or loss of supply (caused by a generator tripping) the grid is rebalanced by a multi-tiered process:
– In the first instance, shortfalls are met by drawing a small quantity of additional energy from each of the remaining generating units on the grid. But while this automatic response provides compensating power for several seconds, it causes generating units to lose momentum and electrical frequency to decline across the grid.
– In the second stage, loss of frequency is sensed by governors attached to each generating unit on the grid causing them to deliver more fuel to the turbines, re-accelerating the generators. Producers are paid a fee to operate at slightly below full capacity to provide these frequency reserves, which are available within as little as 10 seconds and last up to 30 minutes.
– Beyond frequency reserves, the grid can call on “standing reserves”, typically gas-fired peaking plants held on stand-by that can be started rapidly and begin delivering extra power within 20 minutes.
All these responses focus on generation. But in the last resort the grid can begin “load shedding” (cutting off the power to some users to limit the demand on the system). Traditionally, certain industrial users receive power on “interruptable” contracts that allow the grid operators to instruct them to reduce their usage by a specified amount during an emergency.
In future, the industry hopes to develop dynamic demand control (DDC) systems allowing the grid to “defer” less sensitive loads (particularly refrigeration, air-conditioning and heating) by switching them off for a few seconds or even minutes at a time until more standing reserves can be brought online.
DDC would be triggered either by fitting appliances with their own frequency-sensitive governors or installing some two-way communications system.
While loads from individual appliances are very variable and impossible to forecast, aggregate load from millions of appliances linked to the grid is much more predictable over a 24 hour cycle. In effect, the law of large numbers and grid interconnectedness help smooth the demand profile and make supply management possible.
In the same way, generation from individual wind turbines and solar units fluctuates significantly, but power availability becomes more stable if many different types of renewable energy (wind, solar, biomass) are connected to the grid at many different locations: strong sunlight and solar generation in the Mojave desert can make up for power lost when the wind stops blowing in Kansas.
Problems posed by variable power output from renewables can be managed in exactly the same way as variations in load or accidental loss of generating supply.
But as the percentage of renewable generation increases, so do potential imbalances. More renewables such as wind and solar will require more conventional (gas, coal and biomass) generating capacity to be held in frequency and standing reserve (potentially reducing efficiency and increasing cost).
Renewables proponents want to move away from the traditional power-on-demand model to one in which demand as well as supply is managed dynamically. If load as well as generation can be scheduled, via “smart grids” and other control techniques, the amount of generating capacity held in costly reserve could be reduced.
Increasing renewables will also put a premium on long-distance transmission capacity so shortfalls in generation in one region can be made up from increased output in other areas. But the U.S. power grid grew up piecemeal and is plagued by bottlenecks. In particular, there are limited interconnections between the eastern and western United States across the Rocky Mountains, and between Texas and the rest of the country.
Bottlenecks are already causing reliability problems, which will worsen as the percentage of renewables increases unless grid capacity is upgraded.
The fiscal stimulus approved earlier this year directed the Department of Energy to provide technical assistance to help increase transmission capacity across the Rockies and with Texas. But grid management will have to undergo a revolution if the share of renewables is to be raised significantly without an adverse impact on reliability.
Much more investment, and more federal government support through direct funding, loan guarantees or favorable charging regimes will be needed if the renewables aspiration is to be made a reality.