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July 2013 Policy Study, Number 13-5

   

Electricity – Make It, Use It – 24/7/365

Review of Electrical Grid Issues

   

Background

   

 

Importantly, much of the U.S. energy infrastructure – including the electrical grid – dates from the 1880s, with major upgrades and connections made during the 1920s. Operations and upgrades are significantly impacted by “permitting issues, weather events, and limited maintenance.”[3] There are three major grid areas operating in the United States – the Eastern, Western, and Texas grids.[4] In total there are “almost 400,000 miles of electric transmission lines.”[5] Significant technology improvements were completed in the mid-1900s through the installation of automatic switches, which better controlled outages. But no major systemic improvements have been completed since the 1990s. The overall energy infrastructure was given a D+ grade by ASCE in 2013.

 

The demand for electricity is expected to increase by 8 to 9 percent between now and 2020, while current projections show an increase of over 100 gigawatts in generation ability by 2016. This reflects a system basically in balance on the generation end. The problems are on the delivery side.

 

Within each of the three grids there are many power companies and many issues affecting reliability. Some areas have little weather damage, because the lines are newer or buried, while those in tornado or hurricane zones are in the news frequently. Often, many of the worst problems are in the highest population areas on the east and west coasts.

 

The Midcontinent Independent System Operator (MISO), set up according to Federal Energy Regulatory Commission (FERC) rules, is one of the largest non-profit transmission groups in the U.S. with almost 66,000 miles of high-voltage lines throughout an 11-state – plus Manitoba, Canada – region. Power generating companies in all or parts of Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, Nebraska, North and South Dakota, Ohio, and Wisconsin are members.[6] Additionally, MISO manages reliability programs for companies as far west as Montana, and stretching all the way down the Mississippi River to Arkansas, Kentucky, Louisiana, and Mississippi.

 

On average all U.S. customers were without power for 112 minutes in 2011, the most recent data available. This is less than two hours over an 8,760-hour year, a miniscule amount of time. However, this is up 15 percent since 2002 (97 minutes) and the “highest level in 10 years.”[7] Nationally, approximately 500,000 people lose power for an hour or more every day.

 

The estimates of economic impact of this power loss range from $80 to $188 billion per year.[8] According to the ASCE, a power outage costs the average commercial business $1,000 per hour. Industrial costs increase to $4,000 per hour.[9] These figures do not include extreme outage situations caused by major storms such as Hurricane Sandy last year or the Oklahoma tornadoes of 2013.

 

As reported by the Electric Power Institute and the Lawrence Berkeley National Laboratory, Hurricane Sandy caused 8.5 million customers in 21 states to lose power in 2012, and many were still without power a week later.

 

Major blackouts have also been caused by trees touching lines, technician errors, or computer malfunctions. The most recent example of this was the 2003 blackout, which started in Ohio and spread to the “entire Northeast U.S.” and parts of Canada.[10] Potential solutions include both overall system upgrades, including “smart grid” technologies, and individual customer backup systems.

 

Another major concern is “congestion” – caused by imbalances in the amount of electricity available and the amount needed in a specific area. Congestion mostly affects the Northeast U.S. and southern California. It also affects both reliability and consumer costs nationwide.

 

The electric grid in the U.S. functions uniquely compared to most other infrastructure elements (water/roads), because it is mostly privately owned, though heavily regulated. As a result companies are continually buying and selling power sources.

 

The wide variety of potential energy sources, including nuclear power, coal, natural gas, hydro, solar, and wind energy (plus the increasing growth of personal ownership) allows for great flexibility in distributed generation and control of base load, peak load, and backup electricity. This makes estimating future demand with any accuracy difficult, and various agencies have developed very different projections. When you add in the various subsidies and tax breaks for “green” energy sources, the picture becomes even more complex.

 

The growth in generation capacity over the next 30 years is expected to be in natural gas, diesel, and renewable sources. Though many older coal plants are being phased out, coal will remain a critical energy generation source. According to the ASCE, growth in renewables will not significantly impact the overall grid except in the west and southwest.

 

In Iowa the recent announcement of a $1.9 billion investment in wind energy by MidAmerican Energy will add “as much as 1,050 megawatts” of new power-generating capacity and be “as much as 40 percent” of the company’s overall generating capacity.[11]

 

A factor many consumers are not aware of is that the “planning reserve margin” requires that companies are not only able to meet “peak demand” but have backup capacity 15 percent beyond peak demand.[12] This means that much of the electricity generation and transmission capacity is underused for huge periods of time, but must always be ready to operate, 24/7/365. As a result there are large financial investments and capital tied up, with costs which are passed onto consumers whether or not they are ever used.

 

   

 

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