What is the electric power grid, and what are some challenges it faces?

Last Updated: April 27, 2012

The grid of electric power lines has evolved into three large interconnected systems that move electricity around the country. Standards have been developed by the electric power industry to ensure coordination for the linked operations. Challenges facing the power grid include getting approval for corridors of land for new transmission lines within states or that cross multiple states, and the financing and constructing of new transmission lines to assure continued reliability of our electricity supply.

Getting electricity from power generating stations to our homes and workplaces is quite a challenging process. Electricity must be produced at the same time as it is used because large quantities of electricity cannot be stored effectively.

High-voltage transmission lines (those lines between tall metal towers that you often see along the highway) are used to carry electricity from power generating stations to the places where it is needed. However, when electricity flows over these lines, some of it is lost. One of the properties of high voltage lines is that the higher the voltage, the more efficient they are at transmitting electricity — that is, the lower the losses are. Using transformers, high-voltage electricity is "stepped-down" several times to a lower voltage before arriving over the distribution system of utility poles and wires to your home and workplace so it can be used safely.

Around the beginning of the 20th century, there were over 4,000 individual electric utilities, each operating in isolation. Almost all of those used low-voltage connections from nearby generating power plants to the distribution lines serving their local customers.

As the demand for electricity grew, particularly in the post-World War II era, electric utilities found it more efficient to interconnect their transmission systems. In this way, they could share the benefits of building larger and, often, jointly-owned generators to serve their combined electricity demand at the lowest possible cost, and to avoid building duplicative power plants. Interconnection also reduced the amount of extra capacity that each utility had to hold to assure reliable service. With growing demand and the accompanying need for new power plants came an ever-increasing need for higher voltage interconnections to transport the additional power longer distances. Over time, three large interconnected systems evolved in the United States.

Today, transmission and distribution lines owned by an individual utility are no longer resources to be used only by that utility. Electrical systems have been expanded and interlinked. The systems now provide the associated transport of electricity on the transmission lines where buyers and sellers may be geographically spread apart.

Close oversight of operations within the three power grids is needed to keep the various components linked together. The interlinked systems now include over 3,200 electric distribution utilities, over 10,000 generating units, tens of thousands of miles of transmission and distribution lines, and millions of customers.

Originally, each generating company was responsible for maintaining its own electrical system safety and planning for the future needs of its customers. Later, voluntary standards were developed by the electric utility industry to ensure coordination for linked interconnection operations. These voluntary standards were instituted after a major blackout in 1965 that impacted New York, a large portion of the East Coast, and parts of Canada.

Now, planning is done in a much more coordinated manner to achieve adequacy of supply, to establish and oversee formal operational standards for running the bulk power systems, and to address our Nation's security concerns for critical electrical infrastructures. All of this coordination is administered under mandatory procedures set up by the electric power industry's new electricity reliability organization (the North American Electric Reliability Corporation), with oversight provided by the Federal Energy Regulatory Commission and the U.S. Department of Energy.

The National Power Grid

Most of the electrical transmission components have been in existence for many years. It is generally agreed that some replacement and upgrading of current lines will have to be done, and that new lines need to be constructed to maintain the system's overall reliability.

Four significant challenges to improving the power grid infrastructure are:

Siting new transmission lines (and obtaining approval of the new route and needed land) when there is local opposition to constructionDetermining an equitable approach for recovering the construction costs of a transmission line being built within one State when the new line provides economic and system operation benefits to out-of-State customersEnsuring that the network of long-distance transmission lines reaches renewable sites where high-quality renewable resources are located, which are often distant from areas where demand for electricity is concentrated.Addressing the uncertainty in Federal regulatory procedures regarding who is responsible for paying for new transmission lines; this uncertainty affects the private sector's ability to raise money to build them.

There is no "national" power grid. There are actually three power grids operating in the 48 contiguous states: (1) the Eastern Interconnected System (for states east of the Rocky Mountains), (2) the Western Interconnected System (from the Pacific Ocean to the Rocky Mountain states), and (3) the Texas Interconnected System. These systems generally operate independently of each other, although there are limited links between them. Major areas in Canada are totally interconnected with our Western and Eastern power grids, while parts of Mexico have limited connection to the Texas and the Western power grids.

he "Smart Grid" consists of devices connected to transmission and distribution lines that allow utilities and customers to receive digital information from and communicate with the grid. These devices allow a utility to find out where an outage or other problem is on the line and sometimes even fix the problem by sending digital instructions. Smart devices in the home, office, or factory inform consumers of times when an appliance is using relatively high-cost energy and allow consumers to remotely adjust its settings.

Smart devices make a Smart Grid as they help utilities reduce line losses, detect and fix problems faster, and help consumers conserve energy, especially at times when demand reaches significantly high levels or an energy demand reduction is needed to support system reliability.

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Challenges Facing Power Generators in ERCOT

Although nearly all energy experts agree that demand for electric energy in Texas will outstrip supply in the coming years, developers of new power generation facilities are facing significant headwinds. The cause of the problems is a unique mix of circumstances.

The competitive energy markets managed by the Electric Reliability Council of Texas (ERCOT) have been hailed by some as the best in the country for allowing the “free hand” of the wholesale generation market alone to send the appropriate pricing signals for new power plant construction. The following factors, however, pose challenges to ERCOT’s future energy supply:

An unwillingness on the part of suppliers to enter into long-term power purchase agreements.A related lack of liquidity in the term energy markets.A general reluctance on the part of lenders to provide financing for “merchant” projects.Regulatory changes affecting both existing generators and developers of new power plants.The absence of a capacity market.

Because the time needed to develop and complete an electric generating facility can exceed three years, Texans may face serious power shortages if some of these issues aren’t resolved in the near term.

Demand for electricity in ERCOT is rapidly approaching the level of existing supply. ERCOT has a target reserve margin (the percentage of available resources above peak demand) of 13.75%. Maintaining that reserve margin is critical to ensuring stability of supply and avoiding blackouts and brownouts. However, in each reporting year after 2014, ERCOT currently projects the reserve margin to fall below this target level.

Three main factors make adding new generation in Texas difficult: its deregulated market, regulatory issues specific to ERCOT, and weak market signals.

As of Dec. 31, 2001, investor-owned utilities (IOUs) in ERCOT were required to unbundle their operations. Following deregulation of the ERCOT electricity markets in areas served by IOUs, the provision of service to end-use retail customers became competitive, and electric providers no longer had a captive body of retail customers. Without a captive body of customers, it became extremely difficult for suppliers to predict prospective demands for power. As a result, they are now generally unwilling to commit to long-term wholesale power purchase agreements or to the construction of new projects.

Although the useful life of a thermal generation facility can exceed 40 years, the capital costs to complete those facilities are extremely high. Though a 40-year power purchase agreement is not necessary to induce investors to build a new power plant, some level of predictable cash flows for a significant period of time will likely be necessary.

Those investors having a larger appetite for risk may be willing to invest without a long-term contact, but in order to do so, these higher-risk investors would also expect higher returns on their investment and would need to see forward pricing fundamentals/signals that suggest that those higher returns are forthcoming.

In recent times, however, the low price of natural gas has depressed the forward market for power and, as a result (with limited exceptions), those higher-risk investors have yet to see sufficient potential returns at the level required to start construction.

Moreover, even if such investors are persuaded that their equity investment is warranted, in most instances, project debt will also be needed to finance construction.

As lenders tend to be risk-averse, securing financing for uncontracted projects is likely to be a challenge in the current debt markets.

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Proposed Dam Presents Economic and Environmental Challenges in Alaska

The Alaska Energy Authority is planning to build a 735-foot, $5.2 billion structure on the Susitna River in a largely empty south-central part of the state, which is watered by runoff from the arc of the Alaska Range. The dam, designed to generate up to 600 megawatts of electricity, would create a new power supply for more than two-thirds of the state’s population.

But in Alaska, where natural energy resources and wildlife are both foundations of the economy, the proposed dam presents twin conundrums.

One is economic: which is better, creating a reliable source of hydroelectricity and weaning some of the state off natural gas, or building a spur off a proposed pipeline to bring gas from the North Slope to the populated region from Fairbanks to the Kenai Peninsula? Or both? The other is environmental: what serves the environment best, replacing natural gas-fired electricity with hydroelectricity, which is free of greenhouse gas emissions, or keeping the Susitna watershed untrammeled and avoiding the risks involved in changing the dynamics of a major salmon stream?

For environmentalists, the choice is uncomfortable. “It is a bit of a hard choice for the environmental community to have to make. Do we choose a big natural gas project or do we choose a big dam?” said Corinne Smith, a Nature Conservancy official in Alaska responsible for the study of the Matanuska-Susitna Valley where the dam would be located.

While energy is a foundation of the Alaskan economy, it is most visible in the federal arena. The big political fights over energy have involved federal lands, like the Arctic National Wildlife Refuge or the National Petroleum Reserve. Discussions over how Alaskans should generate their own energy are less frequent and lower-key.

But now, the prospect of building the new dam is being drawn into a debate in the Legislature over a proposal much more familiar to environmental groups: the plan to build a $45 billion natural gas pipeline from the North Slope to the Midwest, perhaps including a spur that would carry some gas to south-central Alaska, where regional power plants are already fueled by gas.

Having this gas provide reliable electricity at stable and affordable prices, said an analyst of both projects, would make the dam superfluous and avoid its environmental impacts. But of course, there are significant environmental impacts associated with the 800-mile proposed pipeline.

Can the state afford both? Key legislative leaders think so, even though the oil revenues that made Alaska rich are inexorably dwindling along with the oil bounty of the North Slope.

“We’re lucky we’re financially healthy,” said Representative Charisse Millett, co-chairwoman of the special Energy Committee in Alaska’s House of Representatives. “We don’t want to pick one project — we want to go down parallel paths.”

Moreover, the decades-old dam proposal, dusted off by the Legislature and Gov. Sean Parnell in 2010, would help the state abide by its policy that Alaska obtain half its energy from renewable sources by 2025. The dam legislation passed without a single dissenting vote.

Both the dam and the pipeline appeal to the state’s appetite for supersize ventures, said Steve Colt, an environmental economist at the University of Alaska Anchorage.

“We’re always looking for the next boom and we’ve been remarkably lucky in coming across one thing after another,” he added. “People were thinking the gas pipeline would be the next big thing. Now, it’s the most expensive hydroelectric project ever built in North America.”

Construction of the dam, according to Emily Ford, a spokeswoman for the Alaska Energy Authority, would provide an essential new source of electricity and a hedge against a surge in energy prices. Oil price increases, of course, benefit the state in its role as an exporter of North Slope oil, but hurt regions in the state dependent on oil-fueled electricity and heating.

“We were looking for solutions to provide an affordable and stable power source” for more than 500,000 people in the Railbelt, the south-central region from Fairbanks to the Kenai Peninsula, Ms. Ford said.

Opponents of the dam, however, say that the declining supply of natural gas feeding most of the power plants in the Railbelt could be replaced with supplies form the North Slope, or from untapped resources in the gas-rich areas of the Cook Inlet.

Cook Inlet, at the mouth of the Susitna River, is one of the world’s richest salmon fishing grounds. Susitna is among the four biggest state rivers used by salmon species when spawning.

As Chris Wood, president of the environmental group Trout Unlimited, said, “The fact is that this dam, in ways we don’t know, would change the flow of the Susitna.” In late July last year, for the first time, a reduced population of Chinook salmon resulted in the partial closure of the area for fishing.

The impact of large dams on salmon runs and the riverine environment has kept large hydroelectric projects elsewhere in the country off the federal list of renewable energy sources — but not off Alaska’s.

The concern for Mr. Wood and local opponents is not that the dam will block salmon runs, as large dams in the West have. The site of the Susitna project is far upriver, beyond the reach of all but the hardiest fish.

Instead, the issue is the way the dam will alter the river’s rates of flow. Richard Leo, president of Susitna Dam Alternatives, argued that “in the wintertime, the dam is going to be releasing flow many times greater than normal.” Juvenile salmon, he said, “will no longer be able to hover near the edge of the river, they will literally have to swim for their lives.”

Ms. Ford, the spokeswoman for the energy agency, said that all the major issues, from stream flows to fish behavior, are being studied in an extensive review process that will take at least two more years. In 2015, if things go as planned, the state will ask federal regulators for a license, she said, and construction could start in 2017.

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