Bills Unpaid, Power Is Cut to Province in Philippines

All residential, government and corporate accounts in the province, Albay, south of Manila, lost power at noon on Tuesday. An estimated 160,000 households went dark, hospitals turned to emergency generators and much commercial activity ceased.

The Philippines has struggled for decades to reliably generate, supply and manage electricity, grappling with a welter of power companies that have merged or disappeared into others. Blackouts and cutoffs remain common in remote and poor areas.

The government has worked to make the power system more efficient through a variety of privatization measures, handing broad responsibility to the National Grid Corporation of the Philippines, created in 2008. But some local power companies have been mismanaged, troubled by corruption and burdened by disputed debt from earlier incarnations. Power supply remains unreliable in many parts of the country, and politically connected clients often leave their bills unpaid with impunity.

The National Grid Corporation, with the cooperation of the Energy Department, appears to be taking a new hard line on unpaid bills. In early July, the city of Olongapo, north of Manila, narrowly averted being disconnected over unpaid debt.

Power was restored to Albay on Wednesday at 5 p.m. after Carlos Jericho L. Petilla, the energy secretary, called an emergency meeting of national and provincial power officials, and the local power cooperative agreed to pay the overdue amount for June of about $440,000 within five days. Local officials also agreed that the 100 customers with the highest unpaid balances with the local cooperative, many of them businesses connected to local or national politicians, would remain disconnected.

Mr. Petilla said Wednesday afternoon that power to the province could be cut again if the local cooperative did not pay its bill for July by the Aug. 25 due date.

He said that a long-term solution was being sought, but that the debt was complex, having accumulated over more than two decades.

Edcel Lagman, who represents Albay Province in the Philippine House of Representatives, called the power cut a disaster.

“We are used to devastations brought about by typhoons and volcanic eruptions, but this will be the first time a man-made disaster such as this hit our province,” he said.

Local officials have proposed drawing on a provincial disaster relief fund to help pay the debt, but national officials said it was unclear if this was legal.

Veronica Moran, a worker at the Tyche Boutique Hotel in Legazpi, the provincial capital, bemoaned the disruption after the power went off on Tuesday. “The city is very dark,” she said. “This is disrupting business for everyone.” She said her hotel had had limited use of credit card machines and computers and had been able to use backup generators only part of the time.

“Our guests have been very understanding,” she said. “They know this isn’t our fault. This is the whole province.”

Daisy Armadio, who works at a diabetes clinic in Legazpi, said generators had saved the day.

“We pay our bill on time, but we are still disconnected,” she said. “This is a big problem, but we can manage.”

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Trash Into Gas, Efficiently? An Army Test May Tell

But big drawbacks have prevented the wholesale adoption of trash-to-gas technology in the United States: incineration is polluting, and the capital costs of new plants are enormous. Gasification systems can expend a tremendous amount of energy to produce a tiny amount of electricity. Up to this point, it hasn’t seemed worth the trouble.

Mike Hart thinks that he has solved those problems. In a former Air Force hangar outside Sacramento, his company, Sierra Energy, has spent the last several years testing a waste-to-energy system called the FastOx Pathfinder. The centerpiece, a waste gasifier that’s about the size of a shower stall, is essentially a modified blast furnace. A chemical reaction inside the gasifier heats any kind of trash — whether banana peels, used syringes, old iPods, even raw sewage — to extreme temperatures without combustion. The output includes hydrogen and carbon monoxide, which together are known as syngas, for synthetic gas, and  can be burned to generate electricity or made into ethanol or diesel fuel. The FastOx is now being prepared for delivery to Sierra Energy’s first customer: the United States Army.

Ethanol has long been promoted as an alternative fuel that increases energy independence, and federal law requires the use of greater amounts of it. But most ethanol in this country is produced from corn or soybeans, and many people worry that the mandate is pushing up food prices. Ethanol produced from trash — or agricultural waste, as others are trying — would allay such concerns.

Ineos Bio, a Florida company, announced last month that it had produced ethanol from gasified wood waste, using a method that it expects to be commercially viable, and KiOR Inc. will make one million to two million gallons of diesel and gasoline this year from wood waste at its plant in Columbus, Miss., according to Michael McAdams, president of the Advanced Biofuels Association. Mr. Hart said Sierra Energy’s technology should be complementary with the Florida company’s; the FastOx turns all municipal waste, not just wood scraps, into a gas that Ineos Bio could then transform into ethanol.

The FastOx gasifier is the brainchild of two former engineers at Kaiser Steel, patented by the grandson of one of them and commercialized by Mr. Hart. “It’s a modular system that can be dropped into any area,” Mr. Hart said, “using waste where it’s produced to make electricity where it’s used.” Once it’s off the ground, he said, “garbage will be a commodity.”  

From concept to construction, the story of the FastOx is of one fortuitous accident after another. And while Sierra Energy has not yet proved to be a successful company — it will be a long while before your garbage is shoveled into a FastOx — its system has become the first waste-to-energy technology acquired by the Defense Department, which paid $3 million for it through an environmental technology program. (The California Energy Commission, which supports renewable energy development in the state, also gave Sierra $5 million, to cover the portion of Sierra’s costs that the Pentagon couldn’t.)

The military is looking for ways to reduce its oil consumption, and to make it easier to supply the front lines with the fuel it uses in all its vehicles and generators. “These days, the supply lines are in the battlefield,” said Sharon E. Burke, the assistant secretary of defense for operational efficiency plans and programs. “And we consume a lot of fuel, which makes us a big target.”

MIKE HART got into the energy business by way of a train. In 1993, he bought the Sierra Railroad, a small freight and tourism line in Northern California. During the California blackouts of 2001, he had an idea: “As the lights were going out, I realized every one of my locomotives creates 2.1 megawatts of electricity,” he said — enough to power many hundred homes. “It’s a rolling generator, and inexpensive.”

The train-as-power-generator idea never really left the station, but it got Mr. Hart thinking about alternative energy. Then, as part of a settlement after a fuel spill from one of his trains, he promised to convert his trains to nonpolluting biodiesel.

Biodiesel, however, proved hard to find, and Mr. Hart started looking for new ways to source it. In 2002, he was asked to judge an annual business plan competition called the Big Bang, at the University of California, Davis. That’s where he met Chris Kasten.

Mr. Kasten came to the competition with an idea to use a modified blast furnace to turn waste into fuel. His grandfather, Bruce Claflin, a retired chief industrial engineer at Kaiser Steel in Fontana, Calif., had given him the idea.

Kaiser used blast furnaces to make steel, and Mr. Claflin and a colleague, John Jasbinsek, were tasked with finding “a way to make the blast furnace more efficient and less polluting,” said Mr. Jasbinsek, who is now 86.

Like all blast furnaces, Kaiser’s emitted a flue gas out of the top. It occurred to Mr. Clafin and Mr. Jasbinsek that this gas might have value. The two came up with the idea of injecting oxygen, instead of the atmospheric air that steel makers had always used, to create the chemical reaction that heats the inside of the furnace. This would cut pollution while raising the energy content of the flue gas — in essence, giving the steel maker a second product. But pure oxygen made the system too hot, so they added steam. This gave the furnace a third product: hydrogen, which can be used to produce electricity in fuel cells.

After Kaiser decided to close the Fontana plant in 1983, workers were told to toss all demolition debris into the blast furnace. It was then that Mr. Jasbinsek and Mr. Claflin realized that the furnace could take garbage, too. “No matter what they put in, the furnace melted and gasified it,” Mr. Kasten said. This meant a potential fourth revenue stream — from taking municipal waste that would otherwise go to landfills.

This article has been revised to reflect the following correction:

Correction: August 25, 2013

An article last Sunday about a Sierra Energy gasifier system that the Army will use to turn trash into energy referred incorrectly to a product of the system. It is hydrogen and carbon monoxide, together known as “syngas,” for synthetic gas; the system does not produce “synthetic natural gas.” The article also referred imprecisely to Fort Hunter Liggett, a training base in Monterey County, Calif. At more than 165,000 acres, it is not a “small” base.

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Cut Emissions? Congress Itself Keeps Burning a Dirtier Fuel

But just two miles from the White House stands the Capitol Power Plant, the largest single source of carbon emissions in the nation’s capital and a concrete example of the government’s inability to green its own turf.

The plant, which provides heating and cooling to the sprawling Capitol campus — 23 buildings that include the Library of Congress, the Supreme Court and Congressional office buildings, in addition to the Capitol building itself — is operated by Congress, and its transition to cleaner energy sources has been mired in national politics for years. But the failure of Congress to modernize its own facility also raises questions about the Obama administration’s ability to limit emissions from existing power plants when it has not been able to do so at a government-run facility so close to home.

The office of the architect of the Capitol, which oversees the operations of the plant, first moved to end the use of coal there in 2000 but was turned back by resistance from powerful coal-state senators who wanted to keep it as the primary fuel. The effort was revived in 2007 as a central part of the Green the Capitol Initiative, led by Nancy Pelosi, the House speaker at the time. The effort was defunded in 2011 after the Republicans took control of the House.

By then the plant had reduced the amount of coal in its fuel mix to 5 percent, down from 56 percent in 2007. But it made up the difference primarily with diesel fuel oil because, as the architect of the Capitol, Stephen T. Ayers, told a Congressional panel in 2008, converting the plant to burn natural gas exclusively would have required a modernization costing $6 million to $7 million.

At the time, the plant was spending about $2.7 million a year on fuel oil, about twice as much as it might have cost to produce the same amount of energy using natural gas. The plant remained below its capacity to burn natural gas, according to a 2010 report from the Government Accountability Office, and it continues to burn diesel fuel oil, which, in addition to being much more expensive, is a significant source of emissions.

Some critics say officials at the power plant are purposely choosing to burn dirtier fuel, as a political statement.

“We worked to figure out a way to get around the issue of coal,” said Drew Hammill, a spokesman for Ms. Pelosi. “But it is a futile effort until you get rid of the Republican majority. They do not believe in the word ‘green.’ ”

A review of public records and interviews with city and federal officials suggest that the root of the problem is a lack of enforcement by regulators and insufficient oversight from Congress.

Although the power plant is required to submit emissions reports to the District of Columbia’s Department of the Environment, which coordinates enforcement with the Environmental Protection Agency, and to apply for operation permits for new devices, records show that both agencies have failed to ensure that the power plant is in compliance.

E.P.A. officials with jurisdiction over the plant said that the agency did not have the capacity to inspect all facilities that got operating permits under the Clean Air Act, and that it relied heavily on partners like state and local energy agencies to make sure facilities were in compliance with their permits.

But district records show that the city has regularly failed to ensure that the plant is operating legally. In 2011, members of the city agency’s Air Quality Division discovered that one of the plant’s main boilers had exceeded the 10 ton-per-year limit for nitrogen oxides, which can cause severe breathing difficulties, by more than 20 tons per year since 2000.

“Emissions limits are meaningless if there is not adequate testing to ensure that they are being met,” Mike Ewall, the founder and director of the Energy Justice Network, a grass-roots organization advocating clean energy, wrote in a Feb. 13 letter to the city agency.

Donna Henry, a spokeswoman for the city environment agency, said the city had had difficulties finding records to clarify the plant’s emission history.

The chairmen and the ranking members of the House and Senate committees that oversee the power plant declined to comment, as did the office of the architect of the Capitol, often referred to as A.O.C.

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On Rooftops, a Rival for Utilities

Alarmed by what they say has become an existential threat to their business, utility companies are moving to roll back government incentives aimed at promoting solar energy and other renewable sources of power. At stake, the companies say, is nothing less than the future of the American electricity industry.

According to the Energy Information Administration, rooftop solar electricity — the economics of which often depend on government incentives and mandates — accounts for less than a quarter of 1 percent of the nation’s power generation.

And yet, to hear executives tell it, such power sources could ultimately threaten traditional utilities’ ability to maintain the nation’s grid.

“We did not get in front of this disruption,” Clark Gellings, a fellow at the Electric Power Research Institute, a nonprofit arm of the industry, said during a panel discussion at the annual utility convention last month. “It may be too late.”

Advocates of renewable energy — not least solar industry executives who stand to get rich from the transformation — say such statements are wildly overblown. For now, they say, the government needs to help make the economics of renewable power work for ordinary Americans. Without incentives, the young industry might wither — and with it, their own potential profits.

The battle is playing out among energy executives, lawmakers and regulators across the country.

In Arizona, for example, the country’s second-largest solar market, the state’s largest utility is pressuring the Arizona Corporation Commission, which sets utility rates, to reconsider a generous residential credit and impose new fees on customers, months after the agency eliminated a commercial solar incentive. In North Carolina, Duke Energy is pushing to institute a new set of charges for solar customers as well.

Nowhere, though, is the battle more heated than in California, home to the nation’s largest solar market and some of the most aggressive subsidies. The outcome has the potential to set the course for solar and other renewable energies for decades to come.

At the heart of the fight is a credit system called net metering, which pays residential and commercial customers for excess renewable energy they sell back to utilities. Currently, 43 states, the District of Columbia and 4 territories offer a form of the incentive, according to the Energy Department.

Some keep the credit in line with the wholesale prices that utilities pay large power producers, which can be a few cents a kilowatt-hour. But in California, those payments are among the most generous because they are tied to the daytime retail rates customers pay for electricity, which include utility costs for maintaining the grid.

California’s three major utilities estimate that by the time the subsidy program fills up under its current limits, they could have to make up almost $1.4 billion a year in revenue lost to solar customers, and shift that burden to roughly 7.6 million nonsolar customers — an extra $185 a year if evenly spread. Some studies cited by solar advocates have shown, though, that the credit system can result in a net savings for the utilities.

Utilities in California have appealed to lawmakers and regulators to reduce the credits and limit the number of people who can participate. It has been an uphill fight.

About a year ago, the utilities pushed regulators to keep the amount of rooftop solar that would qualify for the net metering program at a low level; instead, regulators effectively raised it. Still, the utilities won a concession from the Legislature, which ordered the California Public Utilities Commission to conduct a study to determine the costs and benefits of rooftop solar to both customers and the power grid with an eye toward retooling the policy.

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Battery Seen as Way to Cut Heat-Related Power Losses

Such disruptions have plagued utilities for years: how do they keep extra electricity on hand and ready to go, avoiding the need to cut the voltage in stressed neighborhoods and lowering the risk of blackouts?

Now, several utilities, including Con Edison, National Grid and the large European utilities Enel and GDF SUEZ, have signed up to fine-tune and test what they hope could lead to an answer — a battery half the size of a refrigerator from Eos Energy Storage, the company said Tuesday. If the testing goes well, the batteries hold the promise of providing storage that until now has been unaffordable on a large scale.

“Energy storage is no longer an idea and a theory — it’s actually a practical reality,” said Steve Hellman, Eos’s president. “You’re seeing a lot of commercial activity in the energy storage sector.”

Part of the appeal is economic: utilities could buy power from centralized plants during off-peak hours, when it is cheaper, and use it to feed the grid at peak hours when it is typically more expensive. That could also relieve congestion on some transmission lines, reducing strain and the need to spend money upgrading or repairing them. In addition, batteries could help integrate more renewable sources like solar and wind into the power grid, smoothing out their intermittent production.

“Energy storage in general has been kind of a holy grail for utilities — a lot of the generation and demand is instantaneous,” said Joseph Carbonara, project manager in research and development at Con Edison, who is managing the Eos program. “The utilities have always been looking to buffer that.”

Utilities and institutions across the country, many with grants from federal or state energy departments, are testing energy storage technologies. Con Edison and the City University of New York are using a different zinc-based battery from Urban Electric Power to help reduce the school’s peak energy use as part of a New York State Energy Research and Development Authority program. In California, Pacific Gas and Electric is studying sodium-sulfur batteries that can store more than six hours of energy. And Duke Energy is working with lead acid batteries from Xtreme Power that are linked to a wind farm in Texas.

At the same time, there are a host of start-ups racing to develop different technologies for a wide range of applications, and already there are some large-scale batteries tied to the grid. But the technology has generally proved too expensive for widespread adoption.

Eos says it has gotten around that problem. Its battery relies on zinc, a relatively plentiful and cheap element. The company projects that its cost will be $160 a kilowatt-hour, and that it would provide electricity cheaper than a new gas power plant built to help fulfill periods of high demand, Eos executives said. Other battery technologies can range from $400 to about $1,000 a kilowatt-hour.

“They’ve got a cost factor that makes it economically viable to use their batteries,” said Troy DeVries, director of research and development at Con Edison. He added that the batteries did not contain toxic chemicals, making them more appealing for use in a congested city like New York.

In recent years, utilities have had to find creative ways to contend with surging demand during heat waves. Con Edison, for instance, has used generators to support electric substations and, from its central command station, has shut off central air-conditioning units in thousands of homes and businesses. The utility has even canceled Little League night games in Staten Island to save the energy that the field lights would use.

The battery project is still in its early stages, with the company collaborating with each utility to complete its prototypes with an aim of having some up and running next year.

Eos plans to work with the utilities to test small-scale versions of the batteries and how they connect to different power grid systems. The eventual goal would be to develop a battery the size of a cargo container for use on a commercial scale.

Testing on a small scale is necessary, said Michael Oster, the Eos chief executive, because the companies are trying to sell a new technology to a traditionally conservative industry.

“We’re getting that industry involved early — we’re understanding their pain and understanding their needs and getting them comfortable with the technology,” Mr. Oster said. “They need it badly enough that they’re willing to take the risks but also to join in mitigating those risks with others.”

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As Worries Over the Power Grid Rise, a Drill Will Simulate a Knockout Blow

This is why thousands of utility workers, business executives, National Guard officers, F.B.I. antiterrorism experts and officials from government agencies in the United States, Canada and Mexico are preparing for an emergency drill in November that will simulate physical attacks and cyberattacks that could take down large sections of the power grid.

They will practice for a crisis unlike anything the real grid has ever seen, and more than 150 companies and organizations have signed up to participate.

“This is different from a hurricane that hits X, Y and Z counties in the Southeast and they have a loss of power for three or four days,” said the official in charge of the drill, Brian M. Harrell of the North American Electric Reliability Corporation, known as NERC. “We really want to go beyond that.”

One goal of the drill, called GridEx II, is to explore how governments would react as the loss of the grid crippled the supply chain for everyday necessities.

“If we fail at electricity, we’re going to fail miserably,” Curt Hébert, a former chairman of the Federal Energy Regulatory Commission, said at a recent conference held by the Bipartisan Policy Center.

Mr. Harrell said that previous exercises were based on the expectation that electricity “would be up and running relatively quick” after an attack.

Now, he said, the goal is to “educate the federal government on what their expectations should or shouldn’t be.” The industry held a smaller exercise two years ago in which 75 utilities, companies and agencies participated, but this one will be vastly expanded and will be carried out in a more anxious mood.

Most of the participants will join the exercise from their workplaces, with NERC, in Washington, announcing successive failures. One example, organizers say, is a substation break-in that officials initially think is an attempt to steal copper. But instead, the intruder uses a USB drive to upload a virus into a computer network.

The drill is part of a give-and-take in the past few years between the government and utilities that has exposed the difficulties of securing the electric system.

The grid is essential for almost everything, but it is mostly controlled by investor-owned companies or municipal or regional agencies. Ninety-nine percent of military facilities rely on commercial power, according to the White House.

The utilities play down their abilities, in comparison with the government’s. “They have the intelligence operation, the standing army, the three-letter agencies,” said Scott Aaronson, senior director of national security policy at the Edison Electric Institute, the trade association of investor-owned utilities. “We have the grid operations expertise.”

That expertise involves running 5,800 major power plants and 450,000 miles of high-voltage transmission lines, monitored and controlled by a staggering mix of devices installed over decades. Some utilities use their own antique computer protocols and are probably safe from hacking — what the industry calls “security through obscurity.”

But others rely on Windows-based control systems that are common to many industries. Some of them run on in-house networks, but computer security experts say they are not confident that all the connections to the public Internet have been discovered and secured. Many may be vulnerable to software — known as malware — that can disable the systems or destroy their ability to communicate, leaving their human operators blind about the positions of switches, the flows of current and other critical parameters. Experts say a sophisticated hacker could also damage hard-to-replace equipment.

In an effort to draw utilities and the government closer, the industry recently established the Electricity Sub-Sector Coordinating Council, made up of high-level executives, to meet with federal officials. The first session is next month.

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Appeals Court Blocks Attempt by Vermont to Close a Nuclear Plant

“The nuclear power industry has just been delivered a tremendous victory against the attempt by any state to shut down federally regulated nuclear power plants,” said Kathleen Sullivan, a lawyer for Entergy, which owns Vermont Yankee.

The court found that states are “pre-empted” from regulating safety by the Atomic Energy Act of 1946, which made safety a federal responsibility. The Legislature had sought to shut the plant by denying Entergy a “certificate of public good” that is required for all power plants. But the court said Vermont was unpersuasive when it said that the reasons for the denial were that the reactor was too costly and unreliable, and that closing it would encourage the development of renewable energy from wind or wood.

In hearings and floor debate, Vermont legislators referred often to the idea that they could not legislate over the safety of the plant, which is on the Connecticut River near the Massachusetts border, and would have to find other reasons to close it.

“Vermont tried to escape the prohibition by saying, ‘Oh, no, we were really trying to encourage energy diversity,’ ” Ms. Sullivan said.

The court also found that because the reactor operated in a competitive market for electricity, Vermont could not close it because it was too expensive.

The appeals court struck down one finding by the lower court, related to the Constitution’s interstate commerce clause, that would have given Entergy the ability to seek reimbursement from Vermont for its legal costs.

The state has not decided whether to appeal, said Christopher Recchia, the commissioner of the Vermont Public Service Department, which represents consumers before the body that regulates electricity rates. It has also not yet issued the “certificate of public good,” he said.

“We’re still moving forward, and obviously we have been focusing on the areas that the state does have jurisdiction over,” he said, including environmental issues and the economic impact of employment at the plant.

Sandra Levine, a senior lawyer at the Conservation Law Foundation, a nonprofit group that entered the case as an ally of the state, said the court should not have looked at what motivated the lawmakers.

“The legislation speaks for itself,” she said.

But because the appellate judges reaffirmed the ability of courts to examine the record and divine the real reasons for state actions, it could be relevant in New York, where the governor, Andrew M. Cuomo, is seeking to close the Indian Point reactors, which are also owned by Entergy, on the Hudson River in Westchester County.

New York is appearing before the Nuclear Regulatory Commission on whether the two operating reactors there should be allowed 20-year extensions to their initial 40-year operating licenses. But it is also seeking to close the plants by imposing new limits on the use of water from the Hudson.

Other states have made it difficult for reactors to build additional storage for their nuclear waste; several have banned the construction of reactors until the nuclear waste problem is resolved.

While the court decision on Wednesday appears to keep Vermont Yankee safe from local political pressure, financial analysts say that it and other reactors have become far less profitable because the price they get for their electricity has fallen.

Entergy recently announced that it would cut 30 jobs, out of 650, at Vermont Yankee by the end of the year.

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New Tools for Keeping the Lights On

Now, a decade after the largest blackout in American history, engineers are installing and linking 1,000 of those instruments, called phasor measurement units, to try to prevent another catastrophic power failure. When the work is done, the engineers say, they will have a diagnostic tool that makes the old system seem like taking a patient’s pulse compared with running a continuous electrocardiogram.

Gilbert C. Bindewald III, a program manager at the Energy Department, which has spent about $200 million to encourage their installation, said the instruments were “shedding light on the science that’s occurring behind the scenes, within the grid.”

Phasor measurement units work by measuring the rhythm of current at different points on the power grid. Readings at every point within each of the three North American grids — one covering the eastern two-thirds of North America, one covering the West, and one covering Texas — are supposed to be basically the same. If the measurements differ, it can be a sign of imminent collapse. When the current is flowing properly, phasor measurement units record normal readings — about as exciting as “watching paint dry,” in the words of Peter K. Lemme, a senior electrical engineer at the New York Independent System Operator, which runs New York’s grid. As Mr. Lemme spoke, he looked at a real-time display of phasor measurement units across the state.

But then he replayed New York records from an afternoon three weeks ago when a capacitor, a device that helps maintain voltage, suddenly failed at a substation near Utica. In response, measurements taken at an electrical substation near Rochester registered an enormous shock on a graph. In Leeds, south of Albany, the disruption was considerably milder. The disturbance gradually petered out, like a playground swing that slowly comes to rest.

If that glitch had been large enough to threaten a statewide power failure, the new devices could have alerted the engineers to the impending crisis and given them time to react, for example, by shutting down a part of the system to avoid cascading power failures. Tracy A. Flippo, the vice president for transmission operations at the Tennessee Valley Authority, said the devices could provide “precursor information” before a collapse.

The hope is that they could help prevent or at least limit a large-scale blackout like the one that happened a decade ago.

In 2003, as northern Ohio ran short of generation and transmission because of a combination of neglect, mismanagement and human error, circuit breakers took major transmission lines out of service. The power failure then cascaded across 600 miles, eight states and Canada. New York, Cleveland and Detroit went dark, as did Toronto and sections of New Jersey, Pennsylvania, Connecticut and Massachusetts. In New York office buildings were evacuated, thousands of commuters were stranded, and hospitals were flooded with patients suffering in the stifling heat.

“Somebody in Ohio could have recognized that we either need to raise generation or shed load,” said Richard Dewey, senior vice president of the New York Independent System Operator. Or, he said, New York could have seen trouble coming and insulated itself. The two units scrutinized after the blackout, one in Detroit and one in Cleveland, showed the strain.

Other changes to the grid should help, too. The federal government, for example, has given an industry group the authority to set standards. That group, the North American Electric Reliability Corporation, has levied substantial fines against companies that failed in tasks like trimming trees or testing equipment. Untrimmed trees and improper procedures for testing equipment have caused widespread power failures in recent years.

Joel deJesus, a former director of compliance enforcement at the corporation, said that in his view the large fines had been effective. “Wrists have been slapped pretty hard,” he said.

The network of phasor measurement units offers a technological advantage.

So far hundreds of phasor measurement units have been installed across the country, including 48 in New York.

Before then, the operators of the New York grid had only scattered data points within the state. For years they have been mostly blind to the grid outside New York, receiving only a few readings from devices at the borders with New England, Quebec, Ontario, and a region that includes Pennsylvania, New Jersey and Maryland.

But by the end of 2014, officials at the Energy Department said, they anticipate that all 1,000 phasor measurement units will be in operation and linked to one another. The next step, they said, was to figure out how to better present the flood of data to human operators in a useful way.

“The question is, How do we cue them to an event that a computer might be able to see coming?” said Mr. Bindewald of the Energy Department. Initially data will be integrated into computer displays, and later it may be used to set off automatic protective actions that would prevent or limit blackouts.

Experts argue that such a system could easily pay for itself. The 2003 blackout cost billions of dollars in lost economic output.

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An Inventor Wants One Less Wire to Worry About

“It was my last year to do it,” she told me, “so I literally would just carry around a notebook and write down any annoyances, because that would be an opportunity to solve a problem and have an invention.” An admitted “professional Googler,” she’d been researching all day on her computer when she decided to pack it in for the night.

“I was just standing in my room,” she said, “wrapping up my laptop charger and trying to fit it into my bag and suddenly it occurred to me: Wow, this is so archaic. Why are we using these 20-foot wires to plug in our quote-unquote wireless devices?”

“See past old paradigms” is one of those cheesy riffs one might hear from an innovation expert working the business speakers’ circuit. Yet here it was, a question that inched just past what was simply accepted: Why, in a wireless age, do we still have electrical wires?

As Ms. Perry soon learned, there are very good reasons that we don’t beam electricity through the air. Though you can transmit the entire electromagnetic spectrum, from radio waves to gamma rays, there are problems. “I realized that anything on the right half of the spectrum was too dangerous to beam,” she said, “and anything on the left half of the spectrum that was closer to radio was either too inefficient or tightly regulated by the government.”

So she started looking elsewhere and came upon piezoelectricity — a form of charge that is created in certain crystals and ceramics when vibrated. If you have seen Internet assertions about T-shirts “that charge your mobile phone while you wear them,” or about boots on the ground literally creating the charge for a soldier’s radio, you are familiar with the idea of piezoelectricity. Those applications rely on something that’s already in motion.

And here’s where the second eureka happened — enabling her to see how she might build a device to wirelessly charge a battery in a cellphone or a computer from across a room.

“How do I create vibration in the air without actually moving something?” The answer came instantly — it was almost like a stoner’s aha: “Sound is vibration in the air.”

Sound frequency “is basically how many cycles per second air is being pushed through a space,” Ms. Perry says. “We have little hairs in our ears that vibrate in response to sound. We interpret that change in air pressure as sound. But sound is something that exists outside of our head. Literally, it’s just air particles moving in an arranged fashion.” So was it possible to deploy sound waves that humans couldn’t hear or feel, in order to charge a phone?

Nothing in her training prepared her for this kind of research. She was an astrobiologist, after all. She was just 21 and had spent the previous two summers interning at NASA.

So she did what most everybody else does. She clicked on Wikipedia. She started with the “ultrasound” page, then “acoustic.” Soon enough, she was reading academic papers at the forefront of various disciplines.

Her idea, she discovered, meant marrying the fields of sound, electricity, battery technology and other subspecialties. “It was such a multidisciplinary idea,” she said, “and everyone in each different department basically told me that there was basically no way that you could get past all the hurdles.”

She kept running into the same genre of problem. “I was working with a couple of different people at the beginning who would say there was no way to get this high-power sound over this distance without creating shock waves,” she said. “Of course, I would have my 10-minute panic attack and think the whole thing was over. Then I would do some research on my own, and figure out how to achieve high-power sound without creating shock waves.”

Afterward, she said, “I would go back to that person and he would say, ‘Oh, yeah, that should work.’ ” Each expert seemed to dwell in his own private silo, so that whenever she crossed from one discipline to another, she would run into the same wall of constricted thinking.

Even after winning attention at a D: All Things Digital conference, where she transmitted power an impressive three feet using piezoelectrical technology, she still couldn’t attract start-up money.

“After being rejected by literally hundreds of investors — maybe not hundreds, maybe not literally — but lots of investors,” she said, she decided to research who had financed “crazy things,” and wound up gaining the attention of Peter Thiel, the former PayPal entrepreneur whose Founders Fund provides venture capital for unusual ideas.

The Idea will offer an occasional look at the origin of business notions.

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Intermittent Nature of Green Power Is Challenge for Utilities

Except when they aren’t allowed to spin at their fastest. That has been the case several times in the farm’s short existence, including during the record July heat wave when it could have produced enough much-needed energy to fuel a small town. Instead, the grid system operator held it at times to just one-third of what it could have produced.

“We were being told to turn on diesel-fired units that are very expensive and dirty and told to ramp down what is renewable, cost-effective energy for our customers,” said Mary Powell, chief executive of Green Mountain Power, the utility that owns and operates the wind plant. “We should go with the sources that can have the highest value, especially during peak times.”

It is not the first time the grid system operator, ISO New England, which operates in six states, has cut back energy from the farm since it began operating at the end of last year, or from others in the region, including some in Maine and New Hampshire. Other windy states and regions like Texas and the Midwest have experienced similar cutbacks, known as curtailments.

But the recent Vermont episode, which set off a debate among government officials, the New England grid executives and the wind farm producers, highlights a broader struggle taking place across the country as utilities increasingly turn to renewable sources of energy. Because energy produced by wind, for example, is intermittent, its generating capacity is harder to predict than conventional power’s. And a lack of widely available, cost-effective ways to store electricity generated by wind only compounds the complex current marketplace.

Moreover, although the wind industry has been growing for decades, it is still relatively new at operating large-scale wind farms, so it is often only once a farm is up and running that some of the problems emerge, developers say.

And those problems are likely to grow. Last year, wind power was the most prevalent source of new energy capacity — 43 percent of overall generation installed — while its price neared an all-time low, according to a recent report for the Department of Energy by Lawrence Berkeley National Laboratory.

A number of factors can trigger curtailments in wind output, including reducing the danger to bats or birds flying around the spinning blades. But more commonly, regional grid managers, who must match demand and supply instantaneously, call for a reduction in wind power when more energy is produced than the system can safely transport, they say.

Indeed, in New England in recent months, the grid system operator has cut back power from wind and hydroelectric plants several times, generally, its representatives say, because they were making too much electricity. New wind farms are frequently located in sparsely populated areas or along mountain ridges where there has not been a need for transmission lines with a robust carrying capacity, officials say.

In addition, it is more difficult to properly synchronize wind’s fluctuating power flow with a system built for the steadier electric stream that fossil fuel plants tend to produce.

“As these wind turbines are built and interconnected, they’re interconnecting to local transmission lines, and for the most part they can produce electricity and inject it onto the system,” said Ellen Foley, a spokeswoman for the grid operator. “But there may be occasions where they may have to be backed down or curtailed because of the limitations of the line — it’s literally the size of the line.”

The fear, she said, is that a surge in energy could overload and shut down the wires, leading to a drop in voltage on the system that could spread blackouts through the region and to other parts of the country.

This article has been revised to reflect the following correction:

Correction: August 21, 2013

An article on Thursday about challenges affecting renewable energy producers misstated the estimated costs to the Vermont Electric Cooperative under production curtailments at the Kingdom Community Wind farm, ordered by ISO New England, the area’s electric grid operator. The cooperative estimated that the curtailments would cost the cooperative about $1.5 million this year; the estimate did not apply to last winter.

The article also misstated, using information provided by the cooperative, the ownership structure of Kingdom Community Wind. It is owned by Green Mountain Power; it is not “co-owned” by Vermont Electric Cooperative, which shares in the cost of running the wind farm.

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Cut Emissions? Congress Itself Keeps Burning a Dirtier Fuel

But just two miles from the White House stands the Capitol Power Plant, the largest single source of carbon emissions in the nation’s capital and a concrete example of the government’s inability to green its own turf.

The plant, which provides heating and cooling to the sprawling Capitol campus — 23 buildings that include the Library of Congress, the Supreme Court and Congressional office buildings, in addition to the Capitol building itself — is operated by Congress, and its transition to cleaner energy sources has been mired in national politics for years. But the failure of Congress to modernize its own facility also raises questions about the Obama administration’s ability to limit emissions from existing power plants when it has not been able to do so at a government-run facility so close to home.

The office of the architect of the Capitol, which oversees the operations of the plant, first moved to end the use of coal there in 2000 but was turned back by resistance from powerful coal-state senators who wanted to keep it as the primary fuel. The effort was revived in 2007 as a central part of the Green the Capitol Initiative, led by Nancy Pelosi, the House speaker at the time. The effort was defunded in 2011 after the Republicans took control of the House.

By then the plant had reduced the amount of coal in its fuel mix to 5 percent, down from 56 percent in 2007. But it made up the difference primarily with diesel fuel oil because, as the architect of the Capitol, Stephen T. Ayers, told a Congressional panel in 2008, converting the plant to burn natural gas exclusively would have required a modernization costing $6 million to $7 million.

At the time, the plant was spending about $2.7 million a year on fuel oil, about twice as much as it might have cost to produce the same amount of energy using natural gas. The plant remained below its capacity to burn natural gas, according to a 2010 report from the Government Accountability Office, and it continues to burn diesel fuel oil, which, in addition to being much more expensive, is a significant source of emissions.

Some critics say officials at the power plant are purposely choosing to burn dirtier fuel, as a political statement.

“We worked to figure out a way to get around the issue of coal,” said Drew Hammill, a spokesman for Ms. Pelosi. “But it is a futile effort until you get rid of the Republican majority. They do not believe in the word ‘green.’ ”

A review of public records and interviews with city and federal officials suggest that the root of the problem is a lack of enforcement by regulators and insufficient oversight from Congress.

Although the power plant is required to submit emissions reports to the District of Columbia’s Department of the Environment, which coordinates enforcement with the Environmental Protection Agency, and to apply for operation permits for new devices, records show that both agencies have failed to ensure that the power plant is in compliance.

E.P.A. officials with jurisdiction over the plant said that the agency did not have the capacity to inspect all facilities that got operating permits under the Clean Air Act, and that it relied heavily on partners like state and local energy agencies to make sure facilities were in compliance with their permits.

But district records show that the city has regularly failed to ensure that the plant is operating legally. In 2011, members of the city agency’s Air Quality Division discovered that one of the plant’s main boilers had exceeded the 10 ton-per-year limit for nitrogen oxides, which can cause severe breathing difficulties, by more than 20 tons per year since 2000.

“Emissions limits are meaningless if there is not adequate testing to ensure that they are being met,” Mike Ewall, the founder and director of the Energy Justice Network, a grass-roots organization advocating clean energy, wrote in a Feb. 13 letter to the city agency.

Donna Henry, a spokeswoman for the city environment agency, said the city had had difficulties finding records to clarify the plant’s emission history.

The chairmen and the ranking members of the House and Senate committees that oversee the power plant declined to comment, as did the office of the architect of the Capitol, often referred to as A.O.C.

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Appeals Court Blocks Attempt by Vermont to Close a Nuclear Plant

“The nuclear power industry has just been delivered a tremendous victory against the attempt by any state to shut down federally regulated nuclear power plants,” said Kathleen Sullivan, a lawyer for Entergy, which owns Vermont Yankee.

The court found that states are “pre-empted” from regulating safety by the Atomic Energy Act of 1946, which made safety a federal responsibility. The Legislature had sought to shut the plant by denying Entergy a “certificate of public good” that is required for all power plants. But the court said Vermont was unpersuasive when it said that the reasons for the denial were that the reactor was too costly and unreliable, and that closing it would encourage the development of renewable energy from wind or wood.

In hearings and floor debate, Vermont legislators referred often to the idea that they could not legislate over the safety of the plant, which is on the Connecticut River near the Massachusetts border, and would have to find other reasons to close it.

“Vermont tried to escape the prohibition by saying, ‘Oh, no, we were really trying to encourage energy diversity,’ ” Ms. Sullivan said.

The court also found that because the reactor operated in a competitive market for electricity, Vermont could not close it because it was too expensive.

The appeals court struck down one finding by the lower court, related to the Constitution’s interstate commerce clause, that would have given Entergy the ability to seek reimbursement from Vermont for its legal costs.

The state has not decided whether to appeal, said Christopher Recchia, the commissioner of the Vermont Public Service Department, which represents consumers before the body that regulates electricity rates. It has also not yet issued the “certificate of public good,” he said.

“We’re still moving forward, and obviously we have been focusing on the areas that the state does have jurisdiction over,” he said, including environmental issues and the economic impact of employment at the plant.

Sandra Levine, a senior lawyer at the Conservation Law Foundation, a nonprofit group that entered the case as an ally of the state, said the court should not have looked at what motivated the lawmakers.

“The legislation speaks for itself,” she said.

But because the appellate judges reaffirmed the ability of courts to examine the record and divine the real reasons for state actions, it could be relevant in New York, where the governor, Andrew M. Cuomo, is seeking to close the Indian Point reactors, which are also owned by Entergy, on the Hudson River in Westchester County.

New York is appearing before the Nuclear Regulatory Commission on whether the two operating reactors there should be allowed 20-year extensions to their initial 40-year operating licenses. But it is also seeking to close the plants by imposing new limits on the use of water from the Hudson.

Other states have made it difficult for reactors to build additional storage for their nuclear waste; several have banned the construction of reactors until the nuclear waste problem is resolved.

While the court decision on Wednesday appears to keep Vermont Yankee safe from local political pressure, financial analysts say that it and other reactors have become far less profitable because the price they get for their electricity has fallen.

Entergy recently announced that it would cut 30 jobs, out of 650, at Vermont Yankee by the end of the year.

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Intermittent Nature of Green Power Is Challenge for Utilities

Except when they aren’t allowed to spin at their fastest. That has been the case several times in the farm’s short existence, including during the record July heat wave when it could have produced enough much-needed energy to fuel a small town. Instead, the grid system operator held it at times to just one-third of what it could have produced.

“We were being told to turn on diesel-fired units that are very expensive and dirty and told to ramp down what is renewable, cost-effective energy for our customers,” said Mary Powell, chief executive of Green Mountain Power, the utility that owns and operates the wind plant. “We should go with the sources that can have the highest value, especially during peak times.”

It is not the first time the grid system operator, ISO New England, which operates in six states, has cut back energy from the farm since it began operating at the end of last year, or from others in the region, including some in Maine and New Hampshire. Other windy states and regions like Texas and the Midwest have experienced similar cutbacks, known as curtailments.

But the recent Vermont episode, which set off a debate among government officials, the New England grid executives and the wind farm producers, highlights a broader struggle taking place across the country as utilities increasingly turn to renewable sources of energy. Because energy produced by wind, for example, is intermittent, its generating capacity is harder to predict than conventional power’s. And a lack of widely available, cost-effective ways to store electricity generated by wind only compounds the complex current marketplace.

Moreover, although the wind industry has been growing for decades, it is still relatively new at operating large-scale wind farms, so it is often only once a farm is up and running that some of the problems emerge, developers say.

And those problems are likely to grow. Last year, wind power was the most prevalent source of new energy capacity — 43 percent of overall generation installed — while its price neared an all-time low, according to a recent report for the Department of Energy by Lawrence Berkeley National Laboratory.

A number of factors can trigger curtailments in wind output, including reducing the danger to bats or birds flying around the spinning blades. But more commonly, regional grid managers, who must match demand and supply instantaneously, call for a reduction in wind power when more energy is produced than the system can safely transport, they say.

Indeed, in New England in recent months, the grid system operator has cut back power from wind and hydroelectric plants several times, generally, its representatives say, because they were making too much electricity. New wind farms are frequently located in sparsely populated areas or along mountain ridges where there has not been a need for transmission lines with a robust carrying capacity, officials say.

In addition, it is more difficult to properly synchronize wind’s fluctuating power flow with a system built for the steadier electric stream that fossil fuel plants tend to produce.

“As these wind turbines are built and interconnected, they’re interconnecting to local transmission lines, and for the most part they can produce electricity and inject it onto the system,” said Ellen Foley, a spokeswoman for the grid operator. “But there may be occasions where they may have to be backed down or curtailed because of the limitations of the line — it’s literally the size of the line.”

The fear, she said, is that a surge in energy could overload and shut down the wires, leading to a drop in voltage on the system that could spread blackouts through the region and to other parts of the country.

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What were the key energy commodity price trends in 2012?

Last Updated: January 18, 2013

Energy commodity price trends varied widely during 2012. This article provides an overview of key energy commodity price trends in 2012.

Source: U.S. Energy Information Administration based on Bloomberg, L.P.
Note: Price changes are derived by taking the difference in prompt contract price for each commodity between January 1 and December 31, 2012. This method allows for comparisons of different commodity classes on a consistent basis. PRB Coal is Powder River Basin Coal. CAPP Coal is Central Appalachia Coal. WTI is West Texas Intermediate, a benchmark for both physical and financial crude oil pricing located in Cushing, Oklahoma. RBOB Gasoline is a kind of gasoline based on a reformulated blendstock for oxygenate blending (RBOB).

Coal and mid-continent crude oil (WTI) led energy commodity price declines in 2012. Natural gas was the only key energy commodity with a significant price increase when comparing January 1 to December 31. Heating oil, Brent crude oil, and wholesale gasoline (RBOB) ended 2012 close to the level at which they started the year(see graphs, right side).

In 2012, average prices for crude oil and petroleum products were largely close to the 2011 averages, with some fluctuations throughout the year. Natural gas prices declined through the early portion of 2012 but then increased in the early fall and winter. Prices for Central Appalachian (CAPP) and Powder River Basin (PRB) coal declined at the beginning of 2012 and remained significantly below the average levels of 2011.

This article provides an overview of a series of related articles (see Today in Energy, 2012 Briefs) on energy market trends in 2012. To ensure comparability among commodities, the prices shown here reflect near-month contracts of futures prices. Most other articles in this series focused on spot market trends. Some key findings from these articles include:

Crude oil and petroleum products

Brent crude oil averaged $111.67 per barrel in 2012, edging past last year's average price of $111.26 per barrel and marking the second year in a row that the global oil benchmark averaged more than $100 per barrel.West Texas Intermediate crude oil averaged $94.05 per barrel in 2012, down slightly from $94.88 in 2011. The annual average price gap between Brent and WTI reached $17.61 per barrel, up from the 2011 level of $16.38.The national weekly average pump prices for gasoline and diesel fuel during 2012 set record highs of $3.62 and $3.97 per gallon, respectively, and marked the second year in a row that the average price for either transportation fuel failed to drop below $3 per gallon during any week.

See related article – Today in Energy, January 10, 2013 and January 11, 2013

Natural Gas

Average, spot natural gas prices were lower compared to 2011, however both futures and spot prices increased in the latter half of the year.Natural gas prices were generally uniform across the country, except when residential and commercial demand peaked during the colder winter months. During these periods, pipeline constraints into the Northeastern United States led to increased separation of the average natural gas wholesale (spot) prices at major hubs in New England and New York above the average spot price at Henry Hub.

See related article – Today in Energy, January 8, 2013

Electricity

Average, spot, on-peak wholesale electricity prices were lower across the United States and largely followed the trend in natural gas prices. Several short-term price spikes occurred during the summer months in several U.S. regions as electric demand increased to meet summer air-conditioning load.

See related article – Today in Energy, January 9, 2013

Coal

Wholesale (spot) coal prices across all basins fell during the first half of 2012, with steep declines in Powder River Basin (PRB) and Eastern basins, before stabilizing in the latter half of the year.Record exports of both thermal and metallurgical coal helped offset declines in consumption in the power sector.

See related article – Today in Energy, January 14, 2013

Natural Gas Liquids

Daily spot prices for natural gas liquids (NGL)–ethane, propane, normal butane, isobutane, and natural gasoline–were generally down in 2012. Ethane and propane, the lower-priced NGL, experienced the largest percentage declines relative to 2011 average prices. Prices for natural gasoline, isobutane, and normal butane more closely track oil prices.

See related article – Today in Energy, January 15, 2013

A futures market is a trade center for quoting prices on contracts for the delivery of a specified quantity of a commodity at a specified time and place in the future. Futures markets reflect price expectations rather than current prices. The 'near-month contract' reflects the most immediate price expectation.

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How old are U.S. power plants?

Last Updated: March 05, 2013

The current fleet of electric power generators has a wide range of ages. About 540 gigawatts, or 51% of all generating capacity, were at least 30 years old at the end of 2012. Trends in generating capacity additions vary by fuel type.1

Source: U.S. Energy Information Administration, Form EIA-860 Annual Electric Generator Report, and Form EIA-860M (see Tables ES3 and ES4 in the January 2013 Electric Power Monthly)
Note: Data for 2012 are preliminary. Existing generators with online dates earlier than 1930 are predominantly hydroelectric. Data include non-retired plants existing as of year-end 2012; retired generators are excluded. This chart shows the most recent (summer) capacity data for each generator. However, this number may change over time, if a generator undergoes an uprate or derate.

The current fleet of electric power generators has a wide range of ages. The Nation's oldest power plants tend to be hydropower generators.

Most coal-fired plants were built before 1980.There was a wave of nuclear plant construction from the late 1960s to about 1990.The most recent waves of generating capacity additions include natural gas-fired units in the 2000s and renewable units, primarily wind, coming online in the late 2000s.

About 540 GW, or 51% of all generating capacity, were at least 30 years old at the end of 2012 (see chart below). Most gas-fired capacity is less than 20 years old, while 74% of all coal-fired capacity was 30 years old or older at the end of 2012. Companies routinely undertake capital improvement projects to extend the life of their generating capacity. The 'other' category includes solar, biomass, and geothermal generators, as well as landfill gas, municipal solid waste, and a variety of small-magnitude fuels such as byproducts from industrial processes (e.g., black liquor, blast furnace gas).

Learn more about trends in generating capacity additions by fuel type in the following articles:

Coal – Today in Energy, June 28, 2011Nuclear – Today in Energy, June 30, 2011Natural Gas – Today in Energy, July 5, 2011Hydropower – Today in Energy, July 8, 2011Wind – Today in Energy, July 13, 2011Oil – Today in Energy, July 18, 2011
1 This article is based on EIA's, June 16, 2011, Today in Energy article, and was updated in February 2013 to reflect data through 2012..

24 out of the Nation's 25 oldest operating power facilities are hydropower facilities that were built over 90 years ago.

Since 2006, 37% of total electric power industry capacity additions have been wind generators.

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Who are the major players supplying the world oil market?

Last Updated: March 15, 2012 (Figure 1 updated February 7, 2013)

The world oil market is complicated. Companies are often thought of as the primary actors in this market, but governments play a large role as well. To answer this question, we'll explore the role oil companies and governments play in the world oil market and their interactions.

Although international oil companies (IOCs) are often thought of as those most responsible for world oil production, it is national oil companies (NOCs) that actually control the majority of proven oil reserves (85% in 2010) and current production (at least 55% in 2010).

There are three different types of companies that currently supply crude oil to the world market. The distinctions among these three types of companies are important because each has different general operational strategies and production-related goals.

International oil companies (IOCs), including ExxonMobil, BP, and Royal Dutch Shell are entirely investor-owned and primarily seek to increase shareholder value and make investment decisions based on economic factors. These companies typically move quickly to develop and produce the oil resources available to them and sell their output in the global market. Although these producers are affected by the laws of the countries in which they produce oil, all decisions are ultimately made in the interest of the company, not a government.National oil companies (NOCs) that operate as an extension of the government or a government agency, include Saudi Aramco (Saudi Arabia), Pemex (Mexico), and PdVSA (Venezuela). These companies support their governments' programs financially and/or strategically. They often provide fuels to domestic consumers at prices lower than those in the international markets. These companies do not always have the incentive, means, or intention to develop their reserves at the same pace as the commercial companies. Due to the diverse situations and objectives of the governments of their countries, these NOCs pursue a wide variety of objectives that are not necessarily market-oriented. The objectives NOCs pursue, however, include employing citizens, furthering a government's domestic or foreign policy objectives, generating long-term revenue, and supplying inexpensive domestic energy. All NOCs of the Organization of the Petroleum Exporting Countries (OPEC) members fall into this category.NOCs with strategic and operational autonomy that function as corporate entities and do not operate as an extension of the government of their country, including Petrobas (Brazil) and Statoil (Norway). These companies often balance profit-oriented concerns and the objectives of their country with the development of their corporate strategy. While these companies may support their country's goals, they are primarily commercially driven.

OPEC is a group of some of the world's most oil-rich countries (see OPEC member countries in the Did You Know box.) Together, they control approximately 70% of the world's total proven oil reserves (shaded green in Figure 2), and they produce 41% of the world's total oil supply (Figure 3). OPEC's oil exports represent about 60% of the total petroleum traded internationally. Because of this market share, actions by OPEC member countries can influence world oil markets.

OPEC seeks to actively manage oil production of its member countries by setting production targets for each member except Iraq, for which no target is presently set. The track record of compliance with OPEC quotas is mixed, as production decisions are ultimately in the hands of the individual member countries. Each OPEC country has a NOC, but most also allow international oil companies to operate within their borders.

The difference between market demand and oil supplied by non-OPEC sources is often referred to as the "call on OPEC." Saudi Arabia, the largest oil producer within OPEC and the world's largest oil exporter, historically has had the largest share of the world's spare production capacity. In fact, the world's spare capacity for oil production is maintained entirely by OPEC. The cost of developing and maintaining idle spare production capacity is inconsistent with the IOC's business model, which includes earning a return on capital invested.

EIA defines spare capacity as the volume of oil production that can be brought on within 30 days and sustained for at least 90 days. Spare capacity can also be thought of as the difference between a country's current production capacity and maximum production capacity. Should a disruption occur, oil producers can use spare capacity to mitigate increases in world oil prices by boosting production to offset lost volumes.

In addition to influencing the operation of NOCs, governments can also dictate the terms by which other oil companies must abide in their country. Access to a country's reserves may fall into four categories (shown in Figure 4):

Full access (15% of world reserves) — All companies must abide by the laws of the government, but no domestic company is given preferential treatment. Examples include the United States, the United Kingdom, and Canada.Equity access (1% of world reserves) — A NOC exists, but does not get preferential treatment over outside oil companies. Examples include Colombia, Indonesia, and Denmark.Limited equity access (37% of world reserves) — The NOC is given priority access to reserves while outside oil companies' access may be limited through minimum domestic ownership requirements, shared production with the NOC, or other methods. Examples include China, Angola, and Russia.No equity access (47% of world reserves) — The NOC has sole access to reserves. No foreign ownership of oil fields is permitted in these countries, and any outside participation is limited to operation through a domestic affiliate. Examples include Iran, Iraq, and Saudi Arabia.

By limiting outside access and imposing targets, governments of oil-rich countries can directly affect world oil supplies. Limited access to oil can force commercially-oriented companies to change production plans or form strategic alliances with NOCs, further establishing the importance of these oil-rich countries as major players in the world oil market.

The United States has no national oil company. The largest three U.S.-based international oil companies (ExxonMobil, Chevron, and ConocoPhillips) are accountable to their shareholders, not the United States government.

In 2010, the world's top three national oil companies (NOCs) by share of world production were: Saudi Aramco (12%), National Iranian Oil Company (NIOC) (5%), and PdVSA (Venezuela) (4%).

The top three international oil companies (IOCs) by share of world production were: Exxon Mobil (3%), BP (3%), and Royal Dutch Shell (2%).

OPEC members held over 70% of proven world oil reserves as of 2010

Each OPEC country has a national oil company (NOC).

Ecuador and Venezuela are the two members of OPEC in the Western Hemisphere.

OPEC members produced 41% of the world's total oil supply in 2010

"OPEC" and "Persian Gulf" countries are not the same.

The Organization of the Petroleum Exporting Countries, or OPEC, was organized in 1960 for the purpose of negotiating with oil companies on matters of oil production, prices, and future concession rights. Of the 12 countries currently in OPEC, only 6 of them are in the Persian Gulf.

Iran
Iraq
Kuwait
Saudi Arabia
Qatar
United Arab Emirates
Algeria
Angola
Ecuador
Libya
Nigeria
VenezuelaIran
Iraq
Kuwait
Saudi Arabia
Qatar
United Arab Emirates
Bahrain

Outside oil companies have limited or no access to most of the world's proven oil reserves.

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How can we compare or add up our energy consumption?

Last Updated: March 15, 2013

To compare or aggregate energy consumption across different energy sources like oil, natural gas, and electricity, we must use a common unit of measure. This is similar to calculating your food energy intake by adding up the calories in whatever you eat.

In American households we use several kinds of energy. It's difficult to add up or compare the total energy we use because each energy source is typically measured in a different unit: gasoline is usually measured in gallons, electricity in kilowatthours, and natural gas in cubic feet. One way to add and compare different energy sources is to convert them all to a common unit of measure based on their energy content.

One Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. It is approximately equal to the amount of energy that comes from burning one wooden kitchen match. A Btu isn't an everyday term to most people, but you might see it on your energy bill or in a news article.

Because a Btu is such a small unit of energy, there are tens of thousands of Btus in even one gallon of gasoline. The table to the right shows how to convert different energy sources into Btus.

You probably already have experienced converting physical units to energy units. When calculating the total amount of food you eat, you might look up how many calories are in each item and then add up the calories. You can't add a hamburger and a soft drink without the conversion. So you can see that calories are a common unit for measuring the energy content of food.

Let's say you consume a typical fast-food meal of:

If you ate the items listed above, you would have consumed 900 calories. Just as calories are a useful measure to help you compare different food items, Btus are useful for making energy comparisons.

If you want to calculate the total amount of energy you use, the process is similar. You can take the gallons of gasoline consumed by your car, the amount of natural gas and other fuels that heat your home, and the kilowatthours of electricity to run your lights and appliances, and convert them all to Btu equivalents using the conversion rates in the table. Then you can add up the different pieces to get a total amount in common units.

One wrinkle is that electricity is an energy carrier, or secondary fuel source, rather than a primary fuel source. There are significant losses in the conversion of primary fuels to electricity and in the transmission and distribution of electricity to the consumer.

For example, in 2011 the average coal-fired plant used 10,400 Btu of coal to generate one kilowatt hour (=3,412 Btu) of electricity. (Of course, there are regional differences in the primary energy used to generate electricity, and not all generation comes from thermal sources with the associated thermal energy losses.) In addition, another 7-8% of the electricity is used up when it is transmitted and distributed from the power plant to your house. If your focus is on primary energy use (such as coal, natural gas, or oil), you should start your calculation with the energy used to make and deliver electricity instead of the energy in the electricity itself.

Most people are interested in saving energy these days, and you can use Btu equivalents to help compare the different levels of savings resulting from taking different actions or making various lifestyle changes. Which do you think uses more energy in a year: gasoline in the average car or electricity in the average home? It's easy to find the answer if you make some assumptions about average usage and then convert the numbers to Btu. See the answers below.

It's interesting to see in these comparisons that residential use of energy for electricity appears to be lower than that for an average vehicle when you use the consumption Btu value of 3,412 Btu per kWh for electricity. But if you count all the primary energy used to generate and deliver the electricity, average residential use of energy for electricity is actually much higher than it is for a single vehicle. However, nearly 60% of households have two or more vehicles, making the average household use of energy for electricity about the same as it is for two passenger vehicles.

Here's another way to compare energy use. Suppose you hear about a new energy efficiency proposal that will save 1,000 trillion Btu per year, which is about 1% of total U.S. annual energy use. A trillion is a big number to visualize. However, sometimes it's easier to appreciate how much energy is represented by thinking in terms of cars or houses, just like it's easier to think of calories as hamburgers and fries, not the calories themselves.

You could divide the energy used by one car/vehicle (66 million Btu) into 1,000 trillion Btu to find that the energy savings in the same proposal described above is equal to taking approximately 15.2 million vehicles off the roads. These averages provide a way to visualize and understand the magnitude of the energy issues and solutions being considered.

The average passenger car/vehicle (including light trucks, vans, and sport utility vehicles) in the United States uses about 66 million Btu per year, which sounds like a big number for just one vehicle. But total energy use for cars, light trucks, vans, and sport utility vehicles in 2010 was about 15 quadrillion Btu, which is 15 with 15 zeros added on to it. That was equivalent to about 16% of total U.S. energy consumption in 2010.

Energy sources are expressed in different units, but their energy content can be compared using the British thermal unit (Btu)

Conversion Table of Common Energy Sources to Btu Energy SourcePhysical Units and Btu Equivalents1 kilowatthour (kWh) = 3,412 Btu (but on average, it takes about 3 times the Btu of primary energy to generate the electricity)1 cubic foot (ft3) = 1,022 Btu
1 cubic foot = 0.01 therms
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What is the role of hydroelectric power in the United States?

Last Updated: August 29, 2012

The importance of hydropower as a source of electricity generation varies by geographic region. While hydropower accounted for 8% of total U.S. electricity generation in 2011, it provided over half of the electricity in the Pacific Northwest. Because hydroelectric generation relies on precipitation, it varies widely from month to month and year to year.

Conventional hydroelectric generators of varying capacity operated in 48 states in 2011. Operating expenses for hydroelectric generators are lower than for most other forms of electricity generation but facilities are limited by geography and operations are subject to seasonal constraints. There is a large concentration of capacity in the Pacific Northwest, contributing to low wholesale and retail electricity prices in that region, especially in the spring runoff season.

Conventional hydroelectric generators were among the oldest of the Nation's power plants operating in 2011. The vast majority of hydroelectric generators were built before 1980 and recent changes to hydroelectric capacity have been small.

Conventional hydroelectric plants come in two broad categories: run-of-river and storage. A run-of-river plant utilizes the flow of a waterway (usually a river) to turn a turbine, while a storage plant creates a reservoir using a dam that controls water flow over a turbine.

A run-of-river plant has little control over generator output. A storage plant has some control over generation by controlling spillway water flow at intake through the dam, but is still constrained by total reservoir water levels.

There are several other types of non-conventional hydroelectric generators including pumped-storage, hydrokinetic axial flow and wave buoy turbines. Pumped-storage generators represent the only non-conventional form of hydroelectric generation currently in wide commercial use. These systems pump water to high elevations during low load periods then run the same water through the turbines to produce electricity during high demand times. Other hydroelectric technologies, such as wave buoys, are being developed and demonstrated but not in wide use at this time.

Depending on the season and precipitation, the hydroelectric share of total generation varies from 4% to 10%. Precipitation, snowpack, drought conditions, and other meteorological factors contribute to water availability for generation through hydroelectric dams. For example, early snow melt runoff in the Pacific Northwest, elevated snowpack levels throughout much of the Western river basins, and significant rainfall in March in areas of high hydropower capacity resulted in a large increase in hydroelectric generation in 2011.

Most hydroelectric generators in the United States were co-located at dams originally built for other purposes, like flood control, municipal water supply, and irrigation. Operations are affected by environmental considerations associated with water use, fish populations, and impact on wildlife in surrounding areas. For example, fish ladders and lifts have been constructed at many dams to help protect migrating populations.

The Grand Coulee Dam, operated by the U.S. Bureau of Reclamation, is the fifth-largest power plant operating in the world and the largest in the Nation, with a net summer capacity of 7,079 Megawatts.

The U.S. Army Corps of Engineers was the largest operator of U.S. conventional hydroelectric generating capacity in 2011, followed by the U.S. Bureau of Reclamation.

The Nation's oldest power facilities are hydroelectric plants.

The Nation's 25 oldest operating power facilities are hydroelectric, the oldest of which began operating in 1891.

Hydroelectric generation is highly variable because it depends on precipitation.

Source: U.S. Energy Information Administration, Electric Power Monthly, (July 2012).

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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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What is the role of coal in the United States?

Last Updated: July 18, 2012

The United States holds the world's largest estimated recoverable reserves of coal and is a net exporter of coal. In 2011, our nation's coal mines produced more than a billion short tons of coal, and more than 90% of this coal was used by U.S. power plants to generate electricity. While coal has been the largest source of electricity generation for over 60 years, its annual share of generation declined from 49% in 2007 to 42% in 2011 as some power producers switched to lower-priced natural gas.

The United States is home to the largest estimated recoverable reserves of coal in the world. In fact, we have enough coal to last more than 200 years, based on current production levels. Coal is produced in 25 states spread across three coal-producing regions. In 2011, approximately 72% of production originated in five states: Wyoming, West Virginia, Kentucky, Pennsylvania, and Texas.

Over 90% of U.S. coal consumption is in the electric power sector. The United States has more than 1,400 coal-fired electricity generating units in operation at more than 600 plants across the country. Together, these power plants generate over 40% of the electricity produced in the United States and consume more than 900 million short tons of coal per year.

Although coal-fired generation still holds the largest share among all sources of electricity, its use has declined since 2007 due to a combination of slow growth in electricity demand, strong price competition with natural gas, and increased use of renewable technologies. See related article — Today in Energy, July 6, 2012

While the share of our electricity generated from coal is expected to decrease by 2035, the amount of coal used to meet growing demand for power is expected to increase in the absence of new policies to limit or reduce emissions of carbon dioxide and other greenhouse gases. Revised emissions policies could significantly change the outlook for domestic coal use. See related article — Today in Energy, May 4, 2012

Besides its role in generating electricity, coal also has industrial applications in cement making and conversion to coke for the smelting of iron ore at blast furnaces to make steel. A small amount of coal is also burned to heat commercial, military, and institutional facilities, and an even smaller amount is used to heat homes.

Between 2000 and 2010, about 5% of the coal produced in the United States, on average, was exported to other countries. Coal exports come in two forms: metallurgical coal, which can be used for steel production, and steam coal, which can be used for electricity generation. In 2011, U.S. coal exports climbed to 10% (the highest level in two decades), partly because flooding disrupted coal mining in Australia, which is normally the world's largest coal exporter. Metallurgical coal dominated U.S. coal exports in 2011 with Europe the largest importer, followed by Asia. See related article — Today in Energy, June 19, 2012

The United States also imports a small amount of coal; some power plants along the Gulf Coast and the Atlantic Coast find it cheaper to import coal by sea from South America than to have it transported from domestic coal mines.

Although some natural gas plants are more efficient than coal plants at generating electricity, in the past the fuel cost of generating one kilowatthour of electricity from natural gas had typically been higher than that of coal. In 2009, coal began losing its price advantage over natural gas for electricity generation in some parts of the country, particularly in the eastern United States as a surge in natural gas production from domestic shale deposits (made possible by advances in drilling technologies) substantially reduced the price of natural gas. See related article — Today in Energy, July 13, 2012

Coal is plentiful and fairly cheap relative to the cost of other sources of electricity, but its use produces several types of emissions that adversely affect the environment. Coal emits sulfur dioxide, nitrogen oxide, and heavy metals (such as mercury and arsenic) and acid gases (such as hydrogen chloride), which have been linked to acid rain, smog, and health issues. Coal also emits carbon dioxide, a greenhouse gas. In 2011, coal accounted for 34% of the energy-related carbon dioxide emissions in the United States. On the production-side, coal mining can have a negative impact on ecosystems and water quality, and alter landscapes and scenic views.

The economics of burning coal may change if the U.S. adopts policies that restrict or otherwise control carbon dioxide emissions. For example, a cap-and-trade program to regulate carbon dioxide emissions would likely increase the cost of burning coal because of its carbon content, and thereby cause power companies to consider using less carbon-intensive generating technologies such as nuclear, renewables, and natural gas. In March 2012, the U.S. Environmental Protection Agency proposed a new source performance standard for emissions of carbon dioxide (CO2) that would establish an output-based emission limit of 1,000 pounds of CO2 per megawatthour for new fossil-fuel-fired power plants. This emission limit would effectively require that new coal-fired generating units employ carbon capture and sequestration (CCS) technologies to reduce uncontrolled emissions of CO2 by approximately 50%.

Researchers are working on ways to lower the costs and improve the efficiency of various CCS technologies with a goal of capturing approximately 90% of the carbon dioxide from coal plants before it is emitted into the atmosphere and then storing it below the Earth's surface. CCS would theoretically address much of coal's carbon dioxide emissions; however, substantial economic and technological hurdles remain.

In 2011, Wyoming produced 438 million short tons of coal, or 40% of the coal mined in the United States. West Virginia was the second largest producer, with 135 million short tons (12%).

Coal is the largest source of U.S. electricity generation.

Different types of coal have different characteristics including sulfur content, mercury content, and heat energy content. Heat content is used to group coal into four distinct categories, known as ranks: anthracite, bituminous, subbituminous, and lignite (generally in decreasing order of heat content).

There are far more bituminous coal mines in the United States than the other ranks (over 90% of total mines), but subbituminous mines (located predominantly in Wyoming and Montana) produce more coal because their average size is much larger.

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