IER Sues Treasury Department for Public Records of Immediate Public Interest


WASHINGTON – Today the Institute for Energy Research filed an open records lawsuit against the Department of the Treasury relating to continuing efforts in Washington to quietly advance the “climate” industry. This Freedom of Information Act (FOIA) suit, filed in the U.S. District Court for the District of Columbia, seeks certain, specific records relating to the “climate risk disclosure” campaign begun in 2012 by various activist groups including Ceres and Rockefeller Financial Asset Management and led by disgraced former New York Attorney General Eric Schneiderman. That agenda, if implemented, would have immense economic and legal consequences.

In order to educate the public on this matter IER requested correspondence of the Director of the Office of Energy & Environment Peter Wisner over two specified periods during 2017 and 2018, which mention particular terms including “Bloomberg task force,” “G20,” “Task Force on Climate-Related Disclosure,” “climate risk disclosure,” and/or “climate financial disclosure.”

As IER noted in the FOIA request, “This request is made to inform the public about an issue of great public interest, particularly the effort of government employees and outside activist networks’ coordination to advance a government policy — ‘climate risk disclosure’ — that would have tremendous economic and legal consequences.”

Treasury was required by law to demonstrate by June 28 that it intends to process the requests, yet failed to do so even after invoking a ten-day extension. Chiefly, Treasury has failed to provide any responsive records and otherwise has failed to meet its statutory obligation under FOIA. Instead, the agency merely acknowledged receipt of the request.

IER President Thomas J. Pyle stated, “Thanks to previous open records requests, we know that the campaign for ‘climate risk disclosure’ began in 2012 by pressure groups, Wall Street interests, and activist politicians led by Mr. Schneiderman. Now we understand that senior Trump administration officials are possibly working to advance this campaign.

“IER intends to educate the public on what role Treasury officials are playing in assisting the move to impose activist-demanded ‘confessions’ by publicly traded companies of their causation of serious, man-made global warming, seeking penance at the hands of a ‘climate’ securities tort bar, and elected officials eager for large settlement funds to politically distribute.”

Attorney Chris Horner, of the public interest law firm Government Accountability & Oversight (GAO), filed the suit on behalf of IER, and has written extensively on the issue, including earlier this year in a Wall Street Journal letter:

“The effective goal [of the climate risk disclosure campaign] is to coerce ‘confessions’ in energy-related interests’ public filings that catastrophic man-made global warming is a real problem of which they constitute a significant part, that their reserves are in fact worth little to nothing and their previous filings and other statements constitute actionable misdeeds, possibly fraud.”

IER looks forward to resolving the Treasury Department’s public obligations sooner rather than later but intends to fully pursue its rights to review these records in an effort to educate the public about the role of public officials in this ideological campaign with implications for the United States economy.


For media inquiries, please contact Erin Amsberry

The post IER Sues Treasury Department for Public Records of Immediate Public Interest appeared first on IER.


China Looks to Increase Natural Gas Consumption and Supply

In 2017, China was the world’s fastest-growing natural gas market. Consumption grew by 15 percent—over twice the rate of economic growth—and  liquefied natural gas (LNG) imports grew by 46 percent. In 2013, under the country’s National Action Plan on Air Pollution Prevention and Control, natural gas became a central part of the Chinese government’s plan for fighting air pollution. China’s thirteenth Five-Year Plan (2016–2020) set goals for increasing the use of natural gas, including almost doubling the share of natural gas in China’s energy mix in five years—providing up to 10 percent of China’s primary energy by 2020 and 15 percent by 2030.

In 2017, natural gas accounted for about 7 percent of China’s primary energy consumption. Over two-thirds of the natural gas consumed in China is used in industry and buildings (mainly for heating) with little used in power generation due to China’s staggering coal-fired capacity in that sector. The Chinese economy relies heavily on coal, which produces more particulate matter and other criteria pollutants than natural gas. Transitioning from coal to natural gas can reduce China’s soot and smog. China suffers from serious air pollution problems.

To implement the plan, China first required 28 cities in the Beijing-Tianjin-Hebei region to replace small coal-fired boilers with natural gas–fired units. An estimated 4 million households switched from coal to natural gas. Beginning in December 2017 through 2021, China is targeting the replacement of these residential coal boilers across northern China. These small boilers are particularly bad at producing pollution, since their combustion is very inefficient.

To increase natural gas’s share of primary energy consumption, the Chinese government has undertaken a process of gradual price liberalization. Natural gas prices for nonresidential customers were liberalized beginning in 2015. In 2017, the government announced that third parties would receive access to pipelines and LNG import terminals.

China’s Push to Natural Gas Created Shortages

During the winter of 2017 to 2018, much of northern China experienced significant natural gas shortages. Millions of homes were temporarily left without heat. One provincial capital suspended heating in government offices, hotels, and shopping malls. Natural gas–fueled taxis and buses waited in long lines. Industrial output was scaled back to divert natural gas to emergency heating in homes and office buildings.

Contributing to the shortage were limited storage capacity, over stretched LNG infrastructure, gas pipeline shortages, colder than average temperatures, lack of market-based price signals due to the gas market being semi-regulated, and inadequate coordination among government officials.

At the end of 2017, China’s underground natural gas storage capacity was 11.7 billion cubic meters—about  5 percent of total consumption. This compares to natural gas storage capacity in the United States of 17 percent of consumption and in Europe of 27 percent.  

At the end of 2017, China had 16 operational LNG receiving terminals with 71 billion cubic meters of annual import capacity along the country’s east coast. During the peak winter months of December and January, the average nationwide utilization rate was above 105 percent and utilization at some northern terminals exceeded 120 percent. Although southern terminals operated at utilization rates of around 70 percent, the pipeline infrastructure to move natural gas from southern terminals to northern demand centers was insufficient. Chinese companies dispatched trucks to deliver LNG from receiving terminals in the south to cities in the north at distances of over a thousand miles and at a cost of over $30 per million Btu during the winter peak demand—almost three times the spot LNG price during this time period.

In the second half of 2017, pipeline gas deliveries from Turkmenistan dropped substantially due to stronger-than-anticipated demand growth and cold weather in Turkmenistan, unplanned outages at a gas processing facility, and an attempt to negotiate better pricing terms. Despite China’s attempts to purchase more supply from Kazakhstan and Uzbekistan, natural gas pipeline imports from Central Asia remained largely flat during the months of peak winter gas demand.

Natural Gas Production

Most of China’s natural gas supply (about 60 percent) comes from domestic production—almost all from conventional wells. China’s natural gas production increased by nine percent in 2017, but could not keep up with the 15 percent annual growth in natural gas consumption.

Unconventional gas—particularly shale gas—has long-term growth potential in China, but its development has been challenging. China’s shale basins are located in mountainous, arid, remote and also highly populated regions, leading to higher costs. China’s shale is also buried deeper and is more fractured, making it difficult and expensive to extract.

According to the Energy Information Administration, China has the world’s largest shale gas resources at 1115.2 trillion cubic feet (31,579 billion cubic meters). Because of the challenges to producing it, the government subsidizes its production, currently at roughly 20 percent of well-head prices.  

The government’s 2020 target for shale gas production was scaled back from 100 billion cubic meters per year in 2012 to 30 billion cubic meters per year in 2014 due to a number of challenges including difficult terrain, high costs, poor geology, and long distances to markets. One energy consultant predicts that only about 17 billion cubic meters per year of production from shale is attainable by 2020, and would require a near doubling of current production in less than three years.

Helping increase efficiency, Chinese firms can now drill multiple wells at a single pad, known as “well factory” drilling and carry out extended horizontal fracturing up to 3,000 meters. Over the past 8 years, the cost of building a well was nearly halved to an average of under 50 million yuan per well ($7.8 million), and drilling speed has improved by two-thirds to 45 to 60 days. China pumped 9 billion cubic meters of shale gas in 2017—about 6 percent of the country’s total natural gas production.

Source: Forbes

China’s other sources of unconventional natural gas production—coalbed methane and coal gasification—are less likely to materialize over the long run.

Pipeline Imports of Natural Gas

China currently imports natural gas through two pipelines: the Central Asia gas pipeline (from Turkmenistan, Kazakhstan, and Uzbekistan) and the China-Myanmar pipeline. A natural gas pipeline from Russia is currently under construction but is not likely to come on-line until the end of 2019.

In 2017, 39 billion cubic meters of natural gas was delivered by the Central Asia gas pipeline—below the 55 billion cubic meter capacity. Kazakhstan and Uzbekistan have some potential to increase pipeline gas deliveries to China, but producing more natural gas in those countries will take time. Another potential pipeline from Central Asia, known as Line D, could add another 30 billion cubic meters per year import capacity from Turkmenistan. Construction of Line D began in 2014, but the project was delayed in 2016 and suspended in 2017. If the project is completed, the earliest start of deliveries would be 2023 due to uncertainties around construction and timing, and technical difficulties due to the mountainous terrain.

The potential for increased natural gas imports through the China-Myanmar pipeline is also limited with deliveries falling short of the 5.2 billion cubic meter annual contract volume and the high cost of the gas. The Power of Siberia pipeline connecting Russia’s natural gas reserves in Eastern Siberia with China’s northeastern provinces could start deliveries by the end of 2019.  But the ramp up to full capacity—38 billion cubic meters per year of contracted volume—could take well into the mid-2020s. Also, Russia’s eastern gas fields may have a problem of providing the gas when China needs it most during the cold weather months.

Natural Gas Storage

China has plans to increase natural gas storage capacity from about 12 billion cubic meters today to 15 billion cubic meters by 2020 and 35 billion cubic meters by 2030. Last year, the Chinese government began requiring Chinese natural gas companies to build and maintain storage facilities. Upstream companies are required to build storage capacity equal to 10 percent of their annual contracted sales volume and midstream companies (including city gas distributors) are required to provide storage equal to 5 percent of annual consumption. Companies have several years to meet these requirements.

Plans for increasing natural gas storage rely mainly on state-owned enterprises because the financial returns on natural gas storage facilities in China are low. Regulated city-gate prices suppress the seasonal price signals that could incentivize private companies to invest in gas storage.

Although work is underway to expand China’s natural gas storage capacity, there are geological obstacles that limit its growth. In China, depleted oil and gas fields—the most commonly used geological means of storage—are located deep underground, close to densely populated areas or in mountainous regions, which raises safety risks and technical complexity; and the technical expertise to build new facilities is limited.

If the government targets for both natural gas storage capacity and natural gas consumption are met, storage is expected to reach 6 percent of consumption in 2030, compared to just over 5 percent today.

LNG Infrastructure

Analysts generally expect China’s LNG demand to reach 80 to 147 metric tons per annum (109 to 200 billion cubic meters per year) by 2030—roughly two to four times greater than the 38 metric tons per annum (mtpa) consumed in 2017. In most forecasts, China overtakes Japan (which imported 84 metric tons per annum of LNG last year) as the world’s largest LNG importing country in the mid- to late 2020s.

Five new or expanded regasification terminals are scheduled to come on-line in 2018. Several additional terminals are under construction or expanding capacity, with projected online dates between 2019 and 2021. China’s LNG import capacity could increase by half through the early 2020s. Because only about a quarter of China’s new import capacity is in the northern regions, parallel development of the domestic gas pipeline network is also needed. Plans call for an expansion of China’s natural gas pipeline network by 99,000 kilometers (about 60,000 miles) between 2015 and 2025.


China is expected to become the world’s leading LNG importer over the next decade.  Government natural gas targets imply strong demand growth for at least the next decade—although infrastructure constraints could limit consumption in the short and medium terms.  China is developing its vast shale gas resources to help meet demand.

The post China Looks to Increase Natural Gas Consumption and Supply appeared first on IER.

Electricity Bills in South Australia and Other Australian States Skyrocket

Like many European countries, South Australia is betting on renewable energy for its electricity, closing coal plants in favor of less carbon sources, with the outcome that its residents are becoming energy poor due to skyrocketing electricity prices. The region’s reliance on subsidized, intermittent and unreliable wind and solar power has resulted in skyrocketing power prices. Over 100,000 Australian families had their power cut off last year, and another 100,000 are on payment plans with their power providers, making over 200,000 residents energy poor in one of the most energy-rich nations in the world. 109,000 Australian households had their electricity disconnected last year because they were unable to afford their electricity bills, which included over $3 billion in subsidies for Chinese- made solar panels and wind turbines. Electricity bills include the cost of generating power, transmitting it through high-voltage lines, distributing it to homes and businesses, and government subsidies provided to encourage development of renewable energy.


Retail electricity prices of NEM states

Source: Stop These Things Note: Prices in Australian dollars. One Australian dollar equals 0.74 U.S. dollars.


In Victoria, one of Melbourne’s bayside pubs is rationing its heating and cooling and cutting down on staff because of power bills that have reached $24,000 a month. The pub will have to sell over 120 additional pots of beer each day to keep pace with power bills that have tripled from $8000 a month after last year’s closure of the Hazelwood coal power plant. The closure of the 1600-megawatt Hazelwood plant in March 2017 resulted in the loss of over 20 percent of the state’s generation capacity. The electricity company blames the closure of the Hazelwood plant for the tripling of the pub’s power bill.

In Victoria, average retail household power bills increased almost 16 percent to $1275 compared to a year earlier. Average wholesale prices in 2017 increased 85 percent in Victoria (VIC) and 32 percent in South Australia (SA). Average wholesale prices in New South Wales (NSW) and Queensland (QLD) increased 63 percent and 53 percent, respectively.

Prior to the Hazelwood plant’s closure, the plant’s access to low-cost coal kept power prices among the lowest in the electricity market that supplies eastern Australia. Without the Hazelwood plant, the region became a net importer of electricity in the second half of 2017. To cope with the loss of coal-fired electricity, 500 percent more natural gas was used for power generation in 2017 and renewable energy surged, particularly roof-top solar as consumers looked to alternate sources rather than their power supplier.

Average Annualized Wholesale Electricity Prices, 2014-2018

average annualized wholesale electricity prices 2014-2018

Source: The Sydney Morning Herald
Note: Annualized over 12 months ending in February



South Australia, Victoria, and other Australian states are suffering from high electricity prices and potential blackouts because of their unsustainable mix of intermittent renewable energy with insufficient back-up power. Because of high electricity prices and energy poverty, residents with the help of the government are looking towards solar rooftop panels and home storage batteries, which are also costly, to form a virtual power plant and hopefully lower prices.

The United States should learn from Australia’s experience and not be too hasty at turning its generating sector over to intermittent renewable energy. Wind and solar power represent almost 8 percent of the current U.S. generating mix, which so far has not destabilized the grid. But, costly tax credits for wind power have caused negative electricity prices that have resulted in traditional technologies, at times, being uncompetitive.  Wind generators are awarded tax credits equivalent to cash from taxpayers for generating power even when there is no financial need for it. Without the proper back-up power and policies that support it, the United States could end up facing similar cost and unreliability issues and challenges as these Australian states.

The post Electricity Bills in South Australia and Other Australian States Skyrocket appeared first on IER.

Ocean City Wants Invisible Offshore Wind Turbines

Over a year ago, the Maryland Public Service Commission approved wind turbines to be located in the Atlantic Ocean off the coast of Ocean City, Maryland, and the federal Bureau of Ocean Energy Management (BOEM) has been reviewing those plans. But the town of Ocean City is creating a problem for the wind developer by requiring the turbines to be located at least 26 nautical miles offshore—about twice the distance planned—so that they cannot be seen by tourists that flock to the peninsula during the summer months. U.S. Wind, the developer, has offered the town incentives, including ‘free’ electricity, to get the town to renege on its stance but there is no agreement in sight.

Even the offer of other community investments worth hundreds of thousands of dollars each year and an offer to alter its plans if Ocean City agreed to cover the costs of seeking new government approvals could not help U.S. Wind achieve agreement from Ocean City officials. Town officials fear that tourists will abandon Ocean City and flock to other beaches if its horizon is speckled with huge wind turbines. According to U.S. Wind, building that far offshore would require starting from scratch on an offshore leasing process that began in 2010.

According to Ocean City officials, however, the community benefit package that U.S. Wind offered is vague and undefined. They conclude that the money would be better spent on figuring out a way to move the wind turbines further east. They also note that any offers to supply ‘free’ electricity have been vague, not clearly defined and would potentially violate state and federal law.

The Maryland Public Service Commission approved subsidies, to be paid by ratepayers, last year for two offshore wind projects that would add about $1 to average monthly residential electricity bills across the state, which are a necessary part to financing these very expensive projects. The commission approved 62 turbines at least 14 miles off the coast of Ocean City to be developed by U.S. Wind—a $1.4 billion project—and a 15-turbine, $720 million project by Skipjack Offshore Wind LLC to be situated north of the U.S. Wind project.

Despite the approval by the Maryland Public Service Commission, U.S. Wind now claims they will build just 32 turbines at least 17 nautical miles from shore.  U.S. Wind’s original proposal was planned to maximize the project’s profitability, but the company is scaling-back those plans because the market will not bear its larger proposal.

Earlier this year, Ocean City officials pushed for a bill in the Maryland assembly that would have prohibited offshore wind turbines within 30 miles of the coast, but the bill did not make it out of committee. They also asked the Public Service Commission to reconsider the project because of an increase in the proposed turbines’ height–from 200 feet to about 370 feet. Since the offshore wind farms were first approved by the Maryland General Assembly in 2010, the height of the proposed turbines increased due to new technology, making them more visible to those onshore.

U.S. Wind still has several regulatory hurdles it needs to clear to get federal approval, including the presentation of a construction and operation plan to BOEM.

Offshore Wind Power is Expensive

According to the Energy Information Administration, offshore wind turbines are the second most expensive generating technology that the agency considers in its Annual Energy Outlook, behind only solar thermal. The agency estimates that the levelized generating cost of an offshore wind turbine coming on-line in 2022 would be 13.8 cents per kilowatt hour in 2017 dollars—almost 3 times more than a natural gas combined cycle plant and more than twice as much as onshore wind. Transporting and installing turbines on land is significantly easier than constructing foundations and installing turbines at sea—particularly when offshore turbines are becoming much larger.

Offshore projects are massive in scale and size, work has to be performed in a highly corrosive marine environment under variable conditions and installing foundations in seabed of 35 or more meters below sea level is difficult. Performing this work requires a specialized port infrastructure, logistic service providers, construction and maintenance vessels, helicopters and related aviation resources, and other assets. Further, general marine facilities must be strengthened and otherwise upgraded to handle large turbines and foundations. And, offshore wind development has unique transmission concerns, which also add to its cost.


In order for Maryland to reach its goal of 25 percent of its electricity being generated by renewable sources by 2020, it is estimated that at least 2.5 percent will need to come from offshore wind. Maryland electricity consumers and taxpayers will be paying more for electricity produced from these offshore wind farms due to their higher cost and subsidization. For reference, Germany and Denmark—pioneers in offshore wind development—have residential electricity prices that are three times higher than those in the United States. Maryland seems to want to become the state with the first large wind farms despite the higher cost and the failure of the now-cancelled Cape Wind project off Cape Cod, Massachusetts.

A previous article on Maryland’s offshore wind development can be found here.

The post Ocean City Wants Invisible Offshore Wind Turbines appeared first on IER.

Renewables Cannot Even Fill the Void of Retiring Nuclear Plants

According to BP’s 2018 edition of its Statistical Review of World Energy, renewable energy has not been able to fill the void created by retiring nuclear plants despite its large growth in 2017. As a result, the share of non-carbon power generation has fallen slightly over the past 20 years. The data is further evidence that energy sources such as wind and solar cannot replace coal and other fossil fuels and will not lead to significant reductions in carbon dioxide emissions despite decades of subsidies. Despite non-hydroelectric renewable generation increasing by 17 percent, wind and solar accounted for only six percent of total electricity globally.

Public and private entities spent $1.1 trillion on solar and over $900 billion on wind between 2007 and 2016. Global investment in these renewable sources was about $300 billion per year between 2010 and 2016. The $2 trillion in solar and wind investment during the past 10 years represents an amount similar to the global investment in nuclear power over the past 54 years, which totals about $1.8 trillion.


declining power from clean energy

Source: Forbes


Global Carbon Dioxide Emissions

Global energy demand grew 2.2 percent last year–above the 10-year average of 1.7 percent—and up from the previous year’s 1.2 percent increase, due to faster economic growth in both developed and developing countries. The energy demand growth and continued use of fossil fuels increased carbon dioxide emissions by 1.6 percent in 2017 to a new record of 33.4 billion metric tons, after remaining relatively stable for three years.

China and India accounted for nearly half of the increase in global carbon dioxide emissions. The largest increase in carbon dioxide emissions in 2017 were from China (1.6 percent increase), which was a reversal from the past three years when the largest increases in emissions came from India. China’s emissions in 2017 were 0.3 percent higher than the previous peak in 2014. The next highest increment came from India where carbon dioxide emissions increased by 4.4 percent.

Carbon dioxide emissions in the European Union were up by 1.5 percent with Spain accounting for 44 percent of the increase. Germany’s carbon dioxide emissions also increased over the past two years, despite spending $200 billion on renewable energy over the past two decades. Germany is not expected to reach its goal of reducing carbon emissions by 40 percent by 2020 compared to 1990 levels. Germany’s Energiewende (energy transition to renewable energy from fossil fuels and nuclear power) has cost the average German an estimated $2,500 without reaching its goals.

Carbon dioxide emissions in the United States decreased by 0.5 percent. It was the third year in a row that the carbon dioxide emissions in the United States declined. This is the ninth time in this century that the United States has had the largest decline in emissions in the world. Carbon dioxide emissions from energy use from the United States are the lowest since 1992.

Global Coal Consumption

Coal consumption increased one percent in 2017 due to the opening of new coal-fired generating units in China and India. This was the first increase in coal consumption in 4 years. However, it was still 3.5 percent less than its peak level in 2013. Coal’s share of global power generation was 38 percent in 2017—the same as in 1998. Its share had increased in the intervening years when China hit its very high years of economic growth but fell slightly over the past few years, ending at its starting point two decades ago. Coal consumption declined in the United States and the European Union, but increased 0.5 percent in China. China remains the world’s top coal market, with the country consuming 50.7 percent of the world’s coal in 2017.


Global coal consumption and production

Source: Vox


Global Oil Production and Consumption

Oil production cuts by OPEC and non-OPEC countries of almost 1 million barrels per day in 2017 were offset by increased production from the United States and other countries of 1.5 million barrels per day. A new oil production record of 92.6 million barrels per day was reached in 2017–the eight straight year global oil production increased. In 2017, the United States was the world’s top oil producer when natural gas liquids are included, exceeding 13 million barrels per day, followed by Saudi Arabia at 12.0 million barrels per day, and Russia at 11.3 million barrels per day.

Oil demand grew by 1.7 million barrels per day, and totaled 98.2 billion barrels per day in 2017. Oil consumption includes biofuels and fuels derived from coal and natural gas. U.S. consumption increased by 1.0 percent, leading the world at 19.9 million barrels per day. China’s demand increased by 4 percent to a new record of 12.8 million barrels per day.

Natural Gas Production and Consumption

Natural gas consumption grew by three percent to a new record of 355 billion cubic feet per day—the fastest growth since 2010. China’s gas consumption increased by 15 percent. Natural gas production increased by 4 percent. The United States led all countries in both production and consumption of natural gas.

Global Solar and Wind Power Generation

Global solar power generation increased by 35 percent and global wind power generation increased by 17 percent in 2017.


Share of global electricity generation by fuel

Source: Vox



2017 was a year of record oil consumption, natural gas consumption and solar and wind power consumption. But, despite record growth in wind and solar power, carbon dioxide emissions grew 1.6 percent due to declining nuclear power production. Renewable energy could not replace retiring nuclear units in 2017 due to its intermittency and lower capacity factors and therefore is unlikely to meet global demand anytime in the foreseeable future, despite opposite claims by environmentalists. As a result, both global coal consumption and global natural gas consumption increased in 2017.

Interestingly, the United States, which President Trump removed from the Paris Accord last year, had the largest carbon dioxide emissions decline in the world, while the European Union’s emissions went up, along with those of China and India, and the world as a whole.

The post Renewables Cannot Even Fill the Void of Retiring Nuclear Plants appeared first on IER.

Could a Renaissance Be in Store for Existing Nuclear Plants?

Nuclear plants were originally issued 40-year operating licenses by the Nuclear Regulatory Commission. Most utilities had applied for 20-year renewals for their nuclear units, and have operated them for 50 to 60 years. Many utilities are now considering applying for a second renewal and four plants have begun that decade-long process. The initial operating license for nuclear units was issued for 40 years because it was believed that nuclear plants would last 40 to 50 years. But, they, like coal plants, have operated for much longer, providing reliable and relatively inexpensive electricity.

Duke Energy, for instance, has maintained its nuclear units, continually replacing critical equipment.  At the Brunswick plant in Southport, Duke completed a refueling outage earlier this year, installed new turbine controls and upgraded the plant’s diesel generators that keep the facility operational during emergencies. The licenses for the two reactors at the Brunswick plant expire in 2034 and 2036 and are candidates for a second renewal.

Duke’s 11 reactors at six locations in North and South Carolina generate over 56 percent of the power in those two states. To relicense these 11 reactors is less expensive than building a new plant, despite the costs associated with the equipment upgrades and replacements required for relicensing.

The main factor limiting how long a plant could be operational is the reactor vessel, which could become brittle because of the nuclear activity taking place inside it. In most units, however, the lifetime of the reactor vessel is much greater than 80 years.

To keep these units operating for 20 more years will require that the Nuclear Regulatory Commission amends its onerous regulatory policies that caused cost increases and slowed the deployment of nuclear power.

The Nuclear Future That Wasn’t

According to Australian National University researcher Peter Lang, in the 1960s and 1970s, nuclear power transitioned from a technology with rapidly falling costs and accelerating deployment to rapidly rising costs and stalled deployment. If nuclear power had continued with its original costs and deployment, its costs would be around 10 percent of its current cost. And if that were the case, nuclear power would have replaced all coal-burning and three-quarters of gas-fired electric power generation by 2015, substituting for 186,000 terawatt-hours of electricity production over the past 30 years and lowering carbon dioxide emissions substantially. Cumulative global carbon dioxide emissions would be about 18 percent lower and annual global carbon dioxide emissions would be one-third less.

For example, the Oyster Creek Nuclear Generating Station in New Jersey, which opened in 1969, cost $594 million (in 2017 dollars) and took four years to build. That compares to the Watts Bar nuclear unit in Tennessee, which opened in 2016, and cost $7 billion and took over 10 years to build.

The change resulted from the Energy Reorganization Act of 1974, which established the Nuclear Regulatory Commission to focus on safety. The result was construction times increased from four to 14 years, and orders for new nuclear reactors slowed with almost 60 reactors being scrapped.

Further, onerous regulation by the Nuclear Regulatory Commission has resulted in the premature retirement of existing nuclear units and the announcement of many more retirements. Since 2013, six nuclear plants have closed in Florida, Wisconsin, California, Vermont, and Nebraska due to competition from inexpensive natural gas and environmental opposition. Eleven more nuclear plants, including Pennsylvania’s Three Mile Island and California’s Diablo Canyon, have announced that they will close between now and 2025, even though they could  operate for decades.

Source: New York Times 

In 2018, American power generators are expected to retire at least 15.4 gigawatts of coal-fired and 550 megawatts of nuclear plant capacity. According to Bloomberg New Energy Finance, two dozen nuclear plants (about 33 gigawatts) are either scheduled to be retired or will lose money by 2021. When an existing nuclear reactor is retired, it cannot be reopened later, as decommissioning the plant starts immediately.

The 680 megawatt Pilgrim reactor in Massachusetts is slated to retire next year. When it does, it will remove more zero carbon dioxide electricity production than all the wind turbines and solar panels that the state added over the last 20 years. And, any new renewable energy technology (e.g. offshore wind) will just fill a portion of the hole made by Pilgrim’s closure. Some states, such as Illinois, New York and New Jersey, have taken steps to keep some of their nuclear reactors operating.

New York decided to subsidize three upstate nuclear plants. (Indian Point, a large plant near New York City is still slated to close by 2021.) Illinois’s legislature passed a bill that created “zero emissions credits” to help two of Exelon’s financially troubled nuclear plants stay open. New Jersey passed a bill with a $300 million annual subsidy to three of the state’s nuclear power plants, which provide the state with about 40 percent of its electricity. (New Jersey’s Oyster Creek nuclear reactor is still expected to close.)

Policy makers in Ohio and Pennsylvania are evaluating policies to keep their nuclear reactors operating. Besides emissions reductions, considerations include jobs lost due to the closures; becoming overly dependent on natural gas, which has a history of price volatility; established reliability; and fuel diversity.

Proponents of subsidizing nuclear plants argue that energy markets do not properly value the low-carbon benefits that nuclear reactors provide while wind and solar power are subsidized by state renewable mandates and federal tax credits. According to the BP Statistical Review of World Energy, over the past 20 years, the share of non-carbon power generation has fallen slightly, as the growth in renewables has been offset by a loss of nuclear power generation.


The Nuclear Regulatory Commission should allow utilities that maintain rigorous, ongoing preventive maintenance programs across their nuclear fleet and have completed upgrades and investments during their reactors’ operating life, to relicense their units. The capital costs of these plants have already been paid for by consumers, and if they are safe to operate, they should be allowed to continue. In the past, the Nuclear Regulatory Commission has placed such long time delays on reactors such as the San Onofre units in California that the utilities had chosen to retire their units because they could not afford to keep their nuclear units operating at low levels and purchase other power to meet demand.

The post Could a Renaissance Be in Store for Existing Nuclear Plants? appeared first on IER.

The Biofuels Industry Retains Pull in Washington

On Tuesday, the EPA released a proposal to raise the biofuel mandate 3.1 percent to 19.88 billion gallons in 2019.  Under the Renewable Fuel Standard (RFS), fuel suppliers are required to mix billions of gallons of ethanol into gasoline and diesel fuel each year.

Despite objections from across the political spectrum, supporters of the mandate continue to argue that the RFS reduces gas prices, promotes economic growth, and contributes to a cleaner environment. In recent years however, reality has set in as each of these claims has been proven false and the RFS has been exposed for what it really is: a transfer of consumer wealth to the ethanol industry.

A Brief History of Biofuel Mandates

Like a lot of bad government policies, biofuel mandates began in the wake of a crisis caused by a separate government intervention. Congress passed the first biofuel tax credit in 1978 as part of the response to the oil crisis. Subsidies were later expanded starting with the Biomass Research and Development Act in 2000, the Healthy Forests Restoration Act of 2003, and the American Jobs Creation Act of 2004. In addition to that legislation, the various farm bills expanded biofuel programs creating what is now a complicated system of tax breaks, loan guarantees, and outright subsidies for biofuels.

The most notable of these programs remains the RFS, which originated in the Clean Air Act Amendments of 1990. This legislation mandated the sale of oxygenated fuels in certain parts of the country. The Energy Policy Act of 2005 mandated increases in the volume of renewable fuels that must be mixed into the supply of fuel over time. Then, in 2007, the Energy Independence and Security Act significantly raised the mandated quantities.

The Actual Effects of Biofuels Mandates

In February of 2017, the Heritage Foundation’s Nicolas Loris contributed an overview of the effects of biofuel programs to the Cato Institute’s Downsizing the Federal Government project. Here is his list of problems that biofuel mandates have created in the United States:

Cost for Drivers

“Ethanol is not a good substitute for regular gasoline because it contains less energy. Ethanol has only two-thirds the energy content of regular gasoline. Drivers get fewer miles per gallon the higher the share of ethanol and other biofuels mixed into their tanks.”

Food Prices

“Ethanol production uses a large share of America’s corn crop and diverts valuable crop land away from food production. The resulting increases in food prices have hurt both urban and rural families. Families with moderate incomes are particularly burdened by the higher food prices created by federal biofuel policies. Higher corn prices also hurt farmers and ranchers who use corn for animal feed. Higher food prices caused by biofuel policies also hurt low-income families in other countries that rely on U.S. food imports. U.S. corn accounts for more than half of the world’s corn exports.”

Environmental Harm

“Ethanol does have benefits as a fuel additive to help gasoline burn more cleanly and efficiently. However, in a report to Congress on the issue, the EPA projected that nitrous oxides, hydrocarbons, sulfur dioxide, particulate matter, ground-level ozone, and ethanol-vapor emissions, among other pollutants, would increase at different points in the production and use of ethanol… The problem with biofuel policies is that they are both harmful to the economy and they have negative environmental effects. Biofuel policies were sold as being “green,” but today’s high levels of subsidized biofuel use does not benefit the environment.”

The economic impacts of the RFS extend well beyond the fuel industry. The chemical makeup of ethanol can corrode the metal, rubber, and plastic components inside of an engine. It is impossible to say exactly how much of an effect this has on the economy, but we can be reasonably sure that this has diverted some degree of investment toward replacing capital damaged by the addition of ethanol to various types of fuel.

The RFS is also responsible for growing the size of the administrative state. The Energy Independence and Security Act created separate requirements for different types of biofuels and introduced a complex accounting system for greenhouse gases. Additionally, RFS compliance is tracked through the use of Renewable Identification Numbers (RINs). In order to meet the mandated levels established by the RFS, refiners must purchase a sufficient amount of RIN credits. My colleague Kenny Stein explained the problems with the credit system in a blog post earlier this year:

“The opaqueness of the system has left an opening for extensive fraud as well as speculation from entities outside the fuel industry looking to make a quick buck. A cynic might say that this is an unsurprising outcome in an artificial market that only exists because of government engineering.”

It’s clear that there is a gap between the stated goals of the RFS and the actual consequences of the policy. Like other attempts to centrally plan the energy industry, the RFS has raised costs for consumers, hampered economic growth, harmed the environment, and contributed to a culture of cronyism within the energy industry.


For many, it will be easy to ignore the EPA’s proposal because it is a comparatively modest increase to the RFS and well below what the biofuel industry is seeking. But sincere opponents of the RFS should reject even the smallest increase in the biofuel mandates because any increase in the total amount of subsidies provided to a special interest group makes the process of unwinding the program more difficult in the long run as the value of the new subsidies will quickly be capitalized into the value of the businesses the subsidies stand to benefit. This problem is known as the transitional gains trap. It is the primary reason why it is very difficult to get rid of unsuccessful government programs like the RFS.

As others at IER have stressed, policymakers should drop their plans to try to fix the problems with the RFS and pursue a route that targets completely eliminating this destructive policy. The EPA can take the first step in that direction by forgoing this proposed increase to the biofuel mandates for 2019.


The post The Biofuels Industry Retains Pull in Washington appeared first on IER.