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Wind Choked When it was Needed Most Wind

Posted March 27, 2014 | folder icon Print this page

Reliable energy sources and a diverse fuel mix are integral to maintaining America’s electric grid and keeping the lights on. The electric grid must be carefully balanced at all times so that supply matches demand or otherwise blackout would occur. This means that the grid needs reliable sources of generation to keep supply and demand matched at all times. New data on the polar vortex that swept the nation in January show how difficult this can be and highlight the perils of government policies designed to replace reliable energy sources with intermittent ones.

What we already know: as temperatures dropped across the country in early January, the cold weather increased demand for natural gas used both for home heating and for gas-fired electric generators. Surging demand, combined with constrained pipeline capacity, led to spiking prices and inadequate natural gas supplies (some customers had their natural gas service interrupted).



To meet the increased electricity demand and prevent power outages, grid operators relied on coal, nuclear, and even petroleum generating units. Wind energy, on the other hand, actually performed worst when it was needed most, according to new data from the PJM Interconnection. This further debunks the wind industry’s claim that wind energy plays an important role in keeping the lights on during low temperature events.

PJM’s data also highlight a fatal flaw in EPA’s proposed ban on coal-fired power plants. EPA assumes that no new coal plants will be built in the foreseeable future, but EPA failed to see that the problems caused by constrained pipeline capacity and a dwindling number of coal-fired power plants. EPA is causing coal facilities to shutter while subsidized and ill-timed wind power continues to force the premature closure of nuclear plants, creating an absence of reliable alternatives to natural gas and leaving Americans vulnerable to future and more dramatic price shocks.

Wind Choked When it was Needed Most

The PJM Interconnection is a regional grid operator that serves all or parts of 13 Northeastern, Mid Atlantic, and Midwestern states and the District of Columbia. Coal, nuclear, and natural gas together comprise 75 percent of the PJM’s electrical generating capacity (41 percent, 18 percent, and 16 percent, respectively). Wind energy accounts for less than one half of one percent of installed capacity.

In early January, the polar vortex increased energy demand and drove up natural gas prices. As temperatures plunged and demand rose, nuclear and coal generators picked up the slack. In contrast, according to PJM data, wind energy generation dropped from 4 gigawatts (GW) on January 6 to less than 2 GW during demand peaks on January 7 and less than 800 megawatts (MW) on January 9. The following graph from PJM compares grid load to wind generation during the height of the polar vortex.

PJM PolarVortex


While wind production declined steadily as demand rose, nuclear provided a reliable supply of generation to meet demand. Between January 4 and 8, the nation’s nuclear fleet operated at more than 95 percent of capacity, according to the Nuclear Energy Institute.

To illustrate the reliability differences between nuclear and wind, consider this. During the polar vortex, AWEA claimed “wind energy provided massive quantities of extremely valuable electricity when grid operators needed it most,” particularly in Texas, where wind made the “critical difference” in preventing outages. Far from providing “massive quantities” of energy, IER’s analysis found that wind energy operated at just 17 percent of its total capacity in Texas during the polar vortex. AWEA congratulates its industry for production at 17 percent of capacity while nuclear operating at 95 percent capacity goes unrecognized.

PJM’s data demonstrate that wind energy cannot be relied on to provide significant amounts of energy during peak demand. Unlike nuclear, coal, and natural gas, wind is an inherently variable energy source whose output is dictated by Mother Nature, not by consumer demand, prices, or emergency orders. This is why ERCOT, the Texas grid operator, counts only 8.7 percent of its wind capacity toward its reserve level.

Onerous Regulations Threaten the Electric Grid

The polar vortex shows the value of reliable energy to the electric grid. It also highlights the perils of government regulations designed to undermine reliable energy. The Nuclear Regulatory Commission put 38 nuclear units on a retirement list due to a number of factors, including regulatory costs. If all 38 at-risk units were prematurely retired, about one-third of the U.S. nuclear fleet would be shut down. Compounding this problem is the fact that few new nuclear units are scheduled to come on line to replace existing units. This means nuclear power’s contribution to the U.S. energy mix is likely to shrink.

Regulations are also forcing many coal plants into early retirement. EPA regulations will shutter 60 gigawatts, or 20 percent, of the nation’s coal-fired generating capacity by 2016, coinciding with the first year of enforcement for EPA’s Mercury Air Toxics Standards (MATS). But that’s not all, this summer EPA will propose carbon dioxide emission restrictions on existing coal-fired power plants. According to the Energy Information Administration, coal currently provides nearly 40 percent of America’s electricity, but this will decrease under EPA’s regulatory onslaught.

Reliable energy sources like nuclear and coal are needed to maintain the integrity of the electric grid, especially during peak demand. Onerous regulations aimed at shuttering reliable energy sources threaten to undermine grid reliability. In testimony before Congress in December, Philip Moeller, a commissioner for the Federal Energy Regulatory Commission (FERC), warned that the Midwest could experience rolling blackouts in 2016 due a shortfall of coal reserves after the MATS rule takes effect. Given FERC’s central role in ensuring the reliability of the nation’s power grid, policymakers should take notice when Commissioners signal that the grid is facing real reliability issues. Commissioner Moeller did not mention wind energy as a solution to the shortfall.


Reliable energy sources and a diverse fuel mix are essential to the electric grid. When natural gas prices spiked in early January amid record low temperatures, grid operators leaned on nuclear and coal to prevent power outages. These sources performed admirably, with nuclear operating at an average capacity of more than 95 percent.

Wind energy, unlike nuclear, coal, and natural gas, cannot be relied on to provide significant amounts of energy when it is needed most. In fact, wind energy actually became less reliable to the PJM grid operator during the polar vortex as temperatures dropped and demand soared. Even in Texas, where the wind industry claimed victory for the “massive quantities” of wind energy supplied to the grid during the polar vortex, wind energy operated at just 17 percent of its total capacity.

Onerous regulations imperil America’s supply of reliable energy, which in turn threatens grid reliability. EPA regulations, especially the MATS rule, will shutter 20 percent of U.S. coal-fired generating capacity by 2016 and more will close with EPA’s carbon dioxide restrictions. Meanwhile, almost 40 percent of the U.S. nuclear fleet has been put on a list of potential retirements. The polar vortex provides further evidence that government policies should support reliable energy, not undermine grid reliability. Failure to change course will only result in more of the same—price shocks, supply interruptions, and unreliable power.

IER Policy Associate Alex Fitzsimmons authored this post.


China Exceeds U.S. as Largest Net Importer of Petroleum Oil

Posted March 26, 2014 | folder icon Print this page

Oil Production in the United States has been growing by leaps and bounds due to shale oil production made possible by horizontal drilling and hydraulic fracturing and is now at a 25 year high. Oil production in 2013 totaled 7.5 million barrels per day, a level not seen since 1989. Oil production in 2013 was almost a million barrels per day higher than oil production in 2012—a 15 percent increase and the largest annual increase since 1940. The increase in oil production has brought a boom to other sectors with rail car oil shipments up 83 percent and the oil tanker construction business booming with over 15 tanker orders.  With greater oil production, the United States is importing less crude oil and petroleum– 16 percent less in 2013 than in 2012 on a net basis (imports minus exports).  In fact, as of September 2013, China has replaced the United States as the largest net importer of crude oil and petroleum.

Oil Production at a 25 Year High

The increased oil production in 2013 is mostly due to shale oil production in Texas and North Dakota. The Bakken oil field in North Dakota and the Eagle Ford in Texas together accounted for 83 percent of the oil production increase in 2013. The Bakken oil field averaged 0.9 million barrels per day in 2013 and the Eagle Ford produced an annual average of 1.22 million barrels per day. [i]

crude oil production growth


The record crude oil production pushed refinery utilization up to 88 percent for 2013 from 83 percent in 2009.

Due to the higher oil production, net crude oil and petroleum imports decreased to 6.2 million barrels per day—the lowest level since 1987. The 2013 level was 1.15 million barrels per day (16 percent) less than net crude oil and petroleum imports in 2012.  Net crude oil and petroleum imports reached their peak in 2005 at 12.5 million barrels per day and have declined by 50 percent from that peak.

China Exceeds U.S. in Net Petroleum Imports

In September 2013, China’s net imports of crude oil and petroleum products exceeded those of the United States, making it the largest net importer of crude oil and petroleum liquids in the world.  U.S. total annual petroleum liquids production is expected to increase to 13.4 million barrels per day in 2014 – a growth of 31 percent since 2011. With U.S. demand expected to be 18.9 million barrels per day in 2014, its net crude oil and petroleum import level in 2014 would be just 5.5 million barrels per day.[ii] China, on the other hand, is expected to increase demand to over 11 million barrels per day but increase its petroleum liquids production by just 5 percent to a third of U.S. production in 2014, making net crude oil and petroleum imports reach about 6 million barrels per day.

China v US Oil Imports

Source: Energy Information Administration,

In recent years, China has been diversifying the sources of its crude oil imports due to its oil demand growth and geopolitical uncertainties. Saudi Arabia continues to be the largest supplier of crude oil to China, providing 19 percent of China’s 5.6 million barrels per day of imports in 2013. China also imports from Oman, Iraq, the United Arab Emirates, Angola, Venezuela, Russia, Iran, Libya, and Sudan and South Sudan.[iii]

U.S. Oil Production Boom Creates Boom in Rail Shipments and Tanker Construction  

The U.S. oil production boom has created a boom in oil rail shipments, particularly given that the Keystone XL pipeline has been delayed by the Obama Administration for over 5 years now. According to the Association of American Railroads, major U.S. railways delivered 434,042 carloads of crude oil in 2013, 83 percent more than the amount shipped in 2012 (236,556 carloads of crude oil).[iv]

The U.S. energy boom is also having an effect on the country’s shipbuilding industry. Just three years ago, the oil tanker market was dormant in the United States, but was changed by the shale oil boom and the need to move the oil to refiners in the United States. According to the American Maritime Partnership, there are more than 15 oil tankers, along with hundreds of smaller tugs and barges, on order at U.S. shipyards across the country.  And it will take years to build them.

For example, two oil tankers are being constructed at the Aker Philadelphia Shipyard for SeaRiver Maritime, a subsidiary of Exxon Mobil, at a cost of $200 million each. To build the tankers, it takes about 1,000 employees, working more than a year.  The shipyard has orders for four more tankers and two container ships.[v]

While the domestic energy supply is booming, oil companies cannot use foreign ships to move oil and gas around the country due to a 1920 federal law called the Jones Act. Due to the Jones Act, vessels can only move between U.S. ports if they are flagged under U.S. law, crewed by American citizens and built in U.S. shipyards.  Since World War II, shipbuilding in the United States has declined dramatically with only a handful of major shipyards now constructing ships, mostly for the Navy. Thus, the industry is having a hard time meeting the demand for merchant ships at an affordable price. The cost of construction is about three times as much at U.S. shipyards as it is in shipyards in China, Japan and South Korea.


Advanced techniques like horizontal drilling and hydraulic fracturing have turned  our shale oil resources into an oil production bonanza that is reducing our dependence on foreign oil and creating a boom in rail shipments of crude oil and oil tanker construction. They have also helped to make the United States rank second to China in net crude oil and petroleum imports since September of last year.

But the industry is being hampered by Federal laws and policies that are making it difficult to move the crude oil around the country and to help our allies. Lack of adequate access to federal energy resources, a ban on crude oil exports in effect since 1975 due to the 1973 Arab Oil Embargo, a 5-year delay in providing a permit for the Keystone XL pipeline, and the 1920s Jones Act are all having  negative effects on the potential growth opportunity that domestic production promises. The Jones Act  has induced the construction of  over 15 tankers in  U.S. shipyards, which will take years to build, and make energy companies rely on rail, existing pipelines and road transport to move domestic oil and gas around the country.

[i] Wall Street Sector Selector, U.S. Oil Production Hits 25 Year High, March 14, 2014,

[ii] Energy Information Administration, Short-Term Energy Outlook, March 11, 2014,

[iv] The Hill, Railway crude oil shipments up over 83 percent, March 14, 2014,

[v] National Public Radio, A Boom in Oil Is A Boom for U.S. Shipbuilding Industry, March 14, 2014,


Coal Fired Units Shutting Down Despite Lower Generating Prices Coal

Posted March 25, 2014 | folder icon Print this page

The Energy Information Administration (EIA) is reporting that over 5 gigawatts of additional coal-fired plant retirements have been announced by owners and operators of the plants since November 2013 mainly to comply with EPA’s Mercury and Air Toxics Standards (MATS). These 5.4 gigawatts of recently announced retirements are above the 40 plus gigawatts that IER reported in this blog and likely part of the 60 gigawatts that EIA expects to be retired as part of its Annual Energy Outlook 2014 forecast, which is based on existing laws and regulations. Unfortunately, these retirements are only going to cause problems for the grid in keeping electricity on during peak demand periods and to increase prices for consumers. States with a significant amount of coal-fired capacity in the Central part of the United States have lower electricity prices on average than those that generate very little electricity from coal in the Northeast and in California.

The latest Announced Coal-Fired Plant Retirements

The 5,360 megawatts of announced coal-fired capacity to be retired include 21 units at 8 plants in 6 states that 5 companies are planning to shut down[i]:

  • The Tennessee Valley Authority (TVA) announced that it was retiring eight coal-fired units at 3 plants in Kentucky and Alabama totaling almost 3,000 megawatts of generating capacity. These 8 units are in addition to TVA’s previously reported retirement plans announced in 2011. While there are no fixed dates for the planned retirements, TVA indicated that these units will not operate beyond the MATS implementation date of April 2015.
  • South Carolina Electric & Gas announced the retirement of 2 units at the Canadys Station generating facility in South Carolina totaling 295 megawatts of capacity, ceasing operations in early November 2013. The company is closing the plant to reduce emissions and to comply with the MATS regulations.
  • Consumers Energy announced the retirement of 7 units at 3 plants in Michigan totaling 947 megawatts of capacity by April 2016.  The company is shutting down the units because the installation of additional emissions controls to comply with EPA environmental regulations would be uneconomical.
  • Energy Capital Partners is retiring 3 coal-fired units at the Brayton Point generating facility in Massachusetts totaling 1,084 megawatts of capacity in 2017. The company failed to reach a deal with the Independent System Operator of New England (ISONE) on a new power-purchase agreement, which expires on May 30, 2016. Energy capital Partners is also retiring a 435 megawatt generator run on natural gas at Brayton Point.
  • Georgia Power announced the retirement of a 155 megawatt unit at its Mitchell generating facility in Georgia before the end of April 2015. The company had considered converting the unit to biomass, but the conversion was determined to be uneconomic.


Source: Energy Information Administration,

Coal Was Used Heavily during This Winter’s Frigid Weather

Masses of arctic air from the North Pole drove electricity prices this past winter to more than 10 times the previous year’s average in many parts of the country and threatened some areas with winter blackouts. To keep the lights on and houses warm, many parts of the country turned to coal during this extreme cold weather period.  Due mainly to infrastructure issues in natural gas deliverability, natural gas prices skyrocketed this past winter and coal-fired power plants were called upon since coal is less prone to price spikes and shortages.

For example, American Electric Power, which serves Columbus and a vast area of the Midwest, was running 89 percent of the coal plants that it must retire next year. At Muskingum River, three units of a five-boiler coal plant about 100 miles southeast of Columbus were operated during the cold weather period. Two of the five units need half-million-dollar repairs, which will not be undertaken since they must close before those investments can be recouped. The newest unit, commissioned in 1968, will close because it needs upgrades to comply with EPA regulations that would cost hundreds of millions of dollars.[ii]

In the Pennsylvania, New Jersey and Maryland interchange, 12,000 megawatts of coal-fired capacity is retiring. That independent system operator recently set a peak record for winter energy use of around 140,000 megawatts and its summer record is 168,000 megawatts. Although enough capacity is available and new gas-fired units are being built, the pipeline infrastructure has not been sufficient to get the gas to demand centers when most needed, and pipeline permitting has become more difficult for fossil energy projects .

In December, the Federal Energy Regulatory Commission warned Congress that there could be rolling blackouts by 2016 in the U.S. Midwest due to a projected shortfall in power reserves because of coal plant retirements.[iii] Other areas of the country are having similar concerns.

Without the coal plants, electricity prices in the peak periods of winter and summer will likely be higher, so future periods of cold weather will be harder on consumers’ electric bills. Because an unprecedented amount of coal units are retiring in a short period of time, the change is likely to be accompanied by more price volatility.

It is not only coal that is disappearing from the electric generating mix. So is nuclear energy. Last year, the Kewaunee reactor in Wisconsin was closed because it is a merchant plant and cannot produce power at a competitive rate in the Midwest electricity market. Vermont Yankee, a nuclear power station in Vernon, Vermont, is also scheduled to close because as a merchant plant its cost of production is higher than the market rate for power. In California, at the San Onofre plant, two nuclear reactors are closing because of delays at the Nuclear Regulatory Commission in renewing licenses and approving operation after a down period for maintenance.

During the polar vortex all but 3 of the nation’s 100 nuclear reactors were operating at 90 percent of their capacity.

This winter’s cold weather and the natural gas infrastructure problems have illustrated the need for diverse sources of energy supply. But, the nation’s regulators so far are not fully accounting for the need for that diversity. Or, the regulators could be working to fulfill President Obama ’s vow to make electricity prices “skyrocket.”

Major Coal States Have Lower Electricity Prices

Coal-fired generation is still the largest source of generation in the United States producing about 40 percent of the nation’s electricity. But, onerous regulations by the EPA and low natural gas prices have lowered its share from a high of over 50 percent. The states that use coal for the largest share of their generation have electricity rates that are 33 percent lower than other states.  As the graph below shows the states in the central part of the nation that generate a major share of their electricity from coal had average electricity prices in 2012 at 9.45 cents per kilowatt hour, which compares to California electricity prices at 13.9 cents per kilowatt hour, and electricity prices in the Northeast at 14.5 cents per kilowatt hour.[iv]  California and the Northeast have reduced their coal-fired generation to just one percent, and are relying on natural gas and renewables to generate most of their electricity.




Coal-fired power plants are closing at an alarming rate due to EPA’s MATS rule, and the regulatory blizzard is just beginning. These units were used heavily during this past winter to supply power when infrastructure problems caused natural gas prices to skyrocket. Grid operators are warning the country that electric power may be insufficient to meet demand next winter due to these retirements and those of several nuclear reactors. Yet, the EPA is not letting up on its onerous regulations regarding coal-fired power plants with more to come this spring/summer.   A looming storm is building for electricity production in the United States, and few policy makers have been paying attention.  Consumers are not apt to be happy with rapidly accelerating electricity bills and an increased likelihood of insufficient supply.

[i] Energy Information Administration, Planned coal-fired power plant retirements continue to increase, March 20, 2014,

[iii] Bloomberg Business Week, Polar Vortex Emboldens Industry to Push Old Coal Plants, March 10, 2014,

[iv] Advanced Energy for Life, How Coal Can Alleviate Pain at the Plug,


Ukraine: An Important Transit Country for Natural Gas and Petroleum

Posted March 24, 2014 | folder icon Print this page

The Ukraine produces some oil, natural gas, and coal that it uses for domestic consumption, but it must also import these fuels in order to meet demand. The Ukraine’s major importance, however, is as a natural gas and petroleum transit country due to its geographic position and proximity to Russia. In 2013, about 3.0 trillion cubic feet of natural gas flowed through the Ukraine to countries in Eastern and Western Europe, providing 16 percent of Europe’s natural gas consumption. Three major pipeline systems move natural gas from Russia through the Ukraine to Europe and another pipeline moves petroleum.

Ukraine’s Energy Supply and Demand

Most of the Ukraine’s primary energy consumption is fueled by natural gas (40 percent), coal (28 percent), and nuclear (18 percent). In 2012, the Ukraine consumed 1.8 trillion cubic feet of natural gas, producing 37 percent domestically and importing the rest from Russia. A relatively small portion of the country’s total energy consumption is supplied by petroleum and renewable energy sources. In 2012, the Ukraine consumed 319,000 barrels per day of liquid fuels, producing 25 percent domestically and importing the remainder primarily from Russia with some deliveries coming from Kazakhstan and Azerbaijan.

The Ukraine obtains almost half of its electricity from its 15 nuclear reactors and most of the remainder comes from fossil fuels (46 percent) and hydroelectric power (6 percent).  It generates some electricity from wind power (less than 1 percent). The country consumed 78.5 million short tons of coal in 2012, with 90 percent produced domestically.

Payment issues between Russia and the Ukraine have caused Russia to stop deliveries of natural gas and crude oil to the Ukraine in the past with the most recent stoppage over oil deliveries occurring in January 2014 and over natural gas deliveries in 2009.

The Ukraine has an estimated 128 trillion cubic feet of technically recoverable shale gas that could provide the country with a means to diversify its natural gas supplies away from Russia if developed. In January 2013, Shell agreed to explore an area that the government estimates holds about 4 trillion cubic feet of shale natural gas. The Ukraine is planning to develop its shale gas resources by 2020.

Pipelines Transecting the Ukraine

The Bratstvo (“Brotherhood”) and Soyuz (“Union”) pipelines move natural gas from Russia to Western Europe. The Bratstvo pipeline, Russia’s largest natural gas pipeline to Europe, crosses from Ukraine to Slovakia and then splits into two, supplying northern and southern European countries. The Soyuz pipeline links Russian pipelines to natural gas networks in Central Asia and provides natural gas to central and northern Europe. A third major pipeline delivers natural gas from Russia through the Ukraine to the Balkan countries and Turkey.

Nat Gas Pipeline Ukraine

Source: Energy Information Administration,

In 2013, Russia supplied 30 percent of Europe’s natural gas consumption totaling 18.7 trillion cubic feet.  That includes the natural gas consumption of all of the members of the European Union and Turkey, Norway, Switzerland, and the Balkan states. Based on data reported by Gazprom and Eastern Bloc Energy, EIA estimates that 16 percent of the total natural gas consumed in Europe passed through the Ukraine’s pipeline network. Natural gas shipments vary by season, ranging from almost 12 billion cubic feet of natural gas per day in the winter compared to 6 billion cubic feet per day in the summer.

In the past, as much as 80 percent of Russian natural gas exports to Europe transited the Ukraine. That was changed in 2011 when the Nord Stream pipeline that directly links Russia with Germany under the Baltic Sea came on line, reducing that number to 50 to 60 percent.

The southern leg of the Druzhba oil pipeline moves Russian crude oil through the Ukraine, supplying most of the oil consumed by Slovakia, Hungary, Czech Republic, and Bosnia. In 2013, about 300,000 barrels per day of oil transited the pipeline, about 75 percent of its capacity. Crude oil and petroleum products from Russia are also shipped by rail through the Ukraine for export out of the country’s ports.

Can U.S. Abundant Energy Help?

Policy makers are calling on the United States to help with the developing energy crisis in the Ukraine and potentially Europe.  Some of the recent remarks include:

  • Sen. John Hoeven wants the United States to put together a broad strategy to help the Ukraine become more energy secure and reduce its dependence on Russian natural gas.
  •  Sen. Chris Murphy was speculative about the imposed sanctions, “I mean there’s no doubt that if you cut off Russian gas to Europe, it will hurt. There’s no doubt that if you freeze Russian assets in places like Germany and Great Britain, it will hurt them.”
  • Senator Richard Lugar, formerly head of the Senate Foreign Relations Committee, indicated that exporting LNG and building the Keystone XL oil pipeline are strong signals the United States is still invested in fossil fuels. While the politics of both are tumultuous, and any gas exports will “have to strike a balance” with businesses that rely on cheap natural gas in their production processes, “American interests diplomatically and strategically are clearly to get more permits. The fact is we do have the ability and that could make a huge difference because we can send this gas strategically in various directions, and a lot of it.”

In 2012, Russia exported $160 billion worth of crude, fuels and gas-based industrial feedstocks to Europe and the United States. These exports are a major part of the Russian economy, but as can be seen above, European countries are very dependent on their imports of these fuels from Russia. According to Germany’s Chancellor, Angela Merkel, Germany is willing to take the pain that Russian retaliation to sanctions would bring. But that may not be the case for other European countries, who together imported 32 percent of their raw crude oil, fuels and gas-based chemical feedstocks from Russia in 2012. But, this crisis is making the European Union more eager to secure access to U.S. oil and natural gas supplies, which means lifting the ban on oil exports and approving more liquefied natural gas (LNG) export terminals.

The U.S. Department of Energy (DOE) has approved 6 applications for LNG export terminals and the Federal Energy Regulatory Commission has approved a permit for one of those facilities that should beginning operating by the end of 2015. The other 5 may not begin operating until 2017 or 2018. Another 22 applications are awaiting DOE approval. Thus, none of these facilities will be able to help the current crisis with Russia and the Ukraine. Further, most of the early LNG imports are expected to go to Asian buyers under long-term contracts where LNG prices have been about 50 percent higher than in Europe.

It is also not clear that the companies wishing to build these terminals at this time will find it beneficial once the approvals are complete. It is very expensive to build LNG export terminals and those upfront costs will have to be recouped in the price of the LNG. Also, while U.S. natural gas prices are low at this time due to hydraulic fracturing, it is not clear if U.S. natural gas prices will remain at their current $3 or $4 per million Btu level into the future when the companies of these export terminals will still need to recoup their upfront costs. EIA is forecasting that U.S. natural gas prices at the Henry Hub will increase at a rate of 3.7 percent per year between 2012 and 2040.


European countries, including the Ukraine, are dependent on Russia for natural gas and petroleum, and the Ukraine is a major transit country for pipelines and other transshipment of these fuels from Russia. The current crisis in the Ukraine is indicative of the importance of diversity of energy supply and the sources of that supply. For example, the fact that the Ukraine gets almost half of its electricity from nuclear power and mines most of its own coal is beneficial given its dependence on Russian oil and natural gas.

While the United States is a major producer of natural gas, oil, and coal, it is difficult for it to be responsive to current European natural gas needs when the only approved LNG export terminal will not be operating before the end of 2015. But, what the United States can do is formulate an energy strategy for the future for meeting both U.S. needs and those of our allies, as well as exporting the policies and technologies that created the hydraulic fracturing revolution and attendant oil and natural gas boom in the United States. Ensuring a diverse energy portfolio that includes nuclear and coal should also be at the forefront of that strategy.


Natural Gas: How Much Can We Ask Of “The Bridge Fuel”? Natural Gas

Posted March 20, 2014 | folder icon Print this page

Thanks to hydraulic fracturing and anti-coal regulations, low cost and abundant natural gas is displacing coal in the electric generation sector and many have argued that it should replace diesel used by heavy duty trucks in the transportation sector. The low cost of natural gas coupled with regulatory favoritism currently makes natural gas the nation’s fuel of choice. But just how far can this natural gas renaissance take the nation in replacing coal as a utility fuel and petroleum for use in heavy trucks? Let’s take a look.

Natural Gas Use Today

In the United States, natural gas consumption and production remained relatively flat from 1970 through 2005, after which natural gas production from shale plays began increasing rapidly. Since 2005, natural gas production has increased almost twice as fast as its consumption, growing to 24.3 trillion cubic feet in 2013.

Screen Shot 2014-03-20 at 10.08.23 AMSource: Energy Information Administration,

Between 2008 and 2013, U.S. natural gas consumption increased by 12 percent to 26 trillion cubic feet in 2013 due to its abundance, low cost, and ease of use. More than half of the homes in the United States use natural gas as their main heating fuel. Natural gas is also used in homes to fuel stoves, water heaters, clothes dryers, and other household appliances. Natural gas is used in the industrial sector to produce steel, glass, paper, clothing, brick, and as a raw material for many common products. Some products that use natural gas as a raw material are paints, fertilizer, plastics, antifreeze, dyes, photographic film, medicines, and explosives. Natural gas has been a major fuel for electric generation for many decades, but it is increasingly being used in electric generation to replace coal and to back-up intermittent renewable technologies such as wind and solar.

Screen Shot 2014-03-20 at 10.09.35 AM Source: Energy Information Administration,

The largest percentage increase in natural gas consumption occurred between 2008 and 2012, when electric utility consumption of natural gas increased by 38 percent, but natural gas lost some of that gain in 2013 when natural gas prices increased and coal regained some of the share of generation lost in 2012. Regardless, natural gas is still the fuel of choice for new electric generation plants since proposed EPA regulations are essentially banning the construction of any new coal fired generating plants and EPA admits in their proposed regulation that no new coal plants will be built in the next 10 years.

natural-gas-bridge-fuel-1Source: Energy Information Administration,

Projected Natural Gas Production and Use in 2040

The Energy Information Administration expects dry natural gas production to increase by over 50 percent, from 24 trillion cubic feet in 2012 to 37.5 trillion cubic feet in 2040 due mainly to continued growth in shale gas production resulting from horizontal drilling and hydraulic fracturing. Shale gas production is expected to more than double between 2012 and 2040, reaching 19.8 trillion cubic feet in 2040. Of this production, EIA is forecasting that 5.8 trillion cubic feet would be exported on net in 2040 in combined pipeline and liquefied natural gas exports.

In EIA’s forecast, domestic natural gas consumption increases from 25.6 trillion cubic feet in 2012 to 31.6 trillion cubic feet in 2040 (23 percent). The largest share of the growth is for electricity generation, but industrial demand also increases due to competitive natural gas prices. Demand for natural gas in the electric power sector increases from 9.3 trillion cubic feet in 2012 to 11.2 trillion cubic feet in 2040 to replace the expected retirement of coal-fired capacity due to EPA regulations and to support a modest growth in electricity demand. As coal-fired plant retirements outpace new coal-fired capacity additions, coal-fired generating capacity is expected to decline by more than 15 percent.

Screen Shot 2013-12-17 at 7.29.19 AM

Source:  Source: Annual Energy Outlook 2014,

Natural Gas Displacing Coal Use

EIA is not forecasting the demise of coal-fired generation in the electric generation sector because the agency’s forecast is based on existing laws and regulations. So, although the EPA is proposing to implement a regulation during this spring or summer limiting carbon dioxide emissions from existing coal-fired power plants, that regulation was not included in EIA’s 2014 Annual Energy Outlook. But, it is possible that future EPA regulations could essentially ban coal-fired generation (especially if Congress and the courts fail to rein in EPA). Therefore, it is important to assess what the impact on energy supply flows would be in the event EPA proposes a regulation that would effectively achieve the goals of those who oppose the use of coal in the United States.  Such a regulation would lead to the retirement of all existing coal-fired power plants since technology is not commercially available to reduce carbon dioxide emissions from coal plants to the levels that EPA is demanding of new coal-fired power plants.  Let’s look at how much more natural gas the nation would need if it were to replace all the coal-fired power plants in the United States with natural gas.

In 2013, coal-fired plants generated 1,585,998 million kilowatt hours of electricity, according to EIA. Assuming that natural gas combined cycle plants would replace all of that generation, the nation would need 10.8 trillion cubic feet of natural gas beyond that already used to generate electricity in this country, assuming a heat rate for combined cycle of 7,000 Btus per kilowatt hour.   That would increase natural gas consumption from 26.0 trillion cubic feet in 2013 to 36.8 trillion cubic feet if this feat could happen overnight. Since that is not likely, let’s assume this transition will take place over the next 25 years and see how the demand for natural gas would change in EIA’s forecast if the coal-fired generation in 2040 was replaced by natural gas.

Using the same assumption as above for the 2013 calculation, EIA is forecasting that coal-fired power plants would generate 1,675,000 million kilowatt hours of electricity in 2040—about 90,000 million kilowatt hours more than coal’s 2013 generation level (despite EIA’s estimate of  over 50 gigawatts of coal capacity that the agency assumes will be retired due to EPA regulations) since not all the coal-fired capacity in 2013 was utilized. Converting EIA’s coal generation in 2040 to natural gas means 11.5 trillion cubic feet of natural gas would need to be added to the natural gas demand in 2040 that EIA has forecasted. That means total annual domestic natural gas consumption in 2040 would be 43 trillion cubic feet of natural gas (compared to 26.0 trillion cubic feet of natural gas consumption in 2013). Even if the United States did not export any pipeline gas or liquefied natural gas, total domestic production of natural gas of 37.5 trillion cubic feet in EIA’s forecast in 2040  could not meet this demand level and the nation would need to import an additional 5.5 trillion cubic feet of natural gas.

Besides becoming a net importer of natural gas, the United States would need to add significant additional pipeline infrastructure to ensure the gas reaches the many new natural gas fired power plants that would be dotting the landscape. As it is, the pipeline infrastructure was insufficient in the Northeast to get the natural gas to demand centers when cold weather hit during this past winter, and in California and even Texas, consumers were warned to reduce power consumption because of natural gas supply problems. The amount of additional infrastructure that would be needed to replace the coal-fired plants would far exceed this winter’s shortage in pipeline capacity. Further, the construction of those new natural gas fired power plants would cost billions of dollars and raise the price of electricity to consumers who would need to pay for the replacement of the coal-fired power plants targeted by EPA regulation. At an overnight capital cost of about $1,000 per kilowatt, it would cost about $260 billion to replace the coal-fired units in EIA’s forecast in 2040 with natural gas-fired units. Because overnight capital costs exclude finance charges, the actual costs would be much higher.

Of course, wind and solar power would replace some of the lost coal-fired generation. Wind and solar power combined currently generates just 4.4 percent of the nation’s electricity despite adding wind power adding 30 percent of all new electric capacity additions over the past 5 years. Because  wind and solar plants supply intermittent power, they would need to be backed up with reliable natural gas-fired generation. Further, the capacity factors of new combined cycle plants fueled with natural gas are more than 2.5 times that of new wind plants and 3.5 times that of new solar photovoltaic plants providing much more electricity for an equivalent amount of capacity.  Intermittent supplies of electricity carry with them the hidden costs of requiring additional capacity to be bought and maintained to operate when the sun or wind resource are not available.

Converting the Heavy Truck Fleet to Natural Gas

There are some advocates who also favor converting heavy duty trucks, mostly powered by diesel, to natural gas. In EIA’s 2014 forecast, natural gas used to power heavy trucks is the fastest-growing fuel source for new heavy duty trucks, increasing at a rate of 21 percent per year. In 2040, EIA forecasts that the heavy duty truck fleet will consume 102 trillion Btu of motor gasoline; 5,189 trillion Btu of diesel; 599 trillion Btu of natural gas; and 13 trillion Btu of propane.[i] Assuming the proponents’ goal that all of the fleet was converted to natural gas instead would require an additional 5,039 trillion Btu[1] of natural gas or an additional 4.9 trillion cubic feet of natural gas. That would make the demand for natural gas in the United States in 2040 — when combined with the closure of the coal plants — equal to 47.9 trillion cubic feet—10.4 trillion cubic feet  more than the production EIA expects, which would need to be imported.


Status of Liquefied Natural Gas Terminal Approvals

Companies in the United States are allowed to freely export natural gas to Canada, Mexico and other countries with which the United States has a free-trade agreement. However, to export to any other country, companies must obtain approval from the Department of Energy, who must determine that those sales are in the public interest before approval can be granted. The Energy Department has so far approved only six applications out of more than two dozen.[ii] Those six export terminals have a combined export capacity of 8.7 billion cubic feet a day for a total of 3.2 trillion cubic feet a year. Once approval is obtained from the Department of Energy, the export terminal must get a permit from the Federal Energy Regulatory Commission (FERC) before construction can begin. So far, only one company, Cheniere, has been granted a combined operating license from FERC and expects to be operating at the end of next year. There is another 26.88 billion cubic feet per day (9.8 trillion cubic feet per year) of natural gas in the queue at the Department of Energy for approval. Thus, the total amount of capacity from export terminals to non free trade agreement countries is 13 trillion cubic feet, just 3.4 trillion cubic feet less than the amount of natural gas that is needed to replace the coal-fired capacity and the heavy truck fleet in the United States by 2040.

It is unlikely that all of these LNG export projects will come to fruition for the technology is expensive and to be competitive on the world market, domestic natural gas prices need to remain low.  Costs for building liquefaction plants (gas has to be super cooled so that it can be loaded onto large ships) are high around the globe. Project costs for building gas export infrastructure in Australia, for example, have increased between 20 and 40 percent. In Australia, seven projects are under construction at a total cost of about $150 billion. When Chevron’s Gorgon LNG project in Australia is completed, the total cost is expected to be about $52 billion. In Papua New Guinea, Exxon Mobil is building a $20 billion LNG export terminal.[iii]

Companies in the LNG export business need to recoup the large up-front costs of constructing liquefaction and export facilities. The first ones built should have an easier time recovering those costs as prices for LNG in Asia are high and domestic natural gas prices are low. But others could face issues given the domestic price of natural gas, the sustainability of current global pricing structures, and competition from other sources of supply.[iv]

Domestic natural gas prices are not expected to remain at the $3 to $4 dollar range forever. The Energy Information Administration is predicting that natural gas prices at the Henry Hub will increase from $2.75 in 2012 to $7.65 per million Btu in 2040 in real terms, a growth rate of 3.7 percent per year.

Natural Gas Resource Base

The United States has a tremendous resource base of natural gas. According to EIA, our reserves at the end of 2011 totaled 334 trillion cubic feet, almost a doubling in 10 years despite our continued use of the resource. These reserves come from our technically recoverable resource base of natural gas, which the Institute for Energy Research estimated to be 2.744 quadrillion cubic feet. While the resource base is extremely large, its recoverability is dependent on technology and price. Therefore, energy policy makers need to be clear on the competing uses of natural gas and decide what is best for the nation and its energy policy goals.


Natural gas is a versatile energy resource and since it is the fossil fuel with the lowest emissions of carbon dioxide, it is in demand in all sectors of the economy. It has lowered carbon dioxide emissions in the electric generating sector, resulted in the resurgence of the industrial sector in the United States, and remains the major fuel in the residential sector heating homes and providing energy to other appliances in many households. It is being eyed to replace coal in the electric generation sector, to be used to fuel the heavy truck fleet, and to be exported to nations that need more favorably priced natural gas or are dependent on Russian natural gas. Those uses could create a large demand for the fuel that will require huge up front capital costs, large infrastructure changes, and the need to produce much, much more natural gas in the future than our forecasters are predicting.

Moreover, significant voices in the anti-fossil energy political movement are pressuring the U.S. government to take steps to curtail the production of more natural gas in the United States on many fronts.  These include making it harder to produce, transport and consume, and among their targets are hydraulic fracturing, methane, and the carbon emissions from natural gas. All of these matters need to be seriously considered when policy makers are deciding what role they want natural gas to play in the future.

[1] Because compression ignition natural gas engines require about 5 percent use of diesel fuel to ignite the natural gas, only 95 percent of the fuel is assumed to be replaced.

[i] Energy Information Administration, Annual Energy Outlook 2014, Table 68,

[ii] Capital Alpha Partners LLC, LNG Exports: Who Gets permits When?, March 2014,

[iii] EE News, Skyrocketing costs plague push to ‘liberalize’ LNG market, March 12, 2014,

[iv] Power Engineering, Are U.S. Companies Being realistic About Global LNG Prices?, March 10, 2014,


U.S. Oil Production Reaches Highest Levels Since 1989 Oil

Posted March 13, 2014 | folder icon Print this page

U.S. oil production averaged 7.5 million barrels per day (bpd) in 2013, reaching the highest levels since 1989, according to new data from the Energy Information Administration (EIA). Domestic oil production hit 7.9 million bpd in December 2013, an 11 percent increase compared to December 2012. The following chart shows U.S. oil production between 1989 and 2013. Meanwhile, on the federal OCS, production again went down.


Domestic oil output rose by 966,000 bpd—15 percent—between 2012 and 2013, the largest annual percentage increase since 1940. Texas and North Dakota drove the boom, accounting for 83 percent of U.S. production growth since 2000. In December 2013, the Eagle Ford shale formation in Texas produced 1.22 million bpd, while the Bakken shale formation in North Dakota eclipsed 1 million bpd, according to EIA’s Drilling Productivity Report.

Thanks to the shale boom on state and private lands, America is now rapidly displacing imported oil with domestic production. Oil imports fell to their lowest levels since 1996 and 30 percent below the June 2005 peak of 10.7 million bpd, according to EIA. Domestic oil production now supplies 49 percent of U.S. oil demand, up from 43 percent in 2012.

EIA offers a bullish forecast for future growth in domestic oil production. EIA’s latest Drilling Productivity Report predicts combined oil production in key regions (Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, and Permian) to increase by a combined 67,000 bpd in April. EIA expects the Bakken to hit nearly 1.1 million bpd in April and the Eagle Ford to eclipse 1.35 million bpd.

America’s domestic energy boom is made possible by recent technological advancements that combine hydraulic fracturing and horizontal drilling to access previously inaccessible oil trapped in dense shale rock formations. This boom, however, is occurring almost entirely on state and private lands on which the federal government has little control. On lands owned by the federal government, domestic energy production has actually fallen by 15 percent over the last two years. America is becoming more energy secure despite federal policies that restrict access to the country’s vast energy resources. Americans are left to wonder how much more oil we could produce if not for federal policies designed to obstruct domestic energy development.

IER Policy Associate Alex Fitzsimmons authored this post.