Renewable subsidies in Spain, Germany, Italy, and the UK

HRG. 113-623. 2014-7-22. U.S. Security implications of international energy and climate policies and issues. U.S. Senate 113th congress 

MARY HUTZLER, Distinguished senior fellow, Institute for Energy Research, Berlin, MD

RENEWABLE SUBSIDIES IN EUROPE

Spain (Also see Spain’s Photovoltaic Revolution)

In order to enhance renewable energy sources in Spain, the Government enacted legislation to reach 20% of electric production from qualified renewable energy by 2010. To meet this target, the government found it needed to provide incentives to ensure the market penetration of renewable energy, including providing above-market rates for renewable-generated electricity and requiring that electric utility companies purchase all renewable energy produced. In 1994, Spain implemented feed-in tariffs to jump start its renewable industry by providing long-term contracts that pay the owners of renewable projects above- market rates for the electricity produced.18

Because renewable technologies generally cost more than conventional fossil fuel technologies, the government guaranteed that renewable firms would get a higher cost for their technologies. But, because the true costs of renewable energy were never passed on to the consumers of electricity in Spain, the government needed to find a way to make renewable power payments and electricity revenues meet. Since 2000, Spain provided renewable producers $41 billion more for their power than it received from its consumers. 19 (For reference, Spain’s economy is about one-twelfth the size of the U.S. economy.) In 2012, the discrepancy between utility payments to renewable power producers and the revenue they collected from customers was 5.6 billion euros ($7.3 billion), despite the introduction of a 7% on generation. 20 The 2012 gap represented a 46% increase over the previous year’s shortfall.

A massive rate deficit should not come as a surprise. For 5 years, IER has warned of this problem beginning when Dr. Gabriel Calzada released his paper on the situation in Spain and testified before Congress.21 He found that Spain’s ‘‘green jobs’’ agenda resulted in job losses elsewhere in the country’s economy. For each ‘‘green’’ megawatt installed, 5.28 jobs on average were lost in the Spanish economy; for each megawatt of wind energy installed, 4.27 jobs were lost; and for each megawatt of solar installed, 12.7 jobs were lost. Although solar energy may appear to employ many workers in the plant’s construction, in reality it consumes a large amount of capital that would have created many more jobs in other parts of the economy. The study also found that 9 out of 10 jobs in the renewable industry were temporary. 22, 23

Spain’s unemployment rate has more than doubled between 2008 and 2013. In January 2013, Spain’s unemployment rate was 26% the highest among EU member states.24 Spain’s youth unemployment (under the age of 25) reached 57.7% in November 2013, surpassing Greece’s youth unemployment rate of 54.8% in September 2013. 25

The Spanish Government did not believe Dr. Calzada 5 years ago, but they have now been hit in the face with reality. To recover the lost revenues from the extravagant subsidies, the Spanish Government ended its feed-in tariff program for renewables, which paid the renewable owners an extremely high guaranteed price for their power as can be seen by the deficit. Currently, renewable power in Spain gets the market price plus a subsidy which the country deems more ‘‘reasonable.’’ Companies’ profits are capped at a 7.4% return, after which renewable owners must sell their power at market rates. The measure is retroactive to when the renewable plant was first built.26 Therefore, some renewable plants, if they have already received the 7.4% return, are receiving only the market price for their electricity.

 

Wind projects built before 2005 will no longer receive any form of subsidy, which affects more than a third of Spain’s wind projects. As a consequence of the government’s actions to rein in their subsidies and supports, Spain’s wind sector is estimated to have laid off 20,000 workers.

The Spanish Government also slashed subsidies to solar power, subsidizing just 500 megawatts of new solar projects, down from 2,400 megawatts in 2008.27 Its solar sector, which once employed 60,000 workers, now employs just 5,000. In 2013, solar investment in Spain dropped by 90 percent from its 2011 level of $10 billion.

Spain’s 20% renewable energy share of generation from wind and solar power has come at a very high cost to the nation.

Germany

In Germany, as part of the country’s ‘‘Energiewende,’’ or ‘‘energy transformation,’’ electric utilities have been ordered to generate 35% of their electricity from renewable sources by 2020, 50% by 2030, 65% by 2040, and 80% by 2050. To encourage production of renewable energy, the German government instituted a feed-in tariff early, even before Spain.

In 1991, Germany established the Electricity Feed-in Act, which mandated that renewables ‘‘have priority on the grid and that investors in renewables must receive sufficient compensation to provide a return on their investment irrespective of electricity prices on the power exchange.’’ 28 In other words, utilities are required to purchase electricity from renewable sources they may not want or need at above-market rates. For example, solar photovoltaics had a feed-in tariff of 43 euro cents per kilowatt hour ($0.59 U.S. per kilowatt hour), over 8 times the wholesale price of electricity and over 4 times the feed-in tariff for onshore wind power. A subsequent law passed in 2000, the Renewable Energy Act (EEG), extended feed-in tariffs for 20 years.29 Originally, to allow for wind and solar generation technologies to mature into competitive industries, Germany planned to extend the operating lives of its existing nuclear fleet by an average of 12 years. But, the Fukushima nuclear accident in Japan caused by a tsunami changed Germany’s plans and the country quickly shuttered 8 nuclear reactors and is phasing out its other 9 reactors by 2022, leaving the country’s future electricity production mostly to renewable energy and coal. 30

Coal consumption in Germany in 2012 was the highest it has been since 2008, and electricity from brown coal (lignite) in 2013 reached the highest level since 1990 when East Germany’s Soviet-era coal plants began to be shut down. German electricity generation from coal increased to compensate for the loss of the hastily shuttered nuclear facilities. Germany is now building new coal capacity at a rapid rate, approving 10 new coal plants to come on line within the next 2 years to deal with expensive natural gas generation and the high costs and unreliability of renewable energy.31 As a result, carbon dioxide emissions are increasing.

While the United States is using low cost domestic natural gas to lower coal-fired generation, in Germany, the cost of natural gas is high since it is purchased at rates competitive with oil. Also, Germany is worried about its natural gas supplies since it gets a sizable amount from Russia. While domestic shale gas resources are an alternative, particularly since the Germans are hydraulic fracturing pioneers and have used the technology to extract tight gas since the 1960s, Germany’s Environment Minister has proposed a prohibition on hydraulic fracturing until 2021 in response to opposition from the Green Party.33 According to the Energy Information Administration, Germany has 17 trillion cubic feet of technically recoverable shale gas resources.34

Germany has some of the highest costs of electricity in Europe and its consumers are becoming energy poor. In 2012, the average price of electricity in Germany was 36.25 cents per kilowatt hour,35 compared to just 11.88 cents for U.S. households, triple the U.S. average residential price.36 These prices led Germany’s Energy Minister to recently caution that they risk the ‘‘deindustrialization’’ of the economy.

In addition to high electricity prices, Germans are paying higher taxes to subsidize expensive green energy. The surcharge for Germany’s Renewable Energy Levy that taxes households to subsidize renewable energy production increased by 50 percent between 2012 and 2013—from 4.97 U.S. cents to 6.7 cents per kilowatt hour, costing a German family of 4 about $324 US per year, including sales tax.37 The German Government raised the surcharge again at the start of this year by 18% to 8.61 US cents per kilowatt hour representing about a fifth of residential utility bills,38 making the total feed-in tariff support for 2014 equal to $29.6 billion US.39 As a result, 80 German utilities had to raise electricity rates by 4%, on average, in February, March, and April of this year.

The poor suffer disproportionately from higher energy costs because they spend a higher percentage of their income on energy. As many as 800,000 Germans have had their power cut off because of an inability to pay for rising energy costs, including 200,000 of Germany’s long-term unemployed.40

Adding to this is a further disaster. Large offshore wind farms have been built in Germany’s less populated north and the electricity must be transported to consumers in the south. But, 30 wind turbines off the North Sea island of Borkum are operating without being connected to the grid because the connection cable is not expected to be completed until sometime later this year. Further, the seafloor must be swept for abandoned World War II ordnance before a cable can be run to shore. The delay will add $27 million to the $608 million cost of the wind park. And, in order to keep the turbines from rusting, the turbines are being run with diesel. 41 42

Germany’s power has been strained by new wind and solar projects both on and offshore, making the government invest up to $27 billion over the next decade to build about 1,700 miles of high-capacity power lines and to upgrade existing lines. The reality is that not only is renewable energy more expensive, but it also requires expensive transmission investments that existing sources do not, thus compounding the impact on consumers and businesses.

Germany knows reforms are necessary. On January 29, the German Cabinet backed a plan for new commercial and industrial renewable power generators to pay a charge on the electricity they consume. As part of the reform of the Renewable Energy Sources Act, the proposal would charge self-generators 70% of the renewable subsidy surcharge, (i.e. the 6.24 cents per kilowatt hour). Under the proposal, the first 10 megawatt hours would be exempt for owners of solar photovoltaic projects that are less than 10 kilowatts. According to the German Solar Energy Industry Association, about 83% of solar self-generators would be subject to the new charge. Another reform being considered is a reduction in the feed-in tariff from the current average of 23.47 U.S. cents per kilowatt hour to 16.56 U.S. cents per kilowatt hour.43 On July 11, Germany’s upper House of Parliament passed changes to the Renewable Energy Sources Act, which will take effect as planned on August 1. The law lowers subsidies for new green power plants and spreads the power-price surcharge more equally among businesses.44

United Kingdom

Unlike Spain and Germany, the United Kingdom (U.K.) started its feed-in-tariff program to incentivize renewable energy relatively late, in 2010.45 Hydroelectric, solar, and wind units all have specified tariffs that electric utilities must pay for their energy, which are above market rates. Like the other countries, the U.K. has a mandate for renewable energy. The United Kingdom is targeting a 15% share of energy generated from renewable sources in gross final energy consumption and a 31% share of electricity demand from electricity generated from renewable sources by 2020.46 The U.K. generates about 12% of its electricity from renewable energy today. The increased renewable power will cost consumers 120 pounds a year (about $200) above their current average energy bill of 1,420 pounds ($2,362). 47 The U.K. is closing coal-fired power plants to reduce carbon dioxide emissions in favor of renewable energy. In the U.K., 8,200 MW of coal-fired power plants have been shuttered, with an additional 13,000 MW at risk over the next 5 years, according to the Confederation of U.K. Coal Producers. 48 The U.K.’s energy regulator is worried that the amount of capacity over-peak demand this winter will be under 2%—a very low, scary amount for those charged with keeping the lights on—and the lowest in Western Europe.

Beginning in January 2016, the European Union will require electric utilities to add further emission reduction equipment to plants or close them by either 2023 or when they have run for 17,500 hours. Because the equipment is expensive, costing over 100 million pounds ($167 million) per gigawatt of capacity, only one U.K. electricity producer has chosen to install the required technology. Most of the existing coal-fired plants are expected to be shuttered since only one coal-fired power plant has been built in the U.K. since the early 1970s.

To deal with the reliability issue, the U.K. Government is hosting an auction for backup power, but it is unclear how it will work. According to the Department for Energy and Climate Change, electricity producers will be able to bid in an auction to take place this December to provide backup power for 2018. The program, called a capacity market, is expected to ensure sufficient capacity and security of supply. The Department estimates that the U.K. power industry needs around 110 billion pounds ($184 billion) of investment over the next 10 years. The Renewable Energy Foundation (REF) estimates that consumers currently pay more than £1 billion ($1.66 billion) a year in subsidies to renewable energy producers—twice the wholesale cost of electricity. Those subsidies are expected to increase to £6 billion ($10 billion) a year by 2020 to meet a 30% target of providing electricity from renewable energy. 49 As a result, a growing number of U.K. households are in energy poverty. In 2003, roughly 6% of the United Kingdom’s population was in energy poverty; a decade later, nearly one-fifth of the nation’s population is in energy poverty.

As a result, the government has proposed that renewable companies sell their electricity to the national grid under a competitive bidding system. The new proposal limits the total amount of subsidies available for green energy, which were previously effectively limitless. The reduction in subsidies has led to renewable developers scrapping plans amid claims that the proposal will make future renewable development unprofitable.50

The U.K. is both cutting the level of their feed-in tariffs and the length of time they are available. Effective July 1, 2013, the feed-in tariff for solar generated electricity was reduced from 15.44 pence (24 cents U.S.) to 14.90 pence per kilowatt hour. In October 2011, it was 43.3 pence (67.5 cents U.S.) per kilowatt hour—almost three times the reduced level.51 Also, the length of time for the subsidy entitlement is being reduced—for example, it will be 15 years instead of 20 years for wind farms built after 2017.

The reductions indicate that the original subsidies were overgenerous and that wind turbines are unlikely to have an economic life of 20 years. 52

But, according to the Climate Change Committee (CCC), without tougher action, Britain will miss its 31% target of cutting emissions, managing only a 21% reduction instead, which will hinder meeting its commitment to cut greenhouse gas emissions by 80% of 1990 levels by 2050. The CCC called for more progress on insulating homes, promoting the uptake of ground source and air source heat pumps,

Italy

Similar to Germany and Spain, Italy also used feed-in tariffs to spur renewable development, and found it too costly. In 2005, Italy introduced its solar subsidy plan, providing solar power with premiums ranging from Euro 0.445 ($0.60 U.S.) per kilowatt hour to euro 0.490 ($0.66 U.S.) per kilowatt hour. 54 That subsidy resulted in the construction of more than 17,000 megawatts of solar capacity. In 2011, Italy’s solar market was the world’s largest, but that market has slowed due to the removal of subsidies. Italy ceased granting feed-in tariffs for new installations after July 6, 2013, because its subsidy program had reached its budget cap—a limit of 6.7 billion euros ($8.9 billion) as of June 6, 2013. The law restricts above-market rates for solar energy a month after the threshold is reached. Without tariffs, the Italian solar market will need to depend on net metering (where consumers can sell the power they generate themselves to the grid) and income tax deductions for support.55

Italy also undertook other measures. In 2012, the government charged all solar producers a 5-cent tax per kilowatt hour on all self-consumed energy. The government also curtailed purchasing power from solar self-generators when their output exceeded the amount the system needed. Those provisions were followed in 2013 by the government instituting a ‘‘Robin Hood tax’’ of 10.5% to renewable energy producers with more than $4.14 million US in revenue and income greater than $414,000 US. 56 According to Italy’s solar industry, the result of these and other changes has been a surge in bankruptcies and a massive decrease in solar investment.

References

18 Institute for Building Efficiency, Feed-In Tariffs: A Brief History.

19 Financial Post, Governments Rip Up Renewable Contracts, March 19, 2014.

20 Bloomberg, Spain’s Power Deficit Widens by 46 Percent as Steps to Close Gap Founder, April 25, 2014.

21 Institute for Energy Research, August 6, 2009.

22 Study of the effects on employment of public aid to renewable energy sources, Universidad Rey Juan Carlos, March 2009.

23 Eagle Tribune, Cap-and-trade bill is an economy-killer, June 28, 2009.

24 The Failure of Global Carbon Policies, June 11, 2014.

25 Spain Youth Unemployment Rises to Record 57.7 Percent, Surpasses Greece, January 8, 2014.

26 Financial Post, Governments Rip Up Renewable Contracts, March 19, 2014.

27 Wall Street Journal, ‘‘Darker Times for Solar-Power Industry,’’ May 11, 2009.

28 Heinrich Bo¨ll Foundation, Energy Transition: The German Energiewende.

29 Institute for Building Efficiency, Feed-In Tariffs: A Brief History, Aug. 2010.

30 German Federal Ministry of Economics and Technology and Ministry for the Environment, Nature Conservation and Nuclear Safety.

31 Forbes, ‘‘Germany’s Energy Goes Kaput, Threatening Economic Stability,’’ December 30, 2013.

32 BP Statistical Review of World Energy 2014. 33Wall Street Journal, Germany’s fracking follies, July 7, 2014.

34 Energy Information Administration, Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States, June 2013.

35 Europe’s Energy Portal Germany Energy Prices Report.

36 U.S. Energy Information Administration, Monthly Energy Review.

37 Tree Hugger, German Electricity Tax Rises 50 Percent to Support Renewable Energy, October 17, 2012.

38 Reuters, Five million German families faced with higher power bills, February 24, 2014.

39 Frontier Economics, German renewable energy levy will rise in 2014.

40 The Australian, Europe Pulls the Plug on its Green Energy Future, August 10, 2013.

41 New York Times, Germany’s Effort at Clean Energy Proves Complex, September 18, 2013.

42 Renewables International, First municipal offshore wind farm awaits grid connection, June 25, 2014.

43 Bloomberg, Germany moots levy on renewable power use, February 4, 2014.

44 Wall Street Journal, Germany’s Upper House Passes Renewable Energy Law, July 11, 2014.

45 Institute for Building Efficiency, Feed-In Tariffs: A Brief History, Aug. 2010.

46 International Energy Agency, Global Renewable Energy, National Renewable Energy Action Plan.

47 Bloomberg, Green Rules Shuttering Power Plants Threaten UK Shortage, March 19, 2014.

48 Bloomberg, Green Rules Shuttering Power Plants Threaten UK Shortage, March 19, 2014.

49 The Telegraph, Wind farms subsidies cut by 25 percent, July 14, 2013.

50 The Telegraph, Wind farm plans in tatters after subsidy rethink, March 2, 2014.

51 Mail Online, Solar panel payments are about to fall again but the cost of buying them is falling too—so is it still worth investing?, June 14, 2013.

52 The Telegraph, Wind farms subsidies cut by 25 percent, July 14, 2013.

53 The Global Warming Policy Foundation, Proposals to Step up Unilateral Climate Policy Will Trigger ‘‘Astronomical Costs,’’ Peiser Warns, July 15, 2014.

54 International Energy Agency, Global Renewable Energy, ‘‘Old’’ Feed In Premium for Photovoltaic Systems.

55 Bloomberg, Italy Set to Cease Granting Tariffs for New Solar Projects, June 11, 2013.

56 Financial Post, Governments Rip Up Renewable Contracts, March 18, 2014.

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National security implications of international energy and climate change policies

[This is an excerpt of a very interesting senate hearing that looks at how war can be caused by climate change (drought, hunger, rising sea levels), how climate change will affect infrastructure, how the European emissions trading scheme and renewable subsidies has been working out, the enormous amount of wood being burned in Europe to meet renewable standards, and so on.  It’s also of interest to know what our representatives are thinking and who they are listening to.  Much of the testimony not shown is about why we should export our natural gas and oil to Europe so that they aren’t held hostage by Russia.  But why should we export LNG when Europe has 80% as much natural gas as America does? Alice Friedemann  www.energyskeptic.com]

HRG. 113-623. 2014-7-22. U.S. Security implications of international energy and climate policies and issues. U.S. Senate 113th congress, 2nd session, 97 pages

EDWARD J. MARKEY, SENATOR MASSACHUSETTS

Right now dozens of wars and conflicts dot our world map, from the Sudanese desert to America’s longest war in Afghanistan. Two major factors have emerged in the modern era that act to strain the strands of stability until they snap—climate change and energy security. In two regions of our world, climate and energy have recently played major roles in exacerbating what were already tense times. In December 2010, a Tunisian street food vendor lit himself on fire in protest of government corruption and extreme poverty. That spark spread in Tunisia and ignited the Arab Spring. Yet, feeding this anger over years of corruption and autocratic rule was a more immediate hunger. In 2010, terrible droughts in Russia, in China, and floods in Pakistan decimated wheat harvests and created a global shortage. The price of wheat increased dramatically. The Middle East, home to the world’s top nine wheat importers, felt it acutely, especially since the region’s farmers struggled with their own parched fields. Much of Syria was gripped with the worst drought it had ever experienced. The price of bread skyrocketed across the region and demands for regime change were not far behind.

Another weapon has already been deployed in the Russian-Ukraine conflict and in wars across the globe—energy. Russia has already shut off the natural gas spigots to Ukraine. That is more than half of Ukraine’s gas supply gone. When winter arrives and natural gas demand spikes, this could become another political and humanitarian crisis, bringing suffering to Ukrainian families and challenges to the new government. Because of Europe’s reliance on Russian gas, Putin’s energy weapon gives him unparalleled leverage to continue his bullying tactics.

Energy profits can also inflict damage. ISIS, the rebel group destabilizing Iraq, was funded initially by Sunni oil sheiks. ISIS is no longer an upstart insurgency. They are a legitimate threat, consolidating their power around energy holdings as much as sectarian alliances. They have captured Iraqi oil fields. They control much of Syrian oil production, and now they are selling this oil on the black market. Revenues from these operations buy them credibility, weapons, and loyalty—valuable commodities for building a so-called ‘‘caliphate’’ in this volatile region.

Since the Industrial Revolution, our world has burned fossil fuels, increasing temperatures and destabilizing our climate. Since that time, we have become more dependent on these same fuels that have destabilized countries and drawn America into international conflicts.

Tunisia is not the first time famine has played a role in a regional conflict. In a 2007 congressional hearing of mine, one general told the story of Somalia, how drought had caused famine, famine had encouraged conflict, how U.S. military forces were sent to ensure food reached those people who needed it and was not used by warlords to gain further power, and how 18 U.S. soldiers lost their lives in what we now call Blackhawk Down.

Russia is not the first country to use energy as a weapon in geopolitics. Much has changed in the U.S. energy sector since OPEC’s devastating embargo four decades ago. The shale revolution has boosted U.S. oil production to record levels.

Yet much remains the same. Oil still commands a monopoly over our transportation sector. We remain dependent on foreign suppliers to meet nearly one- third of our needs, roughly the same share as 1975, when we banned the export of American oil.

We must do everything in our power today to mitigate the threats that will require military intervention tomorrow. If we fail in our responsibility, it is our men and our women in uniform that will get called upon to try to clean up the mess.

 

DANIEL Y. CHIU, PH.D., DEPUTY ASSISTANT SECRETARY OF DEFENSE FOR STRATEGY AND FORCE DEVELOPMENT, U.S. DEPARTMENT OF DEFENSE, WASHINGTON, DC

Department of Defense’s primary responsibility is to protect our national security interests around the world. To do this, we need to … prepare for the possibility of unexpected developments, both in the near and long term, such as the effects of climate change, sea level rise, shifting climate zones, and more severe weather events, and how these effects could impact our national security. Some of these effects are already being seen today on military bases, installations, and other DOD infrastructure, such as increased flooding from sea level rise and storm surge. The effects of climate change may also compound instability in other countries and regions by affecting things like the availability of food, water, by instigating human migration and competition for natural resources. This could create significant instabilities and potentially provide an avenue for extremist ideologies and conditions that could foster terrorism or other challenges to U.S. national security.

 

AMOS J. HOCHSTEIN, DEPUTY ASSISTANT SECRETARY OF STATE FOR ENERGY DIPLOMACY, U.S. DEPARTMENT OF STATE, WASHINGTON, DC

Recent developments splashed across the front pages of newspapers around the globe serve as the latest reminders of the interplay between energy security and foreign policy. The critical nature of the geopolitics of energy is easily on display when you look at global oil supply disruptions, which are at historic levels of over 3 million barrels per day due to reduced output in Libya, Sudan and South Sudan caused by political instability, politically motivated declines in Nigeria and Venezuela, and reductions in Iran’s exports by over 50% due to effective U.S. sanctions.

Competition for access to and control of energy sources and supply routes can indeed be a source of conflict, and revenues from energy sales can provide funds that prolong conflict. Poor governance of natural resources can also contribute to conflict by allowing pervasive corruption to undermine accountability, deprive economic growth, and encourage civil unrest. As your former colleague Senator Lugar said in sponsoring his legislation, ‘‘the ‘resource curse’ affects [the United States] as well as producing countries. It exacerbates global poverty, which can be a seedbed for terrorism, it empowers autocrats and dictators, and it can crimp world petroleum supplies by breeding instability.’’

Senator MARKEY. The bottom line is that we fight trade wars over automobiles or computer chips. We fight real wars over food and energy. That is what differentiates those commodities. We have to keep that always in the front of our mind.

 

RADM (RET.) DAVID W. TITLEY

There are four important global trends which will provide additional fuel to the accelerating risks of climate change.

  1. Global population growth. Half a billion people have been added since the MAB completed its first report in 2007 and another half billion will be added by 2025. Most of this growth is in Africa and Asia, two of the areas likely to be most impacted by climate change.
  2. Urbanization. Nearly half of the world now lives in urban areas with 16 out of 20 of the largest urban areas being near coastlines. The result is more of the world’s population is at risk from extreme weather events and sea level rise.
  3. Global increase in the middle class, with an accompanying growth in demand for food, water, and energy. The National Intelligence Community predicts that by 2030 demand for food would increase by 35%, fresh water by 40%, and energy 50%. Even without the climate change, it will be a challenge to meet these growth targets. Climate change will further stress the world’s ability to produce food and drinkable water at levels necessary to meet demand. A 2012 National Intelligence Council assessment found that water challenges will likely increase the risk of instability and state failure, exacerbate regional tensions, and divert attention from working with the United States and other key allies on important policy objectives.
  4. The world is becoming more politically complex and economically and financially interdependent, so we believe it is no longer adequate to think of the projected climate impacts to any one region of the world in isolation. Climate change impacts, combined with globalization, transcend international borders and geographic areas of responsibility.

Accelerating risks around the world affect U.S. National Security

The world around us is changing. In recent years we have observed changing weather patterns manifest by prolonged drought in some areas and heavier precipitation in others. In the last few years we have seen unprecedented wildfires threaten homes, habitats, and food supplies, not only across the United States, but also across Australia, Europe, Central Russia, and China. Low-lying island nations are preparing for complete evacuation to escape rising sea levels.

Globally, we have seen recent prolonged drought act as a factor driving both spikes in food prices and mass displacement of populations, each contributing to instability and eventual conflict. In Syria, 5 years of drought decimated farms and forced millions to migrate to urban areas. In overpopulated cities, these climate refugees found little in the way of jobs and were quickly disenfranchised by the government. The ongoing strife in Syria has been exacerbated by drought and rural to urban migration. In this way climate change has exacerbated a region already torn by political and ethnic tensions, serving as a catalyst for conflict.

 

Over the coming decades we are concerned about the projected impacts of climate change on those areas already stressed by water and food shortage and poor governance—these span the globe, but present the greatest short-term threat.

In the longer term it is those areas that will be threatened by rising sea level that are most at risk. There will be only so much we can do to keep the sea out, and in some areas the sea will flow over the walls we build, in some it will flow under or around the walls and make the land and aquifers not useable. We are concerned about low lying islands in the Pacific and great deltas including the Mekong, the delta of Bangladesh, the Nile delta in Egypt, the Mississippi delta and whole regions like the Everglades. Seawater inundation will drastically cut food production in many of these areas and cause millions to lose their ability to live on these retreating areas. Migration will become a larger form of adaptation. We will need to learn how to accept large transnational migration of people peacefully.

Increasing Impacts on Military Readiness

We expect to see an increased demand for forces across the full spectrum of operations.

Domestically in response to extreme weather events and wildfires in the U.S. will increase demand for National Guard, and Reserves. The frequency, severity, and probability that these events may happen simultaneously will also likely increase demand for Active Duty Forces to provide defense support for civilian authority (DSCA). This causes us concern because, in a leaner military, many of our capabilities reside in the Guard and Reserve and if they are being used domestically they are less available to respond to worldwide crisis. We saw this impact following tropical storm Sandy.

Climate change will be a catalyst for conflict in fragile areas and U.S. military involvement could be an option in response to the conflicts.

Our bases will be increasingly at risk from the effects of climate change. Our bases are where we generate readiness. It is where we train, garrison, repair, maintain and prepare to deploy. Our bases are vulnerable to sea level rise, extreme weather including drought, which restricts training because of the threat of wildfire, and in the future increased precipitation in the form of rain and snow may limit training.

Climate change will cause the military to be deployed to harsher environments. Higher temperatures will stress equipment and people

The Nation depends on critical infrastructure for economic prosperity, safety, and the essentials of everyday life. Projected climate change will impact all 16 critical infrastructure sectors identified by Homeland Security. We are already seeing how extreme heat is damaging the national transportation infrastructure such as roads, rail lines, and airport runways. We also note that much of the Nation’s energy infrastructure—including oil and gas refineries, storage tanks, power plants, and electricity transmission lines—are located in coastal floodplains, where they are increasingly threatened by more intense storms, extreme flooding, and rising sea levels. Projected increased temperatures and drought across much of the nation will strain energy systems with more demand for cooling, possibly dislocate and reduce food production, and result in water scarcity. Since much of the critical infrastructure is owned or operated by the private sector, government solutions alone will not be able to address the full range of climate-related challenges.

 

DAVID L. GOLDWYN, NONRESIDENT SENIOR FELLOW, ENERGY SECURITY INITIATIVE AT THE BROOKINGS INSTITUTION, WASHINGTON, DC

The national security challenges the United States faces across the globe have inherent energy components. The most prominent issues include the threat posed by Iran’s nuclear program, continued Russian efforts to foment instability in Ukraine, the emergence of the Islamic State of Iraq and the Levant (ISIL) as a destabilizing force in Syria and Iraq, continued instability in North Africa, and the recent acceleration of the Israeli-Palestinian conflict. These are conflicts involving a great percentage of the world’s major energy suppliers. We face additional challenges to the stability of Central America and the Caribbean, as Venezuela’s economic deterioration puts its ability to provide credit support for regional energy purchases through Petrocaribe at increasing risk. Energy poverty in Africa and South Asia pose risks to stability in those regions. The way in which each of these issues is managed or resolved has implications for global energy markets and by extension our own economic growth and prosperity.

Climate change itself poses a significant risk to national security. The Pentagon’s Quadrennial Defense Review, released in March 2014, identifies climate change as a threat multiplier capable of exacerbating poverty, environmental degradation, political instability, and social tensions—all of which contribute to terrorist activity and other forms of violence.1 A report issued by the government-funded CNA Military Advisory Board, released in May 2014, drew similar conclusions and discussed, among other issues, the contributions of climate-induced drought toward fomenting regional and ethnic tensions in the Middle East and Africa.2

Natural gas is the obvious fuel choice to serve as a bridge to scalable renewable energy. While we should continue to pursue a future with abundant use of renewable energy, renewables will not be able to be adopted for grid based systems at scale in the developing world until the battery storage challenge is addressed.

End Notes

1 Quadrennial Defense Review 2014, United States Department of Defense, March 2014, p. 8.

2 National Security and the Accelerating Risks of Climate Change, CNA Military Advisory Board, May 2014.

3 Jan H. Kalicki and David L. Goldwyn, ‘‘Energy and Security: Strategies for a World in Transition,’’ Woodrow Wilson Center Press and Johns Hopkins University Press, 2013

4 W. David Montgomery, et al, ‘‘Macroeconomic Impacts of LNG Exports from the United States,’’ NERA Economic Consulting, December 2012; Daniel Yergin, et al., ‘‘U.S. Crude Oil Export Decision: Assessing the impact of the export ban and free trade on the U.S. economy,’’ IHS Global Insight, May 2014.

5 ‘‘World Energy Outlook 2013,’’ International Energy Agency, November, 2013.

6 Peggy Hollinger, Christian Oliver, and Jack Farchy, ‘‘Europe risks ‘significant’ gas shortages this winter,’’ Financial Times, July 11, 2014.

7 Tim Gosling, ‘‘Slovak gas link to give Ukraine ‘chance of lasting through the winter’,’’ Financial Times, July 8, 2014.

8 For more information about this issue see: David L. Goldwyn, ‘‘DOE’s New Procedure for Approving LNG Export Permits: A More Sensible Approach,’’ Brookings Institution, June 2014.

9 David L. Goldwyn, ‘‘Refreshing European Energy Security Policy: How the U.S. Can Help,’’ Brookings Institution, March 2014.

10 Conglin Xu, ‘‘Global Oil Market Well Supplied Despite Disruptions to Producers,’’ Oil and Gas Journal, July 47 2014.

11 David L. Goldwyn and Cory R. Gill, ‘‘Uncertain Energy: The Caribbean’s Gamble with Venezuela,’’ Brookings Institution, July 2014.

12 Jed Bailey, Nils Janson, and Ramon Espinasa, Pre-Feasibility Study of the Potential Market for Natural Gas as a Fuel for Power Generation in the Caribbean, Inter-American Development Bank, December 2013.

13 EIA Electric Power Monthly, June 23, 2014.

 

MICHAEL BREEN, EXECUTIVE DIRECTOR, TRUMAN NATIONAL SECURITY PROJECT & CENTER FOR NATIONAL POLICY, WASHINGTON, DC

While advances in technology have improved America’s energy posture in the short term, many of our long-standing vulnerabilities persist and are likely to worsen in the longer term.

The lack of diversified energy sources around the world continues to create undue risk to American national security, the security of our key allies, and global stability and prosperity.

The United States relies on oil for more than 93% of our transportation sector, and most advanced economies are in a roughly similar position. Given that oil is a globally traded fungible commodity, this single-source dependence on oil as a transportation fuel exposes the U.S. and our allies to the full range of risk associated with a complex and frequently manipulated global petroleum supply system. In other words, security and oil are deeply intertwined, with largely negative effects.

Oil resources and infrastructure are therefore key strategic points on the battlefield, shaping the course of the conflict at the tactical and operational levels of war.

One of ISIL’s primary objectives during its recent offensive in Iraq was the refinery in Baiji, the largest in Iraq. Kurdish military action in the conflict to date has been almost entirely defensive, with the sole exception of an early push to secure oil fields. KRG’s seizure of Kirkuk oil province, in part intended to establish defense in depth for Kurdish areas, will also give the Kurds even greater financial and political autonomy from Baghdad. Regional instability and conflict within and between states across the MENA region is driven, in part, because of the uneven distribution of energy resources. This is certainly true in Iraq. Nearly 75% of Iraqi oil production is focused in the Shia-majority south, and the main export terminal in Basra is located there as well. Baghdad’s failure to redistribute revenue from that oil production evenly across Iraq has been a major driver of sectarian and regional conflict. Prized oil fields in the south currently remain productive, but are vulnerable to insurgent attacks and remain an important military prize for all parties to the conflict. Companies will most likely evacuate workers, and quickly, if there are serious security concerns in Basra, a real possibility. This is critical, because continued conflict in Iraq has a significant destabilizing effect on the deeply interdependent global oil market. This instability is already leading to economic and geopolitical consequences around the world, and could impact our economic recovery here at home.

Dramatic increases in Iraq’s oil production are an essential element in most projections of global supply growth. In IEA’s World Energy Outlook, for example, the most likely scenario projects Iraq to double its oil production to 6.1mb/d by 2020, and 8.3 mb/d by 2035.

The IEA projects that Iraq will provide nearly 45% of anticipated global supply growth over the next decade. All of that projected progress is currently at risk. Longer term dynamics, while more difficult to predict, are potentially even more disturbing.

Investments in the Middle East may fall short of projections if armed conflict and cascading instability across the region persist, leading to a potential supply shortfall in the 2020s.

Even as Russia has used energy dependence as a sword against Ukraine, it has employed similar dynamics as a shield against Western European interference in the conflict. Sixteen percent of Europe’s total natural gas consumption comes from Russia through Ukraine.

 

Earlier this year, Russia and China signed a 30-year gas supply agreement worth approximately $400 billion. This agreement may draw the 2 great powers into deeper alignment, with negative repercussions for the U.S. and our allies.

More than 26% of Japan’s electricity came from nuclear power plants before the Fukushima disaster. Now, with all of its nuclear plants on indefinite suspension, Japan is the world’s leading importer of liquefied natural gas. Japan alone consumed 37% of global LNG in 2012. To meet this need, Japan is reportedly considering a natural gas pipeline to Russia to bring in LNG from Siberia. While this would have some benefits for Japan, Russia’s demonstrated willingness to use energy supplies for coercion should give us pause.

IEA projects that U.S. tight oil production will reach a plateau in the 2020s, before dropping to 9.2 mb/d by 2035—leaving us in much the same position we were in before the shale revolution. The global market is projected to remain fairly tight overall along the way, meaning price volatility will continue to be a problem over the next several decades.

This places the U.S. and our allies at risk of continued overreliance on the same large-scale holders of conventional resources, creating cascading risks and impacts around the globe and across the full range of human activity.

Given these dynamics, a singular focus on fossil fuels production and export simply plays into the strengths of our competitors while leaving the U.S. and our allies with continued vulnerabilities.

 

MARY HUTZLER, DISTINGUISHED SENIOR FELLOW, INSTITUTE FOR ENERGY RESEARCH, BERLIN, MD

EUROPEAN UNION EMISSIONS TRADING SCHEME

The Emissions Trading Scheme (ETS) was launched by the EU in January 2005 as an attempt to comply with the 1997 Kyoto Protocol. It was the world’s first cross-border greenhouse gas emissions (GHG) trading program, regulating more than 11,500 installations and about 45% of total EU carbon dioxide emissions. Under the ETS, European companies must hold permits to allow them to emit carbon dioxide. A certain number of those permits were distributed at no cost to the industries that must reduce their output of carbon dioxide emissions. If businesses emit less carbon dioxide than the permits they hold, they can either keep the excess permits for future use or sell the excess permits and make a profit on them.

The early results of the program were that EU emissions were not significantly lowered until the global recession hit in 2008, which lowered emissions for all countries.

There were also misuses and abuses in the system because of its complexity, politicized decision-making, and the incentive to manipulate it.

Before the global recession hit, some EU countries saw faster carbon dioxide emissions growth than the United States, which was not subject to the policy. From 2000 to 2006, the rate of growth of European emissions under the cap-and-trade policy was almost 5 times higher than the rate of growth in emissions in the United States. 1 After the global recession, however, EU carbon dioxide emissions in 2009 were almost 8% below 2008 levels. 2 Due to the global recession, carbon dioxide emissions, in many cases, were lowered below the targets set by the cap-and- trade policy, so companies did not have to take further actions to reduce their emissions. 3 Severe downturns in economic activity result in significant reductions in emissions.

Because the free allocation of permits was based on future estimates of higher emissions levels, which did not materialize, there were too many free government-issued permits. As a result, companies hit hard by the recession were able to make profits by selling the excess permits but chose not to pass those savings onto their customers. Consumers ended up paying higher energy and commodity costs; taxpayers paid for the program’s implementation; and a new middleman was created to run the carbon permit trading program. 4

Europe found the costs of the program to be large. In 2006, individual business and sectors had to pay $24.9 billion for permits totaling over 1 billion tons. In 2011, the global carbon markets were valued at US$176 billion, with 10.3 billion carbon credits traded.5

The World Watch Institute estimated the costs of running a trading system designed to meet the EU’s Kyoto obligations at about $5 billion. The costs of a trading system to meet the EU’s commitments of a 20% reduction by 2020 (against a 1990 baseline) were estimated to be about $80 billion annually. 6

Unlike traditional commodities, which at some time during the course of their market exchange must be physically delivered to someone, carbon credits do not represent a physical commodity, which makes them particularly vulnerable to fraud and other illegal activity.

Carbon markets, like other financial markets, are at risk of exploitation by criminals due to the large amount of money invested, the immaturity of the regulations and lack of oversight and transparency.

The illegal activities identified include the following :

  1. Fraudulent manipulation of measurements to claim more carbon credits from a project than were actually obtained
  2. Sale of carbon credits that either do not exist or belong to someone else;
  3. False or misleading claims with respect to the environmental or financial benefits of carbon market investments
  4. Exploitation of weak regulations in the carbon market to commit financial crimes, such as money laundering, securities fraud or tax fraud;
  5. Computer hacking/ phishing to steal carbon credits and theft of personal information.

German prosecutors searched 230 offices and homes of Deutsche Bank, Germany’s largest bank, and RWE, Germany’s second-biggest utility, to investigate 180 million euros ($238 million U.S.) of tax evasion linked to emissions trading.

The U.K., France, and the Netherlands also investigated carbon traders, who committed fraud by collecting the tax, and disappearing without returning the tax funds.

According to estimates from Bloomberg New Energy Finance, about 400 million metric tons of emission trades may have been fraudulent in 2009, or about 7% of the total market.8

Tax evasion linked to emissions trading is still a problem. This year Frankfurt prosecutors sought the arrest of a British national in connection with suspected tax fraud worth 58 million euros ($80 million).9

Another problem is the lack of predictability regarding the emissions permit price. Companies need to know the price for long-term planning to decide on what actions they should take. The EU permit price ranged by a factor of 3, but even at the higher price range, it was insufficient to meet the emission reduction targets before the global recession hit. 10

A cap-and-trade policy is a highly complex system to implement because there are a large number of participants and the components of the system are difficult to get right as EU’s experience has shown.

Last year, the EU commenced phase three of the ETS toward meeting their target of a 40% reduction in greenhouse gas emissions below 1990 levels by 2030.11 Phase 3, which has a number of significant rule changes, will continue until 2020. As of 2011, carbon dioxide emissions of the original 27 member EU were just 8% below 1990 levels, and the majority of the reduction was achieved by the global recession.

That means the EU has a long way to go to meet its target. In the meantime, energy prices have increased and more and more Europeans are facing fuel poverty, meaning they pay more than 10% of their household income for energy. For example, industrial electricity prices are 2 to 5 times higher in the EU than in the United States and are expected to increase more. Europe’s once comfortable middle class is being pushed into energy poverty as a result of the carbon reduction measures and EU’s renewable programs. According to the European Commission, electricity prices in the Organization for Economic Cooperation (OECD) Europe have risen 37% more than those in the United States when indexed against 2005 prices. By 2020, at least 1.4 million additional European households are expected to be in energy poverty. EU’s ETS and clean energy programs have not significantly reduced emissions, but rather have dramatically raised energy prices, increased national debt, driven businesses out of Europe, led to massive job losses and unemployment, greatly increased energy poverty, and have been plagued by fraud and corruption. This economic malaise, in turn, has made Europe less capable of expending funds for their national defense needs and has contributed to the weakening of multilateral defense organizations like NATO. The European members of NATO are now spending less than 2% of their GDP on defense spending, which is below NATO guidance. 12

AUSTRALIA’S CARBON TAX

Australia implemented a carbon tax in 2012.   The carbon tax, which is currently set at $24.15 Australian currency ($22.70 U.S.) per metric ton, was initially implemented in July 2012 and was designed as a precursor to a cap and trade scheme, with the transition to a flexible carbon price as part of the trading program beginning in 2015. The tax applies directly to around 370 Australian businesses. But the September 7, 2013, election put a damper on the program. Australia’s new government wants to dismantle the legislation that levies fees on carbon emissions and replace it with taxpayer funded grants to companies and projects that reduce emissions. The Emissions Reduction Fund would be funded at A$2.55 billion ($2.4 billion U.S.). 13

Repealing Australia’s carbon tax on July 1, 2014, is estimated to :

  • Reduce the cost of living of its citizens—the Australian Treasury estimates that removing the carbon tax in 2014 to 2015 will reduce the average costs of living across all households by about $550 more than they would otherwise be in 2014 to 2015.
  • Lower the cost of retail electricity by around 9 percent and retail gas prices by around 7 percent than they would otherwise be in 2014 to 2015.
  • Boost Australia’s economic growth, increase jobs and enhance Australia’s international competitiveness by removing an unnecessary tax, which hurts businesses and families.
  • Reduce annual ongoing compliance costs for around 370 entities by almost $90 million per annum.
  • Remove over 1,000 pages of primary and subordinate legislation.

Australia’s lower House of Parliament voted to scrap the carbon tax on July 14, and the Australian Senate voted in favor on July 17, 2014.15 According to Tony Abbott, Australian Prime Minister speaking at a news conference, ‘‘Today the tax that you voted to get rid of is finally gone, a useless destructive tax which damaged jobs, which hurt families’ cost of living and which didn’t actually help the environment is finally gone.’’ The repeal will save Australian voters and business around A$9 billion ($8.4 billion U.S.) a year.16 Australia’s residents found the carbon tax experience to include soaring electricity prices, rising unemployment, income tax hikes, and additional command-and-control regulations. Electricity prices increased 15 percent over the course of a year (which included the highest quarterly increase on record), and companies laid off workers because of the tax. Further, government data shows that the tax had not reduced the level of Australia’s domestically produced carbon dioxide emissions, which is not surprising, since under the carbon tax Australia’s domestic emissions were not expected to fall below current levels until 2045.17

To reduce greenhouse gas emissions to comply with the Kyoto Protocol, Europe (EU) set mandates for renewable generation (20% of its electricity to be generated by renewable energy by 2020) coupled with hefty renewable subsidies as enticements.

The Europeans have found that these subsidies have grown too large, are hurting their economies, and as a result, they are now slashing the subsidies, so enormous that governments are unilaterally rewriting their contracts with renewable generating firms and reneging on the generous deals they initially provided.

 

RENEWABLE SUBSIDIES IN EUROPE

Spain

In order to enhance renewable energy sources in Spain, the Government enacted legislation to reach 20% of electric production from qualified renewable energy by 2010. To meet this target, the government found it needed to provide incentives to ensure the market penetration of renewable energy, including providing above-market rates for renewable-generated electricity and requiring that electric utility companies purchase all renewable energy produced. In 1994, Spain implemented feed-in tariffs to jump start its renewable industry by providing long-term contracts that pay the owners of renewable projects above- market rates for the electricity produced.18

Because renewable technologies generally cost more than conventional fossil fuel technologies, the government guaranteed that renewable firms would get a higher cost for their technologies. But, because the true costs of renewable energy were never passed on to the consumers of electricity in Spain, the government needed to find a way to make renewable power payments and electricity revenues meet. Since 2000, Spain provided renewable producers $41 billion more for their power than it received from its consumers. 19 (For reference, Spain’s economy is about one-twelfth the size of the U.S. economy.) In 2012, the discrepancy between utility payments to renewable power producers and the revenue they collected from customers was 5.6 billion euros ($7.3 billion), despite the introduction of a 7% on generation. 20 The 2012 gap represented a 46% increase over the previous year’s shortfall.

A massive rate deficit should not come as a surprise. For 5 years, IER has warned of this problem beginning when Dr. Gabriel Calzada released his paper on the situation in Spain and testified before Congress.21 He found that Spain’s ‘‘green jobs’’ agenda resulted in job losses elsewhere in the country’s economy. For each ‘‘green’’ megawatt installed, 5.28 jobs on average were lost in the Spanish economy; for each megawatt of wind energy installed, 4.27 jobs were lost; and for each megawatt of solar installed, 12.7 jobs were lost. Although solar energy may appear to employ many workers in the plant’s construction, in reality it consumes a large amount of capital that would have created many more jobs in other parts of the economy. The study also found that 9 out of 10 jobs in the renewable industry were temporary. 22, 23

Spain’s unemployment rate has more than doubled between 2008 and 2013. In January 2013, Spain’s unemployment rate was 26% the highest among EU member states.24 Spain’s youth unemployment (under the age of 25) reached 57.7% in November 2013, surpassing Greece’s youth unemployment rate of 54.8% in September 2013. 25

The Spanish Government did not believe Dr. Calzada 5 years ago, but they have now been hit in the face with reality. To recover the lost revenues from the extravagant subsidies, the Spanish Government ended its feed-in tariff program for renewables, which paid the renewable owners an extremely high guaranteed price for their power as can be seen by the deficit. Currently, renewable power in Spain gets the market price plus a subsidy which the country deems more ‘‘reasonable.’’ Companies’ profits are capped at a 7.4% return, after which renewable owners must sell their power at market rates. The measure is retroactive to when the renewable plant was first built.26 Therefore, some renewable plants, if they have already received the 7.4% return, are receiving only the market price for their electricity.

 

Wind projects built before 2005 will no longer receive any form of subsidy, which affects more than a third of Spain’s wind projects. As a consequence of the government’s actions to rein in their subsidies and supports, Spain’s wind sector is estimated to have laid off 20,000 workers.

The Spanish Government also slashed subsidies to solar power, subsidizing just 500 megawatts of new solar projects, down from 2,400 megawatts in 2008.27 Its solar sector, which once employed 60,000 workers, now employs just 5,000. In 2013, solar investment in Spain dropped by 90 percent from its 2011 level of $10 billion.

Spain’s 20% renewable energy share of generation from wind and solar power has come at a very high cost to the nation.

Germany

In Germany, as part of the country’s ‘‘Energiewende,’’ or ‘‘energy transformation,’’ electric utilities have been ordered to generate 35% of their electricity from renewable sources by 2020, 50% by 2030, 65% by 2040, and 80% by 2050. To encourage production of renewable energy, the German government instituted a feed-in tariff early, even before Spain.

In 1991, Germany established the Electricity Feed-in Act, which mandated that renewables ‘‘have priority on the grid and that investors in renewables must receive sufficient compensation to provide a return on their investment irrespective of electricity prices on the power exchange.’’ 28 In other words, utilities are required to purchase electricity from renewable sources they may not want or need at above-market rates. For example, solar photovoltaics had a feed-in tariff of 43 euro cents per kilowatt hour ($0.59 U.S. per kilowatt hour), over 8 times the wholesale price of electricity and over 4 times the feed-in tariff for onshore wind power. A subsequent law passed in 2000, the Renewable Energy Act (EEG), extended feed-in tariffs for 20 years.29 Originally, to allow for wind and solar generation technologies to mature into competitive industries, Germany planned to extend the operating lives of its existing nuclear fleet by an average of 12 years. But, the Fukushima nuclear accident in Japan caused by a tsunami changed Germany’s plans and the country quickly shuttered 8 nuclear reactors and is phasing out its other 9 reactors by 2022, leaving the country’s future electricity production mostly to renewable energy and coal. 30

Coal consumption in Germany in 2012 was the highest it has been since 2008, and electricity from brown coal (lignite) in 2013 reached the highest level since 1990 when East Germany’s Soviet-era coal plants began to be shut down. German electricity generation from coal increased to compensate for the loss of the hastily shuttered nuclear facilities. Germany is now building new coal capacity at a rapid rate, approving 10 new coal plants to come on line within the next 2 years to deal with expensive natural gas generation and the high costs and unreliability of renewable energy.31 As a result, carbon dioxide emissions are increasing.

While the United States is using low cost domestic natural gas to lower coal-fired generation, in Germany, the cost of natural gas is high since it is purchased at rates competitive with oil. Also, Germany is worried about its natural gas supplies since it gets a sizable amount from Russia. While domestic shale gas resources are an alternative, particularly since the Germans are hydraulic fracturing pioneers and have used the technology to extract tight gas since the 1960s, Germany’s Environment Minister has proposed a prohibition on hydraulic fracturing until 2021 in response to opposition from the Green Party.33 According to the Energy Information Administration, Germany has 17 trillion cubic feet of technically recoverable shale gas resources.34

Germany has some of the highest costs of electricity in Europe and its consumers are becoming energy poor. In 2012, the average price of electricity in Germany was 36.25 cents per kilowatt hour,35 compared to just 11.88 cents for U.S. households, triple the U.S. average residential price.36 These prices led Germany’s Energy Minister to recently caution that they risk the ‘‘deindustrialization’’ of the economy.

In addition to high electricity prices, Germans are paying higher taxes to subsidize expensive green energy. The surcharge for Germany’s Renewable Energy Levy that taxes households to subsidize renewable energy production increased by 50 percent between 2012 and 2013—from 4.97 U.S. cents to 6.7 cents per kilowatt hour, costing a German family of 4 about $324 US per year, including sales tax.37 The German Government raised the surcharge again at the start of this year by 18% to 8.61 US cents per kilowatt hour representing about a fifth of residential utility bills,38 making the total feed-in tariff support for 2014 equal to $29.6 billion US.39 As a result, 80 German utilities had to raise electricity rates by 4%, on average, in February, March, and April of this year.

The poor suffer disproportionately from higher energy costs because they spend a higher percentage of their income on energy. As many as 800,000 Germans have had their power cut off because of an inability to pay for rising energy costs, including 200,000 of Germany’s long-term unemployed.40

Adding to this is a further disaster. Large offshore wind farms have been built in Germany’s less populated north and the electricity must be transported to consumers in the south. But, 30 wind turbines off the North Sea island of Borkum are operating without being connected to the grid because the connection cable is not expected to be completed until sometime later this year. Further, the seafloor must be swept for abandoned World War II ordnance before a cable can be run to shore. The delay will add $27 million to the $608 million cost of the wind park. And, in order to keep the turbines from rusting, the turbines are being run with diesel. 41 42

Germany’s power has been strained by new wind and solar projects both on and offshore, making the government invest up to $27 billion over the next decade to build about 1,700 miles of high-capacity power lines and to upgrade existing lines. The reality is that not only is renewable energy more expensive, but it also requires expensive transmission investments that existing sources do not, thus compounding the impact on consumers and businesses.

Germany knows reforms are necessary. On January 29, the German Cabinet backed a plan for new commercial and industrial renewable power generators to pay a charge on the electricity they consume. As part of the reform of the Renewable Energy Sources Act, the proposal would charge self-generators 70% of the renewable subsidy surcharge, (i.e. the 6.24 cents per kilowatt hour). Under the proposal, the first 10 megawatt hours would be exempt for owners of solar photovoltaic projects that are less than 10 kilowatts. According to the German Solar Energy Industry Association, about 83% of solar self-generators would be subject to the new charge. Another reform being considered is a reduction in the feed-in tariff from the current average of 23.47 U.S. cents per kilowatt hour to 16.56 U.S. cents per kilowatt hour.43 On July 11, Germany’s upper House of Parliament passed changes to the Renewable Energy Sources Act, which will take effect as planned on August 1. The law lowers subsidies for new green power plants and spreads the power-price surcharge more equally among businesses.44

United Kingdom

Unlike Spain and Germany, the United Kingdom (U.K.) started its feed-in-tariff program to incentivize renewable energy relatively late, in 2010.45 Hydroelectric, solar, and wind units all have specified tariffs that electric utilities must pay for their energy, which are above market rates. Like the other countries, the U.K. has a mandate for renewable energy. The United Kingdom is targeting a 15% share of energy generated from renewable sources in gross final energy consumption and a 31% share of electricity demand from electricity generated from renewable sources by 2020.46 The U.K. generates about 12% of its electricity from renewable energy today. The increased renewable power will cost consumers 120 pounds a year (about $200) above their current average energy bill of 1,420 pounds ($2,362). 47 The U.K. is closing coal-fired power plants to reduce carbon dioxide emissions in favor of renewable energy. In the U.K., 8,200 MW of coal-fired power plants have been shuttered, with an additional 13,000 MW at risk over the next 5 years, according to the Confederation of U.K. Coal Producers. 48 The U.K.’s energy regulator is worried that the amount of capacity over-peak demand this winter will be under 2%—a very low, scary amount for those charged with keeping the lights on—and the lowest in Western Europe.

Beginning in January 2016, the European Union will require electric utilities to add further emission reduction equipment to plants or close them by either 2023 or when they have run for 17,500 hours. Because the equipment is expensive, costing over 100 million pounds ($167 million) per gigawatt of capacity, only one U.K. electricity producer has chosen to install the required technology. Most of the existing coal-fired plants are expected to be shuttered since only one coal-fired power plant has been built in the U.K. since the early 1970s.

To deal with the reliability issue, the U.K. Government is hosting an auction for backup power, but it is unclear how it will work. According to the Department for Energy and Climate Change, electricity producers will be able to bid in an auction to take place this December to provide backup power for 2018. The program, called a capacity market, is expected to ensure sufficient capacity and security of supply. The Department estimates that the U.K. power industry needs around 110 billion pounds ($184 billion) of investment over the next 10 years. The Renewable Energy Foundation (REF) estimates that consumers currently pay more than £1 billion ($1.66 billion) a year in subsidies to renewable energy producers—twice the wholesale cost of electricity. Those subsidies are expected to increase to £6 billion ($10 billion) a year by 2020 to meet a 30% target of providing electricity from renewable energy. 49 As a result, a growing number of U.K. households are in energy poverty. In 2003, roughly 6% of the United Kingdom’s population was in energy poverty; a decade later, nearly one-fifth of the nation’s population is in energy poverty.

As a result, the government has proposed that renewable companies sell their electricity to the national grid under a competitive bidding system. The new proposal limits the total amount of subsidies available for green energy, which were previously effectively limitless. The reduction in subsidies has led to renewable developers scrapping plans amid claims that the proposal will make future renewable development unprofitable.50

The U.K. is both cutting the level of their feed-in tariffs and the length of time they are available. Effective July 1, 2013, the feed-in tariff for solar generated electricity was reduced from 15.44 pence (24 cents U.S.) to 14.90 pence per kilowatt hour. In October 2011, it was 43.3 pence (67.5 cents U.S.) per kilowatt hour—almost three times the reduced level.51 Also, the length of time for the subsidy entitlement is being reduced—for example, it will be 15 years instead of 20 years for wind farms built after 2017.

The reductions indicate that the original subsidies were overgenerous and that wind turbines are unlikely to have an economic life of 20 years. 52

But, according to the Climate Change Committee (CCC), without tougher action, Britain will miss its 31% target of cutting emissions, managing only a 21% reduction instead, which will hinder meeting its commitment to cut greenhouse gas emissions by 80% of 1990 levels by 2050. The CCC called for more progress on insulating homes, promoting the uptake of ground source and air source heat pumps,

Italy

Similar to Germany and Spain, Italy also used feed-in tariffs to spur renewable development, and found it too costly. In 2005, Italy introduced its solar subsidy plan, providing solar power with premiums ranging from Euro 0.445 ($0.60 U.S.) per kilowatt hour to euro 0.490 ($0.66 U.S.) per kilowatt hour. 54 That subsidy resulted in the construction of more than 17,000 megawatts of solar capacity. In 2011, Italy’s solar market was the world’s largest, but that market has slowed due to the removal of subsidies. Italy ceased granting feed-in tariffs for new installations after July 6, 2013, because its subsidy program had reached its budget cap—a limit of 6.7 billion euros ($8.9 billion) as of June 6, 2013. The law restricts above-market rates for solar energy a month after the threshold is reached. Without tariffs, the Italian solar market will need to depend on net metering (where consumers can sell the power they generate themselves to the grid) and income tax deductions for support.55

Italy also undertook other measures. In 2012, the government charged all solar producers a 5-cent tax per kilowatt hour on all self-consumed energy. The government also curtailed purchasing power from solar self-generators when their output exceeded the amount the system needed. Those provisions were followed in 2013 by the government instituting a ‘‘Robin Hood tax’’ of 10.5% to renewable energy producers with more than $4.14 million US in revenue and income greater than $414,000 US. 56 According to Italy’s solar industry, the result of these and other changes has been a surge in bankruptcies and a massive decrease in solar investment.

EUROPE’S WOOD CONSUMPTION

Besides incentivizing wind and solar generation, EU is also consuming wood to satisfy its renewable mandate of 20% of generation from renewable energy by 2020.

According to the Economist, wood, the fuel of preindustrial societies, represents about half of all renewable energy consumed in the European Union in some form or another—sticks, pellets, sawdust. 57

In Poland and Finland, wood supplies more than 80% of renewable energy demand. In Germany, despite its push and subsidization of wind and solar power, 38% of non-fossil fuel consumption comes from wood.

According to the International Wood Markets Group, Europe consumed 13 million metric tons of wood pellets in 2012 and its demand is expected to increase to 25 to 30 million tons a year by 2020.

According to the National Firewood Association, the 2012 European consumption of wood pellets is equivalent to over 4 million cords of wood, which equates to over 4 million ‘‘big’’ trees and over 8 million ‘‘average size’’ trees. 58

Because Europe does not produce enough timber to meet this demand, imports of wood pellets are increasing. They increased by 50% in 2010. According to the European Pellet Council, global trade in wood pellets is expected to increase five- or six-fold to 60 million metric tons by 2020. Much of that will come from new wood- exporting businesses that are booming in western Canada and the southern United States. According to a report by Wood Resources International, the southern United States surpassed Canada last year as the leading exporter of wood pellets to Europe, exporting in excess of 1.5 million tons. Those exports are expected to reach 5.7 million tons in 2015. During the third quarter of 2012, three companies announced plans for new pellet plants in Georgia and six others were under construction in the south, together adding as much as 4.2 million tons of capacity by 2015. 59 The increase in wood consumption has caused an escalation in prices. According to data published by Argus Biomass Markets, an index of wood-pellet prices increased by 11%, from 116 euros ($152) a metric ton in August 2010 to 129 euros ($169) a metric ton at the end of 2012. Since the end of 2011, prices for hardwood from western Canada increased by about 60 percent. 60

Wood use in Europe is not carbon neutral.

In theory, if the biomass used to power electricity comes from energy crops, the carbon generated from combustion would be offset by the carbon that is captured and stored in the newly planted crops, making the process carbon-neutral. The wood that Europe is using produces carbon through combustion at the power station and in the manufacture of the pellets that includes grinding the wood up, turning it into dough and submitting it under pressure. The process of producing the pellets, combusting them, and transporting them produces carbon—about 200 kilograms of carbon dioxide for each megawatt hour of electricity generated.

A researcher at Princeton University calculated that if whole trees are used to produce energy, they would increase carbon emissions 79% more than coal over 20 years and 49% more over 40 years, with no carbon reduction for 100 years until the replacement trees have matured.

EUROPE ’S NATURAL GAS SUPPLIES

Europe is worried about continually receiving the 30% of its natural gas supplies that it receives from Russia, but instead of embracing hydraulic fracturing and horizontal drilling on domestic soil, it is looking toward the United States to export LNG to them.

According to a leaked document, the European Union is making its desire to import more oil and natural gas from the United States very clear in the discussions over the Transatlantic Trade and Investment Partnership (TTIP) trade deal. The EU is pressuring the United States to lift its ban on crude oil exports and make it easier to export natural gas to Europe. The EU emphasizes the TTIP’s role in ‘‘reinforcing the security of supply’’ of energy for the member countries, pointing to the political situation in the Ukraine as a key reason to relax rules against U.S. exports. ‘‘The current crisis in Ukraine confirms the delicate situation faced by the EU with regard to energy dependence,’’ the document states. ‘‘Of course the EU will continue working on its own energy security and broaden its strategy of diversification. But such an effort begins with its closest allies.’’ 61

EU could start by developing its shale gas resources throughout its member countries.

According to the Energy Information Administration, Europe has an estimated 470 trillion cubic feet of technically recoverable shale gas resources, around 80% of the U.S. estimated endowment of 567 trillion cubic feet.62

Germany has proposed a prohibition against hydraulic fracturing through 2021. France, which has the second-largest estimated shale gas resources in Europe, has a hydraulic fracturing ban through at least 2017 and Bulgaria also forbids hydraulic fracturing. Poland, which has Europe’s largest technically recoverable shale gas resources at 148 trillion cubic feet, is interested in developing those resources, but has geology problems demonstrated by poor results from exploratory drilling. Several other European countries are now interested in developing their shale gas resources, such as the U.K., the Netherlands, Denmark, and Romania, but none of the European shale-gas exploration efforts are close to being ready for commercial development.63

CONCLUSION

As the Washington Post indicated: ‘‘Cap-and-trade regimes have advantages, notably the ability to set a limit on emissions and to integrate with other countries. But they are complex and vulnerable to lobbying and special pleading, and they do not guarantee success.’’ 64 The European Union has found this to be the case, for their cap-and-trade program did not achieve the intended targets, but made many companies wealthier which in turn resulted in higher energy prices for consumers.

Other ‘‘green’’ energy programs have had similar results in producing higher electricity prices and large subsidies for technologies that contribute only small amounts to their countries’ electricity needs. Countries that have enacted these programs have found them to be very costly and are now slashing those subsidies because the governments and the consumers cannot afford them. It is unclear what benefit the EU and Australia’s climate and ‘‘green’’ energy policies have achieved. Any reduction in carbon dioxide emissions that developed countries make will just be a ‘‘drop in the bucket’’ because total global greenhouse gas emissions will increase as China, the world’s largest emitter of carbon dioxide emissions, and other developing countries continue to improve their economies by using fossil fuels. These developing countries believe it is their turn to develop their economies and to provide energy to their citizens, many of which do not even have electricity. As a result, they either refuse to participate in global climate change programs or have track records of not enforcing such programs. The climate policies of both Europe and Australia have not only driven up their energy prices, but have also harmed their economies and reduced their security capabilities. Because Europe is dependent on natural gas from Russia, it has secretly asked the United States to speed up its review of LNG applications. Europe is clearly worried about further Russian aggression and availability of its natural gas supplies. Australia has learned and repealed its carbon tax with Senate approval on July 17. According to Tony Abbott, Australia’s Prime Minister, in releasing the news of the passage of the repeal legislation to Australia’s citizens, ‘‘We are honoring our commitments to you and building a strong and prosperous economy for a safe and secure Australia.’’ 65 Europe and the United States need to learn that energy security requires energy diversity. For example, during the cold spell in the U.S. Northeast this past winter, natural gas prices spiked because of lack of infrastructure. Lights were kept on due to the availability of coal and nuclear units. But many of those units are now being shuttered, which means that during next winter, the lights may go out in the Northeast.

Ms. HUTZLER replies to later questions. Europe is spending less on defense now than they did prior to the Kyoto Protocol, only 1.6 percent of their GDP. NATO guidance says that they should be spending 2 percent. And we are spending as much as 2.5 percent. In fact, Secretary of Defense Hagel has called on the EU to spend more because of the crisis in the Ukraine.

Carbon trading policies are very complex, which is why you see a lot more criminal activities than you do in a carbon tax. Another place where we have seen abuse in the United States is with renewable identification numbers. Refiners have to use so much biofuel when they produce gasoline, and there has been abuse where there have been fake RIN’s that these people have purchased and we have actually gotten these people—we have found most of this fraud. So it is happening in this country, too.

Some of the policies that Senator Markey seems to advocate in his questions would reduce U.S. energy production, increase oil imports and our trade deficit, and have the effect of reducing U.S. energy security. Senator Markey should understand the implications of ending the tax deductions mentioned below, which is essentially a tax increase on the oil and gas industry resulting in a reduction in domestic energy production, which would result in an increase of oil from overseas suppliers. That said, in regard to tax policy, I believe that all industries should be treated the same, irrespective of the product that the industry produces. There are those who complain about the earnings of the oil and gas companies without understanding the nature of the business, which is the most capital-intensive in the world. The oil and natural gas industry must make large investments in new technology, new production, and environmental and product quality improvements to meet future U.S. energy needs. These investments are not only in the oil and gas sector but in alternate forms of energy (e.g., biofuels). For example, an Ernst & Young study shows the five major oil companies had $765 billion of new investment between 1992 and 2006, compared to net income of $662 billion during the same period. The 57 largest U.S. oil and natural gas companies had new investments of $1.25 trillion over the same period, compared to net income of $900 billion and cash flows of $1.77 trillion. In another Ernst and Young report, the 50 largest oil and gas companies spent over $106 billion in exploration and development costs in 2011, an increase of 38% over those capital investments in 2010. Without these investments, the U.S. oil and gas industry would not have been able to make the strides in increased oil and gas production that they have made and continue to make in this country.1 Earnings allow companies to reinvest in facilities, infrastructure and new technologies, and when those investments are in the United States, it means many more jobs, directly and indirectly. It also means more revenues for federal, state and local governments.

End Notes

1 Energy Information Administration, International Energy Data Base.

2 Ibid.

3 The Wall Street Journal, Cap and Trade Doesn’t Work, June 25, 2009.

4 The Wall Street Journal, Cap and Trade Doesn’t Work, June 25, 2009.

5 Interpol, Guide to Carbon Trading Crime, June 2013.

6 The Wall Street Journal, Cap and Trade Doesn’t Work, June 25, 2009.

7 Interpol, Guide to Carbon Trading Crime, June 2013.

8 Bloomberg, Deutsche Bank, RWE raided in German probe of CO2 tax, April 28, 2010.

9 Reuters, Germany seeks arrest of Briton in carbon trading scam, April 10, 2014.

10 Bloomberg, Deutsche Bank, RWE raided in German probe of CO2 tax, April 28, 2010.

11 European Commission, The EU Emissions Trading System.

12 Defense News, U.S. Pushes NATO Allies to Boost Defense Spending, May 3, 2014.

13 Huffington Post, Australia’s Carbon Tax Set for Final Showdown, July 14, 2014.

14 Department of the Environment, Australian Government, Repealing the Carbon Tax.

15 ABC, Senate Passes Legislation to Repeal Carbon Tax, July 17, 2014.

16 Wall Street Journal, Australia Becomes First Developed Nation to Repeal Carbon Tax, July 17, 2014.

17 Australia’s Carbon Tax: An Economic Evaluation, September 2013.

18 Institute for Building Efficiency, Feed-In Tariffs: A Brief History.

19 Financial Post, Governments Rip Up Renewable Contracts, March 19, 2014.

20 Bloomberg, Spain’s Power Deficit Widens by 46 Percent as Steps to Close Gap Founder, April 25, 2014.

21 Institute for Energy Research, August 6, 2009.

22 Study of the effects on employment of public aid to renewable energy sources, Universidad Rey Juan Carlos, March 2009.

23 Eagle Tribune, Cap-and-trade bill is an economy-killer, June 28, 2009.

24 The Failure of Global Carbon Policies, June 11, 2014.

25 Spain Youth Unemployment Rises to Record 57.7 Percent, Surpasses Greece, January 8, 2014.

26 Financial Post, Governments Rip Up Renewable Contracts, March 19, 2014.

27 Wall Street Journal, ‘‘Darker Times for Solar-Power Industry,’’ May 11, 2009.

28 Heinrich Bo¨ll Foundation, Energy Transition: The German Energiewende.

29 Institute for Building Efficiency, Feed-In Tariffs: A Brief History, Aug. 2010.

30 German Federal Ministry of Economics and Technology and Ministry for the Environment, Nature Conservation and Nuclear Safety.

31 Forbes, ‘‘Germany’s Energy Goes Kaput, Threatening Economic Stability,’’ December 30, 2013.

32 BP Statistical Review of World Energy 2014. 33Wall Street Journal, Germany’s fracking follies, July 7, 2014.

34 Energy Information Administration, Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States, June 2013.

35 Europe’s Energy Portal Germany Energy Prices Report.

36 U.S. Energy Information Administration, Monthly Energy Review.

37 Tree Hugger, German Electricity Tax Rises 50 Percent to Support Renewable Energy, October 17, 2012.

38 Reuters, Five million German families faced with higher power bills, February 24, 2014.

39 Frontier Economics, German renewable energy levy will rise in 2014.

40 The Australian, Europe Pulls the Plug on its Green Energy Future, August 10, 2013.

41 New York Times, Germany’s Effort at Clean Energy Proves Complex, September 18, 2013.

42 Renewables International, First municipal offshore wind farm awaits grid connection, June 25, 2014.

43 Bloomberg, Germany moots levy on renewable power use, February 4, 2014.

44 Wall Street Journal, Germany’s Upper House Passes Renewable Energy Law, July 11, 2014.

45 Institute for Building Efficiency, Feed-In Tariffs: A Brief History, Aug. 2010.

46 International Energy Agency, Global Renewable Energy, National Renewable Energy Action Plan.

47 Bloomberg, Green Rules Shuttering Power Plants Threaten UK Shortage, March 19, 2014.

48 Bloomberg, Green Rules Shuttering Power Plants Threaten UK Shortage, March 19, 2014.

49 The Telegraph, Wind farms subsidies cut by 25 percent, July 14, 2013.

50 The Telegraph, Wind farm plans in tatters after subsidy rethink, March 2, 2014.

51 Mail Online, Solar panel payments are about to fall again but the cost of buying them is falling too—so is it still worth investing?, June 14, 2013.

52 The Telegraph, Wind farms subsidies cut by 25 percent, July 14, 2013.

53 The Global Warming Policy Foundation, Proposals to Step up Unilateral Climate Policy Will Trigger ‘‘Astronomical Costs,’’ Peiser Warns, July 15, 2014.

54 International Energy Agency, Global Renewable Energy, ‘‘Old’’ Feed In Premium for Photovoltaic Systems.

55 Bloomberg, Italy Set to Cease Granting Tariffs for New Solar Projects, June 11, 2013.

56 Financial Post, Governments Rip Up Renewable Contracts, March 18, 2014.

57 Economist, Wood The Fuel of the Future, April 6, 2013.

58 National Firewood Association, Biomass Called Environmental Lunacy, April 10, 2013.

59 Dogwood Alliance, The Use of Whole Trees in Wood Pellet Manufacturing, November 13, 2012.

60 Argus Biomass Markets.

61 Huffington Post, Secret Trade Doc Calls for More Oil and Gas Exports to Europe, July 8, 2014.

62 Energy Information Administration, Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States, June 2013.

63 Europe wants the energy, but not the fracking, July 15, 2014.

64The Washington Post, Climate Change Solutions, February 16, 2009. 65Australia’s carbon tax has been axed as repeal bills clear the Senate, July 17, 2014.

 

Senator MARKEY. Thank you Mr. Breen, for raising the question of what happens with oil production in the United States, because even though we still import 30% of the oil that we consume in the United States, there are advocates for us to start exporting, and the Energy Information Agency is saying we are going to plateau relatively soon in terms of our total oil production. So that goes to a national security issue, too: How wise are we to be exporting our own oil and natural gas when we do not have a surplus today and production is going to slow down and plateau in the relatively near future? Can you talk about that?

Mr. BREEN. Transitioning municipal truck fleets, garbage trucks, buses, things like that to natural gas might help alleviate our single-source dependence on oil to fuel our transportation sector, which I would argue is a strategic risk, being so dependent on oil for that purpose.

Admiral TITLEY. The way I take a look at this as a risk-based issue, so how do we mitigate the risks

 

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Energy & Agriculture, Senate hearing July 20, 2000

US Senate. JULY 20, 2000. Energy and agriculture. S. HRG. 106-930

RICHARD G. LUGAR, SENATOR FROM INDIANA

I begin the hearing by raising what I believe is a very important question: Are Americans prepared for the inevitable consequences resulting from the lack of a strategic energy policy? Does an energy policy exist with our government or with private industry that will guarantee adequate energy supplies for a growing American economy? And, if not, who will tell the American people that we are headed for lower growth in jobs, income, comforts, standard of living, and competitive position in the world? In my judgment, our Nation is facing an emerging energy crisis. Demand for energy is rapidly increasing, and supplies may not be emerging to meet this demand, even at high prices.

We are here today to assess present energy policy and determine if amendments to our policy are appropriate. And in addition to high prices at the gasoline pump, we have been alerted recently to possible shortages of natural gas, and will discuss this morning potential electrical brownouts. In reviewing our energy policy, we must consider the fact that events beyond our borders have tremendous impact. As economics of developing nations continue to grow, so will their demands for energy. Such growth will fuel the greenhouse gas problem and increase world dependence on Persian Gulf oil.

Economic growth in the United States has produced a tight market for many forms of energy. Electricity demand in the first half of the year 2000 is up 3.5 to 4% from the previous year. Over half the increase in world oil demand from 1998 to 1999 was attributable to increased United States demand for oil. The price of natural gas and diesel have risen dramatically due to increased demand, tight supplies, low inventory. We know the United States needs to build new power plants, but current plans are for these plants to be fired by natural gas. Are natural gas supplies adequate to meet that demand? At the Federal level, are we doing enough to address the transmission problems that could be associated with increasingly deregulated electricity markets? The Energy Information Administration forecasts the demand for natural gas is likely to increase by 2% per year over the next 20-years.

Energy security expert Daniel Yergen asks whether we are prepared to make the investments in exploration, new pipelines, and distribution facilities needed to meet this rapidly growing market. At the same time the demand for energy is growing, new environmental regulations are being imposed upon energy facilities and fuels, and many of these policies are needed to produce a cleaner environment. The Reformulated Gasoline Program is one example. We also need to assess our energy research and technology policies in light of the greenhouse gas problem. I have cosponsored Senator Murkowski’s legislation to further the growth of new energy technologies. Senator Daschle and I have introduced a bill to solve the MTBE problem and triple the use of renewable fuels by the year 2010. We have introduced a market trading system to allow oil companies to produce renewable fuels in the areas of the country where they can most economically be marketed.

The infrastructure needed in this country to provide for the projected increases in growth year-by-year and the time frame required for all of these things to happen are not working for us. These again and again are mentioned, that even after people make decisions, there are time lags in large capital investments. For example, the New York Times points out that even given all of the disruption of this year with regard to very high prices for gasoline and protests throughout the country, that the demand for gasoline at the pump has gone down by only seven-tenths of 1-percent.

Is there any comprehensive effort involving yourself, the President, the Vice President, everybody, to try to give some confidence to the American people that even though we have disruptions now that are fully foreseeable, and in some cases not easy to remedy, there is some overall plan? Now, you point out government doesn’t do this alone. Market forces, other countries, all sorts of suppliers, energy research still undone. But I just think there is a growing lack of confidence in the American people that those of us who are in charge have some idea. And what is suspected is that the supplies will be inadequate, that prices will continually go up, and worse still, that even at any price energy will be unavailable to some of our communities.

The thought will come that we should have done more to conserve, that in essence we have been a wasteful people, that somehow growth of jobs and industry and what have you really is not going to be accommodated. This is why I started with, who will give this news to the American people, that essentially we are now headed for a lower growth, lower comforts, hazardous level? I think that is unacceptable. I think the people are going to say, get the supplies, stop horsing around with this situation; find it, invest the money that is required, tell the truth as to how much it is going to cost, but we want to be supplied. In other words, we do not want to be constrained. There may be those in our society who would say that we are profligates and we shouldn’t want that much, but I think the majority are going to say that we do want that much. As a matter of fact, we can have that much, if we use our brains, our capital, our ingenuity, we have some framework of leadership. Now, how do you address this overall, big problem?

BILL RICHARDSON, SECRETARY. U.S. DEPARTMENT OF ENERGY

I want to commend you for your singular contribution in the area of bioenergy, which could be the future for our energy security.

These are the key foundations of our policy: 1) market forces and not artificial pricing. 2) diversity of supply, 3) strong diplomatic relations with energy producing nations. 4) improving the production and use of traditional fuels through new technology development. 5) diversity of energy resources, with long-term investment in alternative fuels and energy sources. 6) increasing efficiency in the way we use energy. 7) maintaining and strengthening our insurance policy against supply disruption, the Strategic Petroleum Reserve.

We need longer term solutions. We need to lower demand and ease America from its dependency on imported energy sources.

If we are to see a meaningful decline in our future reliance on fossil fuels, if we are to lessen our vulnerability to interruptions in energy supply, if we are to kindle a whole new field of agricultural and forestry economics, then we need a cooperative national effort to develop a range of renewable energy sources, and bioenergy can be at the heart of such an effort.

BIOPOWER

Creating such a vigorous market will boost demand for dedicated energy crops, providing new revenue streams for farmers and new cash flow for rural economic development. The current uncertainties on the farm and in our forestry industry could be eased by long term energy crop contracts with biorefineries. This is the focus of the bioenergy initiative, integrating the existing bioenergy and bioproducts programs within the Energy Department and the Department of Agriculture.

We have also already established the National Biobased Products and Bioenergy Coordination Office, and have produced our first integrated, multiagency strategic plan for biofuel and biopowered research. Our FY 2001 budget includes substantial increases for biofuels and biopower, $40 million at the Department of Energy and $44 million at the Department of Agriculture.

For farmers, we recently announced an initiative that affects farmers, fuel efficiency for lighter trucks. I think there is tremendous potential here. This will involve a lot of farm equipment, farm vehicles. This is an investment that we need to work with in the future.

There are also ample opportunities in wind power, which I know is of interest to this committee, and especially to Senator Harkin. Of the top 15 wind resource States, 12 are located in America’s agricultural heartland.

Dan Reicher, Assistant Secretary of Energy for Energy Efficiency and Renewable Energy: We are very excited about the opportunities for biomass. We are focused on programs that will allow us to use biomass to make power, electric power; to make liquid transportation fuels; we think with our large energy demand in the Federal Government itself, powering our 500,000 buildings, we think we can help drive some of these new markets for biomass and bioenergy

We urge Congress to appropriate our request of $154 million for our Weatherization Assistance Program that reduces the heating and cooling costs of low income families by an average of $200 per year to help them cope with the high prices of fuel that they are least able to afford.

I am really worried about our distribution, our generation, our transmission system. We have a grid that is a Third World grid, for a booming economy for the world’s biggest superpower. And that is going to take investing in more power, in regional transmission organizations, in more renewable energy.

The key is also a partnership with the private sector. Technology can take us to more energy security and fuel efficiency. New natural gas technology, new technology for wind, new technology for fuel efficiency, fuel cells, hybrid vehicles, cars, and SUVs that are 40-miles-per-gallon. That last technology is something that I wanted to underscore, too it should be a long term priority.

We are developing a plan, but it is going to require a national dialogue.

TOM HARKIN, IOWA SENATOR

We have had $4 billion in tax incentives for oil and gas production, for more efficient cars and homes and products. Congress hasn’t done anything — we haven’t acted on it. It has been sitting here for at least 2 or 3-years, and not one thing has been done. And Congress has not acted to reauthorize the Strategic Petroleum Reserve, either. So, quite frankly, having been in Congress for a number of years, it just seems like we don’t do anything unless a crisis stares us in the face. I remember when I was on the Science and Technology Committee in the House back in the 1970s, and then once the oil crisis was over with and the Reagan administration came, we dropped all of our research programs on alternative fuels because everyone just, well, everyone felt we didn’t need it then. And so we just drifted through another decade, another almost two decades, without understanding what was happening with our oil and gas supplies.

You know, it just seems like we get caught up in these crises, and it is sort of the old story about the alligator and the swamp. You know, you don’t really tend to think about the long term. But once again, I think we have to begin laying the groundwork and the plans for the mid and long term production of energy in this country. And again, I just want to hear from you as to your thoughts of what your department not only is doing but what you think we should be doing in the area of biobased fuels and bio-based energy production in this country, and what the potential is for wind.

KENT CONRAD, SENATOR FROM NORTH DAKOTA

I think we function in a crisis mode, that is more typical than not for Congress. But a crisis response is not going to work, because when you head over the cliff and are in a brownout, you can’t respond quickly enough. That is the hard reality that we confront. There are long lead time investments that need to be made to expand capacity in oil and gas, expand capacity in renewables and all the rest. Mr. Richardson, I remember when you warned years ago there we were headed for trouble, outlined a series of steps that needed to be taken, including incentives for greater production and incentives for renewables, and unfortunately precious little has been done by the Congress in response to your repeated warnings

TIM JOHNSON, SENATOR FROM SOUTH DAKOTA

This requires a long term plan, and I appreciate the discussion that has taken place here relative to a consensus that we do need less reliance on imported petroleum, but I would have to observe that we need less reliance on petroleum, period. This is a finite, nonrenewable source of energy. So long as this is a finite fuel, so long as we continue to be significantly reliant on foreign nations, we are going to continue to be vulnerable to market shocks such as we have just witnessed this year. I think that we are going to continue to be vulnerable until we become far more serious than we have been with development, research and development of alternative renewable fuels, with a particular eye on agriculturally based fuels.

JAMES SCHLESINGER, FORMER SECRETARY OF DEFENSE AND ENERGY

The first point that I would like to make, and I want to emphasize this point, is that all too frequently we use the phrase ‘‘energy policy’’ or ‘‘national energy policy’’ as a kind of incantation, as a talisman that will ward off distress in the energy area. But we must recognize that an energy policy will have to choose a specific goal or goals, and that means sacrifice of other objectives. In the past, starting with the Arab oil embargo, with President Nixon’s Project Independence, all through the 1970s the great stress was on reducing dependency on foreign oil imports, reducing dependency on OPEC. That has become less relevant from a national security standpoint than it was in those past decades, because of the collapse of the Soviet Union, and therefore the collapse of the Soviet threat to the oil tap in the Middle East, and also because of the Gulf War. Saddam Hussein will be the last Middle East potentate to seek control over the oil supplies of the Middle East. That is not to say that the national security objective has gone away. Oil affects both our foreign policy and our foreign policy calculations, but it is far less serious than it was in the 1970s when there was a Soviet Union.

In the intervening years we have moved away from that willingness to use government intervention in the attempt to reduce dependency on foreign sources of supply, and towards reliance on the market. Sometimes it is presented as if reliance on the market were a free good that solves problems. It solves some problems; it creates other problems. Prices in the marketplace, as we have just experienced, will fluctuate, and when prices go up, consumers are unhappy. When prices go down, producers are unhappy. Avoiding price fluctuations, of course, implies that one controls the market, which is the opposite direction from which we have moved. Also, we depend upon price signals, price signals to create the new infrastructure for expanded capacity. We will not have expanded capacity until those prices go up, and as a consequence, at this time we have problems with the infrastructure for our energy industries, perhaps most immediately, the infrastructure facing the electric power industry in what Secretary Richardson referred to as the ‘‘Third World’’ grid. The reason that we have that, Mr. Chairman, Senator Conrad, is that we moved enthusiastically into competition in the electric power industry without considering the need for expanded capacity in the grid. And as cheap power moved around in the grid, we discovered that we were operating at close to 100% of capacity. If we want to move towards competition and move cheap power around the country, we have got to be prepared to take national measures to encourage strengthening of the grid.

Why are we producing less natural gas? Because the price signals earlier were not right to encourage the drilling activity that is necessary to have the degree of deliverability that is essential to have ample supplies. Moreover, we have a very high depletion rate with regard to natural gas, depletion rates of 30%, sometimes greater, and that means in order to sustain the present level of production, we must find 7-trillion cubic feet a year. That is going to be quite a major effort. So these matters are a reflection of, in large degree, the decision to move towards reliance on the market mechanism. That has many advantages, but it does create the potentiality for price spikes.

Ideally, governments will be flexible and they will anticipate change. We have not been very good at that. I would have thought that the energy problem and environmental problem might have fallen under the purview of the National Economic Council. It may be desirable to have an additional body to coordinate within the Government. The first rule, it seems to me, is that of Hippocrates, which is ‘‘do no damage,’’ or do as little damage as possible. It is clear, I think, that we have changes in our policies that are serious changes. For example, the Project Independence of President Nixon stressed nuclear power. In the subsequent years, to say the least, the stress on nuclear power has gone away. Both President Nixon and President Carter stressed coal conversion. In the light of change, changed attitudes towards greenhouse gases, going towards coal is less than an ideal policy, and national policy has changed as a practical matter. But, in addition to these serious changes in policies, we change policies capriciously, and that, it seems to me, is something that can be avoided. One of the great advantages of a focus on the long run as you suggest, is that it will hold down these capricious changes in policy.

Enhancing the reliability of the grid would be the first thing that I would worry about. I would particularly worry about it because of the possibilities of cyber warfare. The existence of the grid, the reliability of the grid, is a prime target in asymmetric warfare, as a war game of the NSA showed a few years ago, ‘‘Eligible Receiver,’’ in which hypothetically power was shut down along the East Coast. This would have a devastating effect on the country, and worrying about the reliability of the system is particularly germane at this time. Expanded capacity, it will come only as a result of pressure on the industry, because it is uneconomical. Once again, the price signals are not there, Mr. Chairman. It is uneconomical to expand capacity unless there is pressure to bring about capacity expansion.

Last year oil prices had hit $10 a barrel, which had basically crushed the desire to invest in exploration in the world outside of OPEC and forced us to become more dependent on Middle East sources of supply, such that when demand revived, there was less spare capacity around the world. The benefits of last year, as it were, with regard to fuel prices, are part of the cause of the high prices of this year, and we should as a country be looking at ways to stabilize prices. That may include the imposition and then the reduction of taxes on gasoline, for example, such that the price is more stable than it has been. It puts a terrible burden on an independent producer, as being the most dramatic example, to have these kinds of price fluctuations while they are operating on narrow margins.

SENATOR LUGAR. We have had a debate in the past on nuclear energy, and we haven’t had much of a debate recently. The whole issue has been how can we store waste from the past, not do you extend or expand nuclear energy in this country. Other countries are having that debate and are expanding the use of nuclear energy. Now, it could very well be, as we raise this, that the emotions involved in this, or the practical problems of storage of the unspent fuel and the debate we are still having over where it is to go and under what circumstances. But up front the public needs to know this is a big issue, that this is one way in which some energy might come to some parts of the country. Another, as you say, is in the coal conversion area. Clearly, for reasons you have mentioned, the greenhouse gas debate, other environmental considerations, coal has not been favored, certainly soft coal. Some hard coal, on occasion, but nevertheless cost is involved in that, and availability. But there is a lot of coal left in the country

This is why the biomass area, which at best, as we heard today, by 2010 might formulate 10% of our power, not a solution but still an incremental change that at the margins is helpful, given the big figure for energy in our country, and there does appear to be a lot of promise there of renewable supplies.

I mentioned in my opening statement we invited the Saudi oil minister to testify. He is prepared to respond to questions in writing. But one point that he and others have made, with OPEC, is that with the exception of the Saudis and perhaps slightly more capacity in Kuwait, they are already going full steam. So, in essence, they are pointing out this is still a worldwide supply and demand problem in which they do not bear the onus, at least in their judgment, for having precipitated the prices. But it is an interesting point of view, and we will have the record replete with those thoughts.

ROBERT KERREY, SENATOR FROM NEBRASKA

I appreciate, Mr. Secretary, your historical analysis and presentation of how easy it is for us to sort of lose sight of the fact that we still have significant dependency on foreign sources, even though OPEC has weakened, and that it is very important for us, if we want to be productive and we want to have higher standards of living, we still have to have energy to produce those higher standards of living. And we in Nebraska are very much aware of that.

HARRY S. BAUMES, SENIOR VP FOR INDUSTRY & AGRICULTURE, WEFA, INC.

In the farm operation, whether crops or animal production, farmers demand energy inputs for different types of energy inputs, different types of production activities. Planting, harvesting, primarily require diesel fuel or fuels to operate equipment. Electricity powers irrigation systems milking parlors, air conditioning and dryers. Natural gas and liquid propane powers dryers too. Gasoline, diesel, and lubricants are necessary to run equipment. In the aggregate, farmers expended on direct energy inputs an average of over $9 billion per year between 1996 and 1999. By my calculations, that is nearly 5.5% of total cash expenses and about 5% of total production expenses. Estimates of energy expenditures on cash costs are expected to rise considerably for the year 2000. By my estimates, we are looking at a rise in direct energy costs of close to $2.5 billion, pushing the figure to almost $12 billion for the year 2000. Total cash expenses are also estimated to rise, but at a slower rate, so as a consequence we are looking at direct energy costs to increase their share of total cash costs to about 7% from 5%.

Indirect usage by agriculture reflects the amount of energy consumed in production of manufactured inputs, primarily fertilizers and pesticides. Farmers use millions of tons of fertilizer and millions of pounds of pesticide. Fertilizer production, particularly nitrogen production, is extremely energy-intensive. Anhydrous ammonia, the primary feedstock to produce fertilizers, nitrogen fertilizers, is also a product used by farmers. Every ton of ammonia produced in the U.S. requires somewhere between 33- to 34-million BTUs of natural gas. For the past 4-years the price of natural gas has been fairly stable and energy costs in ammonia production have accounted for 75% of the total production cost. Now, more recently, energy prices facing the fertilizer producers are closer to $4 per million BTU of gas, and this has raised the cost considerably. In the absence of being able to pass these costs on to farmers or to buyers, 15- to 20% of the U.S. ammonia capacity has shut down in response to these higher gas prices. Energy-intensive fertilizers and crop chemical costs account for about 43% of the variable cash expenses for corn production, 35% for wheat production, and 40% for soybean production. Couple these with the direct energy costs of 10- to 15% for these crops, and you can clearly see that energy is an important input to agriculture.

TOM HARKIN, SENATOR FROM IOWA

And right now USDA estimates that direct fuel expenses for farmers will increase by $2.5 billion or 40% this year compared to 1999—40% compared to last year. Higher energy prices are also reflected in the greater costs for grain drying, fertilizer, pesticides. The Iowa Farm Business Association estimates that higher energy costs will add more than $1,300 to this year’s expenses for a 660-acre-corn-and-soybean farm. So any actions that can be taken to alleviate the impacts on farmers would certainly help.

Renewable sources now constitute only about 3% of U.S. energy supplies and only about 1.2% of gasoline, but our reliance on foreign petroleum is growing dramatically, to the point where we now import about 60-percent of our petroleum. We are far more reliant now than we were in the 1970s.

Renewable fuels like ethanol and biodiesel enhance our energy security. They increase farm income. They create jobs and economic growth in rural communities. There is also tremendous potential in biomass such as switchgrass, and wind energy, which is a growing industry.

Drill, Baby, Drill. Let The Market Solve All Problems

CHARLES E. GRASSLEY, SENATOR FROM IOWA

The Senate Energy Committee tells us about two-thirds of the known supply of, on-tap supply of natural gas is under Federal lands, and we have seen this trend, because so much of exploration, so much of our country has been taken off bounds for exploration. And when you have lower supply, you have higher prices, obviously. Isn’t it about time that we start looking at encouraging greater exploration in the continental United States? Are we concerned about less reliance upon importation of energy or are we not? And the extent to which we aren’t, and we are always going to be terribly too dependent upon it, but we can do more, and alternative fuels are one of those, and tax credits are one. But when we aren’t making adequate use of what God has given us, it seems to me we ought to. We decimated the exploration and oil drilling business. Last month the number of rigs exploring was down once again, I don’t know whether down to a particular historic low. Qualified people to work in the industry are down. It is very difficult to find the type of people you need. Just the last few years of not being able to explore as freely as in the past has put us in a condition where, even if the change in policy came now, there would be a long lead time to get back to where we ought to be, to find more sources of domestic production.

BENNETT JOHNSTON, former U.S. SENATOR FROM LOUISIANA, Johnston & Assoc., LLC

I was last talking about oil here in the Senate we were importing about 50%. We are importing 56% now. EIA says we are going to import 70% by 2020. So anybody who thinks you are going to reverse that trend is—I mean, I have been hearing this for over a quarter of a century. Nixon’s energy independence was no foreign imports, and it is all a pipe dream. I mean, we don’t have the oil and gas in this country to avoid it.

The problem is one of volatility, and it is a serious problem, and I think the problem is likely to get a lot more serious as we face blackouts, brownouts, rapid escalation in the price of natural gas and continued fluctuation in oil. The question is, what do you do about it? I would say that you should avoid impeding market forces. It is a great temptation.

Let me give you just one example of the current solution du jour for dealing with the problem, and that is the Northeast heating oil reserve. It proposes to take 2-million-barrels, which Secretary Schlesinger says is not enough—it is a pretty good amount—but put that in a government storage. Now, what is wrong with that? Well, first of all, heating oil has got to be turned. You can’t keep it there for years like you can the Strategic Petroleum Reserve. It will chemically degrade if you don’t turn it. Typically, private people turn it five times a year. The government would do so less often, probably once a year.

So the Government will go out and procure storage. Where are they going to get it? Private sector. They don’t have any themselves. So they are going to take out of private sector storage the 2-million-barrels which they will buy. Then that will actually take out of use some 10-million-barrels. If they turn it five times and they have got 2-million-barrels, you take out of use 10-million-barrels in order to get 2-million-barrels of government reserves. Then what is the Government going to do with it? Well, the Government presumably would let it go in times of high prices. Well, you can guarantee high prices because the private people who—it is expensive, you know, to procure and store, private storage. If they see the Government with 2-million-barrels out there overhanging the market, they are not going to put in their usual amount of heating oil. They are going to put in less. So you create the shortage and then you have got to figure out how the Government is going to release it and what kind of regulations you have. I mean, are you going to let people buy it and then resell it at a higher price? It recalls the crude oil allocation problems of the 1970s. I can predict, Mr. Chairman, it is going to be a grand and glorious mess if they do it. Looks like they are going to do it.

And it is not going to work, and when it is not going to work, then they are going to say, ‘‘Well, we didn’t have enough in storage, we’ve got to get more,’’ which is only going to exacerbate the situation. Same thing is true on the Strategic Petroleum Reserve. We created that for the purpose of dealing with serious supply interruptions, not price spikes. The Congress is simply not capable of setting a price which is a proper price and adhering to it. And then the market gets used to that supply, and it makes matters worse rather than better.

What can we do? Let me suggest a number of very simple things, not easy to do, maybe, but they are simple.

You need to drill in those places where you can drill: Arctic National Wildlife Refuge. I cannot understand why this Congress will not drill in the Arctic National Wildlife Refuge. There is no commercial fish there. Caribou is no problem. Right next door in the Prudhoe Bay they drilled, and the caribou population went up 700%. That ought to be proof enough. There is enough oil there, we think, to at least reverse the decline. We drill out in the Gulf of Mexico, which has over 1-billion-pounds-of-commercial-seafood, great recreational areas. No recreation up on the North Slope. I can’t understand why we don’t drill there. We ought to be drilling in places like, for example, Lease Sale 181 out in the Gulf; in the Destin Dome. Let me tell you, in the Destin Dome, my company, Chevron, has a lease out there. I don’t Destin Dome, my company, Chevron, has a lease out there. I don’t miles offshore. We think there are over 2-trillion-cubic-feet of natural gas. Florida has said you can’t drill out there, and it is due for a decision by the Secretary in, I think, next month. This being a political year and Florida being a big State, you can predict how that is going to come out. This is natural gas. It can’t spill. You can’t see it from the beach. It is serviced out of Alabama. And yet Florida says we can’t drill there. And let me tell you, Florida is going to have a natural gas shortage.

When you are talking about reliability, you have got to build more transmission, first of all. That is the biggest thing, because our electricity industry grew by a group of local companies which, you know, it might be State-wide, it might be multi-state, but they were local, and their reliability margins were set by their public utility commissions, and they didn’t basically send a lot of energy outside of their own grid. Now we are interconnected, imperfectly and not well interconnected, and you need to build much more of that transmission. It is going to be a very, very serious problem, the problem of transmission, as well as the problem of additional electricity generation. One of the problems there is there are no more—you can’t go out and buy a turbine now. G.E. has got all of its turbines bought up for years to come. Intergy, in a very smart move, I think, bought them all up. And so if you want to build a new gas-fired power plant, which is the cheapest and the best way to do it now, you have got to wait in line for a long time to get your turbine. So things are going to get worse in electricity before they get better. We ought to do something about siting, siting plants, siting pipelines. It takes too long. In California, let me tell you, people are pulling their hair out in San Diego now over the price of energy because they are way—the price has spiked way up because there is a shortage of supply and there is a transmission problem. We need to speed that along, the siting.

You need to pursue the nuclear option in this country. You can talk about renewables, but renewables are going to be a small part of the solution. Nuclear is 20% of our electricity now, and could be much bigger. It doesn’t cause any greenhouse gas problems. And if you lose what you have now, you are going to exacerbate that natural gas price problem, because the reasonable prices for natural gas depend upon keeping your present nuclear facilities going.

So you are going to have political energy problems, but in the strongest way I can tell you, stick to the basic policy of market forces. We do have an energy policy which was procured at great political loss of blood, and it is called market forces. We need to perfect that, preserve that, and expand it.

 

 

Posted in Congressional Record U.S. | Comments Off on Energy & Agriculture, Senate hearing July 20, 2000

Weatherizing homes costs twice as much as the benefits

Summary: In a randomized controlled trial of over 30,000 households in Michigan, where 6% of them received energy efficiency improvements, the cost of efficiency upgrades were about double the energy savings, with a negative -9.5% rate of return of annually.

[But it’s still a good idea to insulate your home! What price can you put on not suffering, or dying from excess heat or cold?

I have questions about the study.  Energy prices are temporarily cheap because of fracked gas and oil which are likely to peak in 2015-2019, and high unemployment lowering demand. If prices double or triple, then weatherization will pay for itself.

I didn’t see a breakdown of labor and materials. If the purpose of this program is also to create jobs, what percent went to labor rather than insulation, etc.  And what was done exactly? Insulation, caulking, double-pane windows?

Monetary studies are always troubling when it comes to energy.  What’s the EROI of energy saved versus embodied energy in the materials and labor?

Alice Friedemann www.energyskeptic.com]

Study Finds Costs of Residential Energy Efficiency Investments are Double the Benefits

New evidence supports the need for additional policy solutions to confront climate change while more field evidence is gathered to identify the most beneficial energy efficiency investments.

Berkeley, CA, June 23, 2015 – Energy efficiency investments are widely popular because they are believed to deliver a double win: saving consumers money by reducing the amount of energy they use, while cutting climate-forcing greenhouse gas emissions and other pollutants harmful to human health. But a new study by a team of economists finds residential energy efficiency investments may not deliver on all that they promise.
Through a randomized controlled trial of more than 30,000 households in Michigan – where one-quarter of the households were encouraged to make residential energy efficiency investments and received assistance – the economists find that the costs to deploy the efficiency upgrades were about double the energy savings.
“In the case of residential energy efficiency investments, the projected savings overestimate the reality on the ground,” says Michael Greenstone, the Milton Friedman professor of economics and director of the Energy Policy Institute at the University of Chicago (EPIC). “A problem as urgent as climate change must be addressed using policies that deliver the greatest bang for their buck….In the meantime, it is critical that we field test energy efficiency programs to determine which investments offer the greatest potential.”
The study – a part of The E2e Project and led by Greenstone, as well as Meredith Fowlie and Catherine Wolfram of UC Berkeley – assessed the nation’s largest residential energy efficiency program, the Federal Weatherization Assistance Program (WAP). Participating low-income households were provided with about $5,000 worth of weatherization upgrades (e.g. furnace replacement, attic and wall insulation, and weather stripping) per home at zero out-of-pocket costs. The upgrades did reduce the households’ energy consumption by about 10 to 20% each month. But that only translated into $2,400 in savings over the lifetime of the upgrades – half of what was originally spent to make the upgrades, and less than half of projected energy savings.
“Energy efficiency programs are generally viewed as cost effective. This view is often based on engineering calculations and associated savings projections,” says Fowlie, an associate professor of agriculture and resource economics and Class of 1935 Endowed Chair in Energy at UC Berkeley. “Our data-driven analysis that measures the actual returns on energy efficiency investments shows how these projections can be quite flawed. In actuality, the energy efficiency investments we evaluated delivered significantly lower savings than the models predict.”
Past studies have claimed that energy efficiency investments don’t deliver the expected energy savings because of a ‘rebound effect’: households adjust their behaviors and consume more energy services than they had before the investments were made. However, the economists could find no evidence of this ‘rebound effect’ in the households they studied.
Further, some say that the broader societal benefits – savings as a result of reductions in pollution from energy production– justify the investments. Again, the findings did not support this.

Another claim is that energy efficiency programs have a low take-up rate because consumers don’t know about the programs or how to participate, driving down the expected benefits. To investigate this, the authors studied whether extensive outreach and assistance would boost the take-up rate of the program. Using a firm with extensive experience in managing outreach campaigns, the research team made almost 7,000 home visits, more than 32,000 phone calls, and 2,700 follow-up appointments. Yet, despite this aggressive outreach and personal assistance, only 6% of households in the treatment group participated in the program, compared to 1% in the control group. In the end, it cost more than $1,000 for each additional household encouraged to undertake these free energy efficiency investments.
“At the end of the day, the models don’t capture some of the hard-to-quantify costs involved in making energy efficient choices, which could help explain why people aren’t taking advantage of the opportunities as much as the models predict,” says Wolfram, the Cora Jane Flood professor of business administration at UC Berkeley’s Haas School of Business and faculty director at the Energy Institute at Haas. “This is another reason why potential energy efficiency investments need to be rigorously tested in real-world conditions before relying too heavily on them to solve climate change.”

Read the policy brief of the study

Read the full working paper
This research was made possible thanks to generous support from the Alfred P. Sloan Foundation, the MacArthur Foundation, the Rockefeller Foundation, and the UC Berkeley Energy and Climate Institute.

[Some excerpts from the 28 page paper]:

The Weatherization Assistance Program (WAP) is the nation’s largest residential energy-efficiency program. WAP supports improvements in the energy efficiency of dwellings occupied by low-income families. Since its inception in 1976, over 7 million low-income households have received weatherization assistance through the program. Proponents credit the program with saving energy, creating jobs, reducing emissions, and assisting low-income households. The American Recovery and Reinvestment Act PL111-5 (ARRA) dramatically increased the scale and scope of WAP.6 Our analysis seeks to estimate the impacts of weatherization assistance over the ARRA-funded time period. WAP funds are distributed to states based on a formula tied to a state’s climate, the number of low-income residents, and their typical energy bills. The states distribute WAP money to over 1,000 local sub-grantees, which are typically community action agencies (CAAs) or similar nonprofit groups. These sub-grantees are then tasked with identifying and serving eligible households. Participating WAP households receive free energy audits and a home retrofit.

The average participating household in our data received an average of $4,143 of energy efficiency investments and over $1,000 worth of additional house improvements at zero out-of-pocket costs.7 Before implementing a weatherization retrofit, CAA program staff conduct an energy audit of the home. The purpose of the audit is to make recommendations regarding which efficiency improvements should be implemented at the home. During the visit, program auditors collect detailed information about the building structure and other construction details, heating and cooling systems, appliances, ventilation, etc. This information is combined with local climate conditions and retrofit measure costs, then fed into a computer-based audit tool: the National Energy Audit Tool (NEAT). This tool uses engineering algorithms to model the energy use of single-family and small multi-family residential units. NEAT is the most widely used tool for weatherization audits; it is used by state and local WAP sub-grantees, utility companies, and home energy auditors (EERE, 2010).

Michigan is one of the largest recipients of WAP program funding on account of its cold winters and large low-income population, and received over $200 million in ARRA funding for weatherization assistance.  All stimulus funds had to be spent by March 2012. After that point, the pace of weatherization activity dropped precipitously.

A critical issue for the validity of the estimates from this design is how households in this sample were chosen for weatherization. The road from application to energy efficiency investments is long and there are many potential off-ramps. Applicant households may fail to complete the necessary – and involved – paperwork or may be deemed ineligible based on the information they provide. Once paperwork is completed successfully, households are put on a list where the waiting times can exceed one year. After rising to the top of the list, homeowners must accommodate scheduling of energy audits. Households may fail to receive weatherization if they miss an audit appointment, or if the auditors discover risks to WAP contractors (e.g., asbestos in the home). Because of significant delays in ramping up weatherization activities under ARRA, the agencies were unable to complete the weatherizations they anticipated prior to the March 2012 ARRA deadline, which helps to explain why fewer than half of the applicants in our sample were weatherized by mid-2014.

we spent around $475,000 on the encouragement or a little more than $55 per household in the treatment group. The low take-up rates in the encouraged group are quite striking. Program participants receive substantive home improvements, yet incur no out-of-pocket expenses. All households in the encouraged group received some information about the program via a phone call or door hanger. It may seem straightforward to encourage households to participate in a program that provides free efficiency retrofits worth an average of approximately $5,000 that are designed to significantly reduce energy expenditures. In our experience, that was hardly the case. The impact of reducing barriers to participation (e.g., information and process costs) on program uptake is of independent interest both to policymakers and researchers.

In the end, the average cost of encouragement per completed weatherization was about $1,050, which is more than 20% of the average costs of weatherization improvements.

We obtained monthly natural gas and electricity consumption data over the period June 2008 to May 2014. This period includes at least two years of pre-retrofit data for all weatherized households in our sample.

What Explains the Low Rate of Return on These Efficiency Investments?

It is natural to ask why the returns to residential energy efficiency investments are so low. After all, WAP is designed so that the only measures implemented are ones with projected savings to costs ratios greater than one. An important factor leading to negative returns on investment is the incomplete realization of projected energy savings. The projected savings are about 2.5 times the preferred experimental savings estimate. Further, the projected savings are roughly 4 times the quasi-experimental estimates of energy savings. There are relatively few ex-post estimates in the academic peer-reviewed literature, with Davis et al. (2014) and Dubin et al. (1986) serving as notable exceptions.  Both of those papers similarly find low realization rates, although they largely attribute it to behavioral responses (i.e., the rebound effect) which we have shown plays at most a minor role in this paper’s setting.

Because energy efficiency programs are implemented by regulated utilities, there are a number of regulatory filings that estimate ex post program savings and it is not unusual for them to find that the programs deliver estimated savings considerably lower than projected.

Having ruled out the rebound effect as the primary explanation for the gap between projected and realized energy savings, we conclude that the efficiency audit tool must systematically overstate the real returns to these investments.

Along these lines, we explore some alternative sources of this bias. First, we compare the distribution of temperatures observed during our study period against the typical weather patterns on which engineering calculations are based. Although we do observe some moderate spells in our time-frame, on average we observe colder than average temperatures and higher than average degree day measures in our sample; these colder temperatures should lead to greater than average savings. A second potential source of bias concerns the over-statement of baseline energy use. Several studies and utility reports have documented how software-based energy analysis of existing homes tends to over-predict pre-retrofit energy use and retrofit energy savings.46 Indeed, we found in our data that the NEAT program predicts baseline natural gas consumption that exceed actual consumption by more than 25% prior to weatherization. This suggests that the auditing tool could be under-estimating the efficiency properties of the average home prior to weatherization, which may partly explain the over-statement of the benefits of upgrading to a given efficiency standard. Overall, our findings suggest that the NEAT audit tool over-estimates returns by a significant margin. Further, this overestimation of savings does not appear to be due to behavioral responses. This is an important finding in its own right; NEAT is widely used by state and local WAP sub grantees, utility companies, and home energy audit firms.

The results are striking because Michigan’s cold winters and the likelihood that the weatherized homes were not in perfect condition suggests that it may have been reasonable to expect high returns in this setting. Regardless of one’s priors, this paper underscores that it is critical to develop a body of credible evidence on the true, rather than projected, returns to energy efficiency investments in the residential and other sectors. The findings also suggest that the last several decades may have seen too much investigation into the why of the energy efficiency gap and not enough into whether there really was one.

Future research should examine whether the real world returns to energy efficiency investments differ so starkly from engineering projections in other settings.

References

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Allcott, H. and Greenstone, M. (2015). Maximizing money vs. utility: Measuring the welfare effects of energy efficiency programs. Mimeograph.

Barbose, G. L., Goldman, C. A., Hoffman, I. M., and Billingsley, M. A. (2013). The future of utility customer-funded energy efficiency programs in the United States: projected spending and savings to 2025. Energy Efficiency Journal, 6(3):475–493.

Callaway, D., Fowlie, M., and McCormick, G. (2015). Location, location, location: the variable value of renewable energy and demand-side efficiency resources. Working paper.

CPUC (2015). 2010 to 2012 energy efficiency annual progress evaluation report. Technical report, California Public Utilities Commission.

Davis, L. (2008). Durable goods and residential demand for energy and water: evidence from a field trial. RAND Journal of Economics, 39(2):530–546.

Davis, L., Fuchs, A., and Gertler, P. (2014). Cash for coolers: evaluating a large-scale appliance replacement program in Mexico. American Economic Journal: Economic Policy, 6(4):207–238.

Davis, L. and Muehlegger, E. (2010). Do Americans consume too little natural gas? An empirical test of marginal cost pricing. The RAND Journal of Economics, 41(4):791–810.

Dubin, J. A., Miedema, A. K., and Chandran, R. V. (1986). Price effects of energy-efficient technologies: a study of residential demand for heating and cooling. The RAND Journal of Economics, 17(3):310–325.

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EERE (2010). Review of selected home energy auditing tools: in support of the development of a national building performance assessment and rating program. Technical report, U.S. Department of Energy, Energy Efficiency & Renewable Energy.

EIA (2015). Natural gas monthly. Technical report, Energy Information Administration.

Fowlie, M., Greenstone, M., and Wolfram, C. (2015). Are the non-monetary costs of energy efficiency investments large? Understanding low take-up of a free energy efficiency program. American Economic Review Papers and Proceedings. Friedman, D. (1987). Cold houses in warm climates and vice versa: A paradox of rational heating. Journal of Political Economy, 95(5):1089–97.

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Graff Zivin, J. and Novan, K. (2015). Upgrading efficiency and behavior: electricity savings from residential weatherization programs.  arefiles.ucdavis.edu.

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Posted in Weatherization | Tagged , | 1 Comment

Congressional hearings on Rail

June 10, 2008. S. HRG. 110–1165 Keeping America Moving: A review of national strategies for efficient freight movement. 74 pages.

Hearing before the subcommittee on SURFACE TRANSPORTATION & MERCHANT MARINE INFRASTRUCTURE, SAFETY, & SECURITY of the committee on COMMERCE, SCIENCE, & TRANSPORTATION. U.S. Senate 110th Congress 2ND Session

EDWARD R. HAMBERGER, PRESIDENT & CEO, ASSOCIATION OF AMERICAN RAILROADS

In 2007 freight railroads averaged 436 miles per gallon. That is to say, we on average moved one ton of freight 436 miles on one gallon of fuel.

But ultimately, at the end of the day it all comes down to money. We are going to have to invest to expand capacity, and we’ve been doing that. Since 1980 the industry has spent $420 billion on infrastructure and equipment. That includes maintaining and expanding the infrastructure. That is 40 cents out of each revenue dollar goes into capital expenditures or maintenance expenditures.

To place that into perspective, each of the two largest freight rail companies spends more to maintain and improve their track and roadway than all but three of Secretary Glynn’s members at AASHTO spend on their State highway programs. The next two largest railroads would be ranked in the top ten in comparison to what an individual State spends on its highway network. The ability of the railroads to continue investing obviously will depend upon their ability to make an adequate rate of return. As the Congressional Budget Office noted in its report 2 years ago, profits are key to increasing capacity because they provide both the incentive and the means to make those new investments. In order to meet the projected demand, Cambridge Systematics did a study for the Department of Transportation report which estimated that $148 billion will need to be spent on capacity expansion alone, not maintaining, not replacing, capacity expansion, between now and the year 2035, just to maintain the freight rail market share. The Cambridge Systematics report projects that all of that money will probably not be coming from the freight railroads. We believe that there is a role for government to play because of the public benefits of moving freight by rail. Those benefits include fuel utilization, less CO2 emissions, and obviously congestion mitigation. Because of the public benefits, I would like to suggest a couple of policies that Congress may consider.

A comprehensive, reliable, and cost-effective freight railroad service is critical to our Nation. Today, freight railroads account for more than 40% of U.S. intercity ton-miles—more than any other mode of transportation—and serve nearly every industrial, wholesale, retail, agricultural, and mineral-based sector of our economy.

Looking ahead, the United States cannot prosper in an increasingly-competitive global marketplace if our freight is not delivered efficiently and cost effectively. Having adequate freight rail capacity is critical to this effort. Freight railroads must be able to both maintain their extensive existing infrastructure and equipment and build the substantial new capacity that will be required to transport the significant additional traffic our economy will generate. I respectfully suggest that Members of this Committee, your colleagues in Congress, and other policymakers have critical roles to play. Indeed, a primary obligation of policymakers is to take steps that assist—and, just as importantly, not take steps that hinder—railroads in making the investments needed to provide the current and future freight transportation capacity our Nation requires.

A mix of train types determines the speed and spacing of trains on a track. A corridor that serves a single type of train can usually accommodate more trains per day than a corridor that serves a mix of train types. Trains of a single type can be operated at similar speeds and with more uniform spacing between the trains, in part because they have similar braking and acceleration capabilities. This increases the total number of trains that can operate over a track segment each day.

When trains of different types—each with different length, speed, and braking characteristics—share a track segment, greater spacing is required to ensure safe braking distances and accommodate different acceleration rates. As a result, the average speed drops and the total number of trains that can travel over the corridor is reduced.

Moreover, different train types and customer segments have different service requirements. For example, premium intermodal movements demand high levels of delivery reliability, timeliness, and speed; bulk trains (e.g., coal or grain unit trains) may need consistent, managed service with coordinated pick-up and delivery, but high transit speed is often less important; customers who own or manage their own fleet of freight cars may require railroads to undertake network strategies which help them minimize these costs, such as maximizing the number of annual loaded trips rail cars make; passenger trains require high speed and reliability within a very specific time window; and so on. In addition, a railroad must be able to move empty freight cars through the network in a manner which positions them to provide service based on continually-changing levels of customer demand.

Rail traffic is not uniformly distributed each day, so on some days considerably more than 100,000 carloads are originated. In fact, the carloadings on the heaviest business day of the busiest season may exceed by 40 percent those of the lightest business day of the lightest season. The variance is caused in roughly equal parts by seasonal demand and the five-day work week of most rail customers. These demand variations have a significant impact on rail capacity requirements.

Like firms in every other industry, railroads have limited resources. Their ability to meet customer requirements is constrained by the extent and location of their infrastructure (both track and terminal facilities); by the availability of appropriate equipment and employees where they are needed; and by the availability of funds necessary to augment what they already have.

The constraints railroads face—particularly those involving their physical network—cannot be changed quickly.

  1. It can take a year or more for locomotives and freight cars to be delivered following their order
  2. 6 months or more to hire, train, and qualify new employees
  3. Several years to plan, permit, and build new infrastructure

In light of these factors and many more, railroads must design effective operating plans that meet customer requirements within the confines of the physical constraints they face. The complexity of such a plan is enormous. For example, it must incorporate the differing types of demand placed on various portions of a network, as well as the changes in that demand. Sometimes these changes evolve over several (or more) years and are based on changes in underlying markets—e.g., the emergence of the Powder River Basin as the premiere source of domestic coal, the growth of imported goods from the West Coast, or the development of ethanol markets. At other times, these changes are relatively sudden—brought on, for example, by natural events (e.g., floods or hurricanes), economic factors (e.g., export surges due to a weaker dollar), or the loss or gain of traffic flows of a major customer or group of customers through plant openings or closings or the competitive bidding process. Sometimes these changes can be foreseen; at other times, they are wholly unexpected.

A railroad’s operating plan must allocate this demand across a network that has terminal processing constraints (e.g., the number of yard tracks, locomotive facilities, configuration, etc.); line-haul capacity constraints (e.g., number of main tracks and crossover points between them; location and frequency of sidings; types of signaling systems; speed limits; connections with other routes; etc.); locomotive availability (e.g., the number, their horsepower, availability of support facilities for fueling and maintenance, etc.); and employee constraints (e.g., number, location, crew support facilities, equipment maintenance and servicing personnel, etc.). On every major railroad, all of these factors must be combined to develop a plan to move traffic safely and efficiently 24 hours per day, every day of the year. Unlike airline networks, where the period after midnight can usually be used to recover from the previous day’s problems, a rail network operates 24 hours a day. Thus, incident recovery must be accomplished while current operations are ongoing.

Sophisticated computer models are available to assist in the network planning process. However, these simulation results must be interpreted and validated by knowledgeable railroad personnel who use their judgment and experience as to what works and what does not. Because of its complexity, the development of a new network operating plan to accommodate substantially-changed conditions typically takes months or years, not days or weeks.

The need for safe operations trumps everything else, and proper line maintenance is essential for safe rail operations. However, the need for maintenance adds still another level of complexity to rail planning. In fact, because of higher rail volumes and a trend toward heavier loaded freight cars, the maintenance of the rail network has become even more important. Railroads have no desire to return to the days when maintenance ‘‘slow orders’’ (speed restrictions below the track’s normal speed limit) were one of the most common causes of delay on the rail network. That’s why one of the most important parts of any railroad operating plan is the accompanying maintenance plan with which it is integrated, and minimizing the impact of maintenance disruptions on rail operations is one of the major reasons for the additional main track capacity that is being added to the rail network today.

Terminals and their operation are another key consideration for preserving fluidity in a rail network. A train may operate without delay over a segment of main line. However, if it cannot enter a terminal due to congestion, then it must remain out on the main line or in a siding where it could block or delay other traffic. The ability of a terminal to hold trains when necessary and to process them quickly is one of the key elements in preventing congestion and relieving it when it does occur. Thus, one of the most important factors in increasing capacity for the rail network is enhancing the fluidity of terminals. Unfortunately, terminals are often one of the more difficult areas in which to add capacity. They are frequently in, or near, urban areas. Expansion generally means high land cost and, potentially, high mitigation costs. Even in less urban areas, a rail terminal is rarely considered positive by nearby residents, and its development or expansion to accommodate freight capacity growth is usually the subject of intense debate.

Four-Stage Railroad Capacity Upgrade Process

Railroads typically have four stages in the process of upgrading their capacity. They are explained sequentially below, but in actual practice tend to be used in parallel:

  1. Identify and implement process changes that can enhance capacity. This includes a wide variety of steps, such as redesigning the railroad’s transportation and operation; redesigning, negotiating, and implementing new interchange plans with connecting railroads; redesigning yard and terminal operations; working with customers to improve their inbound or outbound flow processes; changing a maintenance plan; redesigning the process utilized to inspect and maintain equipment, rethinking and implementing new freight car distribution strategies; and redeploying locomotives for more effective utilization. Some of these process improvements can be designed and implemented in weeks or months. Others may require a year or more.
  2. Develop and deploy improved information technology and processes for utilizing that technology. This includes improvements in such areas as dispatching and control systems; terminal management systems; maintenance planning systems; transportation planning systems; work assignments; locomotive and freight car monitoring; track defect identification and diagnostic systems; and locomotive maintenance management systems. Some of these improvements too can be implemented in only a few months, while others are more complex and may take several years to develop and implement.
  3. Acquire and deploy assets that can be used ‘‘flexibly.’’ This includes assets such as locomotives, freight cars, and higher-capacity maintenance machinery. These items are not restricted to any particular portion of the rail network, but can be deployed where and when needed. Trained employees are perhaps the most important of the ‘‘flexible’’ assets. Equipment usually requires at least 6 months to acquire, often after many additional months of planning and design; employees usually require at least 6 months to train.
  4. Adding more infrastructure, or ‘‘iron in the ground.’’ This represents long- term assets that, once in place, cannot be redeployed elsewhere. Usually, they take at least 1 year to deploy, and frequently take three to 10 years to plan, design, permit, and build. These include projects such as main line capacity additions (e.g., new main tracks, sidings, and signal systems); new terminal capacity (e.g., intermodal and automotive terminals, freight classification yards, locomotive and freight equipment repair and servicing facilities); large scale upgrades of choke points in urban areas (such as the Alameda Corridor and the series of Kansas City ‘‘flyover’’ projects); new customer access routes; major bridge additions or rebuilds; improving tunnel clearances; and improvements in connectivity between different portions of the rail network.

The massive investments railroads must make in their systems reflect their extreme capital intensity. Railroads are at or near the top among all U.S. industries in terms of capital intensity. In fact, from 1997 to 2006 (the most recent year for which data are available), the average U.S. manufacturer spent 3 percent of revenue on capital expenditures. The comparable figure for U.S. freight railroads was 17 percent, or more than five times higher. Likewise, in 2006, railroad net investment in plant and equipment per employee was $662,000—nearly eight times the average for all U.S. manufacturing ($84,000).

The 4 largest Class I railroads spend far more on capital outlays and maintenance of track and roadway than the vast majority of state highway agencies spend on their respective highway networks. For example, only the highway agencies of Texas, Florida, and California spend more on roadway capital and maintenance than Union Pacific and BNSF each spend on their networks. CSX and Norfolk Southern are in the top ten compared with all states.

2006 in $ Billions. Data includes capital outlays and maintenance expenses

State spending on highways: 7.57 Texas  5.69 Florida  4.19 California  3.59 New York   3.30 Pennsylvania   3.30 Illinois   2.61 Michigan   2.48 North Carolina   2.14 Ohio   1.88 Georgia

Railroad spending on Way & Structures: 4.17 UP   3.89 BNSF 2.62 CSX   2.12 Norfolk Southern

Sources : FHWA Highway statistics Table SF-12 and AAR analysis of R-1 annual reports

The benefits of increased efficiency can be seen through the results of rail efforts to ‘‘supersize,’’ automate, and increase the velocity of traffic flows where practical. For example, railroads have offered trainload service to grain customers who have built high-speed ‘‘shuttle loader’’ elevators, which dramatically improve the efficiency of transporting grain by rail. At BNSF, for example, a typical grain car in shuttle service hauls approximately 3 times as much grain over the course of a year as a car in non-shuttle service.

Challenges to Freight Mobility and Capacity Expansion

The preceding section details many of the ways that railroads are diligently addressing the capacity issue. However, there are a number of serious impediments to meeting the rail capacity challenge which in many cases have prevented, delayed, or significantly increased the expense of realizing the desired capacity improvements. The National Surface Transportation Policy and Revenue Study Commission, in its final report released in January 2008, stated that, ‘‘Simply put, the Commission believes that it takes too long and costs too much to deliver transportation projects, and that waste due to delay in the form of administrative and planning costs, inflation, and lost opportunities for alternative use of the capital hinder us from achieving the very goals our communities set.’’

The Commission’s point often applies to rail infrastructure expansion projects, including projects that involve little or no public financial participation. Under existing law, a comprehensive regulatory regime preempts state and local regulations (with the exception of local health and safety regulations) that unreasonably interfere with railroad operations. Moreover, detailed environmental reviews, when required, identify the impacts of railroad infrastructure projects and determine necessary mitigation measures. Nevertheless, often some members of the affected local communities still oppose many rail expansion projects, and their opposition tends to be quite vocal and sophisticated. Trains do make noise, rail operations may at times be disruptive to those who live or work nearby, and the regional or national benefits of rail freight service are often not readily apparent to, or deemed important by, the local population. Even those who recognize the benefits of rail freight service may prefer that railroads run their trains near somebody else’s building or through some other town. In many cases, railroads face a classic ‘‘not-in-my-backyard’’ problem. In the face of local opposition, railroads try to work with the local community to find a mutually satisfactory arrangement. These efforts are usually successful. When agreement is not reached, however, projects can face seemingly interminable delays and higher costs. For example, Norfolk Southern had to endure almost 5 years of delay and uncertainty before it was allowed to construct and begin operating its terminal in Austell, Georgia, needed to handle rapidly-increasing intermodal traffic within the region. More recently, Union Pacific continues to suffer delays in double-tracking its Sunset Corridor in Arizona due to issues with a state agency.

Strong local opposition can delay a project so long that costs go up

Often, local communities allege violations of environmental requirements to challenge the proposed project. Railroads understand the goals of environmental laws, and appreciate the need to be responsive to community concerns, but community opposition to rail operations can serve as a significant obstacle to railroad infrastructure investments, even when the opposition has no legal basis. These types of delays can have significant negative affects on the costs of rail projects, and, in turn, the ability of railroads to respond to service requests. Based on railroad cost index data from the AAR, just in the 5-years from the first quarter of 2003 through the first quarter of 2008, railroad wage rates rose 15%, wage supplements (fringe benefits, such as health insurance for employees) rose 11%, and the cost of materials and supplies (which includes such items as rail, crossties, and ballast) rose 52%

Railroads will continue to advocate that the time required for these review processes be shortened without adversely affecting the quality of that result, but until that happens, rail expansion projects will often be delayed unnecessarily.

Today’s Earnings Pay for Tomorrow’s Capacity

As described above, the railroads are diligently doing everything they believe to be prudent to maintain and expand their capacity to provide service, including committing record levels of investment.

It is important to note that because U.S. freight railroads are overwhelmingly privately owned and must finance the vast majority of their infrastructure spending themselves, capacity investments are accompanied by substantial financial risk. As the Government Accountability Office noted in a recent report, ‘‘Rail investment involves private companies taking a substantial risk which becomes a fixed cost on their balance sheets, one on which they are accountable to stockholders and for which they must make capital charges year in and year out for the life of the investment.’’

Accordingly, railroad capacity investments must pass appropriate internal railroad investment hurdles—i.e., the investments will be made only if they are expected to generate an adequate return. For this reason, adequate rail earnings are critical for capacity investment. As the Congressional Budget Office (CBO) has noted, “As demand increases, the railroads’ ability to generate profits from which to finance new investments will be critical. Profits are key to increasing capacity because they provide both the incentives and the means to make new investments.’’ If a railroad is not financially sustainable over the long term, it will not be able to make capacity investments to maintain its existing network in a condition to meet reasonable transportation demand, or make additional investments in the replacement or expansion of infrastructure required by growing demand.

Statements about railroads’ ‘‘record profits’’ often ignore the fact that rail profitability in earlier years was relatively poor. Thus, an improvement from earlier years may be a ‘‘record,’’ yet still fall short of the earnings achieved by most of the other industries against which railroads compete for capital. In fact, that is the case with the rail industry. Rail industry profitability has consistently lagged most other industries—and that is still the case today.

Return on equity (ROE) is a common profitability measure. According to data compiled by Value Line (a financial information firm), the ROE for the U.S. freight rail industry in 2006 was 14%—possibly the best ROE it has ever had. (Value Line’s railroad universe includes BNSF, CSX, CN, CP, KCS, NS, UP, and Genesee & Wyoming.) By contrast, the median ROE in 2006 for the 89 industries (encompassing around 1,700 firms) for which Value Line calculates ROE was 16.2%. In 2006 railroads tied for 57th among the 89 industries for which Value Line calculates ROE. Value  Line data for 2007 indicate that the railroad median (14%) again fell well short of the median for all industries (15.8%).

So while recent years may have been the best financial years ever for railroads, they have not been sufficient to bring railroads even to the mid-point among all industries, and the need for financial sustainability is as pronounced today as ever before—especially in view of the projected investment requirements the industry will be facing.

According to the Cambridge Systematics study noted earlier, an investment of $148 billion in 2007 dollars (of which $135 billion is for Class I railroads) will be necessary for rail infrastructure expansion to keep pace with economic growth, meet the DOT’s forecast demand, and maintain (but not grow) rail’s current market share.

That expenditure is in addition to the hundreds of billions of dollars necessary over this period to maintain and replace existing rail infrastructure, and to maintain and replace locomotives, freight cars, and other equipment.

Class I railroads are anticipated to be able to generate (through earnings growth from the additional traffic and productivity gains) only $96 billion of the $135 billion needed for new capacity identified by the Cambridge Systematics study. That leaves a funding shortfall that could be covered by tax incentives for rail infrastructure investments, public-private partnerships, or other means. Railroads will continue to spend significant amounts of their own funds to address the capacity challenges described above. However, they are, and will continue to be, unable to pay for all of the capacity that would be required to serve all shippers’ needs all of the time. Since the amount of rail capital available for investment is limited, investment decisions in these circumstances focus on which investments to choose between, rather than solely whether a specific investment should be made. In such cases, those investment decisions should be based on projected returns that will most favor the long-term sustainability of the rail network.

Public Involvement in Freight Rail Infrastructure

Investment Freight railroads will continue to spend massive amounts to improve and maintain their systems. But even with their improved financial performance, funding constraints will likely prevent railroads from meeting optimal future rail infrastructure investment needs entirely on their own. This funding shortfall means that many rail projects that would otherwise expand capacity and improve the ability of our Nation’s farms, mines, and factories to move their goods to market; speed the flow of international trade; relieve highway congestion; reduce pollution; lower highway costs; save fuel; and enhance safety will be delayed—or never made at all. I respectfully suggest that it is in our Nation’s best interest to ensure that optimal freight railroad capacity enhancements are made. Policymakers can help address the rail capacity funding gap in several ways:

Rail Infrastructure Tax Incentives. S. 1125/H.R. 2116 (the ‘‘Freight Rail Infra structure Capacity Expansion Act of 2007) calls for a 25% tax credit for investments in new track, intermodal facilities, yards, and other freight rail infrastructure projects that expand rail capacity. All businesses that make capacity-enhancing rail investments, not just railroads, would be eligible for the credit. The budgetary cost of a rail infrastructure tax credit (ITC) would be about $300 million per year, but the stimulatory benefit to the economy would be much greater. U.S. Department of Commerce data indicate that every dollar of freight rail infrastructure investment that would be stimulated by a rail infrastructure ITC would generate more than $3 in total economic output because of the investment, purchases, and employment occurring among upstream suppliers. We estimate that new rail investment induced by a rail ITC would generate approximately 20,000 new jobs nationwide. The AAR gratefully

Short Line Tax Credit. Since 1980, more than 380 new short lines have been created, preserving thousands of miles of track (much of it in rural areas) that may otherwise have been abandoned. In 2004, Congress enacted a 50 percent tax credit (‘‘Section 45G’’) for investments in short line track rehabilitation. The focus was on assisting short lines in handling the larger and heavier freight cars that are needed to provide their customers with the best possible rates and service. Since the enactment of Section 45G, hundreds of short line railroads rapidly increased the volume and rate of track rehabilitation and improvement programs. For example, the replacement of railroad ties, a key component of handling heavier cars, has increased by half a million ties per year in both 2005 and 2006 as a result of the credit. Unfortunately, Section 45G expired in 2007. Pending legislation in Congress (S. 881/H.R. 1584, the ‘‘Short Line Railroad Investment Act of 2007’’) would extend the tax credit and thus preserve the huge benefits it delivers.

Public-Private Partnerships. Public-private partnerships (PPPs) reflect the fact that cooperation is more likely to result in timely, meaningful solutions to transportation problems than a go-it-alone approach. Without a partnership, projects that promise substantial public benefits in addition to private benefits are likely to be delayed or never started at all because it would be too difficult for either side to justify the full investment needed to complete them. In contrast, if a public entity shows it is willing to devote public dollars to a project based upon the public benefits that will accrue, the private entity is much more likely to provide the private dollars (commensurate with private gains) necessary for the project to proceed. Partnerships are not ‘‘subsidies’’ to railroads. Rather, they acknowledge that private entities should pay for private benefits and public entities should pay for public benefits. In many cases, PPPs only involve the public contributing a portion of the initial investment required to make an expansion project feasible—with the railroad responsible for funding all future maintenance to keep the infrastructure productive and in good repair. Perhaps the most extensive rail-related public-private partnership envisioned today is the Chicago Region Environmental and Transportation Efficiency Program (CREATE), a $1.5 billion project involving the State of Illinois, the City of Chicago, and major freight and passenger railroads serving the region. CREATE’s goal is to modernize and improve transportation in the region by separating tracks and highways to speed vehicle travel and reduce congestion and delays for motorists; updating track connections and expanding rail routes to reduce transit times; and adding separate, passenger-only tracks in key locations to remove bottlenecks that have slowed passenger and freight movements in the region for decades. The $330 million first stage of CREATE recently got underway.

Say No to Reregulation. Prior to 1980, decades of government over-regulation had brought U.S. freight railroads to their knees. Bankruptcies were common, rates were rising, safety was deteriorating, and rail infrastructure and equipment were in increasingly poor condition because meager rail profits were too low to pay for needed upkeep and replacement. Recognizing the need for change, Congress passed the Staggers Rail Act of 1980, which partially deregulated the rail industry. The record since Staggers shows that deregulation works. Since 1981, rail traffic is up 95%, rail productivity is up 163%, and average inflation- adjusted rail rates are down 54%. And rail safety is vastly improved— the train accident and employee injury rates have plunged since Staggers. Our privately-owned, largely deregulated freight railroads competing fairly in the transportation marketplace have produced the best freight rail system in the world. It is the best for shippers in price and service; best for employees in compensation and safety; and best for the public in reduced pollution and highway gridlock.

Despite the severe harm excessive rail regulation caused prior to Staggers and the enormous benefits that have accrued since then, legislation has been proposed—most recently, S. 953/H.R. 2125 (the so-called ‘‘Railroad Competition and Service Improvement Act of 2007’’) in the 110th Congress—that would reregulate railroads.

Reregulation is bad public policy and should be rejected. It would prevent railroads from earning enough to make the massive investments a first-class rail system requires. Under reregulation, rail earnings, and therefore rail spending on infrastructure and equipment, would plummet; the industry’s existing physical plant would deteriorate; needed new capacity would not be added; and rail service would become slower, less responsive, and less reliable. By perpetuating the myth that service to a shipper by a single railroad is equivalent to unconstrained market power, proponents of reregulation ignore the reality that railroads face extensive competition for the vast majority of their business—including when a customer is served by only one railroad. Railroads do not oppose competition. There is plenty of it out there already, either between two or more railroads, from trucks and barges, or from other competitive forces. And where the marketplace cannot support more than single railroad service, legal safeguards exist to protect against anti-competitive railroad behavior. The current system of rail regulation works. It allows shippers to pay the lowest possible rates consistent with a privately-owned rail system. It makes no sense to destroy the best freight rail system the world has ever seen in order to move toward a discredited system that failed in the past and would fail again in the future.

Public investment in freight rail infrastructure projects is justified because the extensive benefits that would accrue to the general public by increasing the use of freight rail would far exceed the costs of public participation.

Fuel efficiency—Railroads are three or more times more fuel efficient than trucks. In 2007, railroads moved a ton of freight an average of 436 miles per gallon of fuel. If just 10% of the long distance freight that moves by highway moved by rail instead, fuel savings would exceed one billion gallons per year.

Highway congestion—Highway gridlock already costs the U.S. economy more than $78 billion per year just in wasted fuel and time, according to a study by the Texas Transportation Institute. But because a typical train takes the freight of several hundred trucks off our highways, freight railroads reduce highway gridlock, the costs of maintaining existing highways, and the pressure to build costly new highways. • Pollution—The EPA estimates that for every ton-mile of freight carried, a train typically emits substantially less nitrogen oxides and particulates than a truck. • Safety—Fatality rates associated with intercity trucking are eight times those associated with freight rail transportation. Railroads also have lower employee injury rates.

Freight railroads should not be asked to pay for capacity increases needed to accommodate passenger service. These principles are grounded in the tremendous importance of freight railroads to America’s producers and consumers. Freight railroads lower shipping costs by billions of dollars each year and produce an immense competitive advantage for our farmers, manufacturers, and miners in the global marketplace. If passenger railroads impair freight railroads and force freight that otherwise would move by rail onto the highway, those advantages would be squandered. Moreover, highway gridlock would worsen; fuel consumption, pollution, and greenhouse gas emissions would rise; and our mobility would deteriorate—outcomes that are completely contrary to the goals of expanding passenger rail in the first place.

Senator LAUTENBERG. We spend some $40 billion a year on highways, $15 billion on our aviation system, but little to none on rail. What do you think we could do better to balance the Federal transportation policies, to encourage investment in all modes of transportation?

Mr. HAMBERGER. Well, the difference, of course, for freight railroads is that we are privately owned. So I think it would be most appropriate for the Federal Government to provide an investment tax credit, an investment tax incentive, to encourage even more investment than the industry is already undertaking. As you know, we spent on average about 17 or 18% of all revenue over the last 10 years, on capacity expansion. We have done a survey of our members and if the legislation co-sponsored by Senator Conrad and Senator Smith were to pass we believe that an additional $1.5 billion would be spent just by the railroads on capacity expansion. It’s new capacity.

Government Accountability Office, Freight Railroads: Industry Health Has Improved, but Concerns About Competition and Capacity Should Be Addressed, October 2006, p. 56.

Congressional Budget Office, Freight Rail Transportation: Long-Term Issues, January 2006, p. 11.

REAR ADMIRAL RICHARD M. LARRABEE, (RET.), U.S. COAST GUARD; DIRECTOR OF COMMERCE, PORT AUTHORITY OF NEW YORK & NEW JERSEY

Sustainability, ensuring that we are good stewards of the land, is also a driving factor. One of the agency’s goals is to continue to move more freight from the roads to rail. Although approximately 80 percent of the containerized cargo entering our port stays within the region, a significant and growing portion heads to points west and north. About 13 percent of the port’s cargo moves by rail today, but we are investing nearly $600 million in our on-dock rail infrastructure to increase that proportion to about 20% over the next decade.

Just as airports and highways have a reliable source of funding, so must freight infrastructure. The Highway Trust Fund and Passenger Facility Charge at airports have provided a reliable funding source for systems investments in our Nation’s roads and airports. Seaports and intermodal connections should have a comparable funding mechanism to provide needed systematic investment.

Our freight transportation system is the blood circulation system of our Nation’s economy.

Highway congestion costs over $78 billion a year in wasted fuel and time. One train equals several hundred trucks, and getting trucks off the roads decreases road maintenance costs. Railroads are also 8 times safer, and pollute less.

ASTRID C. GLYNN, COMMISSIONER, DEPARTMENT OF TRANSPORTATION, state of NEW YORK

We are starting to see a disturbing rise in total logistics costs, the first in 25 years. In 1980 logistics costs were approximately 16 percent of the GDP. They had dropped to less than 9 percent a few years ago, a significant spur to economic growth. Now we are headed in the opposite direction, with logistics costs at about 10 percent, and this estimate is prior to the recent and dramatic changes in fuel costs.

As a Nation, we rely upon a legacy of 300 or more years of transportation investment to deliver the promise of an economy of the future. Our most recent major investment, the 50-year old interstate highway system, was laid on top of a 19th century rail system. As a direct result of that Federal investment, the rail system adapted and shrank, leaving thousands of modal disconnects that would be unjustifiable and inconceivable if the network were designed today. The reduction in rail track mileage, the increase in rail traffic (both passenger and freight), and changes in the operating strategy of the freight railroads have resulted in more and longer trains operating at reduced speeds, creating more conflicts with highway movement, increased safety risks, bifurcation of communities, and exacerbation the problems of urban traffic circulation. Some of the best-known freight projects or programs—the Alameda Corridor, CREATE, and the Seattle-Tacoma FAST Corridor—are largely grade separations and crossing upgrades that also benefit highway operations and safety. In areas fortunate enough to have robust commuter rail and inter-city passenger rail, the conflicts are between passenger and rail customers each trying to use the same constrained system.

The nation’s gateway seaports and other major modal and intermodal freight traffic generators established over the past three centuries are now embedded in densely populated urban areas. Most cannot be moved. Their efficiency has been compromised by the characteristics of their surroundings which present obstacles to linking with these important freight gateways with the national highway and rail systems. The lack of connectivity leads to substantial negative environmental impacts on local communities. Many of those negative impacts can be mitigated by improving the transportation connections between these freight gateways and the core national transportation system. Deficient intermodal connectors were identified at the time the National Highway System was designated in the mid-1990s. In the decade since there has not been a systematic, national strategy to address the local burden of transportation facilities which provide national benefits.

 

PAUL R. BRUBAKER, ADMINISTRATOR, RESEARCH AND INNOVATIVE TECHNOLOGY ADMINISTRATION, U.S. DEPARTMENT OF TRANSPORTATION

The multi-state international makeup of supply chains, coupled with the fact that much of the infrastructure is owned and operated by multiple public and private entities, will require the establishment of public-private partnerships, cooperations, and better institutional arrangements in order for the Department to achieve its goals.

Changes in demographics, manufacturing, and warehousing, and a dramatic increase in imported manufactured goods and foods, have caused freight funneling at major gateway ports, leading to congestion on the highways and at the rail connections as containers are reloaded on trucks and rail cars. Private sector changes in inventory management and production operations are placing demands on the transportation system that go beyond connectivity to speed, reliability, and throughput. Logistics costs have been rising for some time. As reported by the Council of Supply Chain Management Professionals, logistics costs as a percent of gross domestic product have increased 63 percent since the beginning of 2004.

Moreover, all the freight modes have responded effectively to shipper requirements, providing more frequent service of smaller shipments to accommodate their demands for Just-in-Time deliveries of freight that allow reductions in inventories and logistics costs.

Many long-distance trucking firms use GPS transponders on their cabs to track their assets; this allows businesses to maintain continual awareness of asset movement. Through a collaborative agreement with the American Transportation Research Institute, we can tap into GPS data from over 350,000 trucks that are traversing our Nation’s roadways on any given day. We hope to expand this data to include over 400,000 trucks by 2009. We use this data to calculate travel speed and time reliability throughout twenty-five corridors across America. This helps the Department gain insight into system performance, so that we can better focus our efforts in increasing network capacity. These system performance measures allow every entity involved in transportation, public and private, to better manage its resources.

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Drinking the Kool-Aid. The U.S. Senate believes we are energy independent.

[Some of the interesting parts of this session are $95 billion dollars of new manufacturing, transport, & utilities that are growing to take advantage of the cheap NG here, which will exponentially increase the use of energy. Even if we had 100 years of oil and gas, exponential growth cuts that in half or more… Also battles between Oil & Gas producers to export LNG versus DOW and other industries who want to keep most of the NG here.  There are allegations that the overproduction of NG was an illegal scam for speculative investment in export of LNG, the NRDC on the damage of fracking, and the Wilderness Society about the massive amounts of drilling in America, much of it on Federal Land. This was somewhat surprising to me since so much of the oil & gas company testimony is begging congress for opening up restricted land so they can DRILL, BABY, DRILL.]

2013-2-12. Natural gas resources S. Hrg. 113-1. United States Senate. 188 pages.

TO EXPLORE OPPORTUNITIES AND CHALLENGES ASSOCIATED WITH AMERICA’S NATURAL GAS RESOURCES

Jack Gerard, President and Chief Executive Officer, American Petroleum Institute:

“Six/seven years ago someone estimated [reserves were] about 20 to 30 years. Most recently the EIA has estimated that it’s at least 90–95 years. Other independent analysis—ICF, etcetera have estimated it’s 150 years, and there’s some who’ve believe it’s 200–300 years worth of supply at current levels of consumption. It’s evolving quickly because of breakthrough technology as we define more resources. It’s going up dramatically quickly. What happened today, and I can’t overstate this, what is happening today is unprecedented in the history of our country in terms of our opportunity to become energy secure and self-sufficient. Just think back 5 or 6 years ago nobody was having this conversation. Today we’re the world’s No. 1 gas producer. It’s now estimated through this advancement in technology, we’ll be the world’s No. 1 oil producer by 2020, 7 short years and surpass Saudi Arabia.”

Drinking the Kool-aid: political leaders swallow LNG, fracking fluids, and the belief the US is Energy Independent

[my comment: Leaders represent the businesses within their domain and keep their personal opinions to themselves.  Murkowski and Hickenlooper are leaders from energy-producing states and promote those industries, regardless of what they think, especially ironic from Hickenlooper because he was a host and speaker at the Association for the Study of Peak Oil conference in 2005 when he was Mayor of Denver. Being an energy producer cheerleader is one of many reasons why Americans aren’t hearing about the energy crisis from their leaders]

“The really great thing was when someone dipped a graham cracker into the LNG and passed it around for the rest of us to eat. Senator Wyden waited for me to take the first bite to make sure I didn’t die. It was like a Thin Mint from the freezer. So I think we demystified some of the concerns about LNG (Mufson, S. Feb 9, 2013. Q&A: Republican Sen. Lisa Murkowski of Alaska on her ‘20/20’ vision for energy policy. Washington Post)

JOHN W. HICKENLOOPER, GOVERNOR OF COLORADO: At one point in my office, I’m not sure how this happened, but the new frack fluid is made with food additives, and somehow we all took a swig of the new frack fluid, and it was not terribly tasty, but again, I’m still alive to—like Senator Wyden coming back from Alaska is still alive to tell the story.

RON WYDEN, U.S. SENATOR FROM OREGON.

For the first time in decades, our Nation will be able to rely on its own U.S. energy resources, especially new oil and gas development from shale instead of being dependent on imports from the Middle East and other parts of the world that haven’t always had our best interests at heart. This is a major change for American energy policy.

36 years ago the predecessor to this committee called the Interior and Insular Affairs Committee, and they held hearings on natural gas as the country faced a supply emergency that triggered shortages across the Northeastern United States. During that supply emergency hundreds of thousands of people were laid off as commerce and industry reduced hours or simply shut down altogether. The committee at that time was chaired by our legendary Senator, Henry ‘‘Scoop’’ Jackson, and the committee released a report prepared by the Department of Defense predicting that LNG imports would account for 10% of the country’s gas supply [and that report] has dominated American energy policy until just a few years ago. In 2005, Congress, over the objection of some, swept aside the ability of States to even approve the siting of LNG import terminals. As recently as 2007, when the Congress last enacted major legislation the focus was still overwhelmingly on energy scarcity.

Today, the outlook could not be more different. Instead of scarcity and shortages, the prediction is that domestic production will soon outstrip American demand. Given the dramatic change in the outlook for natural gas supply, it is clearly time for a fresh look at our current policies and to start thinking about how to update those policies to reflect a very new reality.

MARY L. LANDRIEU, U.S. SENATOR FROM LOUISIANA. The wealth of natural gas is extraordinary, with estimates indicating America currently has 317 trillion cubic feet of proven, accessible reserves, and a further 2,000 tcf in total resource base estimates. This is enough to fulfill our current demand, a little over 24 bcf per day, for over 100 years.

Louisiana, Methanex Corporation, which moved its last U.S. plant overseas in 1999, is now spending over $1 billion to move a methanol plant from Chile to Ascension parish, near Baton Rouge. This plant will produce the raw materials for everything from windshield washer fluid to paints and sealants, even wrinkle free shirts. Williams, a petrochemical company based in Tulsa, is planning a new $400 ethylene plant also in Ascension parish, where they will supply our plastics manufacturers. Finally, CF Industries, one of the world’s largest producers of nitrogen fertilizer, is looking to spend $2.1 billion to build a new fertilizer plant in Ascension. That’s over $3.5 billion being invested in one parish in Louisiana, all thanks to our new abundance of domestic natural gas. Of course, that isn’t the whole story; nationwide, these same petrochemical, plastics, steel and fertilizer industries are planning to invest upwards of $80 billion in new plants and new capabilities.

One of the most important topics in our conversation about how best to approach this new wealth of natural gas is the issue of exports, specifically liquefied natural gas, to nations around the world. There are strong arguments to be made on each side, for and against the expansion of these exports, and I am sensitive to both. I believe, however, that there is enough domestic production, and the capacity for enough production increase to support our vital manufacturing industry and allow for responsible levels of export. The recent NERA study, commissioned by DOE, supports this view, and indicates that it is possible for a level of export to exist that both incentivizes increased production while at the same time continuing to provide our domestic consumers with reliable, low-cost natural gas.

LISA MURKOWSKI, U.S. SENATOR FROM ALASKA. Natural gas is now an abundant, affordable, clean source of energy, providing great opportunities for economic growth, and an energy security. When we look at our energy sources just a few years ago, we were talking about the scarcity of our resources. We have now moved from a discussion about scarcity to one of abundance. In addition, our allies overseas are now looking at the United States, they want our natural gas, and we’ve got enough resources to help make that happen.

This requires us to look critically and perhaps rethink some of the conversations that we have had about energy. Last week I introduced a proposal in a document about 115 pages, Energy 20–20, that I hope will spur us to conversations about energy and how we should be looking differently at energy because of exactly this—this paradigm shift, going from one of scarcity to relative abundance. Our resource base estimates have increased 44 percent for natural gas in less than 5 years. That’s pretty incredible. Production is up, prices are low. There’s been a positive impact on our greenhouse gas emissions.

We also need to be careful about intervening in efforts to export our LNG. There’s a long established regulatory process for natural gas exports through the Department of Energy and through the FERC. This includes environmental review under NEPA. So before we reinvent the wheel, I think we need to look at existing laws and regulations and determine if and where there are deficiencies. The debate on this issue has focused on the impacts to domestic natural gas prices and supply, but I think we also need to include within this discussion an understanding of the role that the market forces will play, not only on domestic prices, but the number of projects that may actually be built. These are mega projects that we are dealing with, in every sense of the word, ranging from $8 billion to $25 billion, depending on the amount of existing infrastructure. Up in Alaska, we’re talking about a project of about $65 billion. This is real money. Gas is a global commodity, and other countries, including Canada, are already moving forward. So I don’t think that dragging our feet is an option here, if we want to export our LNG. We should also not forget the positive impacts that exports would have on our trade imbalance and the geopolitical benefits of exporting to our allies.

STATEMENT OF PAUL SANSONE, SANSONE & ASSOCIATES

The ‘Shale Gale’, a huge expansion of available domestically produced natural gas, is the subject of the hearing. I am writing to provide documentation that the legal and regulatory oversight of the industry was manipulated by apparent fraud to secure exception from environmental regulation (Clean Air Act, and Clean Water Act exemptions), fast track approval for LNG ‘‘import’’ terminals ( FERC review not State review), and the right of eminent domain for natural gas pipelines connected to these terminals. Substantial evidence exists that the use of false and misleading information and industry wide racketeering was utilized to allow industry to produce the current oversupply of natural gas and create a political and economic conditions necessary to convert the ‘‘stranded assets’’ of import terminals and pipelines for the export of natural gas. The goal of the apparent fraud and racketeering appears to be a covert effort to convert limited regional natural gas markets into an internationally traded commodity which could be used for speculative investment. The scope and impact of this apparent fraud obligates an immediate investigation, the cessation of any natural gas export permits until the full facts are made public, and the criminal prosecution of those responsible for misleading Congress and the American people.

ANDREW N. LIVERIS, CHAIRMAN & CEO, DOW CHEMICAL COMPANY, MIDLAND, MI

Dow is a major user of natural gas and natural gas liquids (NGL), both as an energy source and as feedstock for production of our products to drive the chemical reactions necessary to make useful products.

Dow’s global hydrocarbon and energy use amounts to the oil equivalent of 850,000 barrels per day, the daily energy use of Australia.

Natural gas is an essential component in thousands of everyday consumer products such as cars, appliances, paper, steel, plastic products, pharmaceuticals, and fertilizer for our farms. Natural gas provides heat, hot water, cooking and electric power to tens of millions of residential consumers.

Manufacturing in the United States is undergoing a renaissance, facilitated in substantial part by reasonable and stable natural gas prices. For the first time in over a decade, domestic manufacturers in multiple industries, including petrochemicals, fertilizers, glass, aluminum and steel, are planning to invest in production facilities in the United States. Over 100 new projects have been announced so far, representing approximately $95 billion in new investments. Dow alone is investing about $4 billion in new U.S. facilities. To a great extent, continuing optimism for U.S. manufacturing is founded on the prospect of an adequate, reliable and reasonably priced supply of natural gas.

A plentiful and affordable natural gas represents a tremendous competitive advantage for American industry. It would be misguided to take actions that threaten this advantage.

As with any other commodity, the supply of and demand for natural gas determine its price, and the balance between the two is affected by governmental policies. At the same time, U.S. manufacturers are particularly sensitive to natural gas price fluctuations.

As natural gas prices rise, manufacturers are more likely than other sectors of the economy to reduce their consumption. Because of this relatively high demand elasticity, manufacturers tend to serve as ‘‘shock absorbers’’ for the economy when natural gas prices rise. They cut consumption of natural gas, which reduces demand and mutes price volatility for others. Gas price increases undermine manufacturing jobs. The United States enjoyed relatively stable natural gas prices from the 1970s to around 2000. Between 2000 and 2009, however, U.S. industrial gas demand fell 24% as prices rose to highs of almost $14.50/MMBtu from a base of roughly $3.50/MMBtu. Job losses in the manufacturing sector totaled approximately 5.4 million between 2000 and 2009, and volatile natural gas prices were a significant factor. Manufacturing’s high demand elasticity also means that governmental policies that tend to encourage upward pressure on natural gas prices affect manufacturers more than other sectors.

Utilizing natural gas domestically would enhance employment and value added throughout the economy. As demonstrated in the chart below*, the effect of deploying 5bcf/day of natural gas in the domestic manufacturing sector would be an increase of $4.9 billion in the national value added (GDP) and a manufacturing employment increase of 180,000 jobs, both directly and through the supply chain. In stark contrast, exporting that same 5bcf/day of natural gas overseas as liquefied natural gas (LNG) would lead to a GDP increase of only $2.3 billion and an employment increase of only 22,000 jobs. Moreover, even within the construction sector the payoff from using natural gas domestically far exceeds the benefits of exporting LNG, as the plant-building construction activity associated with increasing the supply of natural gas to energy intensive, trade exposed industries is more than four and one-half times greater than the construction activity associated with LNG exports.

Shale gas production has created a short-term focus on expanded supply and the effect of that supply on market clearing prices. We believe that focus is misplaced because very few policy-making and investment decisions have an impact over such a short time horizon. Instead, investment and policy-making should be focused on both the medium-and long-term outlook for natural gas. In the medium-and long-term, domestic natural gas demand growth is expected to be driven by several factors, including: • The policy-driven shift in electricity production from coal to natural gas, • Increased investments by industry, which uses forty percent of the nation’s natural gas and gas-produced electricity, and • Increasing numbers of truck and fleet vehicles that use natural gas in lieu of conventional motor fuels. Companies in the manufacturing, transportation and utility sectors are already making investment decisions based on today’s competitive prices and the outlook for affordable and stable natural gas into the future. These decisions will play out over the next ten to twenty years. Our assessments indicate that demand for U.S. natural gas may increase by approximately 60 percent above current levels by 2035. An important corollary question is whether supply can possibly keep up with this new demand.

Congress should be circumspect about policies that could disrupt natural gas supply and pricing, such as:

Policies that focus consumption on one fuel source or that artificially accelerate demand ahead of supply, such as regulations that encourage rapid replacement of coal fired power plants with natural gas power plants. • Bans or unreasonable limitations on recovering natural gas and oil through hydraulic fracturing. • Exporting LNG without a thorough and inclusive process for evaluating the implications for domestic supply and demand, costs to consumers and manufacturers, jobs and economic growth.

Export licensing. Over 70 years ago, Congress recognized that the import and export of natural gas, a finite natural resource, can have critical implications for U.S. prosperity. In the Natural Gas Act, Congress charged the executive branch with regulating the import and export of natural gas in accordance with the public interest. The Department of Energy (DOE) has extensive experience evaluating import applications, but it has had limited experience with export applications. Perhaps not surprisingly, there are no clearly established criteria for DOE to apply in determining the public interest with regard to natural gas exporting. Dow supports expanded exports and trade. However, we also believe it is crucial that DOE have the information and analysis necessary to properly apply the Natural Gas Act requirement that exports be consistent with the public interest. We applaud DOE’s recent acknowledgement that an economic study that it commissioned is but one data point in the broad array of considerations that are relevant for a public interest determination. In short, Dow supports an approach to such determinations by DOE that is based on objective criteria and metrics, established through a public process and applied on an incremental, case-by-case basis in a consistent and balanced manner.

Today, DOE is considering 16 applications to export LNG. Since the proposed importing countries do not have a particular type of free trade agreement (FTA) with the United States, these applications are not covered by the statute’s presumption that an FTA represents a determination that the application meets the public interest test. After approving one such application, DOE has temporarily suspended the processing of ‘‘non-FTA’’ LNG export applications. Implicitly recognizing that more is at stake than can be resolved through its traditional approach to processing export applications, DOE commissioned a report from a private firm to evaluate the macroeconomic effects of higher LNG exports. As detailed in Dow’s January 24 submission to DOE1, this consultant report is fundamentally flawed and underestimates the potential harmful effects of sharply higher LNG exports.

The outstanding authorization requests present what is essentially a new challenge. In the modern era, the U.S. government has not faced the need to determine the public interest in connection with requests to authorize exports of large volumes of natural gas. This Committee should encourage DOE to continue its effort to improve the process for evaluating LNG export applications by providing an opportunity for all affected constituencies and the public at large to comment on how best to assess the public interest as it pertains to exports of natural gas.

Newly discovered sources of natural gas present a great opportunity for the United States. At the same time, natural gas remains a finite natural resource with important implications for U.S. energy security, energy independence and the environment.

Unchecked LNG export licensing can cause demand shocks, and the resulting price volatility can have substantial adverse impacts on U.S. manufacturing and competitiveness. In the recent past, the price of natural gas was very high and volatile until the advent of substantial shale gas production.

DOE interprets the Natural Gas Act’s public interest standard as creating a rebuttable presumption that a proposed export of natural gas is in the public interest. This means that DOE is to approve an application unless those who oppose the application can overcome this presumption.

The topics that DOE has identified for evaluating the public interest are too narrow and vague to capture all of the critical national, regional and local issues at stake with LNG exports or to offer any useful guidance. In response to the economic study it commissioned, DOE has received more than 370 submissions from a broad array of stakeholders covering an equally broad array of topics. The sheer number of submitted comments reflects the depth of interest regarding this issue. Unfortunately, the current process provides no assurance that DOE will consider all aspects of the public interest in any given proceeding. This is inevitable for an administrative process that depends on arguments and evidence submitted by the parties to a specific export application process. These parties are representing their specific interests, and may not adequately represent the totality of the public interest.

We believe the list below provides a good starting point for identifying specific, concrete and forward-looking criteria that DOE should evaluate in connection with LNG export applications: • Domestic manufacturing—How will exports impact natural gas prices and the supply/demand balance? Will natural gas supply be reduced? Will there be less feedstock for announced investment projects? Will the jobs created by increased exports exceed jobs lost by the manufacturing industry? Will additional exports displace U.S. consumption? • U.S. consumers—Will exports reduce the supply of natural gas available for utilities or affect consumer prices or energy costs? Will utilities decrease fuel switching to natural gas? • Energy security—Will exports reduce the volume of natural gas available for domestic use or increase the need to rely on imported petroleum? • Employment—How many new jobs will be created or existing jobs impacted? Are employment gains in the oil and gas sector offset by job losses in other areas of the economy affected by relatively higher natural gas prices? • International trade—Will exports improve the U.S. balance of trade payments sufficiently to offset falling exports in other value-adding sectors of the economy? As to proposed exports to FTA countries, are the exports destined for consumption in the FTA country or will there be transshipment of natural gas to non-FTA countries? How can export applications be disposed of in a manner consistent with U.S. trade obligations? • Environmental—What would the proposed exports’ environmental impact be? • Strategic interests—Will the exports support a strategic American ally in a meaningful way and consistent with stated policy priorities? Do proposed importing countries accord the United States reciprocal favorable international trade treatment? What are the implications for any current or proposed FTA negotiations? • Price and volatility—How is the LNG contract being priced, and is it linked to oil in some manner? What is the expected short and long term impact on natural gas and electricity price volatility? • Other regulatory impacts—What is the potential impact of other regulatory decisions on natural gas demand or supply and what is the interplay between those impacts and exports of natural gas?

We are in year four or five of a 100 year energy advantage.

None of us get the gas price right. Five years ago we had it wrong. We were building import terminals. Five years from now, what’s it going to be? How many terminals should the public interest demand? What is the public interest here? It is to get volatility and instability out of an energy price. We care about agriculture here in this country. We care about defense. We should care about energy. This opportunity to get it right by doing both in the public interest means we should take a crawl- walk-run approach to how many terminals we approve and how many of these occur over time. As I said in my testimony, we’re in the fifth year of our 100-year advantage. You can’t move factories overnight, to state the obvious. Why put at risk the 5 million jobs, the $96 billion worth of investment that are on the books today? Over 60 companies, why put that at risk by doing either or? Why transfer the risk? So be cautious, do what the public interest demands and the DOE application process. I agree, financing will be difficult. I agree, prices will be volatile. But why take the risk and let the speculators set the gas price like they did 10 years ago, and we all remember the Enron’s and what the efficient market did for us 10 years ago. It was hardly efficient. OK. It was very inefficient.

Gas, as already noted, has to be liquefied and shipped at billions and billions of dollars. That is not an open market, that’s a point to point contract. There’s probably 30 of these contracts around the world from nation states to nation states.

ROSS EISENBERG, VP, ENERGY & RESOURCES POLICY, National Assoc of Manufacturers

The NAM is the nation’s largest industrial trade association, representing nearly 12,000 small, medium and large manufacturers in every industrial sector and in all 50 states. Manufacturers are major energy consumers, using one-third of the energy consumed in the United States. For manufacturers, natural gas is a critical component of an ‘‘all-of-the-above’’ energy strategy that embraces all forms of domestic energy production, including oil, gas, coal, nuclear, energy efficiency, alternative fuels and renewable energy sources.

Natural Gas—Fueling Growth in the Manufacturing Sector. The natural gas boom has provided major opportunities for manufacturers across the supply chain. Upstream, manufacturers design and construct drilling facilities; supply machinery and materials, such as cement and steel for hydraulic fracturing and well completion; and perform a wide range of support activities and services for the natural gas extraction process. Midstream, manufacturers provide needed infrastructure, such as pipelines, compressor stations, storage facilities and processing facilities. And downstream, the possibilities-from chemicals to windows to toys to electricity-are truly endless.

 

The natural gas manufacturing supply chain extends even further. All of this new activity will require roads and bridges, which, in turn, requires concrete, brick, gravel and steel. Drilling sites will need vehicles, fuel and significant water supplies- which will need to be supplied, transported and treated. Site employees will need uniforms, and those uniforms will need to be cleaned and maintained. The list goes on and on.

As more natural gas is recovered, domestic manufacturers gain a substantial cost benefit relative to their international competitors. Thanks to newfound supply and price stability, manufacturers in the United States enjoy natural gas prices considerably lower than in China, India, Brazil, Japan and the United Kingdom.1 This is a very important point, since the NAM estimates that due to domestic tax, tort and regulatory policies, it is 20 percent more expensive to manufacture in the United States than in any of its nine largest trading partners-and that excludes the cost of labor. Manufacturers in the United States enjoy a slight competitive advantage regarding energy, and with the right policies, this advantage can grow.

Chemical manufacturers had been the largest beneficiaries of this new abundance of natural gas, owing primarily to less expensive ethane, a natural gas liquid derived from shale gas. PwC identified Bayer Corporation, Chevron Phillips Chemical Company, Formosa Plastics Corporation and Westlake Chemical Corporation as companies taking early advantage of the shale gas boom.

PwC found that the benefits of shale gas for manufacturers were not limited to the major natural gas users; the benefits extended throughout the supply chain. According to PwC, companies that sell goods, such as metal tubular products and drilling and power equipment, were likely to experience near-term growth in sales as domestic natural gas production rates increased. PwC identified projects by U.S. Steel and Vallourec Ohio intended to supply steel pipe and related materials for shale gas extraction activities. These higher production levels would also yield benefits higher in the value chain, such as manufacturers of components used in drilling equipment. Overall, PwC found that 17 chemical, metal and industrial manufacturers commented in SEC filings in 2011 that shale gas development drove demands for their products, compared to none in 2008.

 

In the 13 months that have passed since PwC released its study, the impact of new supplies of natural gas on manufacturing has become even more pronounced. Nucor embarked on plans to develop a $750 million iron facility in Louisiana and announced a $3 billion joint venture with Canadian oil and gas producer Encana for 20 years of access to its natural gas wells.3 Mitsubishi announced plans to build an acrylic-resin processing plant adjacent to a newly constructed ethylene plant.4 Fertilizer manufacturer CF Industries announced that it will spend $2.1 billion to expand its fertilizer manufacturing operations.5 Formosa Plastics Corporation increased the size of its Texas ethylene plant included in the 2011 PwC6 report. Even foreign manufacturers are now seeking to build operations in the United States. Austrian steel manufacturer Voestalpine AG announced in late 2012 it plans to build a $661 million steel factory in the United States.7 South African energy company Sasol announced plans to construct America’s first commercial gas-to-liquids plant in Louisiana, an $11 billion-$14 billion venture.8 Egyptian fertilizer manufacturer Orascom Construction Industries plans to build a $1.4 billion nitrogen fertilizer production plant in Wever, Iowa.9 Canadian methanol producer Methanex announced in 2012 that it will dismantle a methanol plant in Chile and move it to Ascension Parish, Louisiana.10 BlueScope Steel Limited, an Australian company, is building a steel factory in Ohio in partnership with U.S. manufacturer Cargill.11 And Indian manufacturer Essar Global Limited is planning a steel facility for Minnesota.12

Last June, a report by independent global energy research firm IHS CERA predicted that the share of U.S. natural gas produced from unconventional sources will reach 67 percent by 2015 and 79 percent by 2035. 13Fullenbaum, Richard, and John Larson, The Economic and Employment contributions of Unconventional Gas Development in State Economies, June 2012, available at http:// www.anga.us/media/content/F7D4500D-DD3A-1073-DA3480BE3CA41595/files/ statelunconvlgasleconomiclcontribution.pdf .

This would lead to $3.2 trillion in investments to develop the resource

Natural gas liquefaction is a manufacturing process. To convert natural gas to LNG, the gas is purified by removing any condensates, such as water, oil and mud, as well as other gases, such as carbon dioxide and hydrogen sulfide and trace amounts of mercury. The gas is then supercooled in several stages until it is liquefied and ready for shipping.

 

NATURAL GAS AND MANUFACTURING Industry relies on natural gas for much of its energy needs and as a raw material.

 

FRANCES BEINECKE, PRESIDENT, NATURAL RESOURCES DEFENSE COUNCIL 

(many of the references are at the bottom of this post)

Today, there is an extraordinary mismatch between the ever growing scale of fracking—which is occurring in about thirty states—and the limited scope of measures to govern it. Indeed, companies engaged in fracking are not even required to provide enough information to enable scientists and the public to fully understand the nature or extent of the environmental and health risks fracking poses.

Oil and natural gas production are expanding across the nation, largely because advanced hydraulic fracturing (also known as ‘‘fracking’’) and horizontal drilling have made it easier to extract oil and gas from previously inaccessible or uneconomical sites. Fracking involves injecting water and chemicals deep into the earth at extremely high pressure to break up layers of rock that harbor deposits of natural gas and/or oil. Hundreds of thousands of new oil and gas wells have been drilled in the past decade, and oil and gas development is now occurring in about thirty states and under consideration in other states.3 According to some reports, about 90 percent of new wells in North America are fracked (4)

Shale gas production comes with the risk of a range of environmental and health impacts, including contaminated drinking water supplies; the release of methane, a potent greenhouse gas; unhealthy air quality; poorly managed toxic waste disposal; impairment of rivers and streams; disruption of communities; and destruction of landscapes and wildlife habitat. These impacts stem from all aspects of the shale gas extraction process, including hydraulic fracturing itself, site development, well construction , water, wastewater and waste management; and well operation, trucking and other activities that result in air emissions-especially emissions of air toxics, ozone-forming pollutants and methane, a highly potent greenhouse gas.5

 

Natural gas producers are not required by any federal law to identify the chemicals in the fracking fluids they are injecting into the ground, and state disclosure requirements vary widely. Of the states where fracking takes place, only fourteen states require some level of public hydraulic fracturing disclosure and none of these provides comprehensive disclosure. An NRDC analysis found that even where some disclosure is required, the public is hampered in getting this most basic information about fracking. For example, • In some states it is difficult for the public to access the information disclosed; • Only seven of fourteen states mandate the chemical identification of all additives used in fracking fluids; • Only one state has a clear process for evaluating and approving or denying trade secret exemption claims; and • Only six states provide for access to trade secret information by health care providers.10 In addition, enforcement of state rules is uneven; NRDC has found that state agencies have accepted disclosure reports that lack required information.

The lack of standardized, national disclosure greatly hampers the ability of researchers to study the impacts of fracking on health and the environment. Scientists need transparent, thorough and consistent information on what chemicals different communities are being exposed to. The variation in disclosure requirements among states makes it difficult to do comparative studies and deprives communities of information they have a right to know.

Health Concerns Related to Drinking Water and Air Pollution Scientific concern about the health impacts of fracking are growing. In April 2012, the Institute of Medicine (IOM), part of the National Academy of Sciences, convened a two-day workshop of public health experts that included more than a dozen presentations raising concerns about the health implications from natural gas development.11 Additionally, government agencies, including the Agency for Toxic Substances Disease Registry (ATSDR) within the Department of Health and Human Services (HHS) and the Environmental Protection Agency (EPA), have investigated and found risks from individual sites and practices.12 Health-related advisories and informational resources have been made available by the National Institute for Occupational Safety and Health (NIOSH), the Occupational Safety and Health Administration (OSHA)13 and the Pediatric Environmental Health Specialty Units (PEHSU).14

 

Some of the pollutants associated with fracking are also known to cause the same types of respiratory and/or neurological problems that are the focus of concern in impacted communities. Some of these chemicals are also well- established as carcinogens. 15 Fracking also can generate pollution from hazardous substances, including metals, radioactive material, methane and other volatile organic compounds (VOCs), that are found in the geologic deposits being exploited and brought to the surface in the drilling, fracking, and production processes. Chemicals in Drinking Water.—Because fracking is exempt from many environmental monitoring requirements, there are inadequate data on the impact of natural gas production on water contamination. However, data from private wells and a published investigation raise concerns that water contamination from fracking is creating health risks. Potential contaminants include methane, organic chemicals (including benzene, a known carcinogen), metals and radioactive elements. A published study from Pennsylvania documented evidence of drinking water contamination with methane associated with shale gas extraction. These researchers found increased levels of methane in wells closer to well sites including levels that present an explosion hazard for residents. 16 Other household-level investigations conducted by state and federal agencies have also found methane levels in drinking water in homes near drill sites that were caused or are suspected to have been caused by oil and gas operations and present an explosion hazard as well as an asphyxiation hazard for residents. 17 One study reported severe impacts to livestock, including reproductive abnormalities, acute kidney or liver failure and death, in animals that drank from polluted ponds and creeks near fracking operations. 18 The same study also documented a family living near a fracking site that reported symptoms such as headaches, nosebleeds, and skin rashes; the symptoms subsided when the family was relocated, suggesting a causal link with the nearby fracking operations.

Studies linking specific health impacts to drinking water contamination resulting from fracking operations have not yet been conducted, which illustrates the results of under-regulating this industry, but the evidence suggests that current practices may be exposing families to unsafe levels of contaminants.

Air Emissions. Fracking operations release air pollutants that can have health consequences at the local and regional level. As with water, researchers are hampered because fracking operations have been exempted from many monitoring requirements. But some of the health complaints reported by people living near fracking sites, particularly respiratory and neurological symptoms, are consistent with exposure to the chemical contaminants identified in some monitoring reports./ 19/ All of this underscores the urgent need to require effective pollution control equipment and community-level air quality monitoring to better assess the exposures and potential health risks. In the meantime, there is a strong rationale for reducing this contamination immediately to prevent potentially harmful exposures. The research, monitoring data, and public health expertise available to date indicate that natural gas facilities produce air pollution that can increase health risks. These risks increase with proximity, particularly for populations more vulnerable to the impacts of air pollution, which include children, elderly, and those with underlying health problems. Fracking activities expose communities to a range of harmful air pollutants, including known carcinogens, and respiratory, neurological, immunological and reproductive toxins. These pollutants are present in the diesel emissions released by truck traffic and heavy equipment use. Additionally, fracking operations can expose communities to silica dust, which causes lung disease. Workplace investigations at fracking sites have identified both silica and diesel as posing a health hazard for workers exposed on the job site.20 Since state laws allow drilling as close as 100 feet to residences, sensitive populations, such as children, may also be threatened by this pollution. VOCs released from natural gas wells and processing facilities have been shown to play a significant role in increasing unhealthy air quality, including from ground- level ozone. In the past year, four published studies have identified pollution from oil and gas facilities, where fracking is being deployed, as a source of pollutants contributing to regional ozone in Colorado, Texas, and Pennsylvania.21 22 23 24 Ground- level ozone is a powerful respiratory toxicant that is well known to aggravate asthma and other respiratory conditions. Additionally, a study in Colorado found elevated levels of air pollutants close to well sites during well production. Taken together, these pollutants were found to be high enough to put nearby residents at risk for respiratory and neurological health impacts.25 In addition, proximity to these facilities can also subject individuals to light and noise pollution, wastewater spills, noxious odors, and increased health and safety risks from explosions and other malfunctions. For this reason, as noted above, separating vulnerable populations from sources of air pollution and other hazards, should be an integral part of ensuring health and safety. All of these indications of health risks are cause for concern, underscoring the need to better protect the public. That means requiring mandatory disclosure of all chemicals used in fracking, thorough evaluations of potential health threats, the best possible pollution controls and drilling and fracking standards, and increased air and water monitoring both before and after drilling and fracking begin.

 

Climate Change Impacts. When natural gas is burned at a power plant to generate electricity, it emits far less carbon pollution than coal-based electricity. 26 But the production of natural gas produces significant methane emissions 27 Methane, which makes up as much as 90% of natural gas, is a potent global warming pollutant, trapping at least 25 times more solar radiation than carbon dioxide over a 100-year period. According to both the EPA’s national inventory of greenhouse gas emissions and the EPA’s tabulation of individual companies’ emission data reports,28 the oil and gas industry is the nation’s second largest industrial emitter of greenhouse gases (mainly methane and carbon dioxide), surpassed only by electric power plants. 29 Currently, methane leaks into the atmosphere at many points in the natural gas production and distribution process—from wells during extraction, from processing equipment while compressing or drying gas, and from poorly sealed equipment while transporting and storing it. While much better data are needed, EPA estimates that at least 2 to 3 percent of all natural gas produced by the U.S. oil and gas industry is lost to leaks or vented into the atmosphere each year30, and some recent studies suggest that the actual leak rate could be much higher.31 Preventing the leakage and venting of methane from natural gas facilities would reduce pollution, enhance air quality, improve human health, and conserve energy resources. The oil and gas industry can afford methane control technologies. Indeed, capturing currently wasted methane for sale could bring in more than $2 billion of additional revenue each year. Ten technically proven, commercially available, and profitable methane emission control technologies together can capture up to 80 percent of the methane currently going to waste.32 EPA, other federal agencies, and the states should move to require use of these technologies for methane control, and industry itself should move quickly to adopt these measures. Last year, EPA issued a Clean Air Act rule to curb VOC emissions from new and modified sources in the oil and gas industry.33 While this is a step forward, the rule is not strong enough and doesn’t cover existing sources.

EPA should also regulate methane directly, which would achieve much larger emission reductions. D. Water Pollution In addition to the risk of contaminating drinking water, shale gas extraction can pollute streams, rivers, lakes and other waterbodies.34 This can happen in a number of ways, including the following: 1. Depletion of Water Resources.—Large volumes of water are required for fracking operations. Fresh water is often taken from local waterbodies. Because water can be contaminated when it has been used for fracking, it cannot be easily be returned to these waterbodies. Permanent loss of water from fresh water resources can harm water quality and availability and also aquatic species and habitat.35

Spills and Leaks of Fracking Chemicals and Fluids.—Fluids, including hazardous chemicals and proppants used in the fracking process, are typically stored in tanks or pits on site. If not stored properly, they can leak or spill, polluting nearby waterbodies. Fluids can also be stored at a centralized facility near multiple well pads and then be transported to the well by trucks or by pipeline, providing another opportunity for leaks and spills during transit. Fracking fluid can also spill during the fracking process. Leaks from tanks, valves, and pipes, as a result of mechanical failure or operator error at any point during these processes, can and do contaminate groundwater and surface water.36 3. Mismanagement of fracking waste.—After fracking, some of the fracking fluid, often referred to as flowback, returns up the wellbore to the surface. In addition, naturally occurring fluid is brought to the surface along with the produced oil or gas (referred to as ‘‘produced water’’). This waste, consisting of both flowback and produced water, can be toxic, and the oil and gas industry generates hundreds of billions of gallons of it each year.37 In addition to the chemicals that were initially injected, flowback and produced water may also contain hydrocarbons, heavy metals, salts,38 and naturally occurring radioactive material. The wastewater is sometimes stored in surface pits. If the pits are inadequately regulated39 or constructed, they run the risk of leaking or overflowing and can pollute groundwater and surface water.40 The waste may also be disposed of on the surface, reused in another well, re-injected underground, or transported to a treatment facility. Each of these forms of wastewater management carries its own inherent risks, including spills, leaks, earthquakes (in the case of underground injection) and threats to groundwater and surface water. 4. Stormwater Pollution.—During a rainstorm or snowstorm, flowing water causes soil erosion and picks up pollutants along the way, including toxic materials and sediment, and these materials can flow into local waterbodies. Stormwater from fracking operations can be particularly polluted because of chemical and oil and gas residues. (Yet, as is described below, the oil and gas industry is exempt from the stormwater permitting requirements of the Clean Water Act).

Oil and gas development can destroy wildlife habitat and sensitive lands if siting does not take these factors into account. Natural gas production operations involve extensive road building and construction of wellpads that can fragment and destroy habitat and cause species to leave their historic breeding and nesting grounds. Light and noise disturb wildlife populations and may drive them to lower quality habitat, and runoff and spills can pollute aquatic habitat.44 F. Community Impacts Oil and gas development can fundamentally change the nature of communities. Fracking is a heavy industrial activity that entails substantial construction, heavy truck traffic, traffic accidents, and noise and light pollution45. It often attracts an influx of out-of-state workers that can bring increases in crime and violence, sexually transmitted diseases and community strife that can stress local emergency, health and other community resources.46 Under many state laws, oil and gas rights take precedence—or are interpreted as taking precedence—over surface ownership, so oil and gas wells and the associated industrial activity-including chemical and waste storage and disposal-can be located in residential or agricultural areas regardless of zoning or even the wishes of individual property owners. To address these issues, NRDC has launched a Community Defense initiative to provide legal assistance to localities that seek to hold natural gas extraction to appropriate scientific standards, protect their property or exclude oil and gas production from their communities.47

SAFE DRINKING WATER ACT (SDWA) Fracking is exempted from the SDWA unless diesel is used in the fracking process, under a provision enacted in the Energy Policy Act of 2005.48 This exemption prevents the Safe Drinking Water Act from protecting underground sources of drinking water from fracking impacts and exempts the siting, construction, operation, maintenance, monitoring, testing, and closing of fracking sites from regulation under the SDWA. 43 http://www.denverpost.com/environment/

 

CLEAN WATER ACT Oil and gas operations are exempt from the storm water runoff permitting requirements of the Clean Water Act.49 With this exemption, there is no way to know if a company has an adequate Storm Water Pollution Prevention Plan in place to reduce the discharge of pollutants to receiving waters, and to eliminate illegal discharges. CLEAN AIR ACT The oil and gas exploration and production industry is exempt from critical Clean Air Act requirements to adequately assess, monitor, and control hazardous air pollutants.50 This makes it impossible, under existing regulatory statutes, to perform an adequate assessment of air pollution health risks to nearby communities and require adequate safeguards. Excluding this important category of air pollution and air contaminants significantly underestimates the health risks posed by this industry. HAZARDOUS WASTE MANAGEMENT AND SUPERFUND STATUTES Oil and gas waste is exempt from the central federal hazardous waste management law—the Resource Conservation and Recovery Act—including testing, treatment and disposal provisions that govern the assessment, control and clean-up of hazardous waste.51 Similarly, the oil and gas industry is protected from liability for spills under the Comprehensive Environmental Response, Compensation and Liability Act (the Superfund statute), which adopts the same definition of hazardous waste.52

NATIONAL ENVIRONMENTAL POLICY ACT (NEPA) Under a special provision of NEPA, when oil and gas companies lease federal lands, they are often exempt from customary environmental review requirements applicable to other industries.53 A recent Government Accountability Office study found that in a sample from fiscal years 2006-2008, the oil and gas industry received almost 6,900 categorical exclusions (CXs) that waived further environmental review under NEPA. Of that total, almost 6,100 of those CXs were used to waive requirements for permits to drill.54

After electric generation, other primary uses of natural gas energy are in buildings and industrial applications. There are many opportunities to use natural gas more efficiently in these settings. Enhanced building energy codes and stronger efficiency standards for appliances, equipment and cooling and heating systems are among the best ways to use natural gas more efficiently. As is explained in a recent report by the Alliance to Save Energy’s Commission on National Energy Efficiency Policy (on which I served), it is important that DOE stay on track to meet all of its statutory deadlines and responsibilities to strengthen energy efficiency standards for natural gas and electric appliances.58 After a strong start at the beginning of the last term, DOE has fallen behind on this important responsibility.

 

KENNETH B. MEDLOCK, III, JAMES A. BAKER, III, AND SUSAN G. BAKER, fellow in energy & resource economics, & senior director, center for energy studies,  JAMES A. BAKER III INSTITUTE FOR PUBLIC POLICY RICE UNIVERSITY, HOUSTON, TX

According to the US Energy Information Administration, gross withdrawals from shale gas wells in the United States has increased from virtually nothing in 2000 to over 23 billion cubic feet per day (bcfd) in 2011, representing over 29% of total gross production in the US. Moreover, a recent Baker Institute analysis indicates shale gas production could reach over 50% of all domestic natural gas production by the 2030s.1

CNG Vehicles. Currently, natural gas use in transportation is only 0.13% of total gasoline use. So, there is a lot of room for growth. In fact, a 10-fold increase in demand would push demand to about 0.9 bcf/day, which is an increase the U.S. market could absorb with relative ease. But, for the low levels of demand that currently exist to change, it will take substantial investment in fueling infrastructure and large adoption of compressed natural gas vehicles (CNGV) by consumers.4

One thousand cubic feet of natural gas yields eight gallons of CNG. So, if natural gas price is $4/mcf then the cost of natural gas as a feedstock for CNG production is $0.50/gallon. Adding the processing costs for CNG of approximately $1.00/gallon, we have an estimated wholesale price of $1.50/gallon.

The wholesale price of gasoline on the NYMEX is currently at $3.00/gallon. If these prices persist, the per gallon fuel cost of CNG is about half the cost of gasoline, before accounting for things such as distribution costs, profits, local and national taxes, and lease payments by station owners. Assuming all these additional costs are equal for CNG and gasoline, we still have a differential between fuels of about $1.50/gallon.

We could also discuss liquefied natural gas (LNG) options into transportation, but this is primarily for large trucks and local maritime transport.

 

Despite the preceding cost per gallon comparison, cost per gallon is not the appropriate metric for comparison. We must compare the cost per mile of each fuel option. In order to do this for privately-owned vehicles, we need to incorporate the efficiency of a CNGV and a comparable gasoline hybrid vehicle. Then, we can calculate the annual fuel cost savings for each vehicle type.

If we compare the Honda Civic, for example, we have a gasoline hybrid engine efficiency of 44 miles per gallon in the city. The Honda Civic CNGV has a city driving efficiency of 27 miles per gallon. Thus, the cost per mile is $0.0126 lower for the Civic CNGV. If we assume annual driving of 12,000 miles, the fuel savings is $151/year. Assuming a 7 year vehicle life, we see an undiscounted lifetime savings of just over $1,060. The current MSRP for a Civic CNGV is $26,305, and the current MSRP for a Civic Hybrid is $24,200, meaning the price difference is currently $2,105. Thus, the fuel cost savings does not compensate the higher upfront cost of the vehicle. If we discount future savings, the disparity grows. So, the CNGV is not the most attractive option to the consumer looking to purchase a vehicle that also reduces gasoline demand. If annual mileage jumps to 24,000 miles per year, then the undiscounted fuel cost savings just compensates for the fixed cost differential over 7 years. So, high mileage is a prerequisite for the CNGV option to make economic sense given these fuel costs.

The current pricing differential between natural gas and gasoline has been sufficient to promote adoption of CNGVs in commercial fleets. However, commercial fleet opportunities are small when compared to the fleet of privately owned motor vehicles. So, while an economic argument can be made for natural gas into high-mileage commercial fleets, the same is not true for private vehicles, which, absent a change in fixed costs differentials, will limit the movement of natural gas into private vehicles.

Aside from the cost differences, another issue that stands in the way of large scale CNGV adoption is a lack of re-fueling infrastructure. There are currently about 1,100 CNG fueling stations and 59 LNG fueling stations nationwide. These facilities primarily serve large trucks in the case of LNG and light duty trucks in the case of CNG. But, the ability to refuel becomes an issue when one considers the current consumer driving behaviors. In particular, the flexibility implicit in the existing fuel delivery infrastructure (for gasoline) allows drivers the freedom to plan their activities without necessarily planning routes so that they coordinate with re-fueling opportunities. This point is what leads us to the so-called ‘‘chicken-and-egg’’ problem. Namely, consumers bear a cost if they have to search for re-fueling stations (a so- called ‘‘search cost’’), and this cost can prevent them from buying a CNG vehicle, even if the projected fuel savings compensates for the incremental fixed cost. In turn, station owners may be reluctant to install CNG re-fueling capability if CNGVs are not prevalent enough in the vehicle stock to guarantee some demand for the station’s services. Hence, the conundrum—how does one overcome this mismatch to ensure coordinated growth in both CNGVs and re-fueling locations?

Electric Vehicles. Many of the issues facing CNGV adoption into the private vehicle fleet are also faced by EVs, but by differing degrees. Cost of ownership is certainly an issue, as most EVs are more expensive than their non-EV counterparts. Of course, the low cost of electricity can provide significant fuel savings, but even if EV fuel costs are driven down near zero, the projected 7 year undiscounted savings approaches $5,600. The base model Ford Focus EV lists an MSRP of $39,200. This compares with the gasoline-powered base model Ford Focus MSRP of $16,200. So, just as with EVs, the difference in fixed cost is not fully compensated by the fuel savings. Even with the federal tax credit of $7,500, the fuel savings is not sufficient. In other words, rational individuals who buy an EV are doing so for some additional derived benefit.

Aside from the issue of cost, there are also issues associated with re-fueling. Refueling electric vehicles has both short term and long term components. In the short term, the existing generating fleet is sufficient to meet almost any expectation of electricity demand growth associated with EV penetration. Moreover, many consumers can re-charge at home, and in some cases re-charging capability is available at work and other non-residential locations. But, the availability of non-residential re-charging stations is not sufficient to support wider adoption of EVs. As of September 2012, according to the EIA there were 4,592 non-residential re-charging locations in the U.S., where some locations have multiple charging units. Moreover, most of these locations are in only a couple of states. The location of re-charging stations becomes a relevant issue primarily when long distance travel is desired. Currently, range is limited to less than 100 miles per charge in most commercially available EVs on the market today.5 This creates logistical issues for consumers who wish to drive more than 100 miles for a weekend getaway. If we think about the prospects of EVs longer term, investments in charging stations can be made, particularly if consumers show a propensity to buy EVs.

 

Even if the proverbial ‘‘chicken-and-egg’’ problem of vehicles and infrastructure can be overcome, the resulting requirements for new electric generation capacity cannot be understated. If EVs are widely adopted into the vehicle fleet, a recent Baker Institute report put the projected growth in power generation requirements are 5%, 12% and 21% higher than the ‘‘business as usual’’ case in 2030, 2040 and 2050, respectively.

6 See ‘‘Energy Market Consequences of Emerging Renewable Energy and Carbon Dioxide Abatement Policies in the United States,’’ by Peter Hartley and Kenneth B Medlock III (Sept 2010), available at www.rice.edu/energy.

the licenses of 93 existing nuclea r power plants would expire before 2030 and these would need to be extended, or the plants repl aced, before nuclear capacity could increase on net.

The majority of this incremental demand for electricity would likely be met by natural gas. However, it is important to recognize that this incremental demand will take decades to materialize, absent government regulations that accelerate the process.

There are other costs that exist, some of which are not even in the current discussion. Cost of expanding and upgrading electricity infrastructure can become an issue. Effectively, current mechanisms would force non-EV owners to subsidize EV expansion. This could become a political issue. Moreover, currently 18.4 cents per gallon of gasoline purchased flows into the National Highway Fund to support construction and maintenance of public infrastructure. As the gasoline base diminishes, the fund will still need to be solvent, so electricity and natural gas will need to be taxed accordingly. Currently, no such tax exists, so it is left out of most breakeven calculations for purchase of CNGVs and EVs. In the case CNGVs, assuming refueling infrastructure is added, a tax at the pump can be instituted in much the same manner as is currently done with gasoline purchases. But, its implementation will almost certainly be protested by early adopters of CNGVs as it could represent an ex post unexpected increase in the cost of ownership.

 

In the case of EVs, if mechanisms are proposed whereby electricity sales are taxed, then again, non-EV owners are subsidizing EV expansion. While centralized refueling stations are a possibility, their installation is still a pre-requisite capital expense. Moreover, the issue of tax payments is still present. It is more likely that EV owners will recharge at home. So, a mechanism to tax the owners of EVs specifically must be considered. Just as with early adopters of CNGVs, any tax implemented will represent an ex post unexpected increase in the cost of ownership, and will likely be met with resistance.

INDUSTRIAL DEMAND FOR NATURAL GAS There are, of course, also ample opportunities for demand growth in traditional, non-transportation end-uses. Power generation and industrial uses make up the bulk of natural gas demand on an annual basis. Seasonally, the balance shifts more heavily to space heating applications in residential and commercial end-uses, specifically in winter months, but the general trends in annual demand growth are set by industrial and power generation uses. In 2012, power generation comprised 36.1% of annual demand and industrial comprised 32.1%.7 Moreover, the recent low price environment has natural gas use in both sectors poised to grow.

Industrial most recently demand peaked in 1997 (see Figure 1*) reaching levels similar to what was witnessed in the early 1970s. It steadily declined thereafter due to lower cost natural gas in international locations. Industries such as the ammonia and fertilizer industries were heavily favored by lower cost feedstocks elsewhere, and the late 1990s and early 2000s saw many of these types of industrial gas consumers shutter operations in the US Gulf Coast region choosing to move abroad. However, much of this has changed in the last few years, and industrial demand has actually grown since 2009, a trend bolstered by low cost natural gas supply due to growth in shale gas production. 5 For example, the Ford Focus EV has a range of 76 miles and the expectation for continued strong supply and stable pricing is being seen in the slate of recent announcements by firms to expand their businesses that rely on natural gas as a feedstock and energy source. Dow Chemical, an industrial user of natural gas, has recently announced a number of significant expansion plans in Texas.

Other industrial firms have also announced plans to expand domestically. Methanex has moved forward with plans to relocate its Chilean facility to Geismar, Louisiana, and Sasol has announced intent to move forward with a GTL project in Southwest Louisiana. In short, if price does stay low and relatively stable, it is possible that industrial demand could rise to levels not seen since the mid-1990s. This would represent an over 18% increase in industrial gas demand from its current levels. It is important to point out that the long term trend seen in the industrial demand sector bears resemblance to a cycle. Indeed, even the recent growth in industrial demand has been modest in comparison to power generation use. Nevertheless, the past few years have seen a renewal of industrial demand for natural gas. Moreover, the planned capital expenditures by gas-intensive industrial players are quite large

POWER GENERATION DEMAND FOR NATURAL GAS. Natural gas demand in the power generation sector has substantial growth opportunity through fuel substitution, and it can occur in a relatively short time frame. In 2012 we saw a dramatic increase in the use of natural gas in power generation through substitution with coal. In fact, the natural gas share of power generation in 2012 rose to over 30%, which was up from an annual average of 17.9% just 10 years ago. This is in stark contrast to coal, which has seen its market share deteriorate from 50.8% to 36% in the same time frame. In fact, much of the drop in coal’s share in power generation is directly attributable to grid-level switching to natural gas. The rise of gas use at the expense of coal was primarily the result of relatively low natural gas prices, and the fact that there is sufficient natural gas generating capability to allow for large scale, grid-level fuel switching. Much of the existing natural gas fleet that can capitalize on relative price movements was brought into service between 2000 and 2005 (see Figure 2). In fact, natural gas generation capacity surpassed the installed capacity of coal in the US in the early 2000s. Moreover, most of the capacity that was added employs the latest generation combined cycle technology, meaning its thermal efficiency is substantially higher than the majority of the existing coal fleet.

The price of natural gas regularly at a competitive advantage to coal in power generation then older units of the coal fleet will be retired. Initially, the existing natural gas generation fleet will pick up the slack, but eventually, new builds of high efficiency natural gas combined cycle units will be required. This raises the natural gas pricing point for parity because a greenfield expansion must include the cost of capital. However, when one also accounts for the environmental regulations that the US Environmental Protection Agency (EPA) seeks to impose via recent rule-makings, then the competitive balance shifts in favor of natural gas.9

LNG EXPORTS A recent paper by Medlock (2012)19 argues that the volume of LNG exports from the US will ultimately be contingent upon domestic market interactions with the international market. This is because US LNG exports will occur in a global setting, meaning the entire issue must be considered as a classic international trade problem. Only then will any insight be gained with regard to export volumes and thus US domestic price impacts. The paper goes on to argue that (a) the impact on US domestic prices will not be large if exports are allowed, and (b) the long-term volume of exports from the US will not likely be very large given expected market developments abroad.

The bottom line is that the entities involved in LNG export projects may be exposed to significant commercial risk. Much of this conclusion derives from a relatively straightforward analysis of domestic and international natural gas prices taking into consideration the effects of short term deliverability constraints. Indeed, the argument is made that the existing spread in prices between the US, Asia and Europe is transitory.

Spot prices in the UK, US and Asia all move together until the middle of 2010. At that point, the US price begins to drift below the prices in the UK and Asia. This is largely the result of growth in shale gas production in the US. A significant break in the pricing relationship between Asia and Europe occurs at a specific date, March 11, 2011, the day of the disaster at Fukushima. The Asian spot price jumped by almost $2/mmbtu within a week and continued to climb through the end of the year with the closure of every nuclear power plant in Japan. This was the result of an unexpected demand shock as Japanese utilities scrambled to buy any available LNG for power generation. At the same time, the spread between the US and Asia was exacerbated by a negative demand shock in the US. Namely, the winter of 2011/12 was one of the warmest on record in the US, resulting in very low winter heating demands. As a result, natural gas inventories remained very robust and the market was oversupplied, leading to a price collapse to below $2/mmbtu in April 2012. As a result, the spread between the US and Asia rose to as high as $15/mmbtu.

 

The interest in exporting LNG from the US also accelerated during this period. However, it is reasonable to expect Asian price to revert back to its pre-Fukushima relationship with European price as the current deliverability constraints subside—due to new supplies and reactivation of nuclear capacity in Japan. The LNG export opportunity looks a bit more sobering if that occurs. Importantly, if we consider a longer term view of regional prices, we can begin to understand the potential risk in myopic decision making. Figure 5 indicates annual average price delivered to consumers in Asia, the UK and the US from 1980 through 2012. We can see from 2000-2008 the US price was rising, and it coincides with the period during which LNG regasification capacity was constructed with an aim to import LNG to the US. However, the period since 2008 is characterized by a wide divergence in regional prices, and this coincides with the emerging interest to export LNG. One must consider the longer term price relationships because the recent past is not a prelude to the future. In fact, the 20 years prior to the 2000s is characterized by a relatively stable relationship between the regional market prices that saw Asian prices at a consistent but relatively small (to recent history anyway) premium to prices in Europe and the US. One must, therefore, question the nature of the recent divergence in regional prices.

The conclusion reached in the study by Medlock was one of very low export volumes from the US because the pricing premiums that exist today will not likely persist due to new supplies from a variety of sources as well as reactivation of nuclear reactors in Japan. In effect, the high prices in Asia encourage responses on many margins and thus result in a reduction in price. This follows from the adage, ‘‘the best cure for high prices is high prices.’’ 19‘‘US LNG Exports: Truth and Consequence’’ available at www.bakerinstitute.org.

All the information, when taken together, points to a series of cause-and-effect relationships that present challenges for some margins of response and opportunities for others. It will be surprising if ‘‘all of the above’’ actually results in a market- driven equilibrium. The traditional consuming sectors, specifically industry and power generation, face fewer obstacles because the mechanisms for demand growth—infrastructure and technology—are already in place.

Natural gas into transportation may be a mixed outcome, with fleet vehicles—because they are high mileage vehicles—being the most successful in migrating natural gas into the fuel mix. Absent a policy intervention or a cost reduction, passenger vehicles still face hurdles to large scale penetration of CNG due to lower mileage.

 

The likelihood of demand pull coming from international sources in the form of LNG exports is high, but not in large quantities. This follows from the fact that US prices will likely rise to reflect marginal costs and international prices are not likely to remain at their current premiums. In fact, if the Asian price reverts back to its pre-Fukushima relationship with European price then the margin for profitable export of LNG from the US becomes razor thin. Thus, market forces will ultimately limit the volume of US LNG exports. So, perhaps what is needed for demand growth for natural gas is a relatively simply prescription—economic growth. Economic growth stimulates demand for electricity and industrial goods, both of which favor natural gas. Moreover, as demands in these traditional sectors grow, this will create competition for supplies of natural gas for LNG exports and new demands. It is for this reason that the most likely demand for the robust supply of natural gas in the US will come from industrial and power generation uses. Transportation and LNG exports will likely remain marginal influences at best.

Governor HICKENLOOPER, Governor of Colorado.

I think it was 1982 and 1995 that the Federal Government invested over $5 billion in terms of trying to create this ability to extract shale gas from tight shales and to get oil from tight shales. We have to recognize that renewable energy such as wind and solar is intermittent and certainly as we are faced with challenges on storage we need ways to be able to have electrical energy generation go on and off efficiently. Natural gas does that at a level that literally almost no other energy can do, so it becomes a perfect partner for solar and wind. I think it will prove to be the transition energy that will allow us eventually to get to a fully renewable energy environment.

So, I made several points. Firstly, the world market for gas does not exist; it’s a world oil price. The world oil price is currently $117 Brent. It’s got nothing to do with the cost of world production. It’s got nothing to do with the actually the affordability of oil around the world. It’s got everything to do with speculation and geopolitics. Before you index the domestic gas price to the world oil price domestically and this up-swirl that Mr. Gerard refers to, which is why you want to export in the first place, I said we are for exports. But we should be very careful that we don’t do what is called Dutch Disease. Economic theory brings back the highest price back to your domestic sector with unintended consequences. Be careful of unintended consequences. Have the production. Have the exploration. Gas prices should rise from where they are today. They putting in-locking in wells because the gas price is too low. There should be a return for everyone here. A return for the people who have taken the risk. A return for society. Let’s use some of this bounty and transition to a low carbon economy, as Senator Franken talked about. We’re for an all-of-the-above energy strategy. Let’s use natural gas as a transition for our economy first. Let’s let that up swirl occur as a reasonable return for everyone and for American manufacturing jobs and the American consumer. That’s a thoughtful approach to how many of these applications to approve.

Food security, national defense, and energy security, in my view, are national interests. I would imagine the national interests being at the highest hierarchy.

The ingredients of natural gas are what we call feedstocks, natural gas liquids. The bounty of shale gas is, thanks to our great oil and gas sisters and brothers, they—the bounty, the geology, is that the gas is very wet, so-called NGO rich. A God-given gift. This is very unusual. The gas fields around the world are not as rich as U.S. gas fields. Therefore there’s a new unintended consequence, which is all the ingredients for everything from laptops to smart phones to pharmaceuticals to paints and varnishes to carpets to cosmetics, all the vital ingredients, 95% of them come from fossil fuels. The best and lightest fossil fuel is natural gas, so natural gas liquids should not be shipped overseas and be burnt in Japanese cooking ovens. It should be kept home so we can add value at 8 times by building these facilities. There’s $4 billion in Louisiana and Texas alone by Dow Chemical, $20 billion by Sasol, $15 billion by Shell to value-add. This is a big bet that we’re going to get responsible supply.

Energy is the lifeblood of an economy in all of its forms.

We’re in the 4th or 5th year of trying to understand what this bounty is. Can we produce it responsibly across the country? There are regions that differ already. We know that. The geology is different. We don’t know how much supply we have. Let’s be careful testing our country on when a market gets to maturity on liquidity risk. Why should we take the liquidity risk as a country in a totality while someone overseas benefits from our bounty.

Senator ALEXANDER. An image I have is the United States going into Iraq because of oil and because Iraq had gone into Kuwait and there we are. So while I’m a big free market, free enterprise person, I also see the value of the domestic price. I don’t want to lose that. I also see the national security consequences of this.

Senator MANCHIN. … look at all of the human sacrifices this country has made because of our lack of independence on energy? It’s a tremendous price we’ve paid in human life and value.

LEE FULLER, VP OF GOVERNMENT RELATIONS, INDEPENDENT PETROLEUM ASSOCIATION OF AMERICA. Projections suggest that identified resources could provide enough natural gas to meet America’s needs based on current demand for as much as 100 years.

IPAA represents thousands of independent oil and natural gas explorers and producers, as well as the service and supply industries that support their efforts, which will be significantly affected by federal action. Independent producers develop 95 percent of American oil and natural gas wells, produce 54 percent of American oil and produce 85 percent of American natural gas.

Projections suggest that identified resources could provide enough natural gas to meet America’s needs based on current demand for as much as 100 years.

STATEMENT OF THE WILDERNESS SOCIETY, DAVID ALBERSWERTH, Senior Policy Advisor

[This is very interesting. Hardly a session related to energy or natural resources goes by without numerous appeals of oil and gas companies asking to be allowed to “DRILL BABY DRILL” on restricted land].

The oil and gas industry and their allies continue to insist that the only way to address our country’s energy challenges is to open more public lands and waters to oil and natural gas drilling, and reduce environmental and safety standards. In truth, oil and gas drilling in America is already occurring at an astonishing pace and in a bewildering number of places. Yet, in the Rocky Mountain West vast expanses of public lands open to drilling and under lease by the industry are not being used, and thousands of drilling permits issued to companies by the Bureau of Land Management (BLM) are sitting idle. More oil and gas drilling occurs in America every year than anywhere else in the world. As of January 13, there were 1,764 rotary drilling rigs operating on U.S. lands and waters.1

 

America ranks #2 in world natural gas production, and #3 in oil production. The U.S. is the second largest natural gas producer in the world2 and the third- largest producer of oil.3 Tens of thousands of wells are drilled every year in the U.S. At the beginning of the last decade 27,000 oil and gas wells were drilled in the U.S. in one year. But in 2010 over 40,000 new wells were drilled on American lands and waters.4

The West’s public lands are already extensively drilled, leased, and available for leasing. There are tens of thousands of oil and natural gas wells on public lands, with thousands more currently approved for drilling and tens of thousands more planned for the future.5 Tens of millions of acres of federal public lands are available for leasing under current BLM Resource Management Plans. Tens of millions of acres of onshore and offshore federal lands are already under lease to oil and gas companies—the vast majority of it unused. According to BLM data, as of the end of FY 2012, 37,792,212 acres of federal public lands are leased for oil and gas development, an area larger than the State of Florida.6 However, only one third of these leases— 12,512,974 acres— are in production.

In addition, over 34 million acres of offshore federal lands are under lease in the Gulf of Mexico alone, where roughly 4,000 platforms produce oil and/or gas.7

The United States has become a net exporter of refined petroleum products. In 2011, the United States exported more petroleum products, such as gasoline and diesel fuel, than it imported for the first time in decades. The trend has continued into 2012 as the U.S. was exporting about 1,000 Mbbl/d in May 2012, according to the United States Energy Information Agency.8

The oil and gas industry is sitting on nearly 7,000 approved but idle federal drilling permits. Though the industry and their political allies persistently complain about ‘‘restrictive’’ government policies that allegedly are thwarting U.S. oil and gas development, the BLM reported in February, 2013, that 6,990 approved onshore federal drilling permits were sitting idle, unused by oil and gas operators who have obtained them9. The industry has ‘‘shut in’’ thousands of gas wells on western public lands during the past four years, but continues to complain about their alleged ‘‘lack of access’’ to federal lands for drilling. For example, according to the Wyoming Oil & Gas Conservation Commission, as of 2009, there were over 12,500 shut-in coal bed methane wells in the Powder River Basin of Wyoming alone!

Thousands more natural gas wells have been shut-in elsewhere in Wyoming and the West, primarily due to low natural gas prices. Low natural gas prices—not government policies or regulations—are causing many companies to reduce spending on natural gas projects on federal lands, a strategy intended to drive up prices. For example, the CEO of Ultra Petroleum, a large independent producer with major investments in gas wells on federal lands in Wyoming, recently told his investors of the company’s strategy to curtail exploration activities because, ‘‘We don’t believe in cash flow growth or production growth without economic returns.’’11

Moreover, ‘‘Industry-wide, you’re just beginning to see natural gas production roll over. Once it begins, it will accelerate, and I think we are looking at a 2-year window of monthly reductions in domestic natural gas supply. So it’s taken us and the industry some time to react to the market signals, but we have and we won’t be quick to over-invest in the coming years. We’ve seen natural gas prices respond positively, but they are a long, long way away from levels that will attract capital.’’ In other words, natural gas producers will increasingly be curtailing their drilling activities, in a strategy designed to raise consumer prices.

At least one witness during the February 12 hearing implied that federal land management polices are somehow inhibiting the oil and gas industry’s ability to gain access to federal onshore lands for oil and gas development. The relevant facts, however, portray a completely different reality with regard to this question: tens of millions of acres of onshore federal lands are currently available for oil and gas development; tens of millions of acres of federal lands are under lease to oil and gas companies; nearly 7,000 federal drilling permits have been issued to companies but are not being utilized by them; and over ninety-two thousand oil and gas wells are operating on federal onshore lands, with thousands of new wells permitted by the Bureau of Land Management every year. In conclusion and as the accompanying documents demonstrate, the oil and gas industry has available to it tens of millions of acres of onshore federal lands. The real issue that Congress should contemplate is not whether federal policies are unnecessarily inhibiting the extraction of oil and gas resources from our federal lands, but instead whether there are sufficient safeguards in place to assure that (1) the most environmentally sensitive public lands are protected from the adverse impacts of oil and gas development, and (2) that oil and gas extraction and development activities on federal lands are done in an environmentally safe manner.

1 http://investor.shareholder.com/bhi/riglcounts/rclindex.cfm 2Data as of 2010 (most recent available). United States Energy Information Agency http:// www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=3&pid=26&aid=1# 3United States Energy Information Agency. http://www.eia.gov/cfapps/ipdbproject/ IEDIndex3.cfm?tid
5&pid=53&aid=1 4United States Energy Information Agency. http://www.eia.doe.gov/emeu/mer/pdf/pages/ sec5l4.pdf
5 As of December 1, 2008, there were 88,357 oil and gas wells on BLM lands. Government Accountability Office. http://www.gao.gov/new.items/d10245.pdf
6 Bureau of Land Management, http://www.blm.gov/wo/st/en/prog/energy/oillandlgas/statistics.html 7 BOEMRE, Gulf of Mexico Region Blocks and Active Leases by planning Area, January 3, 2011; EIA, Overview of U.S. Legislation and Regulations Affecting Offshore Oil and Natural Gas Activity, p. 2, September, 2005.
8 United States Energy Information Agency, http://www.eia.gov/dnav/pet/ petlmovelwklyldcllNUS-Z00lmbblpdll.htm
9 Correspondence from Celia Boddington, BLM, to David Alberswerth, TWS, February12, 2012.
10 http://www.uwyo.edu/eori/lfiles/co2conference10/tom%20doll%20eoril30june2010l2009- 2010.pdf 11http://phx.corporate-ir.net/phoenix.zhtml?c=62256&p=irol-irhome

JOHN W. HICKENLOOPER, GOVERNOR OF COLORADO, DENVER, CO.

Energy independence used to be a catch phrase that people would throw around, but I think we are legitimately on the threshold of achieving it for the first time in my lifetime… what we’ve seen in the last decade is truly transformational.

The Persian Gulf is more volatile than ever, and we see our national security—40 years after our first energy crisis, the oil is controlled by unfriendly regimes in many cases. A national security issue that remains.

3 issues: the economic recovery, the national security, and climate are tough challenges, but the crux of each of them is energy. In 2005, 60% of our oil was imported. Last year, 41% was imported. That trend is going to go further.  We see that having cheaper natural gas means that we’re more competitive as a country.

We see that chemical industries, the American fertilizer industries, a lot of these associated industries beginning to really take off. Foreign investment in electricity-intensive industries also is coming home for the first time in decades largely because of inexpensive natural gas. It’s also worth pointing out that carbon emissions, because of inexpensive natural gas and the conversion of older, inefficient electrical generation plants fueled by coal, are per capita—CO2 emissions are the lowest since Eisenhower turned over the White House to John Kennedy. We are, as a country,—even though we didn’t ratify the Kyoto Protocols—we are half way toward compliance, and we have reduced our carbon emissions in the United States more than all that other signatories to the Kyoto Protocols.

It really is game-changing. When I was a geologist this was unheard of. We’d find a big field, and we’d think, well, we’re going to adjust how the value of coal— the value of oil, or the value of gas was going to be projected. This has been a technological revolution. We did fracking when I was a geologist. The first well I sat back in 1981 was a—we did a hydraulic fracking enterprise on that. What’s happened is we’ve had better technology, the discovery of massive—these tight shale and shale oil deposits. The real transformation here is that we could see a natural gas supply that is legitimately a hundred years long, and we continue as the technology continues to improve, we find more gas at lower cost.

We are on target to be a net exporter of natural gas by 2020. Domestic development of shale gas and oil, homegrown renewable energy and efficiency strategies are leading us toward energy independence. With less reliance on foreign sources, our exposure to the impacts of global events is reduced. Our oil imports are falling—to approximately 40 percent of our consumption, down from 60 percent as recently as 2006. By next year, imported oil is projected to make up just 32 percent of demand. More energy dollars will stay home, our dependence on foreign supplies will decrease.

We rank fifth in natural gas production and tenth in oil production. Our diverse hydrocarbon resources encompass a variety of shale, tight sand, coal bed methane, and other formations that span the state. This landscape has changed over the years, and has taken a significant turn as operators combine improvements in hydraulic fracturing and horizontal drilling to unlock reserves of oil and gas in formations, such as the Niobrara in Colorado, historically considered impractical for extraction.

As a former geologist, I have some experience with this technology. We worked on so-called ‘‘frack jobs’’ when I was in the industry in the 1980s. The industry, incidentally funded by billions of federal research dollars in the 1990’s, has made great advances since that time.

Natural gas and renewable sources are proving to be ideal partners, since gas efficiently cycles on and off to pair with intermittent resources such as wind and solar power. We are achieving these energy goals across party lines. Gov. Mary Fallin of Oklahoma and I are leading a bipartisan effort to promote the use of natural gas as a transportation fuel for state vehicles. What started with Oklahoma and Colorado a little over a year ago has now expanded to 22 states representing every region of the country. With a little effort we see the potential for including the federal government and perhaps Canadian provinces and other partners to build a market for large vehicle fleets using natural gas. These initiatives target larger and heavy duty vehicles. Converting from diesel power to compressed natural gas reaps the biggest benefit in reductions of carbon, particulates and other pollutants. We are also finding ways to expand the fueling infrastructure, so trash haulers, delivery vehicles, buses, and trucks have more options for refueling.

ASPO 2005: The day kicked off with an address from the Mayor of Denver, John Hickenlooper, who has joined that brave but small band of honest and courageous politicians willing to go anywhere near the issue of peak oil. Indeed his office is a co-organizer of the conference. Under his leadership, Denver is studying city oil use and what would happen at varying levels of oil price – how would the city adapt. A big focus on integrated transport and land-use planning. The Denver area has a very large transit system just approved by voters. The FasTracks system will involve 57 new stations and 50 of them are close to brownfield sites that can be redeveloped with high density zonings to allow 5-8 story buildings that have mixed use residential and commercial buildings. Denver has reduced the vehicle fleet 7% – and the city uses hybrids and biodiesel. Denver International Airport uses 100% alternative fuels. The mayor is trying to promote telecommuting to area businesses – even 10-20% of the week in telecommuting would makes a big difference to congestion and fuel usage. He is trying to look at whether real-estate agents could be persuaded to launch a TV campaign to promote people moving closer to work (on the theory that the real estate agents would have a lot to gain in getting everyone to shuffle around and be closer to work). Denver Mayor Hickenlooper said that it made sense to help the poor with their gas and electric bills in the dead of winter to get them through the coldest months, but to do that forever in the future as the permanent energy crisis hits would bankrupt the city, it can’t be done. And how was he going to keep the snowplows running, collect the garbage, etc? He’ll be meeting with the mayors of Oakland, Chicago, Seattle, Portland, Austin to discuss and share ideas on how to cope with declining energy in cities, and they’ll present their findings at the national conference of mayors.

 

REFERENCES FOR: FRANCES BEINECKE, PRESIDENT, NATURAL RESOURCES DEFENSE COUNCIL, NEW YORK, NY

(4) Fracking Hazards Obscured in Failure to Disclose Wells, Bloomberg, Benjamin Haas (Aug. 14, 2012), http://www.bloomberg.com/news/2012-08-14/fracking-hazards-obscured-in-failure-to- disclose-wells.html
11 Institute of Medicine. 2012. Workshop on the Health Impact Assessment of New Energy sources: Shale Gas Extraction. April 30-May 1, 2012. Washington, DC. http://www.iom.edu/Activities/Environment/Environmental HealthRT/2012-APR-30aspx.
12 Masten, S. 2012. HHS & NIEHS Activities Related to Hydraulic Fracturing and Natural Gas Extraction. Presentation made at the 2012 Shale Gas Extraction Summit: October 2, 2012. http://environmentalhealthcollaborative.org/images/ScottPlenary.pdf; ATSDR, Health Consultation: Public Health Implications of Ambient air Exposures to Volatile Organic Compounds as Measured in Rural, Urban, and Oil & Gas Development Areas Garfield County Colorado (2008); United States Environmental Protection Agency (US EPA). 2012. EPA’s Study of Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources. http://www.epa.gov/hfstudy/ .
13 Occupational Safety Health Administration (OSHA) 2012. Hazard Alert, Worker Exposure to Silica During Hydraulic Fracturing. www.osha.gov/dts/hazardalerts/hydrauliclfraclhazardlalert.html;
14 Pediatric Environmental Health Specialty Units and the American Academy of Pediatrics. 2011. PEHSU Information on Natural Gas Extraction and Hydraulic Fracturing for Health Professionals. http://aoec.org/pehsu/documents/hydrauliclfracturinglandlchildrenl2011lhealthlprof.pdf;
15 ATSDR, Health Consultation: Public Health Implications of Ambient Air Exposures to Volatile Organic Compounds as Measured in Rural, Urban, and Oil & Gas Development Areas Garfield County Colorado (2008)
16 Osborn, SG, A Vengosh, NR Warner, RB Jackson. 2011. Methane contamination of drinking water accompanying gas-well drilling and hydraulic fracturing. Proceedings of the National Academy of Sciences, U.S.A. 108:8172-8176. http://www.biology.duke.edu/jackson/pnas2011.pdf.
17 See, e.g., USEPA 2011. Draft Investigation of Ground Contamination near Pavillion, Wyoming. EPA 600/R-00/000 18Bamberger M, Oswald RE. Impacts of gas drilling on human and animal health. New Solut. 2012;22(1):51–77.
19 McKenzie Witter RZ, Newman LS, Adgate JL. 2012. Human Health Risk Assessment of air Emissions from Development of Unconventional Natural Gas Resources. Sci Total Environ. 2012 May 1;424:79-87. 20 Esswein E et al 2012. NIOSH Field Effort to Assess Chemical Exposures in Oil and Gas Workers: Health Hazards in Hydraulic Fracturing. Presentation made at IOM Roundtable: The Health Impact Assessment of New Energy Sources: Shale Gas Extraction. April 30-May 1, 2012
21 Petron G, et al. 2012. Hydrocarbon emissions characterization in the Colorado Front Range: A pilot study. Journal of Geophysical Research, VOL. 117.
22 Gilman JB, Lerner BM, Kister WC, de Gouw J, 2013. Source signature of volatile organic compounds (VOCs) from oil and natural gas operations in northeastern Colorado. Environ Sci Technology DOI: 10. 1021/es304119a
23 Litovitz A, et al. 2013. Estimation of regional air-quality damages from Marcellus Shale natural gas extraction in Pennsylvania. Environ. Res. Lett. 8.
24 Olaguer E 2012. The potential near-source ozone impacts of upstream oil and gas industry emissions. Journal of Air and Waste Management. 62:8, 966–977
25McKenzie Witter RZ, Newman LS, Adgate LS, Adgate JL. 2012. Human Health Risk Assessment of air Emissions from Development of Unconventional Natural Gas Resources. Sci Total Environ. 2012 May 1;424:79–87.
26 U.S. Environmental Protection Agency, Clean Energy-Air emissions, available at http:// www.epa.gov/cleanenergy/energy-and-you/affect/air-emissions.html.
27NRDC, Leaking Profits: The U.S. Oil and Gas Industry Can Reduce Pollution, Conserve Resources, and Make Money by Preventing Methane Waste (Mar. 2012), available at http:// www.nrdc.org/energy/leaking-profits.asp.
28EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2010, Table ES-2, http:/ www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2012-Main-Text.pdf, 29EPA, Greenhouse Gas Reporting Program, 2011 Data, http://epa.gov.ghgreporting/ghgdata/ reported/index.html
30 U.S. Energy Information Administration, Natural Gas Gross Withdrawals and Production, 2010 data. available at http://www.eia.gov/dnav/ng/nglprodlsumldculNUSla.htm; U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks (1990- 2009) (Apr. 15, 2012). Net emissions of methane are just over 600 bcf (billions of standard cubic feet), while gross withdrawals were approximately 26,800 bcf; this implies a net leakage of approximately 2.3 percent.
31Robert Howarth et al., ‘‘Methane Emissions from Natural Gas Systems,’’ Background Paper Prepared for the National Climate Assessment (reference number 2011-0003) (Feb. 25, 2012), available at http://www.eeb.cornell.edu/howarth/Howarth%20et%20al.%20– %20National%20Climate%20Assessment.pdf.
32NRDC, Leaking Profits: The U.S. Oil and Gas Industry Can Reduce Pollution, Conserve Resources, and Make Money by Preventing Methane Waste (Mar. 2012), available at http:// www.nrdc.org/energy/leaking-profits.asp.
33U.S. Environmental Protection Agency, Federal Register Vol. 77, No. 159, Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews (Aug. 16, 2012), available at https://www.federalregister.gov/articles/2012/08/16/2012-16806/oil-and-natural-gas-sector-new-source-performance-standards-and-national-emission-standards-for.
34Hydraulic Fracturing Can Potentially Contaminate Drinking Water sources, NRDC, http:// www.nrdc.org/water/files/fracking-drinking-water-fs.pdf.
35 Soeder, D.J., and Kappel, W.M., 2009, Water Resources and Natural Gas Production fromt he Marcellus Shale: U.S. Geological Survey Fact Sheet 2009-3032, 6 p., available at: http:// pubs.usgs.gov/fs/2009/3032/.
36 See, e.g., DEP Investigating Lycoming County Fracking Fluid Spill at XTO Energy Marcellus Well, http://www.portal.state.pa.us/portal/server.pt/community/newsroom/ 14287?id=15315&typeid=1.
37 U.S. Government Accountability Office, Energy-Water Nexus: Information on the Quantity, Quality, and Management of Water Produced during Oil and Gas Production, GAO-12-156 (Washington, D.C.: Jan 9, 2012).
38 Otton, J.K., 2006, Environmental aspects of produced-water salt releases in onshore and estuarine petroleum-producing areas of the United States: a bibliography: U.S. Geological Survey Open-File report 2006-1154, 223p.
39 NRDC, ‘‘Petition for Rulemaking Pursuant to Section 6974(a) of the Resource Conservation and Recovery Act Concerning the Regulation of Wastes Associated with the Exploration, Development, or Production of Crude Oil or Natural Gas or Geothermal Energy,’’ September 8, 2010, 18–23.
40 See, e.g., DEP Fines Atlas Resources for Drilling Wastewater Spill in Washington County, http://www.portal.state.pa.us/portal/server.pt/community/newsroom/14287?id=13595&typeid=1 41Ohio EPA investigating dumping of drilling waste water in Youngstown area, Feb. 4, 2013, Bob Downing, Beacon Journal, http://www.ohio.com/news/ohio-epa-investigating-dumping-of- drilling-waste-water-in-youngstown-area-1.370584 42http://www.denverpost.com/breakingnews/cil18880544 E. Impacts on Wildlife Habitat and Sensitive Lands

 

 

 

Posted in Congressional Record U.S., Natural Gas | Tagged , , , , | Comments Off on Drinking the Kool-Aid. The U.S. Senate believes we are energy independent.

Economic Peak Natural Gas and Oil – shale is another Bank & Wall Streetscam

Shale drillers companies are struggling to pay $235 billion of high-yield, high-risk debt taken on during the past 3 years of the U.S. shale boom. Shale drillers have consistently spent money faster than they’ve made it, even when oil was $100 a barrel. Bloomberg

In a presentation at the Ira Sohn Investment Conference on May 4, Greenlight Capital hedge fund manager David Einhorn revealed that:

  • Wall Street and banks are clearly incentivized to enable the frack addicts: they greased the skids by underwriting debt and equity securities that allowed them to garner billions in fees.
  • Large oil frackers spent $80 billion more than they got from selling oil.
  • It’s not clear if investors are furnished a clear analysis of the returns these companies actually generate.
  • Tight oil is not profitable even at oil prices of $100 per barrel.As oil prices rose, frackers should have been drowning in cash. But none of them generated excess cash flow, not even when oil was at $100 a barrel. In fact, the opposite was true.
  • Recently, oil prices have declined. Because the frackers have less revenue, they’ve been forced to cut Capex. Though they will continue to spend more dollars than they take in, production is no longer growing.  A business that burns cash and doesn’t grow isn’t worth anything. On the $36 of revenues per BOE [barrel of oil equivalent], Pioneer Natural Resources spends about $14 on field operating expenses and another $6 on corporate expenses. Subtract the historical $28 of Capex, and they lose $12 for every BOE developed. That’s like using $50 bills to counterfeit $20s.

Energy analyst Art Berman likewise found 25 shale oil  companies with a cumulative negative cash flow of  $67 billion over the last four years.

Rational investors would not buy stock in companies losing so much money with this much debt. But ignorant investors have billions of dollars in large mutual funds (i.e. 401K, IRA, or taxable). Greedy investors in high-yield junk bond funds also keep the bubble going. The public risks losing a lot of their savings in the next financial crash and most of them don’t even know it.

The belief in our “energy independence” has already started a transition from coal to natural gas power generation, increasing numbers of truck fleets running on CNG and LNG, and $95 billion dollars of new petrochemical, fertilizer, and other businesses with plans to relocate from overseas or expand/build new factories in America to benefit from cheap gas prices.

The Congressional record of house and senate committee meetings is full of talk about “energy independence” and ridicule about “peak oil” because of a great deal of testimony is from energy production companies and the Energy Information Administration telling them that we have a 100-year supply of U.S. oil and gas,  and that we should export some of it to Europe to reduce Russian influence.

This has led me to thinking we need an Energy jester. Kings used to have a Fool who was the only person that could tell the King the Truth without having his head cut off.  What we need is an Energy Fool who will tell political leaders that both U.S. and global oil, natural gas, and coal may not be as abundant as they appear.  The fool can even cite peer-reviewed scientific literature.  Since only 1% of political leaders have a scientific background, that wouldn’t make a difference on energy or any other topic, another reason we find ourselves on the edge of a cliff.  Or perhaps already falling like Wily Coyote with legs wheeling in the air as the roadrunner speeds off to safety…

The consumption of this possibly imaginary 100-year supply of natural gas is expected to be 60% higher in 2030 (and more if we export LNG). But wait! That would cut the 100-year supply to 50 years or less (exponential growth is key to understanding the energy crisis).

Many experts (Berman, Hughes, Powers, Heinberg) expect the geological peak of shale oil and gas in 2019 or sooner. Economically it could be now, in 2015, if the enormous debt companies have racked up drives them out of business, lowers production, or stops them from expanding production.

In “Drilling Deeper”, Hughes shows that oil plays decline 60 to 91% the first 3 years and 1400 wells are needed in the Bakken just to keep production FLAT. EVERY YEAR.  From the sweet spots in 4 of 15 counties with the highest amount oil/gas.  Hughes thinks the 2012-2040 total oil production will be 13.9 billion barrels, 72% of the EIA estimate of 19.2 billion barrels.  And that shale gas production will be 39% less than the EIA 2040 prediction, dropping to 33% of the EIA’s forecast production rate in 2040.

Alice Friedemann, www.energyskeptic.com

June 18, 2015. The Shale Industry Could Be Swallowed By Its Own Debt by Asjylyn Loder. Bloomberg.

Drillers’ debt ballooned to $235 billion at the end of the first quarter, a 16% increase in the past year, even as revenue shrank.

Shale drillers have consistently spent money faster than they’ve made it, even when oil was $100 a barrel.

Credit markets have played a big role in keeping the entire sector alive,” said Amrita Sen, chief oil analyst at Energy Aspects Ltd., a consulting firm in London.

The debt that fueled the U.S. shale boom now threatens to be its undoing. Drillers are devoting more revenue than ever to interest payments. S&P lowered the outlook or downgraded the credit of almost half of the 105 U.S. exploration and production companies that it rates, according to a May report.

Continental Resources Inc., spent almost as much as Exxon Mobil Corp., a company 20 times its size. Continental borrows at cheaper rates than many of its smaller peers because its debt is investment grade. S&P assigns speculative, or junk, ratings to 45 out of the 62 companies in the Bloomberg index.

Interest payments are eating up more than 10% of revenue for 27 of the 62 drillers in the Bloomberg Intelligence North America Independent Exploration and Production Index, up from 12 a year ago. Oil and gas companies accounted for one-third of the 36 corporate-debt defaults worldwide this year, and missed interest payments are the leading cause of default.

The question is, how long do they have that they can get away with this,” said Thomas Watters, an oil and gas credit analyst at Standard & Poor’s in New York. The companies with the lowest credit ratings “are in survival mode,” he said.  The companies in the Bloomberg index spent $4.15 for every dollar earned selling oil and gas in the first quarter, up from $2.25 a year earlier, while pushing U.S. oil production to the highest in more than 30 years.

Almost $20 billion in bonds issued by the 62 companies are trading at distressed levels, with yields more than 10 percentage points above U.S. Treasuries, as investors demand much higher rates to compensate for the risk that obligations won’t be repaid.

Companies have reduced spending to cope with lower prices, but those cuts will eventually lead to production declines, further shrinking revenue, Watters said.

Interest expense can drain a company’s finances. At this time last year, Quicksilver Resources Inc. was spending more than 20% of its revenue on interest. The company missed a debt payment in February and has since filed for bankruptcy. Sabine Oil & Gas LLC missed an interest payment in April and another this month.

Jan 6, 2015. Deep Debt Keeps Oil Firms Pumping Producers Have Increased Their Borrowings by 55% Since 2010 By Erin Ailworth. Wall Street Journal.

American oil and gas companies have gone heavily into debt during the energy boom, increasing their borrowings by 55% since 2010, to almost $200 billion. Their need to service that debt helps explain why U.S. producers plan to continue pumping oil even as crude trades for less than $50 a barrel, down 55% since last June. But signs of strain are building in the oil patch, where revenue growth hasn’t kept pace with borrowing.

March 17, 2015. Quicksilver Resources Files Bankruptcy as Gas Price Drops, by Tiffany Kary, Bloomberg.

Natural gas producer Quicksilver Resources Inc. sought bankruptcy protection $1.21 billion in assets and $2.35 billion in debts, following a February warning that they wouldn’t pay interest on $298 million of bonds maturing in 2019. In addition to the 2019 notes,  the company also has $350 million in notes due 2016, $325 million in notes due 2021, and $200 million in notes due 2019, according to the filing. The notes due 2019 and the notes due 2021 closed at 4 cents in New York, down from $2.49 a year ago.

Dune Energy Inc., an oil and gas explorer, and Cal Dive International Inc., a provider of manned diving services for the offshore oil and gas industry, also filed for bankruptcy protection this month.

May 20, 2015. “Shale-ionaires” Suffering from Wave of Bankrupt Oil Drillers by Kelly Gilblom. Bloomberg

At the height of the U.S. energy boom, Texas landowner John Baen received about $100,000 a month in royalty payments from companies producing oil and natural gas on his property. Now the checks are much smaller, and so far, 4 of the producers sending him checks have caved in to rising debts as oil prices slumped, seeking court protection from their creditors. For many smaller, cash-strapped producers, current prices of almost $60 still aren’t enough to make ends meet compared to the $100-plus prices seen during the boom days.

There have been at least a dozen bankruptcy filings in recent months, and more than a dozen have defaulted on bond payments or warned investors of challenging times ahead, according to data compiled by Bloomberg.

Royalty payouts from bankrupt operations have shrunk to a fraction of the rates paid before the crash and landowners can be left with no one to take responsibility for abandoned waste, spills and other hazards, say industry experts who have past experience with oil busts.

Many more companies, which make monthly royalty payments to tens of thousands of people, may go bankrupt in the next year, said John Castellano, a managing director at AlixPartners LLC, who focuses on company restructuring.  “We’re seeing highly-levered companies, with high break-even cost requirements, with little ability to generate cash and little access to liquidity — I don’t believe we are near the end of this”.

WBH Energy Partners LLC is typical of companies seeking court relief from debts.

May 4, 2015. Shale Oil Drillers Plunge After Einhorn Slams Fracking Costs by Joe Carroll. Bloomberg

Money manager David Einhorn slammed the shale drilling industry that ushered in a new era of U.S. oil production as wasteful, expensive and a terrible investment. “Pioneer Natural Resources Co., burns cash and isn’t growing, why is the market paying $27 billion for this company?

Einhorn also singled out Concho Resources Inc., Whiting Petroleum Corp., EOG Resurces, and Continental Resources Inc. as examples of shale explorers that spend too much and generate too little cash.

March 31, 2015. Shale Producer Samson Says Bankruptcy May Be Best Option by Bradley Olson. Bloomberg

Samson Resources Corp., an oil and natural gas producer controlled by private equity giant KKR & Co., warned investors that bankruptcy may be its best option. Filing for Chapter 11 protection “may provide the most expeditious manner in which to effect a capital structure solution,” the Tulsa, Oklahoma-based company said Tuesday in its annual report.

Samson told investors it’s at risk of defaulting on its debts, saying its financial condition raises “substantial doubt” that it can continue as a going concern, according to the filing. Samson’s $2.25 billion of 9.75% notes due in February 2020 dropped to a record low of 21.7 cents on the dollar.

Other producers including Dune Energy Inc., BPZ Resources Inc. and Quicksilver Resources Inc. have also sought bankruptcy protection as a rapid decline in oil prices has led banks to rein in lending, drying up cash for drilling across North America.

March 24, 2015. Driller That Skipped First Bond Coupon Said to Start Debt Talks by L. J Keller. Bloomberg 

American Eagle Energy Corp., the Colorado oil producer that missed the first payment on $175 million of bonds it sold last year, has asked creditors to enter confidential debt-restructuring talks and discussed a potential bankruptcy filing as part of the restructuring plan.

American Eagle, is among energy companies now struggling to service $120 billion of high-yield, high-risk debt taken on during the past 3 years amid the U.S. shale boom.

Since oil prices peaked in June, average borrowing costs for the riskiest companies have more than doubled, data compiled by Bloomberg show.

Natural gas driller Quicksilver Resources Inc. and oil explorer BPZ Resources Inc. — two energy companies that missed interest payments this year — filed for Chapter 11 bankruptcy protection earlier this month. Plunging crude prices have also sent offshore contractor Cal Dive International Inc. into bankruptcy court.

The company’s 11% notes due September 2019 have lost more than two-thirds of their value since they were issued, costing investors more than $117 million. The notes last traded March 18 at 32 cents on the dollar. American Eagle’s debt is 1.3 times higher than what its enterprise value suggests the company is worth. American Eagle said it will write down assets by about $79.4 million because of falling energy prices, according to a March 16 regulatory filing.

Also see (from http://shalebubble.org/):

 

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Peak oil sands, low EROI, high debt, limited pipeline and refinery capacity

Peak tar sands, a.k.a. oil sands

Techno-opmtimists claim that technology will enable nasty, sour, gunky, expensive, difficult unconventional oil to fill in the gap of declining conventional oil.

Conventional oil is declining too quickly for unconventional to match

But that’s not likely, because the decline in conventional production is between 4–8% annually (Höök 2009), equal to a new North Sea (~5 Mb/d) coming on stream every year to keep present output constant (Fantazzini 2011). This equals 5 new Saudi-Arabia’s  by 2030 just to offset the decline in existing production (Aleklett 2010).

Höök (2009) provides additional data on giant oil field decline rates and finds the average decline rate has increased by around 0.15% per year since mid-1960s – a trend that is expected to continue. Decline rates are even higher for smaller fields. As future production becomes more reliant on non-giant fields, average decline in existing production will increase. The increasing decline rate is seldom discussed and may be as high as 7,000,000 barrels/day by 2030 (Aleklett 2010).

Although tar sands production may be as high as 4 million b/d in 2030, the easiest, high quality sands are being mined and melted in situ now. Mining depends on adequate water and natural gas supplies. If either becomes less available. production declines. Meanwhile, the entire infrastructure is rusting and corroding, maintenance costs in the harsh environment will take an increasingly larger toll on Energy Returned On Invested as time goes on. The very low EROI of 5 now doesn’t include the cost to transport and refine tar sands oil in Gulf refineries.  The true EROI is more likely around 3, not even close to the 12 to 14 EROI needed.

There are other limits to growth of Canadian Tar Sands

Refinery limits. According to James Burkhard, managing driector of HIS CERA, “Canadian oil sands would eventually hit the limits of existing cross-border capacity by around 2019. Even before that, however, oil sands supply would run up against the capacity limits of Canada’s existing US customers—refineries in the Mid-Continent—to process oil sands production. This could occur as soon as 2015 and is a key reason Canadian producers are seeking access to the much bigger refining market in the US Gulf Coast. To expand the reach of Canadian oil into the U.S. you need a pipeline to the U.S. Gulf Coast which is the largest, most sophisticated refining center in the world” (U.S. SENATE)

Economic. If tar sand prices are unaffordable by society, whether from a deflationary low price or a high-demand, high price, “The Market” will be unable to afford to increase oil sand production.  A financial crash would also stop the money from flowing to new production projects.

On average, the oil price needs to be $85 for oil sand companies to break even. With low oil prices and huge debt loads, companies could find themselves unable to get financing:

  1. Canadian Oil Sands Ltd. said Thursday it would further slash its dividend and capital spending budget in response to the sharp drop in oil prices and a rising debt load. The company’s net debt stood at $1.51 billion as of Dec. 31, 2014.
  2. Southern Pacific Resource Corp. and Connacher Oil and Gas Ltd. announced last week that they’d hired banks to help raise cash so the companies can avoid missing interest-rate payments. Trading in the bonds shows investors expect less than half the principal to be paid back from the energy companies in Alberta’s oil sands.
  3. Connacher, with about C$977 billion in debt, said two days earlier that it had hired Bank of Montreal to look at its liquidity and capital structure after saying in November that cash flow may not be sufficient to cover interest payments on debt and it will need to get additional funds next year to stay in business. The company’s August 2018 notes were trading at about 40 cents on the dollar, according to data compiled by Bloomberg.
  4. MEG Energy Corp., a Calgary-based oil-sands developer, said Dec. 4 it reduced its capital budget for this year by a third and plans to keep 2015 spending flat and funded with cash on hand. Canadian Oil Sands Ltd., said Dec. 3 it’s lowering its dividend by 42 percent.
  5. Canadian Natural Resources Ltd., the nation’s largest producer of heavy oil, has set aside C$2 billion it can remove from its budget of C$8.6 billion next year if prices remain low.

Canadian Association of Petroleum Producers

2030 production changed from 6.4 million b/d to as low as 4.3 million b/d to as high as 5.3 million b/d 835,000 b/d lower oil sands in situ, 33,000 b/d oil sands mining, and 260,000 b/d conventional oil.

Oil Sands production

  • 2014: 2,200,000 b/d (912,000 mining 1,200,000 b/d in situ)
  • 2030: 3,000,000 b/d to 4,000,000 b/d

Conventional oil

  • 2015: 1,400,000 b/d
  • 2020: 1,300,000 b/d

Delayed projects

  • Royal Dutch Shell Plc: Carmon Creek for 2 years that will produce 80,000 barrels a day.

Canceled  projects

  • Royal Dutch Shell Plc: 200,000 barrel-a-day Pierre River mine
  • Total SA: C$11 billion Joslyn mine producing 160,000 barrels-a-day
  • Cenovus Energy said that it would reduce investment spending by 27%, and set aside plans for two oil sands project expansions.

June 17, 2015. Oil-Sands Megaproject Era Wanes as Suncor Scales Back. by R. Penty. Bloomberg.

The era of the megaproject in Canada’s oil sands is fading. Canadian oil-sands spending is poised to drop 30% to $19 billion this year while total oil production will be 17% lower in 2030 compared with last year’s estimates.

High cost, low crude oil prices, tax increases, lack of pipelines, etc., are causing producers such as Suncor Energy Inc. and Imperial Oil Ltd. to shift to smaller projects like cheaper, bite-sized drilling programs that deliver quicker returns and require less labor.

With crude 46% below last year, companies globally have delayed or scrapped about $200 billion in big projects according to a June 16 report from Ernst & Young LLP.

“New oil sands projects, especially the mining projects, are very difficult,” said Amir Arif, an analyst at Cormark Securities Inc. in Calgary. “It’s hard to make the economics work.”

 

Feb 2, 2015. Lower Oil Prices Strike at Heart of Canada’s Oil Sands Production By I. Austen. New York Times. 

For as long as 400-ton dump trucks have been rumbling around the open pit mines of Canada’s oil sands, crews from Kal Tire have been on hand to replace and repair their $70,000, 13-foot diameter tires. But the relationship, going back over a decade, didn’t spare the company when oil prices began plummeting.

Canada’s oil sands prompted an unprecedented expansion over the last decade. But the roughly $155 billion spending spree left the industry with unusually high production costs.

Now, oil sands operators are scrambling to limit the damage, as crude prices hover near 7-year lows.

Suncor, the largest oil sands operator, announced plans to eliminate about 1,000 contract jobs. Shell Canada said it would cut its oil sands work force by about 10%. Cenovus Energy said that it would reduce investment spending by 27%, and set aside plans for two oil sands project expansions.

The enormous projects are difficult to switch off. Companies must keep pumping crude to cover the sizable debt on their multibillion-dollar investments.

Imperial Oil, controlled by Exxon Mobil, said 4th-quarter earnings dropped by 36%.

While production may keep humming along, the big question is whether oil sands producers can break even at current prices.

An oil sands project takes five to 10 years to design and build, and they have a life span of 25 to 50 years. Fort Hills, a project now under construction in a partnership led by Suncor, has a budget of $10.7 billion.

Once such projects are up and running, the expenses are significant, given the process needed to get the oil-laden bitumen from the ground. It must either be dug up or blasted from under the ground using steam. Two energy-hungry steps are then needed to separate the bitumen from the sand and to turn it into usable oil known as synthetic crude.

References

Aleklett, K., et al. 2010. The Peak of the Oil Age – analyzing the world oil production Reference Scenario in World Energy Outlook 2008. Energy Policy, 38(3), 1398-1414. DOI: http://dx.doi.org/10.1016/j.enpol.2009.11.021

Fantazzini, D., et al. 2011. Global oil risks in the early 21st Century. Energy Policy, 39(12), 7865–7873. DOI: http://dx.doi.org/10.1016/j.enpol.2011.09.035

Höök, M., et al. 2009. Giant oil field decline rates and their influence on world oil production. Energy Policy, 37(6), 2262–2272. DOI: http://dx.doi.org/10.1016/j.enpol.2009.02.020

U.S. SENATE. Jan 31, 2012. U.S. Global energy outlook for 2012. S. HRG. 112-378.

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Should America Export Oil? Congressional record

March 19, 2015. CR 2015-3-19 U.S. Crude oil export policy . Congressional record. 150 pages.

HEARING BEFORE THE COMMITTEE ON ENERGY AND NATURAL RESOURCES UNITED STATES 114th CONGRESS FIRST SESSION

CHARLES T. DREVNA, PRESIDENT, AMERICAN FUEL & PETROCHEMICAL MANUFACTURERS

We’ve been lurching from energy crisis to energy crisis for as long as most of us can probably remember.

MARIA CANTWELL, U.S. SENATOR FROM WASHINGTON

Teddy Roosevelt in his Administration Papers on Conservation of Minerals in 1909. Teddy Roosevelt’s Administration found, ‘‘The greatest waste of petroleum has been in exporting crude petroleum and petroleum products to foreign countries. The necessity for it has been due to the sudden increase of production due to the discovery and immediate development of large fields and only by this means has it been possible for the producers to continue to obtain a constant market for petroleum where ever produced. This immediate purchase of product has meant a gain of millions of dollars to the producers.’’ I think the same observation is relevant today.

The U.S. Congress banned the export of crude oil in 1975 after oil exporting nations had used their export capacity as an economic weapon which caused serious damage to the U.S. and to the global economy. Since that time there has never been a reason to revisit the ban. For decades we, in Congress, have debated the best ways to deal with our country’s ever increasing dependence on imported foreign oil. Within the last decade we actually started to see that situation reverse as we started consuming less, producing more and importing less.

Now the oil industry is asking to repeal the export ban. As our oil industry producers produce more at home but our consumption stays relatively flat, our industry wants to sell American oil into the foreign markets where it can get a higher price. But let’s be clear about this.

The United States is and will remain a net oil importer. As we talk about whether we should export oil, we need to keep in mind that for every barrel of oil we export we will be importing even more.

The question before us today is whether this policy change will be in the interest of the American people. As policy makers our obligation is not to any particular industry nor to any particular economic theory. Our responsibility is to decide what policies provide the greatest good to the greatest number of people. As we consider these questions of whether this export ban is still the right policy for America, I think we should think about three variables. First, price. Economic effects of oil and gas prices ripple through our economy. Lower oil prices act like a tax cut for the vast majority of Americans. No one wants to see the price at the pump go up, not in my State of Washington or I’m sure throughout the country. In a published poll this week by Allstate in the National Journal Heartland Monitor, 79 percent of Americans said the current price drop has made a difference in their financial situation. The same percentage of respondents said they are using what they save at the pump daily for other necessities or paying down debt. I would rather have Americans get their own fiscal house in order verses more at the pump for their transportation needs. Second, safety. The oil is moving around our country in ways that we never anticipated, even just five years ago. Oil production has increased faster than the infrastructure needed to transport it in the safest ways. My state currently has tens of thousands of barreled oil traveling through every major population center of our state. And I want to be clear about this. We currently do not have the regulations on the books to safely transport this product. I am going to be working for further measures to make sure that we do get those standards in place. Third, energy security. No one consumes oil. We consume gasoline, diesel and other products that are made from oil. If we are sending oil abroad while some regions of our country then have to import gasoline, diesel and home heating oil, that were refined someplace else are we exporting

CARLOS PASCUAL, FELLOW, CENTER ON GLOBAL EN- ERGY POLICY, COLUMBIA UNIVERSITY, SENIOR VICE PRESIDENT, HIS: I want to address why eliminating the export ban on crude oil will create jobs, raise incomes, stimulate economic growth, lower gasoline prices and strengthen our national security and American influence in the world. From my experience I have seen that lifting the export ban would increase U.S. credibility and leverage in convincing international partners to adopt policies that mirror U.S. interests on Iran, Russia, free trade and even the environment. The ban on crude oil exports is an anachronism that grew out of a period of scarcity in the 1970s. The United States now has the fastest growing oil economy in the world. Since 2008 the U.S. crude oil output increased by 81 percent. This increase exceeds the combined production gains from the rest of the world. The conditions that justify the crude oil export ban in 1973 no longer apply.

RYAN LANCE, CHAIRMAN AND CEO, CONOCOPHILLIPS After decades of declining production our national fortunes are truly changing. This energy renaissance has benefitted our country both domestically and geopolitically. We really have shifted the oil market’s center of gravity away from unstable sources. Even as President Obama said, ‘‘America is number one in oil and gas.’’ We have a bright energy future. That’s a new concept for us. We did it through American-made technology and ingenuity, but there is a problem. We’re producing more oil than our refineries can process economically. They could install new condensate splitters to process more light oil, but that could cost, on average, $400 million per refinery.

CHARLES T. DREVNA, PRESIDENT, AMERICAN FUEL & PETROCHEMICAL MANUFACTURERS

Debate should be grounded in fact. To that point I’d like to describe a survey we released yesterday that

simply asked our members what they are doing and what their plans are in the near term to deal with this new light crude oil. In other words, this survey is not based on modeling or hypothetical scenarios, but on actual refiner’s plans. Bottom line. The refiners plan to increase their use of their light, sweet crude by over 730,000 barrels a day from 2014 through ’16. This is more than EIA’s projected increase for that time frame. The survey also pointed out the importance of being able to access the new production. For the refiners getting the crude has been much more of a bigger issue than refining it. If logistics were not an issue, respondents could process 1.5 billion barrels a day more crude in 2016 than they did in 2014 without any further investments than they already have in the works today.

The survey asked about the logistic activities to get new production to refineries. Most crude delivery was actually from the Bakken region where, in North Dakota, not surprising since this was a new region never connected to the refining system. But old regions in the Permian and the Eagle Ford areas in Texas also had significant crude delivery activities.

While these old regions had some delivery infrastructure problems, or infrastructure in place I should say, the reinvigorated production required some more infrastructure to get it to refiners. These results underscore, once again, that policies facilitating

[Most of this has testimony from industries who are for export because they’d financially benefit, and industries against it who would not]

 

 

Congressional record. January 30, 2014. Crude oil exports hearing, US Senate HRG. 113–355. 67 pages.

HEARING BEFORE THE COMMITTEE ON ENERGY AND NATURAL RESOURCES, UNITED STATES SENATE 113th CONGRESS 2nd session to EXPLORE OPPORTUNITIES AND CHALLENGES ASSOCIATED WITH LIFTING THE BAN ON U.S. CRUDE OIL EXPORTS

HON. RON WYDEN, U.S. SENATOR FROM OREGON. The fact is energy is not the same thing as blueberries and accordingly it is treated differently under Federal law. The Energy Policy and Conservation Act allows for the export of crude oil only when doing so is in the national interest. There simply isn’t that kind of requirement for blueberries or other commodities. National security, of course, is involved when Americans talk about exporting energy. Right now there are several armed conflicts around the world, in South Sudan, Libya, Mozambique and elsewhere that are certainly being inflamed by fights to control oil. Now I’ll put Oregon blueberries up against just about anything. But the last time I looked, nobody is fighting a war over blueberries. It’s hard to believe that only a few years after campaigns for America’s energy independence, having been dominated by slogans such as ‘‘drill, baby, drill,’’ our country now finds itself having a serious discussion on whether it should export crude oil. Energy independence has been a well-worn staple of virtually every politician’s energy speech for decades. Now our country is in the enviable position of having choices about our energy future.

In any energy debate it’s never very hard to find a voice for the various regions of America, for various industries in America and for various ideological points of view in America. Consumers, however, often don’t have one. I just want it understood that on my watch, the consumer is not going to get short shrift. Now it looks like a number of influential voices want to start exporting oil. I just want to hammer home the point this morning that, for me, the litmus test is how middle class families are going to be affected by changing our country’s policy on oil exports. It is not enough to say some algorithm determines exports are good for the Gross Domestic Product or some other abstract concept. American families and American businesses deserve to know what exports would mean for their specific needs when they fill up at the pump or get their delivery of heating oil. Simply charging forward and hoping for the best is not the way you get the best policy decisions. The responsibility of our committee, and we have always worked on these issues in a bipartisan way, is to make sure consumers are not going to get hammered by the cost of gas going up because of some theory that everything is just going to turn out hunky dory in the end.

We’ve all heard about how it’s a global price. I’m sure we’re going to hear that again today. But a global price does not automatically mean a stable price. If oil stops flowing from Saudi Arabia next week, American consumers and businesses would feel it in a hurry.

HAROLD HAMM, CHAIRMAN AND CHIEF EXECUTIVE OFFICER, CONTINENTAL RESOURCES, INC., OKLAHOMA CITY, OK.

In October 2011 DEPA put a stake in the ground and predicted American energy independence by 2020. America’s independent oil and gas producers have unlocked the technology and resources that made this a reality, not the majors. As a result we can today mark the recent 40th anniversary of the OPEC oil embargo by ending their oil scarcity in America and along with it ending the last short sighted regulation passed during that same period.

  • America now counts their natural gas supplies in centuries.
  • Experts agree we’ll be energy independent in terms of crude oil within this decade. This phenomenon was brought about by a group of independent American producers and missed by the general consensus of the industry.
  • It was in complete contrast to the popular belief that the United States would be running out of oil and gas at the turn of the 21st century.

 

GRAEME BURNETT, SENIOR VICE PRESIDENT, DELTA AIR LINES, ATLANTA, GA

Behind the U.S. military, Delta is the largest user of jet fuel in the world and jet fuel is our largest expense. Because of this we are uniquely situated both as an end user of crude oil and as a refiner to comment on the crude oil export ban and the current debate over whether to lift it. We believe strongly that the ban on U.S. crude oil exports is good policy and that lifting export limits now would come at the expense at the American consumer, who would pay more for gasoline, more for heating oil and more for the price of an airline ticket. Today the going price for a barrel of U.S. crude is $11 less than a barrel sold in Europe. This price differential can be easily explained. The U.S. crude market is a competitive one with price determined by supply and demand. Once the U.S. domestic market incorporated the increased supply of crude from places like North Dakota, the price of a domestic barrel of oil came down.

It’s clear who gains from this scenario. The oil exploration and production companies, many of which are foreign owned. With the increased supply of U.S. crude helping to push prices down these companies want to sell U.S. crude on the global market at higher prices largely determined by OPEC.

Our country’s refinery workers also stand to lose from lifting export limits. Some recent history can help explain why. Before the shale oil boom there was too much capacity in the refineries in the Northeast, along the Gulf Coast and many were closing. In fact Delta purchased its Pennsylvania refinery in 2012 from ConocoPhilips after their facility had been closed nearly 1 year. The shale oil revolution breathed new life into U.S. refineries and created jobs for thousands of refinery workers. In thinking about the merits of the export ban we should also consider one of its goals, which was to help achieve energy independence. By independence I mean the ability to meet our energy needs from sources within North America. Notwithstanding the upswing in domestic production this country still imports around 33 percent of its daily crude oil needs from outside of North America. That’s why exporting U.S. crude makes little sense. If we allow for the export of U.S. crude we’ll have to import more oil from overseas and subject ourselves once again to an increasing degree of price volatility and higher global prices. In sum, the export ban works.

AMY MYERS JAFFE, EXECUTIVE DIRECTOR OF ENERGY AND SUSTAINABILITY, INSTITUTE OF TRANSPORTATION STUDIES, GRADUATE SCHOOL OF MANAGEMENT, UNIVERSITY OF CALIFORNIA, DAVIS, CA

[She makes long POLITICAL arguments about why we should export to Europe to weaken adversaries such as Iran and Russia] Another senator characterized her point of view as: What is your opinion of Ms. Myers Jaffe’s argument that U.S. crude exports, used as a tool of geopolitics, may have the effect of reducing volatility in the global oil market, much of which is driven by geopolitical conflicts?

What we’re really discussing is No. 1, what is the best way to organize free markets and to eliminate distortions and who gets the profit from the exports. Will the refining industry get the profits from the export or the upstream oil and gas industry get the profits from the export or will other industries get the profits from the exports because we’re not in here to discuss banning all energy exports from the United States.

Because we have physical bottlenecks that prevent us from exporting our surplus of natural gas we are currently exporting coal. We need to understand that when you block, like the little boy with the finger in the dike, when you block a hole in one point of the dike, water pressure comes to another point in the dike and something will be exported that’s a different thing. I think the natural gas example is the best example because nobody expected the United States, with its best, new abundance of natural gas and the industry and lower electricity prices that it is promoting, nobody expected the result of that to be the export of coal to Europe. I’m just returning from the World Economic Forum in Davos. I can tell you that the entire discussion focused around Europe’s need to reevaluate their entire energy policies because they are importing coal. Their emissions are going up. They are not drilling for natural gas. They realized that they have these huge distortions that have created a great economic advantage for the U.S. economy and a great disadvantage for the European economic system.

I want to remind the committee and our public that when we had a temporary disruption gas land supply during Hurricane Rita and Katrina as Senator Landrieu might remember, Europe loaned us gasoline supplies from their mandatory strategic stocks that they require industry to hold. That is how we weathered through our crisis. We need to consider our relationship with our allies like Europe when we think about our future export policies.

Energy exports will weaken some of our adversaries such as Iran and Russia. US shale gas has already played a key role in weakening Russia’s ability to wield an energy weapon over its European customers by displacement.

Energy exports also improve our balance of trade.

DANIEL J. WEISS, SENIOR FELLOW AND DIRECTOR OF CLIMATE STRATEGY, CENTER FOR AMERICAN PROGRESS

Since 2008 the United States has produced more and used less oil due to advances in drilling technology, innovatingly employed by Mr. Hamm and his company and due to more efficient vehicles. This reduced oil imports and lowered our vulnerability to a foreign oil supply disruption that could cause a gasoline price spike. Lifting the ban on crude oil exports could squander this recently improved energy security and price stability. To maintain these benefits we urge you to defend the existing domestic crude oil export ban.

Although domestic production has significantly grown over the past 5 years, the Energy Information Administration projects that crude oil crude oil production will peak in 2019 and begin a steady decline after that.

This energy abundance could be a temporary phenomenon.

The EIA also predicts that in 2014 the U.S. will consume 5 million barrels per day more of oil and liquids than we produce. This gap between demand and supply will continue at least through 2040 growing by 13 percent. This is hardly energy independence.

Our transportation system is almost entirely powered by oil which makes crude oil different from many other commodities. American families, the economy and our energy security are vulnerable to sudden foreign oil supply disruptions and price spikes.

The U.S. imports more oil from the Organization of Petroleum Exporting Countries (OPEC) than from any other single source. OPEC oil is very vulnerable to supply disruptions.8 EIA found that interruptions may occur frequently… for a variety of reasons, including conflicts [and] natural disasters… Total outages among the Organization of the Petroleum Exporting Countries (OPEC) producers recently rose to historically high levels.9

A commission of retired senior U.S. military officers recently noted that ‘‘No matter how close the country comes to oil self-sufficiency, volatility in the global oil market will remain a serious concern.’’10 Oil produced in the United States is significantly less vulnerable to supply disruptions and therefore provides more energy security. There is little benefit to Americans from lifting the ban, particularly since oil companies are already making huge profits even with it. The five largest oil companies—BP, Chevron, ConocoPhillips, ExxonMobil, and Shell—made a combined total profit of $1 trillion over the last decade, based on their quarterly financial reports.11

I think all discussion about energy independence or almost all of it is focused on supply. That is something we control some of and some we don’t.

My view is we need to focus on reducing our demand because that is something we do have control over. It will help save consumers money. It will help reduce the carbon pollution that will cause extreme weather, that will disrupt our energy production and transportation system. So I think we need to really focus on reducing demand. Particularly when it comes to transportation which is fueled over 90 percent by oil, we need to invest in alternatives to oil whether it’s electric vehicles, whether it is natural gas fueled trucks, whether it is public transportation, advanced biofuels. All of those things will give consumer choices so we are not solely dependent on this one fuel to run, essentially run, our economy because as long as we are we’ll still be here having discussions about energy security and energy independence.

The Energy Information Administration (EIA) recently found that Organization of the Petroleum Exporting Countries (OPEC) supply disruptions in 2013 reduced the anticipated growth in world global fuels supply. EIA reported this finding in the just published ‘‘Short-Term Energy Outlook Supplement: Uncertainties in the Short-Term Global Petroleum and Other Liquids Supply Forecast.’’1 EIA determined that In January 2013, EIA’s Short-Term Energy Outlook (STEO) projected that global liquid fuels supply growth would average 1.0 million bbl/d in 2013, but EIA’s latest estimate shows that global supply grew by about 0.6 million bbl/d in 2013. The difference mainly reflects higher-than-expected unplanned supply disruptions among OPEC producers.2 This same analysis found that OPEC disruptions increased in the second half of 2013, reaching 2.6 million bbl/d by the end of the year because of increased disruptions in Libya. The issues underpinning the outages in these countries are unresolved, resulting in uncertain oil production outlooks for these countries.3

As the production of U.S. oil has grown, the importation of foreign oil has declined from 57 percent in 2008 to 40 percent in 2013.4    [my comment: THAT’S JUST 17%]

This includes a 35 percent reduction in crude oil imports from OPEC since 2008, which was the second largest amount of imports since 1973.5 As U.S. domestic production continues to grow, EIA projects OPEC crude oil imports will decline by 47 percent between 2013 and 2020.6 Despite the important growth in domestic oil production, the U.S. will consume over 5 million barrels of oil and liquids per day in 2014 compared to the amount it produces.7

Unless there are large reductions in demand, the demand-supply gap will grow if the U.S. exports crude oil and liquids. This gap could be filled by oil from both OPEC and non-OPEC nations. If the U.S. begins to export significantly more oil than it did in 2013, it would have to import oil to offset the exports. Oil companies would like to export ‘‘lighter’’ crude oil because there has been a slight increase in light oil production in the U.S. over the past few years.89 In 2013, EIA reported that domestic crude oil was light, with an average API gravity of 35.3. Imported oil was intermediate, with an average API gravity of 28.10 EIA projects that the increase in domestic production will ‘‘replace imports of medium and heavy crude.’’11 If exports were allowed, refiners could import slightly heavier oil as they were before the domestic production increase began in 2009. The three largest importers of heavy oil are Canada, Mexico, and Venezuela, with average imports of 2.6 million barrels per day (mbd), 1.0 mbd, and .8 mbd, respectively, during the first 11 months of 2013.12 Presumably, some of the increase in heavier crude oil to offset any domestic exports will come from Venezuela, which is a member of OPEC. I am not aware of any projections of changes in future oil imports from these three nations if the crude oil export ban is lifted.

As you note, much of the price volatility in the global oil market ‘‘is driven by geopolitical conflicts.’’ I am not an expert in the regional conflicts in the Middle East, Africa, or other oil producing regions. However, even from my lay person’s perspective it seems that ancient sectarian disagreements, government repression, joblessness, and vast disparities of wealth in these nations are a major part of many of these conflicts. It is difficult to imagine, for instance, that the export of one million barrels of oil per day from the U.S. would have much impact on these factors.

In October, New York became the first state to establish a ‘‘strategic gasoline reserve’’ to prevent serious supply disruptions during extreme weather events or other emergencies.34

Amy Myers Jaffe recently promoted a mandate to ensure a certain amount of refined product inventories. She wrote: Regulators [should] mandate a minimum level of mandatory refined product inventories in the United States. Such a system exists in Europe and Japan and allowed Europe the flexibility to provide gasoline to the United States during the production shortfalls that occurred following Katrina and Rita, preventing worse dislocations. The system helped Japan in the aftermath of the Fukushima crisis.

New York plans to store up to 3 million gallons of gasoline for first responders and other motorists. Establishment of additional reserves could supply gasoline in other states in the event of future supply disruptions. Because of technical limitations on storing significant amounts of gasoline for long periods of time, there would probably have to be multiple smaller reserves rather than several large reserves, as with the Strategic Petroleum Reserve. The Senate Energy Committee should explore the need for such gasoline reserves, as well as the technical and economic feasibility of building and maintaining them.

A US government program reserving the right to use for strategic national emergency releases a portion of this mandated minimum supplementary industry refined product stocks of 5% or 10% of each refining company’s average customer demand would ensure that needed supplies of gasoline or heating oil in inventory to ease the impact of sudden weather related demand surges or accidental disruption of consumer supplies.35 I believe that this proposal would help address future extreme weather or other unforeseen events that cause gasoline supply disruptions.

some of the citations:

1 Energy Information Administration, Short-Term Energy Outlook Supplement: Uncertainties in the Short-Term Global Petroleum and Other Liquids Supply Forecast (U.S. Department of Energy, 2014), available at http://www.eia.gov/forecasts/steo/special/pdf/2014lspl01.pdf.

2 Ibid 3Ibid

4Energy Information Administration, AEO2014 Early Release Overview (U.S. Department of Energy, 2013), available at http://www.eia.gov/forecasts/aeo/er/pdf/0383er%282014%29.pdf.

5Energy Information Administration, ‘‘U.S. Imports from OPEC Countries of Crude Oil,’’ available at http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=mcrimxx2&f=a (last accessed February 2014).

6Energy Information Administration, ‘‘Imported Liquids by Source, Reference case,’’ available at http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2014ER&subject=8- AEO2014ER&table=101-AEO2014ER&region=0-0&cases=ref2014er-d102413a (last accessed February 2014).

7Energy Information Administration, AEO2014 Early Release Overview (U.S. Department of Energy, 2014), Figure 12, available at http://www.eia.gov/forecasts/aeo/er/ earlylproduction.cfm?src=Petroleum-b2. 8Energy Information Administration, Annual Energy Outlook 2013 (U.S. Department of Energy, 2013), Figure 98, available at http://www.eia.gov/forecasts/aeo/MTlliquidfuels.cfm.

9Crude oil with an API gravity greater than 35.0 is ‘‘light,’’ while oil with an API gravity less than 25.0 is ‘‘heavy.’’ In 2013, EIA reported that domestic crude oil was light, with an API of 35.3. Imported oil was intermediate, with an API of 28.

10Energy Information Administration, Annual Energy Outlook 2013, Figure 98.

11Energy Information Administration, ‘‘WTI-Brent Spread Projected to Average $11 per barrel in 2014,’’ This Week in Petroleum, February 12, 2014, available at http://www.eia.gov/oog/info/ twip/twip.asp.

12Energy Information Administration, ‘‘U.S. Imports by Country of Origin,’’ available at http:// www.eia.gov/dnav/pet/petlmovelimpcusla2lnuslepc0lim0lmbblpdlm.htm (last accessed February 2014).

 

Posted in Congressional Record U.S. | Tagged , | 1 Comment

Implications of declining EROI on oil production 2013 by David J. Murphy

Murphy, David J. December 2, 2013. The implications of the declining energy return on investment of oil production. Trans. R. Soc. A 2014 372

[This is a great paper on EROI, highly recommended. Without EROI studies, we risk building energy capturing contraptions that end up being useless, consuming more oil than generated, the Easter Island Heads of our former civilization. Alice Friedemann, energyskeptic.com]

Declining production from conventional oil resources has initiated a global transition to unconventional oil, such as tar sands. Unconventional oil is generally harder to extract than conventional oil and is expected to have a (much) lower energy return on (energy) investment (EROI). Recently, there has been a surge in publications estimating the EROI of a number of different sources of oil, and others relating EROI to long-term economic growth, profitability and oil prices. The following points seem clear from a review of the literature: (i) the EROI of global oil production is roughly 17 and declining, while that for the USA is 11 and declining; (ii) the EROI of ultra-deep- water oil and oil sands is below 10; (iii) the relation between the EROI and the price of oil is inverse and exponential; (iv) as EROI declines below 10, a point is reached when the relation between EROI and price becomes highly nonlinear; and (v) the minimum oil price needed to increase the oil supply in the near term is at levels consistent with levels that have induced past economic recessions. From these points, I conclude that, as the EROI of the average barrel of oil declines, long-term economic growth will become harder to achieve and come at an increasingly higher financial, energetic and environmental cost.

Introduction

Today’s oil industry is going through a fundamental change: conventional oil fields are being rapidly depleted and new production is being derived increasingly from unconventional sources, such as tar or oil sands and shale (or tight) oil. Indeed, much of the so-called ‘peak oil debate’ rests on whether or not these sources can be produced at rates comparable to the conventional mega-oil fields of yesterday.

What is less discussed is that the production of unconventional oil most likely has a (much) lower net energy yield than the production of conventional crude oil. Net energy is commonly defined as the difference between the energy acquired from some source and the energy used to obtain and deliver that energy, measured over a full life cycle (net energy=E(out)- E(in)). A related concept is the energy return on investment (EROI), defined as the ratio of the former to the latter (EROI=E(out)/E(in)). The ‘energy used to obtain energy’, E(in), may be measured in a number of different ways. For example, it may include both the energy used directly during the operation of the relevant energy system (e.g. the energy used for water injection in oil wells) as well as the energy used indirectly in various stages of its life cycle (e.g. the energy required to manufacture the oil rig). Owing to these differences, it is necessary to ensure that the EROI estimates have been derived using similar boundaries, i.e. using the same level of specificity for Ein. Murphy et al. [1] suggested a framework for categorizing various EROI estimates, and, where applicable, I will follow this framework in this paper.

Estimates of EROI are important because they provide a measure of the relative ‘efficiency’ of different energy sources and of the energy system as a whole [2,3]. Since it is this net energy that is important for long-term economic growth [3–6], measuring and tracking the changes in EROI over time may allow us to assess the future growth potential of the global economy in ways that data on production and/or prices cannot.

Over the past few years, there has been a surge in research estimating the EROI of a number of different sources of oil, including global oil and gas [7], US oil and gas [8,9], Norwegian oil and gas [10], ultra-deep-water oil and gas [11]and oil shale[12]. In addition, there have been several publications relating EROI to long-term economic growth, firm profitability and oil prices [3, 13–15].

The main objective of this paper is to use this literature to explain the implications that declining EROI may have for long-term economic growth. Specifically, this paper: (i) provides a brief history of the development of EROI and net energy concepts in the academic literature, (ii) summarizes the most recent estimates of the EROI of oil resources, (iii) assesses the importance of EROI and net energy for economic growth and (iv) discusses the implications of these estimates for the future growth of the global economy.

(a) A brief history of energy return on investment

In the late 1960s, Charles Hall studied the energy flows within New Hope Creek, in North Carolina, USA, to understand the migration patterns of the fish within the stream. His conclusions [16] revealed that, by migrating, the fish were able to exploit new sources of food, which, after accounting for the additional energy cost of migration, conferred a large net energy gain upon the fish. In other words, owing to the abundance of food in the new locations, the fish were able to gain enough energy not only to ‘pay’ for the energy expenditure of that migration but also to grow and reproduce. Comparing the energy gained from migration to the energy expended in the migration process was ostensibly the first calculation of EROI.

In the autumn of 1973 the price of oil skyrocketed following the Arab oil embargo (the so-called ‘first oil shock’), which sent most OECD economies tumbling into recession. The apparent vulnerability of OECD nations to spikes in the price of oil led many researchers to focus on the interaction between the economy and energy. Then, in 1974, the journal Energy Policy dedicated a series of articles to the energy costs of production processes. The editor of this series, Peter Chapman, began the series with a paper titled ‘Energy costs: a review of methods’, and observed that ‘this subject is so new and undeveloped that there is no universally agreed label as yet’ [17], and followed up two years later with a second paper [18]. Today this area of research is spread among a number of different disciplines, including, but not limited to, ecological economics, industrial ecology and net energy analysis, and the EROI statistic is just one of many indicators calculated.

Also during this period researchers started using Leontief input–output tables as a way to measure the use of energy within the economy [19–22]. For example, Bullard & Herendeen [23] used a Leontief-type input–output matrix to calculate the energy intensity (in units of joules per dollar) of every major industrial sector of the US economy. Even today this paper serves as a useful model for other net energy analyses [8,24]. In addition, a workshop in Sweden in 1974 and one at Stanford, CA, in 1975 formalized the methodologies and conventions of energy analysis [25,26].

In 1974, the US Congress enacted specific legislation mandating that net energy be accounted for in energy projects. The Nuclear Energy Research and Development Act of 1974 (NERDA) included a provision stating that ‘the potential for production of net energy by the proposed technology at the stage of commercial application shall be analyzed and considered in evaluating proposals’. Further influential papers by the Colorado Energy Research Institute, Bullardet al.and Herendeen followed this requirement [27–29]. Unfortunately, the net energy provision within the NERDA was never adopted and was eventually dropped.

In 1979, the Iranian revolution led to a cessation of their oil exports (the second oil shock), which precipitated another spike in the price of oil and squeezed an already strained US economy. Responding to this, and in an attempt to control deficits and expenditure, President Reagan of the USA enacted Executive Order 12291 in 1980. This order mandated that ‘regulatory action shall not be undertaken unless the potential benefits to society from the regulation outweigh the potential costs to society’.

 

In other words, all US regulatory action had to show a net monetary benefit to US society, and the idea of measuring benefits in terms of net energy fell even further from the policy arena.

Net energy analysis remained insignificant in US energy policy debates until the dispute over corn ethanol emerged 25 years later [30,31].

Although the political emphasis had now shifted towards economic analysis, the 1980s still provided useful papers on net energy analysis (e.g. [32]). In 1981, Hall published ‘Energy return on investment for United States petroleum, coal, and uranium’, which marked the first time that the acronym EROI was published in the academic literature [33]. Later that year, Hall & Cleveland [34] published ‘Petroleum drilling and production in the United States: yield per effort and net energy analysis’. This paper analyzed the amount of energy being produced per foot drilled and found that the ratio had been declining steadily for 30 years. Further publications by Hall and colleagues then tested hypotheses relating economic growth to energy use, introduced explicitly the concept of energy return on investment and examined the EROI of most major sources of energy [35,36].

Following growing concern about environmental impacts, climate change and sustainability, documented in the Brundtland Report in 1987 [37], emphasis began to shift from energy analysis to greenhouse gas (GHG) emissions and life-cycle analysis. Life-cycle analysis (LCA) itself was born out of the process and input–output analyses codified in the aforementioned energy literature of the 1970s and 1980s, and can be used to calculate EROI and other net energy metrics. Beginning around the turn of the century, researchers began to recognize the complementarity between LCA and net energy and began publishing on the matter [38].

There was another surge in publications in net energy analysis in the 2000s, due mainly to a growing global interest in renewable energy, and therefore an interest in metrics that compare renewable energy technologies. The debate about whether or not corn ethanol has an EROI greater than one is a good example [30,31]. There has also been a number of studies using the input–output techniques developed in the 1970s to track emissions production and/or resource consumption across regions [39].

 

Today, research within the field of net energy analysis is expanding rapidly. The main renewable energy options, including, but not limited to, solar photovoltaics, concentrating solar, wind power and biofuels, have each been the focus of studies estimating their net energy yield [31,40,41].

Furthermore, with the expansion of oil production into ultra-deep water, tar sands and other unconventional sources, as well as developments with shale gas, there has been a renewed interest in whether or not these sources of energy have EROI ratios similar to conventional oil and gas, and publications are expected to be forthcoming .

Recent estimates of the energy return on (energy) investment for oil and gas production

There has been a recent resurgence in EROI studies for liquid fuels, beginning with Cleveland [ 8], who estimated the EROI for oil and gas extraction in the US, Gagnon et al. [7], who estimated the same EROI for the whole world, and a number of additional studies that were contained in a 2011 special issue of the journal Sustainability. This section reviews the findings of these papers. Unless otherwise noted, all of the oil EROIs reported here are equivalent to the standard EROI (EROIstnd), as reported in Murphy et al. [1], which means that both the indirect and direct costs of energy extraction are included in the EROI calculation, but costs further downstream, such as transportation and refinement, have been omitted.

Cleveland [ 8]estimated two values for the EROI of US oil and gas that differed in the method of aggregating different types of energy carrier. The first method used thermal-equivalent aggregation, i.e. volumes of natural gas and oil are combined in terms of their heat content in joules. The second method uses a Divisia index, developed by Berndt [42], and uses both energy prices and consumption levels to adjust for the ‘quality’ of each energy carrier. Quality corrections are often used in energy analysis to adjust for the varying economic productivity of different energy carriers—for example, since electricity is more valuable, in terms of potential economic productivity, than coal, it is given more weight in the aggregate measure [43]. Quality-corrected measures better reflect the ability of energy carriers to produce marketable goods and services, so are arguably more useful.

 

The EROI values calculated using the energy quality-corrected data for US oil and gas production are consistently lower than those calculated from the non-quality-corrected data. This reflects the fact that many of the inputs to production are high-quality (i.e. high-priced) energy carriers such as electricity and diesel, while the outputs are unprocessed crude oil and natural gas.

Nevertheless, both estimates show the same trend over time: namely, an increase until the early 1970s, a decline until the mid-1980s, a slight recovery until the mid-1990s, followed again by decline (figure 1).

According to Cleveland, the overall downward trend from the 1970s till the mid-1990s is the result of higher extraction costs due to the depletion of oil in the USA. The up and down fluctuations within this aggregate trend are likely to be linked to changes in oil prices influencing the rate of drilling in the USA, with higher prices encouraging more drilling in less promising areas, which in turn leads to a lower yield and a lower aggregate EROI. Gagnon et al. [7] estimated the EROI for global oil and gas from 1992 to 2006 using the same energy aggregation techniques as Cleveland [8], i.e. both thermal equivalence and Divisia indices. In both cases, the EROI at the wellhead was around 26 in 1992 and increased to 35 in 1999 before declining to 18 in 2006 (figure 1).

It is not surprising that the EROI for global oil and gas is higher than that for the USA considering that oil production peaked in the USA in 1970 due mainly to the depletion of its biggest oil fields, while global production continued to flow and even increase from the mega-oil fields of the Persian Gulf.

US producers are increasingly reliant upon smaller and poorer-quality fields in difficult locations (e.g. deep water) together with the enhanced recovery of oil from existing fields—all of which are relatively energy intensive. In contrast, most OPEC members are still producing oil from high-quality supergiant fields.

The first few years of the Gagnon dataset and the last few years of the Cleveland dataset overlap in the early 1990s and both show a general increasing trend. The results from Gagnon et al. [7] then show that the increase in the early 1990s reaches a maximum in 1999, followed by a monotonic decline through the 2000s. Much like the Cleveland paper, Gagnon et al. assume that the decline is due to the depletion of easy access resources, but, as mentioned earlier, this trend also could be dependent on the trend in oil prices.

In addition to the estimates of Cleveland [ 8] and Gagnon et al. [7], Guilford et al. [9] estimated the non-quality-corrected EROI of conventional oil and gas production for the USA. They found that the EROI of oil production has declined from a peak of 24 in the 1950s to roughly 11 in 2007 (figure 1). By deriving separate estimates for exploration and production, they show how depletion reduces the rate of production from existing fields and gives incentives for increased exploration for new fields, both of which lower the aggregate EROI. They also suggest that natural gas is subsidizing oil production and that the EROI for oil alone is likely to be much lower.

Figure 1. EROI estimates from three sources, Gagnon et al. [7], Cleveland [8] and Guilford et al. [9]. The Gagnon et al. [7] data represent estimates of the EROI for global oil and gas production using aggregation by Divisia indices. The Cleveland [8] data represent the trend in EROI values for US oil and gas production calculated using the Divisia indices to aggregate energy units. The Guilford et al. [9] data represent estimates of the EROI of US oil production from 1919 to 2007

Figure 1. EROI estimates from three sources, Gagnon et al. [7], Cleveland [8] and Guilford et al. [9]. The Gagnon et al. [7] data represent estimates of the EROI for global oil and gas production using aggregation by Divisia indices. The Cleveland [8] data represent the trend in EROI values for US oil and gas production calculated using the Divisia indices to aggregate energy units. The Guilford et al. [9] data represent estimates of the EROI of US oil production from 1919 to 2007

Despite differences in coverage and approach, the results from these three studies are broadly consistent, namely a general increase in EROI until 1970, then a general decline until the early 1980s, an increase through the mid-1990s and then a decline.

 

Grandell et al. [10] estimated the EROI of oil production from Norwegian oilfields to be roughly 20 in

  1. They also note that as the fields deplete they expect the EROI to decline further. Brandt [44] estimatedthattheEROIfromCalifornianoilfieldshasdeclinedfromover50 in the 1950s to under 10 by the mid-2000s. Similarly, Hu et al. [45] estimated that the EROI from the Daqing oil field, the biggest oil field in China, had declined from 10 in 2001 to 6.5 by 2009.

 

Two other recent EROI estimates of particular importance are those of Moerschbaecher & Day [11], who estimated the EROI of ultra-deep-water (depths greater than 1524 m or 5000 feet) production in the Gulf of Mexico, and Cleveland & O’Connor [12], who estimated the EROI of oil shale production.

Moerschbaecher & Day [11] estimated the EROI for deep-water oil production to be between 7 and 22. The range in EROI values is due to a sensitivity analysis performed by the authors that incorporated three different energy intensity values as proxies for the energy intensity of the ultra-deep-water oil industry. They also noted that, owing to the large infrastructure requirements of the deep-water oil industry, the real value is probably closer to the lower end of the range presented.

Cleveland & O’Connor [12] estimated that the EROI for oil shale production using either surface retorting or in situ methods was roughly 1.5, much lower than for other unconventional resources. Oil shale is the production of oil from kerogen found in sedimentary rock and is distinct from ‘shale oil’ or, preferably, ‘tight oil’, which is oil trapped in shale or other impermeable rock. Oil shale is discussed here because the western USA has vast resources of oil shale, but production costs are much higher than for other forms of unconventional oil [46].

The following summarizes the aforementioned studies:

  • EROI 11: average for US oil production today, down from roughly 20 in the early 1970s
  • EROI 17: global average, down from EROI of roughly 30 in 2000
  • EROI 10: ultra-deep-water oil production is probably less than 10
  • EROI 1.5: Oil shale (kerogen), not tight oil (aka ‘shale’ oil)

Energy return on (energy) investment, oil prices, and economic growth

 

The economic crash of 2008 occurred during the same month that oil prices peaked at an all-time high of $147 per barrel, leading to numerous studies that suggested a causal link between the two [47,48]. In addition, other researchers involved in net energy analysis began examining how EROI relates to both the price of oil and economic growth [3,13,15,49–51].

 

Murphy & Hall [3] examined the relation between EROI, oil price and economic growth over the past 40 years and found that economic growth occurred during periods that combined low oil prices with an increasing oil supply. They also found that high oil prices led to an increase in energy expenditures as a share of GDP, which has led historically to recessions. Lastly, they found that oil prices and EROI are inversely related (figure 2), which implies that increasing the oil supply by exploiting unconventional and hence lower EROI sources of oil would require high oil prices. This created what Murphy & Hall called the ‘economic growth paradox: increasing the oil supply to support economic growth will require high oil prices that will undermine that economic growth’.

 

Other researchers have come to similar conclusions to those of Murphy & Hall, most notably economist

James Hamilton [47]. Recently, Kopits [50], and later Nelder & Macdonald [49], reiterated the importance of the relation between oil prices and economic growth in what they describe as a ‘narrow ledge’ of oil prices. This is the idea that the range, or ledge, of oil prices that are profitable for oil producers but not so high as to hinder economic growth is narrowing as newer oil resources require high oil prices for development, and as economies begin to contract due largely to the effects of prolonged periods of high oil prices. In other words, it is becoming increasingly difficult for the oil industry to increase supply at low prices, since most of the new oil being brought online has a low EROI. Therefore, if we can only increase oil supply through low EROI resources, then oil prices must apparently rise to meet the cost, thus restraining economic growth.

Skrebowski [51]provides another interpretation of the relation between oil prices and economic growth in what he calls the ‘effective incremental oil supply cost. It should be noted there are wide divergences in estimates of oil development costs depending on what is included and the treatment of financial costs, profits and overheads. Those used here are estimates of the prices needed to justify a new, large development.’

According to data provided by Skrebowski, developing new unconventional oil production in Canada (i.e. tar sands) requires an oil price between $70 and $90 per barrel. Skrebowski also indicates that new production from ultra-deep-water areas requires prices between $70 and $80 per barrel. In other words, to increase oil production over the next few years from such resources will require oil prices above at least $70 per barrel. These oil prices may seem normal today considering that the market price for reference crude West-Texas Intermediate ranged from $78 to $110 per barrel in 2012 alone, but we should remember that the average oil price during periods of economic growth over the past 40 years was under $40 per barrel, and the average price during economic recessions was under $60 per barrel (dollar values inflation adjusted to 2010) [3]. What these data indicate is that the floor price at which we could increase oil production in the short term would require, at a minimum, prices that are correlated historically with economic recessions.

Heun & de Wit [15] found indicates that the price of oil increases exponentially as EROI declines [equation and explanation snipped, see pdf]. They suggest that the nature of the relation between EROI and the price is such that the effect on price becomes highly nonlinear as EROI declines below 10.

Figure 2. Relationship between oil prices and EROI. (Adapted from Murphy & Hall [3].)

Figure 2. Relationship between oil prices and EROI. (Adapted from Murphy & Hall [3].)

 

 

 

 

 

 

 

 

 

 

King & Hall [13] examined the relation between EROI, oil prices and the potential profitability of oil-producing firms, termed energy-producing entities (EPEs). They found that for an EPE to receive a 10% financial rate of return from an energy extraction process, which, for example, has an EROI of 11, would require an oil price of roughly $20 per barrel.3 Alternatively, a 100% financial rate of return for the same extraction project would require $60 per barrel (figure 3). King & Hall also echoed Heun & de Wit, suggesting that the relationship between EROI and profitability becomes nonlinear when the EROI declines below 10.

The pertinent results from the literature summarized in this subsection are as follows:

  • there appears to be a negative exponential relationship between the aggregate EROI of oil production and oil prices;
  • there appears to be a comparable relationship between EROI and the potential profitability of oil-producing firms;
  • the relationship between EROI and profitability appears to become nonlinear as the EROI declines below 10;
  • the minimum oil price needed to increase global oil supply in the near-term is comparable to that which has triggered economic recessions in the past.

Understanding the relationship between energy return on (energy) investment and net energy

The mathematical relation between EROI, net energy and gross energy can be used to explain why, at around an EROI of 10, the relation between EROI and most other variables, such as price, economic growth and profitability, becomes nonlinear. The following equation describes the relation between EROI, gross and net energy [3]:

Equation 3.2 net energy = gross energy (1 – 1/ EROI)

Figure 3. Oil price as a function of EROI. The lines on the figure correspond to various rates of monetary return on investment (MROI). (Adapted from King & Hall [13].)

Figure 3. Oil price as a function of EROI. The lines on the figure correspond to various rates of monetary return on investment (MROI). (Adapted from King & Hall [13].)

 

 

 

 

 

 

 

 

 

 

 

Using this equation, we can estimate the net energy provided to society from a particular energy source or (rearranging) the amount of gross energy required to provide a certain amount of net energy [52].

We can interpret equation (3.2) as follows:

  • an EROI of 10 delivers to society 90% (1 – .2 = 90%) of the gross energy extracted as net energy
  • an EROI of 5 will deliver to society 80% (1 – .2 = 80%)
  • an EROI of 2 will deliver only 50% (1 – .5 = 50%).

This exponential relation between gross and net energy means that there is little difference in the net energy provided to society by an energy source with an EROI above 10, whether it is 11 or 100, but a very large difference in the net energy provided to society by an energy source with an EROI of 10 and one with an EROI of 5. This exponential relation between gross and net energy flows has been called the ‘net energy cliff’ [53]and it is the main reason why there is a critical point in the relation between EROI and price at an EROI of about 10 (figure 4).

Figure 4. The 'net energy cliff' graph, showing the relation between net energy and EROI. As EROI declines, the net energy as a percentage of total energy extracted declines exponentially. Note that the x-axis is in reverse order. (Adapted from Mearns [53].)

Figure 4. The ‘net energy cliff’ graph, showing the relation between net energy and EROI. As EROI declines, the net energy as a percentage of total energy extracted declines exponentially. Note that the x-axis is in reverse order. (Adapted from Mearns [53].)

Calculating the minimum energy return on (energy) investment at the point of energy acquisition for a sustainable society

‘The true value of energy to society is the net energy, which is that after the energy costs of getting and concentrating that energy are subtracted.’ H. T. Odum [6]

According to equation (3.2), as EROI declines, the net energy provided to society declines as well, and, at some point, the amount of net energy will be insufficient to meet existing demand.

The point at which the EROI provides just enough net energy to society to sustain current activity represents the minimum EROI for a sustainable society.

But estimating empirically the actual minimum EROI for society is challenging. Hall et al. [24] estimated that the minimum EROI required to sustain the vehicle transportation system of the USA was 3. Since their calculation included only the energy costs of maintaining the transportation system, it is reasonable to expect that the minimum EROI for society as a whole could be much higher.

Exploring the minimum EROI for a sustainable society is beyond the scope of this paper. Instead, I will examine how, in theory, the minimum EROI could be calculated by using some simple models. I will first do this by examining how the idea of net energy grew from analyzing the energy budgets of organisms.

The energy that an organism acquires from its food is its gross energy intake. Let us assume, for simplicity’s sake, that an organism consumed 10 units of gross energy, but to access this food it expended 5 units of energy. Given these parameters, the EROI is 2 (=10/5) and the net energy is 5. It is important to note that the expended energy created an energy deficit (5 units) that must be repaid from the gross energy intake (10 units) before any growth, for example, in the form of building fat reserves or reproduction, can take place.

An economy also must have an influx of net energy to grow. Let us assume that Economy A produces 10,000 units of energy at an EROI of 10, which means that the energy cost of acquisition is 1,000 units and the net energy is 9,000. Like organisms, economies also have energy requirements that must be met before any investments in growth can be made. Indeed, researchers are now measuring the ‘metabolism of society’ by mapping energy consumption and flow patterns over time [54]. For example, economies must invest energy simply to maintain transportation and building infrastructure, to provide food and security, as well as to provide energy for direct consumption in transportation vehicles, households and business, etc. The energy flow to society must first pay all of these metabolic energy costs before enabling growth, such as constructing new buildings, roads, etc.

Building off this idea of societal metabolism, we can gain additional insight into the relationship between EROI and economic growth by differentiating between 3 main uses of energy by society:

  1. Metabolism, which could be described as the energy and material costs associated with the maintenance and replacement of populations and capital depreciation (examples include food consumption, bridge repair or doctor visits)
  2. Consumption: the expenditure of energy that does not increase populations or capital accumulation and is not necessary for metabolism (examples include purchasing movie tickets or plane tickets for vacation; in general, items purchased with disposable income)
  3. Growth, the investment of energy and materials in new populations and capital over and above that necessary for metabolism (examples include building new houses, purchasing new cars, increasing populations).
Figure 5. (a-d) Flow diagrams relating net energy, EROI and gross energy production for a hypothetical Economy A. Each diagram describes the energy flows according to a different EROI, where the EROI is (a) 10, (b) 5, (c) 2 and (d) 1.5

Figure 5. (a-d) Flow diagrams relating net energy, EROI and gross energy production for a hypothetical Economy A. Each diagram describes the energy flows according to a different EROI, where the EROI is (a) 10, (b) 5, (c) 2 and (d) 1.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 5 (a-d) illustrates how the flows of energy to the three categories change as EROI declines. Let us assume that the metabolism of Economy A requires the consumption of 5000 units of energy per year. So, of the 10,000 units of energy extracted, 1,000 must be reinvested to produce the next 10,000, and another 5,000 are invested to maintain the infrastructure of Economy A. This leaves 4,000 units of net energy that could be invested in either consumption or growth (figure 5a).

As society transitions to lower EROI energy sources, a portion of net energy that was historically used for consumption and/or growth will be transferred to the energy extraction sector. This transfer decreases the growth and consumption potential of the economy. For example, let us assume that, as energy extraction becomes more difficult in Economy A, it requires an additional 1,000 units of energy (2,000 total) to maintain its current production of gross energy, decreasing the EROI from 10 to 5 and the net energy from 9,000 to 8,000. If the metabolism of the economy remains at 5,000 units of energy, Economy A now has only 3,000 units of energy to invest in growth and/or consumption (figure 5b).

If the EROI for society were to decline to 2, the amount of energy that could previously be invested in growth and consumption would be transferred completely to the energy extraction sector. Thus, given the assumed metabolic needs of Economy A in this example, an EROI of 2 would be the minimum EROI needed to provide enough energy to pay for the current infrastructure requirements of Economy A, or, to put it another way, an EROI of 2 would be the minimum EROI for a sustainable Economy A. If the EROI were to decline below 2, for example in some biofuel systems [31], then the net energy provided to society would not be enough to maintain the infrastructure of Economy A, resulting in physical degradation and economic contraction (figure 5d).

There are a few caveats to this discussion of the minimum EROI that need to be addressed. First, it is important to remember that this is a simple example with hypothetical numbers, and, as such, the minimum EROI for our current society is probably, and maybe substantially, higher. Second, over time, efficiency improvements within the economy can mitigate the impact that lower EROI resources have on economic growth by increasing the utility of energy. That said, the exact relation between energy efficiency improvements and declining EROI is yet to be determined. Third, the model assumes that metabolic needs will be met first, then consumption and growth. This may not necessarily be the case.

It is quite possible that there could be growth at the expense of meeting metabolic needs. Likewise, we can consume at the expense of growth or metabolism. Either way, the net energy deficit that results from declining EROI will become apparent in one of the three sectors of energy use.

The gross energy requirement ratio

‘Now, here, you see, it takes all the running you can do, to keep in the same place.’ The Red Queen, in Through the looking-glass [55,p.15]

Another way to explore the impact that a decline in EROI can have on net energy flows to society is to consider the ‘gross energy requirement ratio’ (GERR). The GERR indicates the proportional increase or decrease in gross energy production that is required to maintain the net energy flow to society given a change in the EROI of the energy acquisition process. The GERR is calculated by dividing the gross energy requirement (GER) of the substitute energy source by the GER of the reference energy source.

The GER is the minimum amount of gross energy production required to produce one unit of net energy.

Both of these equations are outlined below [2]:

 

Equation 5.1 GER(X) = EROI(X) / EROI(X) – 1

Equation 5.2 GERR = GER(X) / GER(REF)

The GERR is most useful when examining how transitioning from high to low EROI energy sources will impact the net energy flow to society. For example, the average barrel of oil in the USA is produced at an EROI of roughly 11 [9]. Using equation (5.1), an EROI of 11 results in a GER of 1.1, i.e. 1.1 units of gross energy must be extracted to deliver 1 unit of net energy to society, with the 0.1 extra being the amount of energy required for the extraction process. For comparison, delivering one unit of net energy from an oil source with an EROI of 5 would require the extraction of 1.25 units of oil. If conventional oil at an EROI of 11 is our reference GER, and our substitute energy resource has an EROI of 5, then the GERR is 1.14. This GERR value indicates that, if society were to transition from an energy source with an EROI of 11 to one with an EROI of 5, then gross energy production would have to increase by 14% simply to maintain the same net energy flow to society. The net effect of declining EROI is to increase the GERR, requiring the extraction of larger quantities of gross energy simply to sustain the same net energy flow to society (figure 6).

Implications for the future of economic growth

The implication of these arguments is that, if we try to pursue growth by using sources of energy of lower EROI, perhaps by transitioning to unconventional fossil fuels, long-term economic growth will become harder to achieve and come at an increasingly higher financial, energetic and environmental cost.

Figure 6. The GERR as a function of declining EROI. In this example, the reference EROI was 11. As such, the GERR value associated with an EROI of 4 represents the proportional increase in gross energy required to deliver one unit of net energy if society transitioned from an energy source with an EROI of 11 to one with an EROI of 4.

Figure 6. The GERR as a function of declining EROI. In this example, the reference EROI was 11. As such, the GERR value associated with an EROI of 4 represents the proportional increase in gross energy required to deliver one unit of net energy if society transitioned from an energy source with an EROI of 11 to one with an EROI of 4.

Revolutionary technological advancement is really the only way in which unconventional oil can be produced with a high EROI, and thus enhance the prospects for long-term economic growth and reduce the associated financial, energetic and environmental costs. This technological advancement would have to increase the energy efficiency of unconventional oil extraction or allow for increased oil recovery from fields discovered already [56]. Alternatively, there could be massive substitution from oil to high EROI renewables such as wind or hydropower [57].

It is difficult to assess directly how much technological progress is being or will be made by an industry, but we can get a glimpse as to how the oil industry is faring by comparing how production is responding to effort. If new technological advancements, such as hydraulic fracturing and horizontal drilling, represent the types of revolutionary technological breakthroughs that are needed, then we should at least see production increasing relative to effort. The data, however, do not indicate that this is the case. From 1987 to 2000, when the US oil industry increased the number of rigs used to produce oil, there was, as expected, a corresponding increase in the amount of oil produced (figure 7 not shown, see paper). But from 2001 to 2012 the trend shows very little correlation between drilling effort and oil production.

Biofuels are the only currently available non-fossil substitute for oil that is being produced at any sizable scale, but factors such as economic cost, land-use requirements and competition with food production restrict their potential contribution (see [58]). Most importantly, the EROI of most large-scale biofuels5 is between 1 and 3 [30,31], which means that we would be substituting towards a fuel that is even less useful, from a net energy perspective, for long-term economic growth. Others claim that substituting towards renewable electricity is the key; for example, Jacobson & Delucchi [59] argue that wind and solar energy could power global society by 2030. Even if their analysis stands up to scrutiny (and some claim that it does not [60,61]), the high price of oil in the transition period may provide a significant constraint on economic growth. Without high levels of economic growth, the investment capital needed to build, install and operate renewable energy will be hard to acquire.

The other option is to construct coal-to-liquids (CTL) or gas-to-liquids (GTL) operations, but even these solutions have their own difficulties (see [62]). For example, both CTL and GTL operations represent an energy conversion process, not an energy extraction process, which, in terms of EROI, simply adds to the cost of producing the final fuel and lowers the overall EROI. CTL and/or GTL will most probably lead to a significant increase in GHG emissions [63]. For GTL, there is a narrow window of low gas prices and high oil prices in which the GTL process can remain profitable [63]. Achieving profitability is easier in a CTL operation because of cheap coal, but the future availability, quality and cost of that resource is also becoming uncertain [64]. And, again, it will most probably be decades until any sizable portion of global demand for oil is met from a series of GTL or CTL plants, and in the mean-time economies will still be struggling to grow in a high oil price, low oil EROI environment.

Lastly, increasing oil production from low EROI resources is expected to degrade the global environment at an accelerated rate, for two main reasons. First, on average, the environmental impact per unit of energy is larger for unconventional oil than for conventional oil. GHG emissions, for example, are somewhere between 15% and 60% higher for gasoline and diesel produced from tar sands when compared to that produced from conventional petroleum [65,66]. Similarly, the water used per unit of energy produced is also much higher for most low EROI sources of energy [67]. Second, declining EROI increases the GERR. As society switches to lower EROI resources, simply maintaining the flow of net energy to society will require a proportionally larger amount of gross energy extraction, thus increasing the environmental impact associated with that extraction. This evidence indicates that the environmental impacts of energy extraction are most probably related exponentially to EROI, mimicking the relation between EROI and price (figure 8). This relationship holds as long as the flow of net energy to society remains the same or even increases despite a decrease in EROI. The relationship weakens if, when met with lower EROI resources, we simply decrease our effort in energy acquisition, i.e. embrace conservation.

The ecology of societal succession

‘Energy fixed tends to be balanced by the energy cost of maintenance in the mature or “climax” ecosystem.’ E. P. Odum [68]

Societal succession from the beginning of the Industrial Revolution to today mimics ecosystem succession in important and illuminating ways. The early stages of ecosystem development are marked by rapid growth (figure 9a), where the energy fixed through photosynthesis (gross photosynthesis) is greater than the energy consumed through respiration, resulting in a gain of net energy in the ecosystem. This gain in net energy leads to the accumulation of biomass (the energy equivalent of biomass in the context of society is embodied energy). As Odum [68] observed, as succession occurs, the gross photosynthesis of the ecosystem tends to balance with respiration as the steady-state, or ‘climax’, successional stage is reached. In other words, in the climax stage, almost all of the energy fixed by the ecosystem is used in maintenance respiration by the biomass that has accumulated over the years.

The simple diagram of forest succession (figure 9a not shown)is reflected by societal succession (figure 9b not shown)since the beginning of the Industrial Revolution until today. Figure 9 shows how gross photosynthesis is equivalent to humanity’s gross energy production-i.e. the total biomass, coal, oil, natural gas, etc. produced each year. Forest respiration is the equivalent of societal metabolism-i.e. the energy and material costs associated with the maintenance and replacement of populations and capital depreciation. The accumulation of biomass is the equivalent of societal growth-i.e. investments in populations and infrastructure that will increase overall societal metabolism. Lastly, the net energy provided to society is that left after accounting for the metabolic needs of society (i.e. net energy = gross energy production – societal metabolism). Historically, we have simply found and produced more energy as the metabolism (i.e. energy demand) of society grew. Indeed, the exponential increase in global economic output over the past 200 years is highly correlated with the same exponential increase in energy consumption (figure 10).

The question is: can global society continue to produce enough energy to outpace the increased metabolic requirements of a growing, and now very large, built infrastructure? Answering this question for each energy source is clearly beyond the scope of this paper, but the answer for oil seems clear, as the production of conventional oil seems to have peaked in 2008 [71], and both unconventional oil and other feasible substitutes have a much lower EROI. Both of these factors are likely to place contractionary pressure on the global economy by decreasing the flow of net energy to society.

The main difference between society and nature, in terms of figure 9, is in the reason for the peak and initial decline in gross energy acquisition. In forests and other natural ecosystems, the amount of gross photosynthesis declines and reaches parity with respiration as the forces of competition and natural selection create a steady-state, or ‘climax’, ecosystem. These forces exist also for society, but they are in the form of declining EROI, geological depletion, environmental degradation, climate change, water pollution, air pollution, land-cover change and such, and all the other factors that are occurring today that make it harder and harder to produce energy easily. In the end, ecosystems are able to successfully transition from a growth-oriented structure to a steady state; it is unclear whether society will be able to do the same.

Figure 10. GDP as a function of energy consumption over the past 200 years. (Adapted from Kremmer [69] and Smil [70].)

Figure 10. GDP as a function of energy consumption over the past 200 years. (Adapted from Kremmer [69] and Smil [70].)

 

Summary

The concept of energy return on investment (EROI) was born out of ecological research in the early 1970s, and has grown over the past 30 years into an area of study that bridges the disciplines of industrial ecology, economics, ecology, geography and geology, just to name a few. The most recent estimates indicate that the EROI of conventional oil is between 10 and 20 globally, with an average of 11 in the USA.

The future of oil production resides in unconventional oil, which has, on average, higher production costs (in terms of both money and energy) than conventional oil, and should prove in time to have a (much) lower EROI than conventional oil. Similar comments apply to other substitutes such as biofuels. The lack of peer-reviewed estimates of the EROI of such resources indicates a clear need for further investigation.

Transitioning to lower EROI energy sources has a number of implications for global society.

  1. It will reallocate energy that was previously destined for society towards the energy industry alone. This will, over the long run, lower the net energy available to society, creating significant headwinds for economic growth.
  2. Transitioning to lower EROI oil means that the price of oil will remain high compared to the past, which will also place contractionary pressure on the economy.
  3. As we try to increase oil supplies from unconventional sources, we will accelerate the resource acquisition rate, and therefore the degradation of our natural environment.

It is important to realize that the problems related to declining EROI are not easily solved. Renewable energy may indeed represent the future of energy development, but renewables are a long time off from displacing oil. Lastly, it seems apparent that the supply-side solutions (more oil, renewable energy, etc.) will not be sufficient to offset the impact that declining EROI has on economic growth. All of this evidence indicates that it is time to re-examine the pursuit of economic growth at all costs, and maybe examine how we can reduce demand for oil while trying to maintain and improve quality of life. A good summary of these problems is also given in Sorrell [72].

For society, we can either dictate our own energy future by enacting smart energy policies that recognize the clear and real limits to our own growth, or we can let those limits be dictated to us by the physical constraints of declining EROI. Either way, both the natural succession of ecosystems on Earth and declining EROI of oil production indicate that we should expect the economic growth rates of the next 100 years to look nothing like those of the last 100 years.

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