U.S. Senate hearing on our aging water infrastructure

[ Even though conventional oil production has been on a plateau since 2005, there is no sense of alarm or urgency to try to fix infrastructure before oil is rationed and not enough exists to replace or repair it. Some day people will ask why energy was used to build skyscrapers, keep roads smooth as a babies bottom in the empty deserts of Nevada, and a million other non-essential uses, instead of fixing dams and replacing century old water delivery systems.  After all, if our hydroelectric dams fall apart, there won’t be any electricity to power the elevators in Trump towers, without water delivery systems we’ll all be drinking lead, giardia and cholera laced water, grow less food as irrigation systems fall apart, be unable to transport goods on inland rivers as locks fail, be unable to cool power plants and have to shut them down, or treat and get rid of sewage wastes.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation, 2015, Springer]

USEPA. April 2010. Aging Water Infrastructure. U.S. Environmental Protection Agency, EPA Science matters newsletter Vol 1 #1

USEPA. April 2010. Aging Water Infrastructure. U.S. Environmental Protection Agency, EPA Science matters newsletter Vol 1 #1

Senate 113-225. July 25, 2013. Aging Water Infrastructure. United States Senate hearing, 68 pages.


BRIAN SCHATZ, U.S. SENATOR FROM HAWAII.  Today the Subcommittee on Water and Power is holding an oversight hearing on aging water infrastructure in the United States. In 2008 this subcommittee held a similar hearing and we learned then that the maintenance backlog for the Bureau of Reclamation’s water facilities alone exceeded $3.2 billion. Unfortunately this situation hasn’t improved much in the last 5 years. In fact we just witnessed a near disaster right here in the Nation’s capital when water in Prince George’s County was nearly shut off to tens of thousands of residents during the hottest week of the summer due to an aging water main that was about to collapse. This incident has brought much needed attention to today’s hearing topic.

Just this year the American Society of Civil Engineers gave the United States a D or worse for nearly every water infrastructure category on its report card. This is not acceptable because the impacts of a failing water system can be profound. Dam failures pose a significant risk to the safety of our communities and deteriorating water treatment facilities can lead to water borne illnesses.

The Bureau of Reclamation is the Nation’s largest wholesale water supplier serving more than 31 million people, providing irrigation water for 10 million acres of farm land and is the second largest producer of hydroelectric power in the West.

The Army Corps of Engineers maintains over 700 dams with 353 hydropower generating units that can provide up to 25 percent of our country’s hydropower.

As Chair of this subcommittee I often think about the connection between energy and water. The topic of aging infrastructure is a critical component of the energy/water nexus. So much of our water infrastructure is tied to energy.

Hydropower is the obvious example, but water infrastructure is also responsible for irrigation which helps to grow our biofuels and is used for cooling at power plants and used to extract and move energy resources such as coal, oil and gas. When our water infrastructure begins to break down not only do we lose water through leaky pipes, we also waste energy. So aging water infrastructure quickly becomes a topic of concern for those of us interested in the production of energy and energy efficiency.

The economic impacts of unreliable water delivery and waste water treatment services increase costs to businesses and to households. According to a report from the American Society of Civil Engineers, between now and 2020 the cumulative loss to the Nation’s GDP would be over $400 billion. Disruptions to electric generation due to aging water infrastructure will also increase the cost of electricity to those states and regions that use Federal hydropower.

Many challenges exist in managing and financing the upgrades and repairs needed to mitigate the impacts of aging water infrastructure. Further, severe weather events are increasing stresses on existing facilities. Floods will strain waste water systems and ongoing drought will mean reduced hydroelectric power generation.

LOWELL PIMLEY, Deputy Commissioner of Operations, Bureau of Reclamation, Department of the Interior

Maintaining our infrastructure is becoming more costly over time due to the conditions of some of our components, cost increases in the broader economy and the need for additional facilities, rehabilitation, replacement and extraordinary maintenance.

Most of Reclamation’s major dams, reservoirs and hydroelectric plants and irrigation systems are 60 or more years old. A facility’s age is not the sole measure of its condition, but the condition of each component really is the central factor in the long term maintenance needs of the general asset.

Our large portfolio of water resource infrastructure constantly presents new maintenance, replacement and modification challenges. The aging process will inevitably lead to increased pressure on Reclamation and our 350 operating partners’ budgets. As such Reclamation and the operating entities anticipate infrastructure maintenance needs will continue to grow over time.

We are the Nation’s largest wholesale water supplier, and the 348 reservoirs we administer have a total storage capacity of 245 million acre-feet of water. We bring water to more than 31 million customers and provide approximately 20 percent of western farmers with water to irrigate about 10 million acres of farmland. We are also the Nation’s second largest producer of hydroelectric power, generating more than 40 billion kilowatt-hours of energy each year. In the 111 years since Reclamation’s creation, the Federal government has invested almost $19 billion in original development costs for our facilities. In present value terms, the amount that the Federal government has spent to construct this infrastructure is estimated to be $94.5 billion.


The infrastructure that the Corps helps to maintain includes 705 dams, 14,700 miles of levees, 13,000 miles of coastal harbors and channels, 12,000 miles of inland waterways, 241 locks and hydropower plants at 75 sites with 353 generating units. These projects help provide protection and reduce risk to the Nation, facilitate approximately 2 billion tons of commerce to move on the Nation’s waterways and can provide up to 24 percent of the Nation’s hydropower.

Almost 60 percent of our locks are at least 50 years old. Almost half of our dams at our hydropower plants are more than 50 years old.


As the Nation’s dams, levees, divergent structures and other water resource infrastructure age, decision-makers are faced with the question of whether to operate Federal water projects under the current statutory framework or to alter existing policies to facilitate the repair, rebuilding or transfer of those assets. My testimony will focus on water resource infrastructure owned by the Federal Government. The Federal Government owns water resource facilities with a combined replacement value of about $352 billion. The Bureau of Reclamation and the Army Corps of Engineers are the principle agencies charged with constructing and maintaining these investments, many of which are more than 50 years old.

The second anticipated challenge is financing. Several assessments have concluded that aging water resource infrastructure is likely to become a greater challenge over time due to increasing repair needs and expected flat or declining appropriations

Reservoir Storage Restrictions: According to the Corps and Reclamation, at least twelve federal reservoirs are currently operating at lower storage levels than designed as a result of dam safety concerns, some of which relate to aging infrastructure;

Hydropower Unavailability and Forced Outages: According to agency data, over all hydropower peak availability over the last 10 years was down by about 7% and 9% at Corps and Reclamation units, respectively. Forced outages for both agencies were also up over this same period.

Lock Unavailability: According to Corps data, lock unavailability, which often occurs due to repairs related to deteriorating infrastructure, has increased by approximately 45% over the last 20 years in terms of the number of lock outages and has increased by almost three-fold in terms of hours of repair.


The nation’s neglect of its water resources infrastructure threatens our long-term economic vitality and our national security. This infrastructure is aging and is not being upgraded to meet the demands of this century. Much of what we do every day and many of our economic successes are tied to the availability of water infrastructure. The gradual deterioration of what was once a world class water resources infrastructure can only have deleterious effects on the nation. To this end, I would like to make some points about the aging water infrastructure of the United States:

  1. There is no question that our water infrastructure is aging and that its condition is fragile. Study after study has made this clear. The impacts from having aging infrastructure are substantial and without action they will become critical. Because most of this infrastructure is out of sight and because many fine professionals work every day to keep it operating under difficult conditions, the full extent of the challenge we face is generally not understood by government officials, businesses, and the public.
  1. Climate change will exacerbate the impacts of this aging and will increase the potential for system disruptions and collapse. Climate change could be a ‘‘tipping point.’’
  1. There is a substantial link between the production of energy and the condition of the water resource infrastructure. In many cases these linkages are overlooked or are poorly understood. Energy needs water and water needs energy.
  1. The nation must take steps to address the aging infrastructure problem. It is another case of ‘‘pay me now’’ or ‘‘pay me a lot more later.’’ A failure to act on aging infrastructure will have serious consequences now and will increasingly burden our children and grandchildren. Delay only drives up costs. Priorities must be established based on the risks to public safety and the national economy. A fix-as-fails approach is unsustainable and short sighted.


The nation’s water infrastructure is found in every city and village across our land. It is the dams that provide storage for floodwaters, water supply, recreation, hydropower, downstream navigation, and environmental stewardship. It is in the engineered rivers that carry millions of tons of cargo from farm fields, fuel extraction, and factories to ports and facilities and that drive domestic and international trade. It is the irrigation canals that carry millions of gallons of water to many of the same farm fields. It is the levees, coastal barriers and other flood mitigation activities that provide security for those living in areas at risk of flooding and hurricanes.

The extent of this infrastructure becomes apparent in examining the statistics on the numbers and nature of structures. However, true appreciation emerges in recognizing the diversity behind these numbers. Dams vary in size from the giant (Grand Coulee) to the small (local recreation dams). Major locks and dams on the Mississippi provide 1200 foot chambers for transiting vessels, while small facilities facilitate commerce and recreation on rivers like the Monongahela and the Ouachita. Water and wastewater treatment facilities serve millions of our citizens in metropolitan areas but also provide support to the residents of small villages.

The statistics describe a massive national asset base:

  1. 87,000 dams in the National Inventory of Dams and tens of thousands smaller dams that are not. The average age of the 87,000 dams is 52 years. Of 14,000 high hazard dams, 2000 are deficient. More than half of the 2525 hydroelectric dams regulated by the Federal Energy Regulatory Commission (FERC) are older than 80 years.
  2. At least 40,000 miles of levees. Because, in the case of many levees, the current structures were built on top of or integrated within earlier structures, it is difficult to accurately determine their ages. The legacy of many of the major structures dates to the late 19th or early 20th century. Reports by FEMA and the US Army Corps of Engineers indicate serious deficiencies in many of the structures.
  3. 8,116 miles of irrigation canals for which the federal government is responsible and thousands of miles of canals operated by local sponsors.
  4. 54,000 community drinking water systems with over one million miles of pipe. In 2002, EPA estimated that by 2020 the useful life of 9% of the nation’s drinking and waste water piping will have expired and 36% will be in poor or very poor condition. There are some 240,000 water main breaks each year. Even the National Capital Region is not immune.
  5. 14,780 municipal waste water treatment facilities. The normal life span of such facilities varies by type but is in the range of 25 years for mechanical-electrical components and 50 years for structures. As with drinking water piping, there is no national inventory of wastewater piping but estimates range from 700,000 to 800,000 miles, much of which was installed immediately following World War II and its now at the end of its useful life.  The growing need to develop adequate storm water capacity adds to the challenge. (Capacity limitations of 19th century storm water drainage caused a significant flood in the Washington DC Federal triangle in 2006
  6. 12,000 miles of commercially navigable channels, with over 200 lock chambers.8 More than 50% of the locks and dams have exceeded their design life, and many are over 70 years old.
  7. 300 commercial harbors and 600 smaller harbors. The viability of these facilities is a function of the maintenance of adequate channel and harbor width and depth. The growing size of modern vessels exceeds the current depths of many coastal ports and inadequate dredging has reduced the capacity of many inland ports.

Grading the condition of the water infrastructure

Every four years, ASCE sends the nation a Report Card for America’s Infrastructure, which grades the current state of its national infrastructure on a scale of A through F. In 2013, ASCE’s most recent Report Card gave the nation’s infrastructure an overall grade of D+, a slight rise from the 2009 Report Card.

In the water arena all categories were rated at D or below except for ports which were rated C l. ASCE indicates that since 1998, grades in all categories have been near failing primarily due to delayed maintenance and underinvestment.

The cost to the nation to remediate identified deficiencies and support modernization of the national infrastructure by 2020 is in excess of $3.6 trillion.

Unfortunately, the exact condition of the infrastructure is not accurately known and aging continues. Recent reports on dams and levees indicate that in the case of levees both the exact location and condition of a substantial percentage of the national levee stock is unknown. In the case of dams, lack of funding for inspections and differences among standards applied by states call into question the uniformity and arguably the reliability of the assessments that are made. Some dams such as those related to mine tailings receive only cursory review emphasizing only the potential risks to miners and not necessarily to surrounding communities. Water and wastewater systems are buried, and even with sophisticated technologies, accurate assessment of their condition is difficult and costly to obtain.

Much of the national water infrastructure has exceeded its design life and some is approaching the century mark. Major levee failures such as those in New Orleans result in billions of dollars of damages. Dam failures in the past have resulted in significant loss of life. As was illustrated in the weeks following Superstorm Sandy, loss of water and wastewater systems can bring communities to their knees and shut down all economic activity. Offices are unable to open and factories are unable to produce. When flood structures fail or their capacity is exceeded, transportation corridors are closed and health and sanitation facilities become inaccessible.


According to the 2011 study, America’s Climate Choices, conducted by the National Research Council at the behest of U.S. Congress (P.L. 110-161), ‘‘. . .climate change is occurring, is very likely caused by human activities, and poses significant risks for a broad range of human and natural systems.’’ The study points out the potential for sea level rise and large storms to result in significant coastal erosion and for more intense rainfall to increase the probability of flooding in selected areas around the nation. The study notes that these threats make it ‘‘prudent to design the infrastructure for transportation, water, and utilities to withstand a range of weather extremes including intense rainfall flooding and drought scenarios. . .

  • A Federal Advisory Committee Draft Climate Assessment14, released earlier this year, found that:  ‘‘Summer droughts are expected to intensify in most regions of the U.S., with longer term reductions in water availability in the Southwest, Southeast, and Hawai’i [sic] in response to both rising temperatures and changes in precipitation.
  • Floods are projected to intensify in most regions of the U.S., even in areas where average annual precipitation is projected to decline, but especially in areas that are expected to become wetter, such as the Midwest and the Northeast.
  • Expected changes in precipitation and land use in aquifer recharge areas, combined with changes in demand for groundwater over time, will affect groundwater availability in ways that are not well monitored or understood.
  • Sea level rise, storms and storm surges, and changes in surface and groundwater use patterns are expected to challenge the sustainability of coastal freshwater aquifers and wetlands.’’
  • The assessment also reports that the ‘‘reliability of water supplies is being reduced by climate change in a variety of ways that affect ecosystems and livelihoods in many regions. . ..’’

The 2012 report by a task committee of the Intergovernmental Panel on Climate Change, Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation, identifies many of the same impacts.

Growth in population will also influence the need for infrastructure activity. The U.S. Census Bureau currently projects that the population of the United States will increase by 27%, 85 million, between now and 2050.  This growth will increase the need for expansion and upgrading of much of the water infrastructure and, as indicated below, will increase the number of people at risk to floods and coastal storms. The aging infrastructure may well be both too old and too small.

In June 2013, the Federal Emergency Management Agency released a report indicating the increases in potential flooding across the United States that could result from climate change and population growth between now and 2100.16 ‘‘For the [contiguous US] riverine environment, the typical 1% annual chance floodplain area nationally is projected to grow by about 45%, with very large regional variations. The 45% growth rate is a median estimate implying there is a 50% chance of this occurring. . . 30% of these increases in flood discharge, SFHA, and base floodplain depth may be attributed to normal population growth, while approximately 70% of the changes may be attributed to the influence of climate change. . . for the coastal environment, under the assumption of a fixed shoreline, the typical increase in the coastal SFHA is projected to also be about 55% by the year 2100, again with very wide regional variability. The 55% increase is a median estimate so there is a 50- percent chance of this occurring.’’ Figure 3 provides the geographic distribution of these changes.

Climate and population change will have direct effects on our aging water infrastructure. Structures designed to protect against current or past flooding and coastal erosion threats may not be able to stand up against the forces of larger events or deal with the increased magnitude of these events. Increases in population, will in many cases require current water and wastewater systems to be not only upgraded but also to be sized to the increased demands that will be expected. Additional surface or subsurface storage may be required and older facilities may not be in a position to be modified or expanded. Major storm flows, which are currently stressing many of existing dams and levees, may increase even more under climate change and further threaten those that rely on these structures. Sea level rise is already affecting the US East and Gulf coasts.

Droughts will also increase the stress on water infrastructure. During droughts rivers run low and substantially increase the amount of dredging and other maintenance activities required in channels and at ports. Droughts result in severe stress on water supply systems, whether for agricultural or municipal and industrial use. They also increase the pressure for additional storage or expansion of the water supply storage in existing facilities.


There is a substantial link between water and energy. This should be recognized and addressed in in plans to deal with aging water infrastructure.

In 2012, the heads of 15 of the world’s largest National Academies met in to discuss important scientific issues facing the world community.  The ‘‘Energy and Water Linkage: Challenge to a Sustainable Future’’ was one of three topics addressed by the group. Following the meeting, in which I was fortunate enough to participate as a facilitator, the Academy heads signed a statement identifying the issues they had discussed. In this statement, they reported that:

  • Needs for affordable and clean energy, for water and adequate quantity and quality, and for food security will increasingly be the central challenges for humanity: these needs are strongly linked. . . It is critically important that planning and investment in energy and water infrastructure and associated policies take into account the interaction between water and energy. A systems approach based on specific regional circumstances and long-term planning is essential. Viewing each factor separately will lead to inefficiencies, added stress on water availability for food protection and for critical ecosystems, and a higher risk of major failures or shortages in energy supply.’’
  • They also noted that energy production requires water and that the production of water supplies in adequate amounts and quality requires energy. They pointed out that fossil fuel and nuclear power plants and solar thermal require large water withdrawals and some water consumption and indicated that even use of ‘‘increasingly important ‘unconventional sources’ such as tar sands gas hydrates in gas and oil and tight formations have substantial implications for quantity and quality of water. . .producing alternative transportation fuels, in particular biofuels. . . can involve substantial impacts on water resources and water quality’’ .

Our aging inland waterway infrastructure also has a significant tie to energy production. Twenty-two percent of the nation’s energy products are carried on inland waterways barges that are energy efficient. Inland waterways separate potentially volatile cargo from heavily populated areas. Operating as part of the national intermodal transportation system, waterways also provide alternative routes should problems occur with energy product movement on parallel systems such as pipelines and rail, increasing the resilience of the overall system and the resultant national security.

Hydropower production, although providing only 8 to 12 percent of the national energy pool, provides critical services in many parts of the country. 20th century development in the Tennessee Valley and in the Columbia basin relied on use of low cost hydroelectric power. Many communities are reliant on hydropower for base supply and many others for the peaking power necessary to meet electricity needs during periods of high demand. Many of the nation’s hydropower facilities are aging and, although carefully supervised by the Federal Energy Regulatory Commission and state agencies, require substantial and continuous attention. Again, where rate setting becomes political instead of true cost based, funding challenges will develop.


Filling the information gaps As a follow-up to Katrina, in 2009 a congressionally directed National Committee on Levee Safety reported that considerable attention needed to be paid to the development of an inventory of the nation’s levees and their conditions. Some work has been accomplished by the U.S. Army Corps of Engineers and FEMA in addressing levees under their oversight but the work is far from complete and no action has been taken by the Congress on recommendations of the National Committee on Levee Safety. The condition of tens of thousands of miles of levees in the US has yet to be assessed and many of these levees have yet to be precisely located.

Information about the condition of only 75% of the 87,000 dams has become part of a national inventory of these structures. We know where the dams are located and if their failure would pose a threat to those below the dams, but we have yet to complete thorough assessments of the condition of all dams. Some of these dams date to before the Civil War. On a positive note, the condition of the approximately 4000 dams under federal oversight has, for the most part been assessed and continues to be monitored, even if funds to deal with identified problems cannot be fully addressed. Four percent of dams are federally owned and the Federal Energy Regulatory Commission (FERC) provides oversight of an additional 2525 private and public dams.19 In 2007, Section 2032 of the Water Resources Development Act (PL 110-114) directed the President to, within two years, conduct an analysis of the vulnerability of the nation to flooding.

Such an analysis would identify the exposure—what is in the path of a potential flood or storm surge—and the vulnerability of affected communities to such events. Vulnerability reflects the ability of existing flood protection infrastructure to carry out the functions for which it was designed. No funds have been appropriated by Congress for this activity, in the nearly six years since the law was passed and, as a result, no analysis has taken place.

The Environmental Protection Agency has invested resources in gathering information about the condition of water and wastewater infrastructure and has prepared reports that identify the challenge the nations faces in drinking and waste water. Such analyses however represent only estimates and given that much of the infrastructure is below ground, there is considerable uncertainty with the completeness of the survey information.

The inland waterway community has suggested raising the tax on fuel use by their vessels to increase the amount of funding available in the Inland Waterway Trust Fund to carry out needed infrastructure renewal. Legislation to this end is currently being considered in the Water Resources Development Act, but even this self-taxing has opponents who see it as a violation of the ‘no new taxes’ principle.

Much of the infrastructure for ports and harbors is privately or non-federal government owned as opposed to being supported by the federal government. Various approaches have been used to successfully modernize the on-land infrastructure necessary to operate the ports. Funding of dredging to maintain channel depth and width is shared by the federal government and local sponsors and, where the federal government does not have plans for its share of the work, local sponsors must either assume the entire cost or live with the consequences of inefficiently sized channels.

Similarly a large percentage of dams are privately or non-federally owned. There are a few state loan or grant funding sources to rehabilitate dams and some federal funding through the Department of Agriculture Natural resources Conservation Service, but these funds usually only support state or municipally owned dams. Private owners, even the most conscientious ones, typically do not have the funding needed to do necessary safety upgrades.


The nation is faced with an aging water resources infrastructure and with resource significant requirements to properly maintain and upgrade this infrastructure, and to adapt it to the potential impacts of climate change and growth. Unless there are significant and rapid changes in the national economy and adjustment of long-standing responsibilities, it is unlikely that the federal government will be in a position to fund the needed maintenance, rehabilitation and upgrades. It is more likely that new approaches will have to be taken and that much of the burden will continue to rest at the local level. This fact must be recognized by all concerned.


Continuing to believe or to support beliefs that somehow enormous sums of money will be found by the federal government to completely eliminate this significant national backlog in the infrastructure is unrealistic and support of this belief is unethical. For example, the Senate version of the Water Resources Development Act contains provisions that would provide local levee districts access to $300 million annually for levee repairs. Given that the maintenance backlog is estimated to be over $50 billion, it would be foolish for levee districts across the country to believe that all they need do is wait until their turn for funding to deal with the infrastructure deficiencies they currently face. Similarly, putting off other actions such as price rises for services in the hope that they may later be found to be necessary, is unrealistic and deceptive. It should be made clear that federal resources that are available will go to those facilities where there is the highest national interest and need and where the return on investment is highest and the greatest risks to life and property exist.

The nation must take steps to address the aging infrastructure problem. A failure to act on aging infrastructure will have serious consequences now and will increasingly burden the future.

CHARLES KIELY, Assistant General Manager, District of Columbia Water & Sewer Authority 

DC Water serves the more than 17 million people who live, work and visit the District every year. We maintain and operate 1,350 miles of water pipe, over 3,700 valves, 4 pump stations, 5 reservoirs, 3 elevator water tanks, more than 9,300 public hydrants that deliver our current water across Washington, DC. The median age of the water system is over 78 years old with some pipes in service today that were installed before the American Civil War.

Once that water is used it is returned to our sewer system that is even older than the water system with a median age of 85 years old. The sewer system has 1800 miles of separated and combined water and storm water lines, 9 base water pumping stations, 16 storm water pumping stations, 12 inflatable dams and a swirl facility. The existing sanitary sewer system in the District dates back to 1810.

I have with me an actual section of tuberculated, unlined, cast iron main that we frequently encounter on our drinking water system to bring to the surface what lies deep along the ground in many areas across the country. Tuberculation is the cause of corrosion materials inside the pipe that accumulate over time. As these deposits grow they restrict the flow of water for everyday use and fire suppression. The tuberculated deposits can also impact the quality of the water we deliver and they promote microbiological activity and can cause discolored water and can also impact disinfection. This aging infrastructure that delivers water and sewer services is a vital resource to every home, business and facility in the District, including the Capitol. Our work also affects vital ecosystems and our rivers and waterways. Balancing the delivery of service, improvements in treatment and the cost to ratepayers is one of the largest challenges facing DC water today.

We are ramping up to replace 1 percent of this infrastructure per year, 3 times the rate of replacement in previous years, but still on a hundred year replacement cycle.

Unlike roads and bridges our extensive assets are very deep underground and problems can persist for many years without detection. Some may recall that DC Water was involved in emergency work recently at 14th Street where segments of the road fell down and actually collapsed the sewer that was constructed in 1897. All told the emergency repairs caused most of the intersection to be closed for 11 days.

Emergency repairs are costly and they do not rehabilitate or replace the 100-year-old assets that remain in the ground.

Moreover, extreme weather events place additional stress on the aging combined sewer system. For unusually intense rain events in the summer and fall of 2012 resulted in damaging overland flooding and sewer line backups in homes located in a section of the northeast boundary trunk sewer. This system originally constructed by the Federal Government in the late 1800s was identified as insufficient soon after its construction. More recent development and the associated increase in a previous area only exacerbated the problem.

DC Water is responsible for maintaining approximately 150,000 sewer laterals in public space and we replace approximately 400 per year. A sewer lateral is the underground pipe, typically four inches in diameter that connects the home or business to the main sewer line.

Disruptions from aging infrastructure are not limited to commercial areas downtown. Recently, an 8-inch water main break on a residential street washed out two manholes that extended 50 feet below the surface to a deep sewer. The restoration work took 31 days and ultimately cost our customers over $600,000. While the repair was taking place, DC Water had to run pumps and generators to bypass the sewer flow. The street was closed for over one month causing a major inconvenience to our customers in the neighborhood.



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The dark side of religion: how ritual human sacrifice helped create unequal societies

April 5, 2016. The dark side of religion: how ritual human sacrifice helped create unequal societies. University of Auckland, New Zealand.

Journal article: Watts, J., et al. April 14, 2016. Ritual human sacrifice promoted and sustained the evolution of stratified societies. Nature 532, 228–231

A new study finds that ritual human sacrifice played a central role in helping those at the top of the social hierarchy maintain power over those at the bottom.

“Religion has traditionally been seen as a key driver of morality and cooperation, but our study finds religious rituals also had a more sinister role in the evolution of modern societies,” says lead author of the study Joseph Watts.

Researchers from the University of Auckland’s School of Psychology, the Max Planck Institute for the Science of human History in Germany and Victoria University, wanted to test the link between how unequal or hierarchical a culture was – called social stratification – and human sacrifice.

The research team used computational methods derived from evolutionary biology to analyse historical data from 93 ‘Austronesian’ cultures. The practice of human sacrifice was widespread throughout Austronesia: 40 out of 93 cultures included in the study practised some form of ritualistic human killing.

Early Austronesian people are thought to have originated in Taiwan and, as they moved south, eventually settled almost half the globe. They spread west to Madagascar, east to Rapa Nui (Easter Island) and south to the Pacific Islands and New Zealand.

Methods of ritual human sacriifice in these cultures included burning, drowning, strangulation, bludgeoning, burial, being cut to pieces, crushed beneath a newly-built canoe or being rolled off the roof of a house and decapitated. Victims were typically of low social status, such as slaves, while instigators were usually of high social status, such as priests and chiefs.

The study divided the 93 different cultures into three main groups of high, moderate or low social stratification. It found cultures with the highest level of stratification were most likely to practice human sacrifice (67%, or 18 out of 27). Of cultures with moderate stratification, 37% used human sacrifice (17 out of 46) and the most egalitarian societies were least likely to practice human sacrifice (25%, or five out of 20).

“By using human sacrifice to punish taboo violations, demoralize the underclass and instil fear of social elites, power elites were able to maintain and build social control,” Mr Watts says.

Professor Russell Gray, a co-author of the study, notes that “human sacrifice provided a particularly effective means of social control because it provided a supernatural justification for punishment. Rulers, such as priests and chiefs, were often believed to be descended from gods and ritual human sacrifice was the ultimate demonstration of their power.”

A unique feature of the research was that the use of computational evolutionary methods enabled the team to reconstruct the sequence of changes in human sacrifice and social status over the course of Pacific history. This allowed the team to test whether sacrifice preceded or followed changes in social status.

Co-author, Associate Professor Quentin Atkinson says: “What we found was that sacrifice was the driving force, making societies more likely to adopt high social status and less likely to revert to egalitarian social structure.”

Posted in Human Nature | 1 Comment

Shale Euphoria: The Boom and Bust of Sub Prime Oil and Natural Gas

[ Yet in the United States, these house hearings have stated that the U.S. is energy independent, that shale oil and gas will give us a century of energy independence: House 112-176 in 2012, House 113-1 2013, and several others.  In fact we have so much oil and gas, that we ought to export it: House 113–131 2014.  This article explains how the middle class was fleeced yet again by Wall Street and banks.

Even though dozens of companies have gone bankrupt, they are still drilling because (Durden 2016):

  1. Daily costs for operating wells are below current spot prices. While drilling new wells is not economical, it is perfectly logical to keep exploiting existing wells. Fracked wells usually start to see a significant decline in production after about two years of operations, though bankrupt companies will see production fall, two years can be a very long time to pump.
  2. “Creditors want to extract maximum value from the company and the best way to do that …is to keep the oil flowing. Bid-ask spreads on oil assets for sale are simply too wide for most companies to be interested in selling assets while in Chapter 11. Instead, creditors maximize the present value of their assets by continuing to pump oil. This oil can either be stored leading to a large risk free profit, or it can be sold on the spot market. Either way, bankrupt producers are acting in the best interests of their creditors by continuing to pump. Unfortunately, those actions are not in the best interests of the broader industry or energy sector stock investors.
  3. Management at bankrupt producers also have little reason to do anything other than keep the crude flowing. In the current energy market, getting a job is very difficult, especially for top managers coming from a bankrupt producer. As a result, managers rationally want to make sure they stay useful in Chapter 11 and that means trying to convince creditors to keep the company operating rather than converting to a Chapter 7 liquidation. Not all O&G firms should be kept operating – some firms are better off being liquidated – but creditors often lack the necessary industry expertise to be able to distinguish between firms that have a future after emerging from Chapter 11, and those that don’t and are better off in a Chapter 7 sale. And again, management has very little incentive to put themselves out of a job by recommending Chapter 7.

Alice Friedemann  www.energyskeptic.com author of “When Trucks Stop Running: Energy and the Future of Transportation, 2015, Springer]

FEASTA. March 23, 2016. Shale Euphoria: The Boom and Bust of Sub Prime Oil and Natural Gas. Foundation for the Economics of Sustainability.

The aim of this article is to show that the shale industry, whether extracting oil or gas, has never been financially sustainable. All around the world it has consistently disappointed profit expectations.Even though it has produced considerable quantities of oil and gas, and enough to influence oil and gas prices, the industry has mostly been unprofitable and has only been able to continue by running up more and more debt.

How could this be? It seems paradoxical and defies ordinary economic logic. The answer is to be found in the way that the shale gas sector has been funded. It is part of a bubble economy inflated by monetary policy that has kept down interest rates. This has made investors “hunt for yield”. These investors believed that they had found a paying investment in shale companies – but they were really proving that they were susceptible to wishful thinking, vulnerable to hype and highly unethical practices that enabled Wall Street and other bankers to do very nicely. Those who invested in fracking are going to lose a lot of money.

A Global Picture of disappointed expectations

Around the world big expectations for fracking have not been realized. One example is Argentina where shale oil reserves were thought to rival those in the USA. It is a country where there has been local opposition while central government pushed the industry in alliance with multinational companies and its own company YPC. However profitability has been elusive. To have any hope of profitability shale development has to be done at scale to rapidly bring down costs enough to make a profit. That requires a lot of capital and companies will not make this capital available without being sure that they are going to make a lot of money – but they cannot be sure until they have done tests for up to two years.

“It’s a sort of chicken and egg dilemma. Without profits, the estimated $20 billion a year needed to develop the play won’t come. And without this investment in drilling tens of thousands of wells, the economies of scale won’t be reached on the fields to cut costs.

“A reason not to rush into production — only 400 wells have been drilled — is that wells must be tested for up to two years to gauge the potential of the shale rock before a company will commit billions of dollars. This is especially the case now that low global oil prices have slimmed investment budgets for frontier plays.” (Charles Newbury, “Struggles to cut cost delay oil production in Argentina” Platts Oilgram News. August 17th 2015 at http://blogs.platts.com/2015/08/17/cut-cost-delay-oil-play-argentina/ )

The situation in Argentina highlights the underlying problem for the economics of shale oil and shale gas. Unconventional oil and gas fields have much higher costs than conventional ones. Tapping “conventional” oil and gas from permeable geological strata is cheaper in that the oil and gas flows underground and can be pumped out with less engineering. In contrast an “unconventional gas field” has to release the gas from impermeable rock and therefore needs up to 100 more wells for the same amount of gas (or oil). A field must achieve economies of scale to have any chance of making a profit. It needs more activity underground to fracture the rock and it needs more activity on the surface to facilitate that. That is why it is more dangerous to the environment and public health – and also why it is more financially expensive. It requires more ongoing capital equipment too. Without a high gas (or oil) price all of these activities cannot be made profitable.

Looked at in this way “unconventional oil and gas” is not the magical answer for peak oil (or later for peak natural gas) that it might have once seemed to be. To be long term viable the fracking sector requires three things: favorable geology, high oil and gas prices and easy and cheap credit. All three have proven elusive, making for disappointing results in all of the locations around the world where it has been tried. Unconventional gas is struggling to get off the ground outside of the USA and Australia. And in the USA, where it started, although it managed to get the credit to pay for the capital expenditure there are now grave doubts that a mountain of credit will ever be paid pack.

But let’s look outside of the USA too. Take Europe for example. In 2011 the international oil and gas industry and the Polish government thought Poland was going to be a major source of shale gas. 75 exploratory wells were drilled up to 2015 and 25 were fracked. The amount of gas recovered was one tenth to one third of what was needed for the wells to be commercially viable. Besides retreating from Poland, the industry has pulled out of nascent shale drilling efforts in Romania, Lithuania and Denmark, usually citing disappointing yields.

In the UK and Ireland too fracking is still stuck at the pre-exploratory stage, largely because of the rapid and powerful development of a movement of opposition. Although not definitive, a moratorium in Scotland and a “presumption against” fracking by planners in Northern Ireland, are political set backs for the industry. Yet even if the public and political opposition was not there, there would be reasons to doubt that fracking is viable in the UK. The doubt starts with the geology. While the British Geological Survey has produced maps of shale layers, and while it has been suggested that the carbon content might be there, the data is lacking for other key parameters, for example for rock porosity. In addition the shale in the UK has more folds and faults when compared to US fields. This might to lead to more earthquakes which would damage the wells – plus leading to a potential failure to achieve the pressure needed for fracturing if fracking fluid leaks into small faults when pushed underground.

Oil and Gas Prices

Now there are further doubts because of low and falling oil and gas prices. Here the issues are a little different for oil compared to natural gas on the one hand and for the situation in the USA as compared to other producing zones in the world on the other. That said, what all exploration and production companies are facing, whether in oil or gas production or whether in the USA or elsewhere, is that prices that are too low. It is proving difficult or impossible for most producers to make a profit given the costs of extracting and distribution. That has been especially noticeable for shale gas. Let us however first look at oil prices.

During the crash of 2007-2008 global oil prices crashed from a high peak but then recovered again. Between November 2010 and September 2014 there were 47 months in which oil prices were over $90 a barrel. This period of high oil prices can be described as being broadly reflective of supply and demand. On the demand side the global economy recovered, to a large degree stimulated by a massive credit-fueled residential and infrastructure boom in China. This pumped up demand. On the supply side production from Libya and Iran was kept out of the world market because of the turmoil in Libya and sanctions against Iran. Thus, while there was some production increase from Saudi Arabia and, eventually, even more from Iraq, these increases were largely cancelled by Iran and Libya. Demand exceeded supply and prices remained high but the situation began to change in the autumn of 2014.

On the demand side the Chinese economy stalled while on the supply side production increased. OPEC as a whole was not the main source of that increasing production, and nor was Russia – the main source of increasing oil production was the boom in US shale oil. For reasons to be explored, production from the USA continued to soar even though prices fell and after a price rally early in 2015 prices continued to fall into 2016.

A similar downward trend has occurred around the world in natural gas prices – though in the USA they have been lower far longer – and certainly too low to allow for profitability.

In regard to gas the issues are somewhat different from oil because the market for natural gas is less globally networked. Natural gas markets are based on global regions and different gas prices in different parts of the world. Thus there is a North American gas market, a European gas market and a market in the far east. There are multiple long distance gas pipelines that are important economically and geopolitically. Wars and rivalries are fought over pipeline routes – this is a component in the Syrian conflict. However natural gas could not be transported so easily between continents – until recently, because now there is an infrastructure for sea transported liquefied natural gas under development (LNG). Sea transported LNG begins to change things because it makes the market for natural gas more globally competitive.

At a risk of simplifying a varied picture, natural gas prices in various areas have been stable at a low level or drifting downwards over the last two years and insufficient for profitability in a gas fracking sector. In both the USA and Europe natural gas prices are half of what they were in 2014. In the USA this has been because of overproduction of gas, conventional and unconventional, with conventional production declining and being replaced and overtaken by unconventional production – as of late in 2015 however shale gas production too began to fall. For years production has been unprofitable in all but the best areas and in decline. Now it is in decline generally.

In Europe production decline because of depleting conventional gas fields has not prevented a fall in the gas price because demand has been falling too and this is likely to remain the case. Thus a recent report published by the Natural Gas Programme of the Oxford Institute for Energy Studies, concludes that European gas demand will not recover its 2010 level until about 2025. The decline in demand has been due to warmer winters but also due to low demand because of the low growth in manufacturing which has shifted to Asia, because of low population growth and because of energy saving measures too. At the time of writing it is being suggested that the competitive threat from the development of an LNG infrastructure will encourage Gazprom to change its pricing strategy to try to fight off future competition from sea transported supplies. In summary, it is highly likely that the gas price in Europe will remain low for a long time. If so, this completely undermines any remaining case for fracking for natural gas in Europe, and particularly Britain.

At current gas prices all the exploration and production companies active in the UK and Ireland would struggle to make a profit. There are 4 studies of extraction costs of natural gas by fracking in the UK – by Ernst and Young, Bloomberg, Oxford Institute of Energy Studies and Centrica. All have maximum and minimum extraction costs. Current gas prices per therm are less than the minimum extraction cost in the lowest study. So for the industry to continue at all it has to assume that gas prices will rise in the future.

shale costs

Low Gas price vs high extraction costs: Zachery Davis Boren, Greenpeace Energy Desk; August 2015 http://energydesk.greenpeace.org/2015/08/20/super-low-gas-price-spells-trouble-for-fracking-in-the-uk/

So what is the future for oil and gas prices? Of course the future is inherently uncertain – a President Trump might provoke any number of wars making America great again – it is difficult to see how Muslims could be banned from entry into the USA without that affecting oil and gas imports from Muslim countries. Or again heightened conflict between Iran and Saudi Arabia might escalate with massive consequences, and not just for the oil and gas price. In these and other conceivable situations, the more chaos the less companies will want to invest anyway. Whether prices are high, or low, if there is too much turmoil conditions will not favor new investment. But leaving aside extreme geo-political scenarios will prices go up or will they go down? If oil and gas prices rise will this be sufficiently and for long enough for unconventional gas to be developed sustainably in the narrow financial or business sense?

The rising price scenario

It is important to grasp the idea that a rising prices scenario is only credible in conditions where a proportion of the industry has been driven out of the business – which is the hope of the Saudi oil industry. What the Saudis would like to see is not only the US fracking companies driven to bankruptcy but the banks that fund them with badly burned fingers and unwilling to finance the industry any more. That said the Saudis too have limited pockets. Their current aggressive foreign policy has to be funded from somewhere and it is conceivable that they could lose the capacity to push the anti-shale agenda through to the bitter end.

If the oil price does bounce back the beneficiaries would be the survivors. There is a view then that the current low prices will eventually lead, not only to falling production in the future but to bankruptcies and capital expenditure cut backs both in the conventional and unconventional sectors. It would speed the decline of oil fields like those in the North Sea where investment is now being slashed. With declining supply, inventories will be sold off, the market will move back into balance…. and then further the other way – so that eventually demand again exceeds supply. Higher prices, possibly spiking, will encourage new investment and the fracking companies will surge back at the other side of the crisis.

What must however be assumed for this to happen is that at some point “growth will resume” because, over the last 200 years, it always has. If growth resumes the demand for energy will revive in order to feed it – making more material production and consumption possible. Some economists argue that one factor encouraging a revival in demand ought to be the low energy prices themselves. Higher energy prices act as a drag on the economy so low energy prices should do the opposite – i.e. stimulate it. In a recent speech the chair of the US Federal Reserve, Janet Yellen, said that falling energy prices had, on average put an extra $1,000 in the pockets of each US citizen. It is assumed that this would encourage extra spending and thus extra income.

The falling or stagnant prices scenario

An alternative view is more skeptical about the revival of the global economy and of demand because of the high level of debt. In an economy where indebtness is low, falling energy prices probably would act as a stimulus for energy consumers. But will there be any or enough stimulus where the debt to income ratio is high? In an indebted economy windfall gains from reduced energy prices are likely to be partly used to pay off debts rather than being spent.

A further issue is what will happen because of the way in which the finance sector has made itself vulnerable? It has channeled substantial credit to the energy sector – to exploration and development companies that now have difficulties paying this credit off? It certainly will not help in finding investment money to get fracking off the ground in the UK and elsewhere if it all ends in tears in the USA.

In the pessimistic scenario, if the economy does not revive then there can be some skepticism that energy prices will revive too. This is the scenario in which deflationary conditions continue and even deepen. In this view, the global economy is entering a long period of stagnation, decline and chaos. Some economists are describing how growth has slowed using descriptive phrases like “secular stagnation”. The fate of the Japanese economy from the early 1990s onwards gives grounds for comparison and concern. After a quarter of a century Japan has not escaped prolonged recessionary conditions. Because the global economy is highly indebted central banks have driven down interest rates to zero and now even below that. This has led to a bubble in asset markets but it has done little to spur generalized economic growth.

There could be a vicious circle here – without demand arising and a sustained growth process pushing up energy prices, the profitability of the unconventional sector will never be sufficient to make future investment in that sector pay. In these circumstances future oil and gas production will not rise. Production will fall in the USA, especially as more of the identified sweet spots in the best plays are exhausted.

In textbook supply and demand theory falling supply should eventually lead, ceteris paribus, to a rise in prices that justifies more investment and therefore more production. However “ceteris paribus” (other things remaining unchanged) does not apply in a stagnating or a declining economy. A declining economy is not one where private economic actors invest money in the hope of a future return because the necessary confidence and conviction about the future is not there. Purchasing power is hoarded, purchases are deferred where possible, debts are paid off where possible. These actions tend to intensify the deflation. If this is what happens, and it seems likely, it will make the problems of the shale gas sector even worse.

The Fracking Companies and the Finance Sector

Before the current difficulties, Wall Street made a fortune in fees arranging debt finance for the US shale sector. Investors who were “looking for yield” instead of the ultra low interest rates payable on government debt thought the way to find that yield was to pile their money into junk finance to fund the frackers. Despite the economic reality Wall Street encouraged the misinvestment. Now the wall of energy sector junk finance repayable in the future is huge. The further forward one goes the higher it is. How much of this debt will ever be repaid? And what will happen to those who lent it if it is not? Given what has already been said the long run ability of the sector to repay its debt seems highly questionable. How did it come to this?

debt wall

Source: http://www.artberman.com/art-berman-shale-plays-have-years-not-decades-of-reserves-february-23-2015/

For several years prior to the crash of 2007-2008 the finance sector in the USA were knowingly giving loans to people with no income, no jobs and no assets. The people who organized this were doing so because they were earning fees on each loan arranged. What did they care about the virtual certainty that the loans would never be paid back? The crash was the inevitable result – the consequence of an ethical catastrophe. The banks had packaged the loans up into mortgage backed securities and sold them on so that someone else other than the originating bank carried the risk. Ratings agencies played their role in this crooked system and got fees rating securities that others called “toxic trash” as AAA. Meanwhile derivatives contracts against defaults on these rotten securities were also sold even though it was not possible to pay up when the defaults happened – without being bailed out by the monetary authorities, as happened with AIG.

The Shale Bubble – toxic water, toxic air and toxic finance too

For several years after 2007-2008 shale was the next big money spinner – and the next ethical catastrophe for Wall Street. Just as it was blindingly obvious for years that sub prime would crash, but it was a nice money spinner at the time, so Wall Street has made a lot of money pumping up the shale bubble. All the evidence about health and environment costs have been ignored and the information about them suppressed. The information about the economics was ignored too. Of course, someone has to lose eventually but “while the music has played” there has been plenty of money for all sorts of players – petroleum engineers and geologists, PR companies, corrupt politicians, the companies supplying the pipelines, rigs and fracking gear. They had their snouts in the money trough and in many cases abandoned their ethics and their critical faculties while they were feeding.

Nor were investors looking closely enough at where they were going or at what they were funding. Even before the current price crash, many US fracking companies, just like those in Argentina and Poland, were struggling to make real profits yet vast quantities of money were channeled to them. Honest and astute observers who could see that the shale boom was a Wall Street induced bubble were ignored. One example was a report written by Deborah Rogers in early 2013 in which she drew attention to the difference between the reality and the message put out by the PR machine.

According to Rogers “Industry admits that 80% of shale wells ‘can easily be uneconomic.’ Massive write-downs have recently occurred which call into question the financial viability of shale assets and possibly even shale companies. In one case, assets were written off for more than 50% of the purchase price within a matter of months……publicly traded oil and gas companies have essentially two sets of economics. There is what may be called field economics, which addresses the basic day to day operations of the company and what is actually occurring out in the field with regard to well costs, production history, etc.; the other set is Wall Street or “Street” economics. This entails keeping a company attractive to financial analysts and investors so that the share price moves up and access to the capital markets is assured. “Street” economics has more to do with the frenzy we have seen in shales than does actual well performance in the field. With the help of Wall Street analysts acting as primary proponents for shale gas and oil, the markets were frothed into a frenzy. Boom cycles have the inherent characteristic of optimism. If left unchecked, such optimism can metamorphose into a mania such as we saw several years ago in the lead up to the mortgage crisis. (Deborah Rogers, “Shale and Wall Street” Energy Policy Forum 2013 http://shalebubble.org/wp-content/uploads/2013/02/SWS-report-FINAL.pdf)

Long before the price slide beginning late in 2014, the much hyped boom was not what it seemed. Roger’s article shows many parallels between the crazy and unethical excesses of Wall Street prior to the 2007 crash and what has been happening in the shale boom. As had happened with subprime mortgages which were bundled up to become part of mortgage backed securities and then sold on – new kinds of financial assets were invented and sold to allow the unwary to invest their money in order as to “get a part of the action” and participate in the shale bonanza too. One bank instrumental in all of this was Barclay’s Capital, working together with a company called Chesapeake Energy. To help Chesapeake the Barclay’s financial wizards invented a structure called a Volumetric Production Payment (VPP). Rogers quotes a finance industry magazine, Risk, from March 2012.

“The main challenges in putting together the Chesapeake VPP deal were getting the structure right and guiding the rating agencies and institutional investors—who did not necessarily have deep familiarity with the energy business—through the complexities of natural gas production.”

The resulting financial assets were highly complex, off balance sheet, and as Barclay’s admitted the rating agencies had to be “guided” so that they could understand the complexities of the deal. (So much for the competence and independence of the resulting “rating”).

Production taking precedence over profitability (and over economic rationality)

The result was that current profitability took second place to an industry PR narrative about what was supposedly going to happen in the future as the shale companies grew and grew. Prior to the crash of 2007 bank employees were under pressure and being incentivised by bonuses to make as many loans as possible – even though many loans were unsound. Now the fracking company managers were being incentivised to produce as much product as possible even though they were losing money.

The measure of the future dream was production growth rather than what it ought to have been – profitable production growth. The latter depended on whether that production growth was actually covering costs of production and it was not.

It should be stressed again that this was happening before the current price slide. For example an analyst Arthur Berman looked at the financial figures for Exploration and Development Companies representing 40% of the US shale industry for 2013 and 2014 and found them to be powerfully in the negative. There was a $14 billion negative cash flow in 2014. (http://www.artberman.com/art-berman-shale-plays-have-years-not-decades-of-reserves-february-23-2015/)


Nevertheless the good news headlines about the production growth kept the share prices rising and the managers were on bonuses to make that production growth happen. Apart from the skeptics and the communities whose environments and health were under attack, the industry, the government, some naïve academics and Wall Street, all played their part in pumping up the dramatic narrative of the resurgent American Oil and Gas Dream. Eventually the USA would rival Saudi Arabia and more…becoming great again no doubt. As a more recent article in the Wall Street Journal explained:

“Markets have been waiting for U.S. energy producers to slash output during a period of depressed crude prices. But these companies have been paying their top executives to keep the oil flowing. Production and reserve growth are big components of the formulas that determine annual bonuses at many U.S. exploration and production companies. That meant energy executives took home tens of millions of dollars in bonuses for drilling in 2014, even though prices had begun to fall sharply in what would be the biggest oil bust in decades. The practice stems from Wall Street’s treatment of such companies’ shares as growth stocks, favoring future prospects over profitability. It has helped drive U.S. energy producers to spend more unearthing oil and gas than they make selling it, energy executives and analysts say.

It has also helped fuel the drilling boom that lifted U.S. oil and natural-gas production 76% and 31%, respectively, from 2009 through 2015, pushing down prices for both commodities. “You want to know why most of the industry outspent cash flow last year trying to grow production?” William Thomas, CEO of EOG Resources, said recently at a Houston conference. “That’s the way they’re paid.” (Ryan Dezember, Nicole Friedman and Erin Aillworth. “Key Formula for Executives Pay: Drill Baby Drill” http://www.wsj.com/articles/key-formula-for-oil-executives-pay-drill-baby-drill-1457721329)

The Euphoric Economy at Work – how to rip off manic investors

All of this raises the question of how, with profitability so low, this reckless show has managed to stay on the road for so long and still continues. A cynical answer would be to say that the function of Wall Street is to connect the greedy and stupid with people and institutions without scruples who will spend their money for them. For this to happen optimism must be generated at all times whether this optimism has any foundation or not. The study of bubbles is all about people who are able to swim in an ethical sewer oblivious to their environment. They are too “euphoric” or high on the prospect of making a lot of money to calmly calculate what is happening. Another word for this is mania. It helps to consider this as a period of collective madness like a mania – a period of collective excitement in which the capacity for ethical and other judgements are impaired.

In this collective insanity one can think of the money making calculations like this – if you buy the right to drill and are able to identify the geologically favorable “sweet spots” then at first the results are likely to be good. Instead of then drilling the less favorable locations and seeing your profits fall away you tell beautiful stories to another company with deep pockets enticed by the good news of the early success. So it is possible to sell the less favorable areas. Or maybe you sell the company, merging it with another. In this Wall Street (or the City of London no doubt) will come to your aid because it makes nice fees from mergers and acquisitions. The new owners then makes the loss. It is the buying company that then has to write down its balance sheet when it subsequently discovers that it was sold a mirage.

The stories about being duped are never told as loudly and plainly as the stories of the wonderful shining future that sell the fraud in the first place. That’s because managers do not like to speak loudly about their incompetence to avoid the embarrassment of admitting they were duped. It is usually possible to deny that it would have been possible for them to know what was happening and, after all, why should these managers care when it was other people’s money that they were losing? (The money of shareholders or bond holders).

But if the faith in the industry can be maintained then these kind of deals can at some time make the banksters and crooked production company bosses much more money than merely by drilling and fracking for shale gas or oil. Thus buying and selling drilling leases (bundled up together just like sub prime mortgages were) was a great money spinner for companies like Chesapeake. The greater the euphoria generated, the more money to be made. This is Deborah Rogers again:

“Aubrey McClendon, CEO of Chesapeake Energy, stated unequivocally in a financial analyst call in 2008: ‘I can assure you that buying leases for x and selling them for 5x or 10x is a lot more profitable than trying to produce gas at $5 or $6 mcf.’”

Eight years later Aubrey McClendon was dead. He had been charged on a federal indictment of bid rigging from late 2007 to 2012 and drove his car at high speed into a bridge. There was a strong suspicion that he had killed himself.

The madness of shale goes on. Wall Street and the shale companies are still managing to play the same game of passing the risk parcel to the bigger fools who will take the loss. If people can be persuaded to buy into the companies just before they go bust then the smarter and bigger players can get out. At the time of writing (March 2016) there are suspicions that the banks are orchestrating a rise in the price of oil in order to help the shale companies raise capital which will enable them to pay off the banks while letting “the suckers” take the fall. This led one analyst to describe the glut, not just of oil, but of stupidity.

“Even the experts are stunned by this unprecedented glut in stupidity of managers of other people’s money: “Billions of dollars of dilutive equity continue to roll in with seemingly no end in sight,” Houston-based oil investment bank Tudor, Pickering, Holt & Co. said in a research note.” (http://oilprice.com/Energy/Crude-Oil/In-Risky-Move-Wall-St-Backs-Shale-With-Nearly-10-Billion-In-Equity.html)

Ethical or Financial Bankruptcy – which is more fundamental?

It is common in economics to refer to markets becoming frothy at times like this. Commentators seek to find the fundamentals underlying the “froth” (perhaps better described as scum). But what are “the fundamentals” in this story? The really fundamental thing is not that this sector is financially bankrupt – it is that it is ethically bankrupt too. An ethically bankrupt sector is definitely not sustainable. Any economic sector that destroys the environment including the climate, assaults public health and then enlists government in a corrupting endeavour to write and use the regulations in such a way as to undermine the very possibility of resistance is corrupt to the core. An industry that destroys people’s health and environment and then settles in court on condition that people are bound to secrecy about what has happened to them, as is common practice in the USA, cannot be trusted to tell the truth. It does not surprise in the least therefore that the unethical business methods of this sector, as well as the unethical methods of its allies in finance, also rely on trickery and defrauding anyone stupid enough to invest their money in it.

What will happen in the USA will no doubt have a big impact for the future credibility of the fracking industry in the UK and elsewhere in the world. That story is not yet in its final chapter but what has happened in the USA is already a cautionary tale and we would be stupid to ignore it. Local authorities in the UK should be careful that they are not caught out picking up the environmental costs of a collapsing industry. It has already happened in the USA and Canada – the advantage of limited liability to an industry without ethics is that it enables it to pass the cost of clearing up to communities after bankruptcies.

“CBC News reported that falling gas and oil prices have prompted many smaller companies to abandon their operations in Alberta, Canada, leaving the provincial government to close down and dismantle their wells. In the past year alone, the number of orphaned wells in Alberta increased from 162 to 702. At the current rate of work,
deconstructing the inventory of wells abandoned just in the past year alone will be a 20-year task.” (Source: Johnson, T. (2015, May 11). Alberta sees huge spike in abandoned oil and gas wells. CBC News. http://www.cbc.ca/news/canada/calgary/alberta-sees-huge-spike-in-abandoned-oil-and-gas-wells-1.3032434 )

In conclusion – a mountain of debt that will never be repaid?

People might ask, if the future of fracking is so much in doubt then why bother to build a movement of opposition to oppose it? The answer can be expressed by adapting a famous quote by John Maynard Keynes. In the original Keynes says “the market can remain irrational longer than you can remain solvent”. The market can also remain irrational long enough to do a lot of damage. What this article has barely done at all is refer to what are called, in economics-speak, the “external costs” of fracking – the damages to climate, to local environments and to public health. Nor has this article examined the claimed benefits to employment and to local economies which are usually grossly overstated. There is now plenty of evidence about these things. What I have tried to do instead is to show that even in the narrowest of meanings of “economic” fracking does not make sense. A lot of damage is being done and there will be little positive to show for it. The ability to continue this destructive path is due to the legacy of political influence of the fossil fuel lobby in government and in the finance sector. The legacy influence has been strong enough to ignore and crush the opposition despite the damage. In the USA it can be argued that the fracking boom has been an irrational, unethical and ultimately unprofitable attempt to extend the lifetime of fossil fuels in order to keep the oil and gas industry in work, aided and abetted by Wall Street. It is an industry trying to secure a future for an influential network of professional and business interests that should, in truth, be being wound down – including the engineers, the university departments of petroleum geology, the regulators to name a few. A mountain of debt has been accumulated to perpetuate the illusion that these people have a future in which they can go on much as before – a mountain of financial debt that will never be repaid.

Stupidity has a knack of getting its way – Albert Camus

Sources and further reading:

On geological uncertainties: Mason Inman “Can Fracking Power Europe?”, March 2016 at http://www.scientificamerican.com/article/can-fracking-power-europe/

Charles Newbury, “Struggles to cut cost delay oil production in Argentina” Platts Oilgram News. August 17th 2015 at http://blogs.platts.com/2015/08/17/cut-cost-delay-oil-play-argentina/

Low Gas price vs high extraction costs: Zachery Davis Boren, Greenpeace Energy Desk; August 2015 http://energydesk.greenpeace.org/2015/08/20/super-low-gas-price-spells-trouble-for-fracking-in-the-uk/

European natural gas supply and demand: https://www.oxfordenergy.org/publications/the-outlook-for-natural-gas-demand-in-europe/ and https://www.oxfordenergy.org/wpcms/wp-content/uploads/2016/01/Gazprom-Is-2016-the-Year-for-a-Change-of-Pricing-Strategy-in-Europe.pdf

Oil Majors as a source of investment capital http://www.telegraph.co.uk/business/2016/02/12/oil-firms-urged-to-avoid-dangerous-investment-cuts /

Deborah Rogers, “Shale and Wall Street” Energy Policy Forum 2013) http://shalebubble.org/wp-content/uploads/2013/02/SWS-report-FINAL.pdf

Fragility of UK explorer’s finances: http://www.companywatch.net/wp-content/uploads/2016/01/oil-and-gas-smaller-cap-research-11-January-2016-final.pdf

Crisis in US Shale Sector: http://www.bloomberg.com/news/articles/2016-03-11/oil-boom-fueled-by-junk-debt-faces-19-billion-wave-of-defaults

Arthur Berman “The Miracle of Shale Gas and Tight Oil is Easy Money” http://www.artberman.com/the-miracle-of-shale-gas-tight-oil-is-easy-money-part-i/



Ryan Dezember, Nicole Friedman and Erin Aillworth. “Key Formula for Executives Pay: Drill Baby Drill” http://www.wsj.com/articles/key-formula-for-oil-executives-pay-drill-baby-drill-1457721329

“Energy in the economy”: Brian Davey Credo. Economic Beliefs in a World in Crisis Feasta books 2015. http://www.credoeconomics.com Chapters 32 and 33.

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Implications of Refinery closures for Homeland Security and Critical infrastructure safety

House 112-76. March 19, 2012. The Implications of Refinery Closures for U.S. Homeland security and Critical Infrastructure safety. House of Representatives.  

[Excerpts from the 54 page testimony]

Our country relies on a complex and modern infrastructure system to distribute energy domestically. This reliance is critical to delivering necessary supply to meet demand in the Northeast as well as in all regions of our country. Any minor disruption in this system can create major problems for many of the very things that we depend on every day, from heating our homes to fueling our vehicles. A major disruption can cause serious issues for our Nation and our security.

If a buyer is not found for the Philadelphia refinery and the facility is closed, over half the refining capacity in the Northeast will be removed in a span of only 6 months. I have serious concerns as to how much stress this puts on the current infrastructure system and the increased risk in the event of a natural disaster, terrorist attack, or other geopolitical event.

After Hurricanes Katrina and Rita hit the Gulf Coast, we witnessed just how vulnerable the reliance on the Gulf Coast and pipeline infrastructure for energy supplies can be. Five days after Hurricane Katrina struck, the U.S. Minerals Management Service reported that 88.5% of Gulf crude oil production was shut down or off-line. This amounted to 25% of the total Federal off-shore crude production, leaving many platforms evacuated or destroyed. Less than a month later, Hurricane Rita made landfall in the Gulf, resulting in significant damage. The cumulative effect of these two storms resulted in the temporary suspension of operations at ten refineries, a loss of over 2 million barrels per day from the market, and significant pipeline disruption.

The Colonial pipeline, a critical artery for the Northeast to receive our refined fuel products from the Gulf, was temporarily closed, along with Capline and Plantation pipelines.

Of similar concern is the threat to oil facilities from acts of terrorism. Since the September 11, 2001, terrorist attacks, there has been great concern about the security of the Nation’s critical infrastructure including oil refineries and pipelines. Al-Qaeda and its affiliate networks have previously expressed interest in attacking critical infrastructure in the homeland including oil and gas facilities. Last year, the Department of Homeland Security and the FBI warned State and local police across the United States that al- Qaeda has a continued interest in attacking oil and natural gas targets. In fact, this information came directly from intelligence that was seized during the raid of Osama bin Laden’s compound in Abbottabad. Al-Qaeda targeting the oil infrastructure has long been a part of the al-Qaeda playbook.

In 2002, the group claimed responsibility for the bombing of a French oil supertanker off the coast of Yemen. In a brazen February 2006 operation, al-Qaeda attacked the Abqaiq facility in eastern Saudi Arabia. The facility is one of the world’s largest and it produces 13 million barrels of oil per day. Although the damage inflicted by the attack was quickly contained, the mere news of an attack pushed oil prices up by $2. Perhaps more significantly, experts believe that attacks on oil and gas infrastructure could be an increasingly common likelihood as al-Qaeda changes its target set to an area that would garner the most attention and inflict the most damage on the United States’ economy. Relatedly, the Department of Homeland Security recently warned about cyber-attacks against the oil and gas sectors by the hacker group Anonymous.

In closing, the threat to our energy distribution system is very real. Accidents, natural disasters, and terrorist attacks have proven to disrupt oil facilities’ operations in the past. I expect that they will also do it in the future. That is partly why I am concerned about further pressuring our delivery systems to accommodate in the event of Philadelphia refinery closures. I look forward to hearing from today’s witnesses on how these closures will impact the region and the country and how we can provide for the continuing security of our oil distribution systems and the safety of our homeland.

CHAIRMAN PATRICK MEEHAN. The rising cost of energy of course is dominating the headlines and impacting so significantly our budgets, our business budgets, and our family budgets, demonstrating, I think, for all of us how economic security, energy security, and National security are all really inextricably intertwined in this industry. There were riots because of rising fuel prices back in the late 1970s. I remember 1979 when I was growing up in Bucks County, some of the first gas riots occurred in the Five Points section of Levittown, my hometown in southeastern Pennsylvania,

BRIAN HIGGINS. What are the other options for getting oil to this area? Are the ports in this area equipped to both handle crude oil? Are any nearby ports able to handle waterborne oil products? Even if there are ports that can handle waterborne oil products, will there be an ability to inject oil into the pipelines used by the refineries? Furthermore, we also need to look at the security issues involved in relying on cargo ships and pipelines to supply oil to this region. We know that before his death, Osama Bin Laden asked al-Qaeda operatives to target pipelines, oil tankers, and dams in the United States. Since bin Laden’s death, however, is this still a threat? What exactly are the Department of Homeland Security and the Department of Transportation doing to ensure that these pipelines are not vulnerable to terrorist attacks? In addition to terrorist attacks, what are the Department of Homeland Security and the Department of Transportation doing to ensure that in the event of a natural disaster, oil will reach the Northeast if the Pennsylvania refineries are closed? After Hurricanes Katrina and Rita, we witnessed just how vulnerable these pipelines can be. We need to know how to be prepared in the event of a natural disaster.


HITRAC’s initial analysis shows that the refinery closures should not have homeland security impacts due to this loss of supply.

HITRAC serves as the analytic arm of the Department’s Office of Infrastructure Protection and provides strategic, operational, and tactical analysis to our public- and private-sector partners so that they can make more-informed decisions regarding the management of risk. Our work supports homeland security-related exercises, training activities, contingency and security planning, and response to real-world incidents that affect the Nation’s infrastructure. Modeling complex real-world systems such as the petroleum network underpins all of the analysis performed by HITRAC. A massive and complex network of refineries, transmission pipelines, tank farms, and terminals produce and deliver refined petroleum products. Because the network is so interconnected, interruption of any of these components could cascade into other parts of the system causing imbalances and shortages. However, the system is dynamic. In the event of a disruption in one part of a pipeline network, for example, flow can sometimes be diverted to functioning pipelines or production can be surged at another refinery while consumers respond to shortages and resulting price increases by limiting consumption. Because of the significant role that petroleum plays in our economy, HITRAC has undertaken a number of capability development efforts to better understand the domestic and international fuel supply. In 2011, for example, we completed a model of the National transportation fuel system, which helps analysts estimate the effects from damage or disruption to components of this system.

HITRAC has provided support to decision makers during a wide variety of real-world incidents, including flooding in the Midwest, Hurricane Irene, the Japanese earthquake and ensuing risks of tsunami and radiation fallout, wildfires in the Southwest, earthquakes in Peru and Haiti, and industrial accidents including the BP Oil Spill.

The crude oil and petroleum product network forms a complex and integrated supply chain, which is global in its scope. Supply-chain analysis examines the ways individual firms make operational decisions in response to disruptions, including how they purchase goods, produce products, sell them in markets, and ship them via different modes of transportation. Disruptions within these chains can affect the ability of some infrastructure entities to provide their products or service to the population. Foreign facilities and foreign sources of materials are of particular concern because they are farther away, are outside of U.S. Federal assistance, and may be more prone to disruption than domestic sources and facilities.

Mr. MEEHAN. This committee deals with the issue of terrorism, and one of the great concerns that we have is the vulnerability of pipelines and other kinds of assets within the network from refineries to transmission pipeline to tank farms and terminals to the most vulnerable presumably among them, pipelines themselves, and I just did sort of a quick off the back of the cuff look just going through January 2006, we had a jihadist website that linked al-Qaeda that encouraged attacks on the United States pipelines. That was in January 2006. In June 2007, the jet fuel pipelines at JFK were targeted and attacked. In July and September 2007, we had the Mexican rebels detonated bombs along the pipelines along the Mexican coast. In November 2007, we had a United States citizen that was convicted of trying to conspire to blow up a pipeline from here in the middle district of Pennsylvania. We had testimony earlier this morning that bin Laden in Abbottabad had created an identification of pipelines as one of the principal targets. What is the vulnerability that we have to the sureness of supply here if a pipeline like the pipeline that is servicing us that will be used as the substitute to serve the capacity here can be impacted? Can it be impacted and will it have a downstream implication for our region?

Mr. WALES. Over the past several years, the Office of Infrastructure Protection has conducted over 60 vulnerability assessments on pipeline infrastructure throughout the country. In some cases, in conjunction with that, we have conducted over 80 buffer-zone protection plans. That is, working with State and locals and the private sector on integrated planning related to the security and resilience of those pipelines, and as part of those buffer-zone plans have given out over $10 million in grant funds to local communities to execute the planning and improve security around pipelines. In addition, during the fiscal years of 2012 and 2013, the Office of Infrastructure Protection will be executing a regional resiliency assessment of the Colonial and Plantation pipelines because they are a real critical artery in our overall energy infrastructure on the East Coast and in some cases because of the closing of these refineries they are becoming even more critical.

We would say that part of that regional resiliency assessment will have us conducting detailed assessments of various critical chokepoints along those pipelines both hydraulically critical pumping stations as well as control centers and others.

Our primary concern would be a prolonged damage to the pipeline that kept it down for more than a week, more than 2 weeks. I think, you know, once you start getting beyond a week or 2, the ability for the excess inventory and terminals along its route starts to be diminished and then you could start to have more serious impacts,

Mr. CARNEY. I think you have identified the main homeland security risk with respect to the concentration of refining capacity here in the United States, and it is hard for me to imagine that our homeland security is not threatened in some way by that, by concentrating the facilities that will deliver refined products or petroleum products to regions in the country as opposed to having a more distributed network. In addition, the discussion this morning has centered around the off-shoring frankly of refining capacity, which would then make the United States, in my opinion, less independent, less energy-independent and more at risk to overseas attacks on whatever facilities. I appreciate the fact that you are going to do an analysis of those pipelines in particular because it seems to me that it is a little bit hard to wrap my head around the fact that Dr. Gruenspecht has indicated that the Colonial pipeline is near capacity and we are going to be relying on it to move product here to our region, that that won’t have a negative impact. But setting that aside, will your study include the risks associated with relying more on refined product coming from overseas where facilities in other parts of the world that we can’t protect, so to speak, are at risk?

Two of the refineries have already closed. So we are talking about long-term implications of our own energy independence as a Nation as well as the security of that network, and it is hard for me to imagine that it is not going to be a greater risk. It is a little disturbing to hear, Dr. Gruenspecht, that a lot of these facilities are basically taking domestic supplies and exporting refined products in a world where we are importing such a big part of our petroleum needs, that the market drives certain of these products overseas. In fact, my understanding is, a lot of those refined products out of the Gulf Coast are for export. Is that accurate?

Mr. GRUENSPECHT. We have been exporting increasing amounts of product from the Gulf Coast. Obviously the Gulf Coast also is a major source of supply to other parts of the country. It is the major refining center in the country. Roughly half of the refining capacity in the country is on the Gulf Coast.

Mr. CARNEY. So at a time when we are putting in policies that are having negative implications for our demand for end-products, i.e., the use of ethanol and other biofuels, to help the Nation be more energy-independent, because of the way the markets work, we are still exporting product, which is making us less independent.

Let me give you a real-world example of where this is in operation around the world. One of the biggest threats that we face in the world right now is the threat of a nuclear-armed Iran, and one of the actions that we have taken in the Congress is to impose sanctions on Iran, which have been putting significant pressure, economic pressures on the country. One of those sanctions is to attack their need for refined petroleum products because they don’t have refining capacity in the country, and it is having devastating impacts. Can’t you just flip that around?

Finally, there has been a great deal of attention recently on the future of electric vehicles as the “future of transportation.” It was recently reported that the United States is pursuing a trade case against China over its practices related to rare earth minerals, a vital component of hybrid car batteries. The same reports note that China controls 97 percent of the world’s supply of rare earth minerals. As Congress and the administration seek ways to increase our energy security, economic security, and National security, AFPM urges policymakers to weigh the full spectrum of trade-offs.

While weaning the United States off oil is a good talking point, artificially forcing the market to adopt expensive new technologies that rely on the fair trade practices of China could bring a new set of challenges. In the meantime, the United States can instead develop its own abundant supply of energy, which can increase our energy, economic, and National security. The United States can do so without subsidies or mandates, all our industry needs is the room to do it. As we look to diversify our energy sources, we must not turn our back on petroleum-derived fuels that we will continue to depend upon for decades to come. To do so would simply disadvantage the consumer, harm our National economy, and erode our energy security.

Robert Greco, Group Director, Downstream & Industry Operations, American Petroleum Institute.

About 75 U.S. refineries have closed since 1985. As this has happened, however, the remaining larger, more efficient facilities have expanded capacity so the total U.S. refining has actually increased by 13%.

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Unpave low traffic roads to save energy and money

The U.S. has 4.1 million miles of roads (1.9 million paved, 2.2 million gravel). About 3 million miles of roads have less than 2,000 vehicles a day, less than 15% of all traffic. The paved portion of these low-volume roads ought to be evaluated for their potential to be unpaved.

Many of these roads should have never been paved to begin with, but the costs of construction, asphalt, and energy were so cheap it was done anyway.  Now many rural roads are past their design life and rapidly deteriorating.  It is both difficult and expensive to maintain them, and dangerous to let these roads fall apart and degrade into gravel on their own.

Examples of road safety effects caused by failing asphalt roads. The failures force traffic to travel outside of the lane and disrupt traffic movement.

Examples of road safety effects caused by failing asphalt roads. The failures force traffic to travel outside of the lane and disrupt traffic movement.

Unpaving low-volume roads saves energy and money. According to Karim Ahmed Abdel-Warith at Purdue University, preserving low-volume roads costs several hundred million dollars a year, more than half of the annual investment in roads.

Unpaving would also slow vehicle speeds down, further increasing miles per gallon from less aerodynamic drag.

Since roads harm biodiversity, getting rid of a road entirely should be done when possible.

The NRC paper I’ve taken excerpts from below requested feedback from the 27 states that have already depaved roads. This report provides many helpful guidance documents on depaving roads for communities interested in pursuing this.

NOTE: I’ve also added notes from another document below: The Promise of Rural Roads. Review of the Role of Low-Volume Roads in Rural Connectivity, Poverty Reduction, Crisis Management, and Livability

Alice Friedemann   www.energyskeptic.com

Fay, L., et al. 2016. Converting Paved Roads to Unpaved Roads.  Transportation Research Board of the National Academies, Washington, D.C.

“The historic trend has been to pave roads, not unpave them.   These policies arose in the last century when the costs of asphalt, fuel, and all construction expenditures were low compared with current costs and the axle loads carried on rural low-volume roads were significantly lighter than current loads. The rising cost of asphalt and fuel and a significant increase in traffic and traffic loads on low-volume rural roads due to commercial, agricultural, and energy trucks, combined with stagnant or decreasing budgets, are causing a situation in which the cost of rehabilitating and maintaining very low-volume paved roads on the existing road network often is no longer feasible

This study found that the practice of converting paved roads to unpaved is relatively widespread; recent road conversion projects were identified in 27 states on mainly rural, low-volume roads that were paved when asphalt and construction prices were low. Those asphalt roads have now aged well beyond their design service life, are rapidly deteriorating, and are both difficult and expensive to maintain. Instead, many local road agencies are converting these deteriorated paved roads to unpaved as a more sustainable solution.

Many local road agencies reported cost savings after converting, compared with the costs of continuing maintenance of the deteriorating paved road, or repaving.

Low-volume, rural roads serve as main routes for numerous industries, farmers, and ranchers to get raw material from source to distribution or processing centers, provide ingress to remote public lands, and act as transportation arteries for millions of rural residents. Most of these rural roads have low or very low traffic volumes and have unpaved, aggregate surfaces. Historically, unpaved roads have been considered the lowest level of service provided. In a demonstration of progress and an effort to improve road conditions for rural residents, many agencies paved low-volume roads with little or no base preparation when asphalt and construction prices were low. Those asphalt roads have now aged well beyond their design service life, are rapidly deteriorating, and are difficult and expensive to maintain.

The increasing sizes of agricultural and commercial equipment, including that used by the energy sector, are compounding road deterioration in many areas. Traditionally, these roads were maintained or repaved at regular intervals, but with the increasing traffic loads, increasing cost of materials, and stagnant or declining road maintenance budgets, many agencies do not have the funding to support these activities. Instead, many local road agencies are looking to convert deteriorated paved roads to unpaved ones as a more sustainable solution.

The state of the practice for converting roads from paved to unpaved involves reclaiming or recycling the deteriorated pavement surface, supplementing existing materials as needed, compacting, and for some applying or incorporating a surface treatment, such as a soil stabilizer or dust-abatement product. In a few cases, no recycling of the old pavement was done, and new surface aggregate was simply placed over the deteriorated road surface. However, most agencies that have done conversions recycle the old surface in-place and reshape and compact it as a base for a new aggregate surfacing. Thereafter, the new surfacing ranges from locally available gravel to high-quality surface aggregate that can be maintained with motor graders to sustain adequate crown and a smooth surface. Many of the roads that have been converted from paved to unpaved had annual average daily traffic (AADT) of between 21 and 100 vehicles, suggesting that many of the roads that are being converted should not have been paved initially or that road usage patterns have changed significantly since paving.

Local road agencies are converting roads primarily as a result of a lack of funding for maintenance and construction, safety issues, and/or complaints from the public. Road budgets have remained stagnant or declined in recent decades, but the costs of labor, materials, and equipment have continued to increase. Consequently, local road agencies have been left underfunded and are struggling to maintain their existing road network. Limited maintenance of deteriorating roads (e.g., pothole patching) often is all that can be done with existing resources, with repaving often being cost-prohibitive.

The reported cost of converting ranged from $1,000 to $100,000 per road segment or mile within the United States and Canada. The variation in costs is attributed to how costs are tracked by agencies, how the conversion was done, equipment requirements, supplemental materials, surface stabilization and dust abatement, and addressing drainage and road base issues.

NEEDED: Unpaving guides

A significant lack of available resources, such as a handbook or design guide, for practitioners who are considering or performing road conversions was noted. Numerous survey respondents indicated that they did not use any documented resources when planning and performing the conversion and often used a trial-and-error approach. In addition, road agencies rarely document procedures and outcomes of road conversions, such as construction problems, crash rates, public concerns and reaction, and comparative maintenance costs of the new surface. Completing successful conversions is possible with appropriate investigation and design, selection of quality granular surfacing materials, and good construction, and by involving and educating the public as part of the process. However, limited information has been published to guide practitioners in these processes.


There are more than 4.1 million mi of roadways in the United States. There is no uniform agreement on how many of these are low-volume roads. About 53% are unpaved and are maintained by local and state transportation departments.  Unpaved roads are nearly always considered low volume.

For the purpose of this project, low-volume or very low-volume roads are defined as roads with AADT of less than 250 vehicles, based on research that determined that converting paved roads to unpaved was cost-effective at this threshold.

The spectrum of options of surface types for low-volume roads ranges from gravel with no treatment to stabilized gravel to bituminous sealed bases to asphalt and concrete pavements. Each road surface type has its own merits and represents one tool in the road management toolbox. Unpaved roads can be defined as those with a surface course of unbound aggregate (gravel) where no binder, such as tar, bitumen, cement, lime, or other chemical additive, is used. An unpaved road often requires blading at least once annually to maintain the road surface in a drivable and safe condition. Paved roads are defined as those with an asphalt concrete or portland cement concrete surface, or roads that possess any combination of asphalt binder and aggregate intended to provide waterproofing, adhesion, structural strength, and frictional resistance.


Active versus Passive Conversion

Many transportation agencies facing budget shortfalls and deteriorating paved roads are converting their paved roads to gravel (active conversion), whereas other agencies are allowing roads to deteriorate to unpaved conditions owing to a lack of funding for maintenance (passive conversion). Active conversion is the process of converting a paved road to an unpaved road using equipment and personnel to recycle the old pavement into a pulverized material that can be used as a base for a new aggregate surfacing or as part of the new surface. Passive conversion of a road from paved to unpaved is the natural process of the paved road breaking down and deteriorating to an unpaved surface as a result of exposure to the elements and wear and tear from vehicle traffic. Based on survey and interview responses, active conversion is a far more common practice, however some local road agencies find that passive conversion occurs simply as a result of a lack of funding for properly maintaining roads.

Factors to Consider for Unpaving

  • Road condition: This dictates whether a deteriorated paved surface can be economically repaired to restore it to an acceptable condition or whether there is a need for complete rehabilitation or reconstruction, which may not be affordable. In the latter instance, conversion to gravel can be considered.
  • Safety: The deterioration of a paved road surface may be such that it may be safer to convert to a gravel surface either permanently or for an interim period until the road can be rehabilitated or reconstructed.
  • Presence of heavy and overweight vehicles: A high volume of heavy vehicles has a significant impact on the standard required for pavement maintenance and rehabilitation. Initial costs to repave or repair a road to an appropriate standard for these vehicles may be unaffordable for achieving an acceptable life cycle. Gravel roads can be much cheaper to repair when damaged, but the frequency of repair may be greater.
  • Maintenance capability: Specific equipment and skills are required for paved and unpaved road construction and maintenance. The availability and affordability of either contracted or in-house equipment or skill need to be assessed to compare the ability to maintain each surface type effectively. Dust and erosion control may be a significant factor and could be considered for unpaved surfaces.
  • Environmental issues: Air and water quality impacts from dust and erosion can affect human, plant, animal, and aquatic health and create a safety hazard to drivers. Products used to stabilize the road surface and reduce dust can also affect the adjacent environment if incorrectly selected or applied.
  • Dust and erosion control: These issues may or may not be a significant factor, but it is essential that they be considered for all surfaces.
  • Availability and quality of suitable unpaved road–wearing coarse aggregate sources: The quality and properties of the aggregate have a significant impact on the surface condition and frequency of maintenance required on unpaved road surfaces. Appropriate unpaved road surfacing aggregates are not offered by many commercial aggregate suppliers and can be expensive or difficult to obtain. This issue is more important than many managers recognize.
  • Network significance of the road: Primary routes that are frequently used by public transport (including school buses) or emergency vehicles or are priority snowplow routes generally are not recommended for conversion from paved to unpaved surfaces. Local roads serving limited access to residences or businesses are better candidates.

Changes in Traffic Patterns and Vehicle Type

Modern agricultural equipment (i.e., tractors, combines, farm trucks) have greatly increased in size and carrying capacity, along with greater crop yields, creating increased maintenance issues on paved and unpaved rural roads (Anderson 2011), with accelerated degradation of low-volume roads (Figure 6). Multiaxle semis, concrete haulers, large-load log trucks, and rising traffic volume can be equally destructive (Etter 2010; Taylor 2010) (Figure 7). In some areas of the country where oil drilling and extraction have increased, such as North Dakota, Texas, and Pennsylvania, significant damage to roads from oil field traffic has occurred (Floyd 2013). Many of these rural paved roads have passed the end of their design life (Anderson 2011).


The 2010 Wall Street Journal article “Roads to Ruin: Towns Rip Up the Pavement” highlighted the economic strain many counties face when trying to maintain paved roads in rural areas (Etter 2010). A recent study found that the state of Iowa would need to increase road funding by $220 million annually just to maintain the current road network (Anderson 2011). Similar funding shortfalls for local road maintenance budgets are occurring across the country (Canfield 2009; Taylor 2010; Landers 2011). Cold-weather states in particular have high maintenance costs resulting from the repair of damage caused by freeze-thaw cycles but little available funding because of essential winter maintenance operations (Canfield 2009).

Coupled with declining budgets, agencies have seen raw material prices increase. Costs for gasoline, diesel, and asphalt binder, all petroleum-based products, are tied to fluctuating oil prices (Taylor 2010). However, fuel taxes, which are a primary source of funding for road maintenance, have remained constant in this time period. Improved fuel consumption technologies have further reduced this source of income.

The recent economic downturn has made governments reluctant to increase other taxes and has resulted in people driving less.



  • According to a county road commissioner, Michigan is ranked 50th in per capita spending on road maintenance in the country (Canfield 2009; Rajala 2010). In Montcalm County, patching of a primary road cost more than $39,000 in 2008 and 2009. However, it cost only $7,300 for the road to be converted to gravel.
  • Road conversion projects in Benzie County, Michigan, have resulted in significant savings in maintenance costs by eliminating the need for two-person patch crews working 1 to 2 days per month and replacing that process with annual brine application
  • The Branch County Road Commission in Michigan was spending nearly $2,000 per week making repairs to a road. A 1-mi stretch of the road was converted to gravel at a cost of $6,370
  • In Emmet County, Michigan, repairing just more than 3 mi of a severely potholed road cost $20,000 to $30,000 per year. After the road was converted to gravel, maintenance costs were reduced by about $10,000 annually, with an initial (up-front) cost of $12,000 for pulverizing the paved road


  • In 2013, the Indiana LTAP published Assessment Procedures for Paved and Gravel Roads, a handbook that addresses some of the issues facing underfunded counties in Indiana. Cost estimates from the report place the cost of recycling a paved asphalt road, stabilization of the base, and addition of a new gravel surface at $42,000 per mile. Alternatively, the cost to maintain the asphalt with similar treatments to the subsurface and a new asphalt overlay was estimated at $112,000.
  • In Hancock County, Minnesota, estimates for initial construction and 5 years of maintenance suggested a total cost savings of $3,000 per mile (Minnesota Department of Transportation 2010).
  • In North Dakota, Stutsman County expenses outweigh income, and the county has revenue to maintain only 48 of the 233 mi of paved road. Cost estimates for repaving a deteriorated road segment were around $75,000 per mile, whereas projected costs for maintaining the road as gravel were $2,600 per mile. The county estimated it would cost $32,000 per mile in maintenance costs over the 20-year life-cycle for a low-volume paved road, whereas that same 20-year maintenance cost would drop to $4,300 per mile for a reclaimed road and lower still to $1,700 per mile for a gravel road (Landers 2011).
  • In Allamakee County, Iowa, the cost estimate for surfacing roads was about $100,000 per mile, compared with only $5,000 per mile to remove the pavement and add new gravel (Louwagie 2011).

West Coast: In Lake County, California, paved roads were recycled with a pulverizer followed by an enzyme application. The county won an award in 2009 from the California Chip Seal Association for Innovative Project of the Year for the resurfacing of two of the converted roads. Overall, the county saved about $190,000 with the technique used instead of a traditional pavement overlay

East Coast:  High asphalt and transportation costs were motivation for Cranberry Isles, Maine, to consider converting three of its major roads to gravel (Rajala 2010). Repaving was estimated to cost the town (population 118) nearly $500,000, whereas converting to gravel cost $58,000, with most labor performed by public works personnel.

How to depave a road

The most important piece of equipment is a reclaimer of appropriate weight and power, which ensures the correct ratio of crushed asphalt to granular surfacing material and the right size of the crushed material (1 inch or less).  Reclaimers are faster and more efficient than a motor grader with a ripper or scarifier and require less  labor and a better, uniform recycled material and in the end, a better driving surface. If this is done correctly, then it will be much cheaper and easier to maintain the road in the future with a grader, and less likely that large pieces of crushed asphalt will rise to the surface, lowering ride quality.

Reclaimed road material is milled or crushed to 1 inch or smaller by the reclaimer, and then smaller material, fines or aggregate added as needed to create a smooth driving surface with reduced cobbling (large chunks of asphalt) Another good practice was following the reclaimer with a padfoot roller to further break up the reclaimed material and aid in initial compaction, followed by smooth drum or rubber tire roller compaction to achieve an optimal driving surface.

The hardest part of converting a road that needs minimal maintenance is getting the correct ratio of granular surface material to asphalt, and can require additional passes with the reclaimer or a padfoot roller.  Shaping the road to achieve the proper crown is also important.

Other good practices include:

  • Supplementing the existing road materials with additional aggregate, including fines or changing the depth of reclamation to achieve the proper ratio of granular material to reclaimed asphalt.
  • Proper maintenance after the conversion to ensure increased longevity of the road
  • Using a stabilizer
  • Not converting roads without appropriate drainage

Pavement surfaces were recycled in place using a reclaimer or a ripper on a grader, ideally sizing the material to 1-inch top size. When necessary, additional gravel was added and mixed to supplement existing material, after which the roads were shaped and compacted. Road conversions typically were completed by agency staff with agency-owned or rented equipment. The remaining conversions were completed by a contractor.

Road stabilization is often done with chlorides or enzimes to mitigate base deficiencies and stabilize the granular portion of the reclaimed road surface for better and safer driving surfaces. Some found that enzyme stabilizers reduced maintenance.  But overusing them can result in potholes, adding to maintenance.

Dust suppressants are used to help to stabilize the road surface, provide a better driving surface, reduce dust levels, and get public acceptance of converted roads.

Tools and equipment used in road conversion include: Reclaimer, chemical or enzyme stabilizer, Dust suppression: chloride, used asphalt emulsion, or waste brine from gas and oil wells, scarifier, paving machine with gravel, dump truck, motorgrader

Ready to depave?  Resources and documents


Decision Tree for Unpaving Roads is a preliminary assessment of the state of the practices for “issues surrounding the maintenance, preservation, and possible conversion of a low volume paved road to gravel.” This document provides a summary of relevant literature and a survey of state and county transportation agencies on this topic [CTC & Associates LLC, Decision Tree for Unpaving Roads, Office of Policy Analysis, Research, and Innovation, Research Services Section, Minnesota Department of Transportation http://www.dot.state.mn.us/research/TRS/2010/TRS1007.pdf

“Turning Deteriorated Paved Roads Back into Gravel Roads: Sheer Lunacy or Sustainable Maintenance Policy?” This journal article that describes circumstances in Finland that led to three local road programs developing guidelines to determine if a road qualified to be converted from paved to unpaved [Mustonen et al., “Turning Deteriorated Paved Roads Back into Gravel Roads: Sheer Lunacy or Sustainable Maintenance Policy?, Transportation Research Record: Journal of the Transportation Research Board, No. 1819, Transportation Research Board of the National Academies, Washington, D.C., 2003 http://trrjournalonline.trb.org/doi/abs/10.3141/1819a-15

“Improvements to Linn Run Road: Case Study on Turn- Back of Asphalt-Paved Road Surface to Maintainable Gravel Road Surface” is a journal article detailing the conversion of a deteriorated paved road to gravel by the Pennsylvania Bureau of Forestry in conjunction with The Center for Dirt and Gravel Road Studies at Pennsylvania State University [Shearer, D.R. and B.E. Scheetz, “Improvements to Linn Run Road: Case Study on Turn-Back of Asphalt-Paved Road Surface to Maintainable Gravel Road Surface,” Transportation Research Board, Washington, D.C., 2011, pp. 215–220 http:// trrjournalonline.trb.org/doi/abs/10.3141/2204-27


The Gravel Roads: Maintenance and Design Manual was developed in 2000 but is still relevant as a guidance document. This document discusses road shaping, drainage, definition of “good” surface gravel and the volume required, and maintenance guidance for gravel roads [Skorseth, K. and A.A. Selim, Gravel Roads: Maintenance and Design Manual, South Dakota Local Transportation Assistance Program and Federal Highway Administration, Washington, D.C., 2000 http://ntl.bts.gov/lib/12000/12100/12188/20020819gravelroads.pdf

A revised version of Gravel Roads: Maintenance and Design Manual was completed in 2015 and published with the title: Gravel Roads: Construction and Maintenance Guide. Updated information and photos are included to guide gravel road managers, equipment operators, and field supervisors. Roadway shape, drainage, recommended surface gravel specifications, and basic construction guidance are the key points covered Skorseth, K., R. Reid, and K. Hieberger, Gravel Roads: Construction and Maintenance Guide, FHWA Publication No. FHWA-OTS-15-0002, 2015).

Best Practices for the Design and Construction of Low Volume Roads Revised presents how MnPAVE, a mechanistic-empirical software program, can be used to design pavement types based on traffic loading, design life, and vehicle type, and provides guidance on subgrade and embankment soils and recommendations for density and compaction. Although this document speaks more to pavements, information on subgrade preparation and best practices to follow specifications may be gleaned from the document [Skok, E.L., D.H. Timm, M. L. Brown, T.R. Clyne, and E. Johnson, Best Practices for the Design and Construction of Low Volume Roads Revised, Minnesota Department of Transportation, St. Paul, 2003 http://www.lrrb.org/media/reports/200217REV.pdf

Guidelines for Geometric Design of Very Low-Volume Local Roads developed by AASHTO (2001) addresses the unique needs of very low-volume roads (LVR) with limited traffic and reduced crash rates to avoid overdesign for safety and engineering of these roads. The document provides recommended ranges of values for critical dimensions that can be used to supplement existing road design manuals [American Association of State Highway and Transportation Officials, Guidelines for Geometric Design of Very Low-Volume Local Roads, 2001 https://bookstore.transportation.org/itemdetails.aspx?id=157

Low-Volume Roads Engineering: Best Management Practices Field Guide is a handbook outlining best management practices for low-volume road design and construction. Recommended practices for topics, including planning, location, survey, design, construction, maintenance, and road closure, are covered in the book [Keller, G. and J. Sherar, Low-Volume Roads Engineering: Best Management Practices Field Guide, U. S. Agency for International Development, Washington, D. C., 2003 http://www.fs.fed.us/global/topic/sfm/low_resolution_roads_bmp_guide.pdf

Environmentally Sensitive Maintenance for Dirt and Gravel Roads is a guidance document based on information and training products developed by the Pennsylvania State Conservation Commission and the Penn State Center for Study of Dirt & Gravel Roads that addresses environmental issues associated with gravel roads such as erosion, sediment, and dust and mitigation methods [Anderson, J.A. and A.L. Gesford, Environmentally Sensitive Maintenance for Dirt and Gravel Roads, Pennsylvania Department of Transportation, Harrisburg, 2007 http://water.epa.gov/polwaste/nps/sensitive.cfm

Unsealed Roads Manual: Guidelines to Good Practices is a manual that provides direction and information to road authorities on management and the economics of unsealed roads. The manual was developed by the Australian Roads Research Board and is focused on gravel road maintenance in arid regions [Guimarra, G., Unsealed Roads Manual: Guidelines to Good Practices, 3rd ed., Australian Road Research Board, Vermont South, Victoria, Australia, 2009 http://trid.trb.org/view.aspx?id=1162958

Unsealed Roads: Design, Construction and Maintenance is a guide detailing various aspects of unpaved roads from initial design, to maintenance and rehabilitation. The guide was developed in South Africa and focuses on soil, gravel, climatic conditions present in the country (Paige-Green, P., Unsealed Roads: Design, Construction and Maintenance, #20. Department of Transport, Technical Recommendations for Highways, Pretoria, South Africa, 2009).


Assessment Procedures for Paved and Gravel Roads was developed by the Indiana Local Technical Assistance Program in 2013 and provides an assessment procedure that can be used by local agencies to aid in determining the most appropriate surface type for a given road. Two assessment methodologies were developed specifically for Indiana using cost data from local roads programs. The first methodology provides a basic framework for the comparison of costs for alternative road surface treatment options. The second methodology uses a multi-objective assessment procedure to determine the relative ranking of each alternative road surface treatment option based on cost, traffic volume, development, public preference, and other variables. The tool was developed for use in Indiana, but because the costs, practices, and weighting factors can be modified, this tool can be successfully used by any state local roads program [Figueroa, C., et al, Assessment Procedures for Paved and Gravel Roads, Indiana Local Technical Assistance Program, West Lafayette, 2013

http:// rebar.ecn.purdue.edu/ltap1/multipleupload/Pavement/ Assessment%20Procedures%20for%20Paved%20 and%20Gravel%20Roads.pdf

Pavement Surface Evaluation and Rating (PASER) Manual for Asphalt Roads is a tool that can be used to quickly assess road pavement condition on a scale from 1 to 10 (Walker et al. 2013). The ratings are associated with road condition categories and prescribed treatment options. The PASER assessment tool allows for comparison of road segment quality and the identification of roads requiring treatment. The PASER system is not a robust analysis of road conditions such that the ranking cannot be used in “mechanical-empirical transportation asset management programs.” PASER manuals have been developed for gravel, concrete, brick and block, sealcoat, and unimproved roads [Walker, D., L. Entine, and S. Kummer, Pavement Surface Evaluation and Rating (PASER) Manual for Asphalt Roads, Transportation Information Center, University of Wisconsin–Madison, 2013 http://epdfiles.engr.wisc.edu/pdf_web_files/tic/manuals/asphalt-paser_02_rev13.pdf

Gravel Road Management Tools is a summary of the state of the practice of gravel road management tools used and identifies the needs of local agencies. The information presented in the document was captured through two surveys by the Minnesota Local Roads Program and from county engineers across the country through the National Association of County Engineers (NACE) [Local Road Research Board (LRRB), Gravel Road Management Tools, Minnesota Department of Transportation, St. Paul, 2014 http://www.dot.state.mn.us/research/TRS/2014/TRS1407.pdf

To Pave or Not to Pave is a summary article that highlights the work completed by Jahren et al. (2005) and Skorseth and Selim (2000), both of which are summarized in this chapter, as well as additional tools that can be used when deciding whether or not to pave a road (Kansas LTAP 2006). A video associated with this document can be found at: http://www.mnltap.umn.edu/Videos/ToPaveOrNot/ToPaveOrNot.swf

Kansas LTAP, To Pave or Not to Pave, Lawrence, 2006 (http://www.kutc.ku.edu/pdffiles/2006_Paving Guide.pdf

Economics of Upgrading an Aggregate Road was developed in Minnesota for local road programs and provides guidance on when a road should be improved and recommended procedures for doing so (i.e., grading, regraveling, dust control/soil stabilization, reconstruction/regrading, paving). This study conducted a cost analysis and looked into the effects of traffic volume and type, road surface type, and cost. A method was developed to estimate the cost of maintaining a gravel road, which includes labor, equipment, and materials. This document addresses methods for local road agencies to communicate to the public the why and how of maintenance techniques and policy decisions [Jahren, C. T., D. Smith, J. Thorius, M. Rukashaza-Mukome, D. White, and G. Johnson, Economics of Upgrading an Aggregate Road, Minnesota Dept of Transportation, St. Paul, 2005 http://www.lrrb.org/media/reports/200509.pdf

When to Pave a Gravel Road provides information on how to assess if a gravel road should be paved. This document takes a question-and-answer approach to 10 discussion points to be considered by local government officials when considering paving a gravel road Kentucky Transportation Center, Appendix D: When to Pave a Gravel Road, Kentucky Transportation Center, University of Kentucky, Lexington, n.d. http://water.epa.gov/polwaste/nps/upload/2003_07_24 NPS_gravelroads_appd.pdf

Local Road Surfacing Criteria is a document that provides a methodology for evaluating road sections. It includes a software tool and a user’s guide, which is designed to aid in making local road surfacing decisions. The methodology allows users to compare costs for different road types from paved to gravel [Zimmerman, K. A. et al, Local Road Surfacing Criteria, South Dakota Department of Transportation, Pierre, 2004 http://sddot.com/business/research/projects/docs/sd200210_Final_Report.pdf

A Local Road Surface Selection Tool was developed based on the Local Road Surfacing Criteria (Zimmerman and Wolters 2004). The online tool serves as an analytical tool that applies low-volume road management methodologies to allow users to compare costs associated with different road surface types and the maintenance of various surface types and aids in the selection of the appropriate surface for a given set of circumstances. At this time, the tool can be used for counties in Minnesota, North Dakota, and South Dakota http://dotsc.ugpti.ndsu.nodak.edu/SurfaceSelection/

Context Sensitive Roadway Surfacing Selection Guide is a road surface selection tool that is designed to incorporate context-sensitive design parameters from the beginning planning stages well into design and construction. The guide provides a surface selection tool, which can be integrated easily into current processes, allows for multidisciplinary input, and provides a broad list of possible road surfacing options [Maher, M., C. Marshall, F. Harrison, and K. Baumgaertner, Context Sensitive Roadway Surfacing Selection Guide, 2005

Development of Guidelines for Unsealed Road Assessment” is a journal article summarizing the manual developed for the unified standard assessment of unsealed roads in South Africa in collaboration with the South African Committee of Land Transport Officials. The manual outlines various criteria for visually assessing an unsealed road surface in an effort to provide continuity and consistency across the many road authorities in South Africa [Jones, D., P. Paige-Green, and E. Sadzick, “Development of Guidelines for Unsealed Road Assessment,” Transportation Research Record: Journal of the Transportation Research Board, No. 1819, Transportation Research Board of the National Academies2003, pp. 287–296″


Center for Dirt and Gravel Road Studies (http://www. dirtandgravel.psu.edu/

Minnesota Local Road Research Board (LRRB) (http:// www.lrrb.org/ Minnesota Local Technical Assistance Program (LTAP) http://www.mnltap.umn.edu/topics/lowvolume/

North Dakota State University, Upper Great Plains Transportation Institute (NDSU/UGPTI) http://www.ugpti.org/

South Dakota Local Transportation Assistance Program (LTAP)  http://www.sdstate.edu/engr/ltap/  Transportation Engineering and Road Research Alliance (TERRA)  http://www.terraroadalliance.org/  TRB Low-Volume Roads (LVR) Committee and Conferences  http://www.trb.org/AFB30/AFB30.aspx

Unpaved Roads Institute (URi) http://unpavedroadsinstitute.org


Abdel-Warith. 2014. Simple Empirical Guide to Low-Volume Road Design. TRB 2014 Presentations of Interest County Engineers Research Focus Group.

FHA. July 1994. Roadway widths for low-traffic volume roads. Federal Highway Administration, Research and Technology, FHWA-RD-94-023.

Transafety. February 1, 1997. Road Management & Engineering Journal. Transafety.


Faiz, Asif. September 2012.  The Promise of Rural Roads. Review of the Role of Low-Volume Roads in Rural Connectivity, Poverty Reduction, Crisis Management, and Livability. Transportation Research Circular E-C167. Transportation Research Board, National Research Council.  52 pages.

roads worldwide kilometers paved unpaved








Everything that sustains us—grown, mined, or drilled—begins on a low-volume road.

Nearly 30 million km of low-volume roads connect the world’s population.

The contents of this e-circular are based on research and analysis undertaken by author Asif Faiz in his individual capacity. The conclusions and recommendations contained in this document are those of the author, and do not reflect the views of TRB or the National Academies.


There is no universally accepted average annual daily traffic (AADT) threshold for defining a low-volume road. AASHTO in its Geometric Design Guidelines for Very Low-Volume Local Roads specifies an AADT of 400 or less. For purposes of geometric design standards, the working criterion for most researchers in the field is around 2,000 AADT for LVR and 400 for “very” LVR. The definition, however, varies widely across jurisdictions with the upper limit being as high as 5,000 AADT. — Mike Long Chair, TRB Low Volume Roads Committee

About 33.8 million km of roads girdle the Earth’s land mass of 148.9 million km2 (an average 0.23 km/km2 of land area); about 57% of it is paved (i.e., sealed with an engineered bituminous, concrete, or stone surfacing).

Nearly all the unpaved roads (13 million km) and an estimated 85% of paved roads (17 million km) are LVRs with an average annual daily traffic (AADT) of 1,000 vehicles per day (vpd) or less.

In this review, an AADT threshold of 1,000 vpd is used for defining LVRs. This is a common traffic threshold considering worldwide practice, at which higher design speeds and related standards (wider lanes, paved shoulders, gentler curvature) kick in.

In its report on U.S. Highway Statistics, 1 FHWA aggregates all rural arterials with an AADT of 1,000 or less in a single category. Irrespective of the AADT threshold (ranging from 400 to 1,000 vpd), LVRs account for about 80% to 85% of the global road network and very low-volume roads (VLVRs) account for about 70% to 75%. An AADT threshold of 5,000 would encompass nearly 98% of the world’s roads.

These 30 million km of classified LVRs have a wide variety of geometric and paving standards ranging from barely motorable earth roads to modern high-speed two-lane paved highways. The global asset value (replacement cost) of these LVRs is conservatively estimated at about US$7.6 trillion (a lower-bound estimate), equivalent to about 50% of the estimated 2010 gross domestic product (GDP) of the United States. Beyond this classified system is another realm of designated trails, tracks, and paths as well as minor roads that serve enclave development (mines, industrial estates, agricultural plantations, irrigation schemes, tourism, forestry, etc.), and together number into millions of kilometers and also contribute to basic access and mobility.

The global public road network increased by some 3.9 million km (a 13% increment) in the first decade of the new millennium (1–3). And there was a quantum increase in the quality of roads with 4.2 million km upgraded or constructed to paved standard.

Road Expansion and Modernization in China Over the last decade, China has emerged as the global leader in rural road expansion and modernization with its road network crossing the 4 million km threshold in 2010 and the share of paved roads increasing from about 25% in 2000 to 44% in 2006 and 61% in 2010.

The United States has the largest road system in the world (6.52 million km in 2009, with 67% paved), growing from about 3.71 million km in 1900 to 3.89 million km in 1910; 4.97million km in 1920; 5.30 million km in 1950; and 6.32 million km in 2000. About 26.4% of the system is classified as urban and about 84% of total network (63% of urban and 87% of rural) has an AADT of less than 1,000.

Wilfred Owen in his classic study of transport and communications in India— Distance and Development — noted that in 1949 “the U.S. had 2.5 million miles of local rural roads. Yet despite the high degree of mechanization and motorization of America’s farms, more than half of this local (rural) road network was unsurfaced earth roads and 90% of the surfaced mileage was gravel. The most important functions of these rural roads were as routes for mail delivery (1.5 million miles), school buses (700,000 miles), and milk collection (500,000 miles)”. In 1945, 64% of all American farms were on an all-weather road and only 10% were less than a mile distant. The primary focus of road building was on grading and drainage and half the annual expenditure on rural roads (for the system as a whole) was for maintenance. But he went on to caution that a substantial percentage of local roads built in the United States up to 1950 rendered little or no service of any kind. According to an estimate by the U.S. Bureau of Public Roads (the forerunner of FHWA), about 400,000 miles of American local roads proved to be nonessential; the overbuilding of rural roads at the time, under the pressure of farm and political lobbies, cost U.S. taxpayer some $2.4 billion (in 1950 dollars). And the overbuilding of that era still casts a shadow on the ability of local governments in the United States to maintain and service this vast network of rural roads, further expanded, improved, and upgraded during the next 50 years.


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House hearing 2014: Should the U.S. export oil and natural gas?

[Of course selling off our gas and oil is a crazy stupid idea as this excellent article Shale Euphoria: The Boom and Bust of Sub Prime Oil and Natural Gas explains.  Alice Friedemann   www.energyskeptic.com ]

House 113–131. April 2, 2014. The Crude truth: evaluating U.S. Energy trade policy. House of Representatives. 67 pages.

Until recently, United States crude production had been on a steady decline. In 1970, domestic production peaked at 9.6 million barrels a day. By 2008, we were producing almost half. Only 5 million barrels were being pumped per day. Then America did what America does best, and innovated. New technologies of horizontal drilling and hydraulic fracturing ushered in an American energy revolution. Because of drilling in places like the Bakken and Eagle Ford, U.S. crude production has increased 56% since 2008. Some experts even believe that the United States will become the largest crude producer in the world by next year.

But not all is good news. The oil being found in these places is light sweet crude. Unfortunately, the majority of the refineries connected to the production sites are built to handle heavy sour crude. We need new refineries, new pipelines to be built to process the light crude but, of course, that will take years. In the meantime, we should sell our light crude abroad to those who want to buy it. That would bring billions of dollars and thousands of jobs into the economy of the United States. It is an obvious solution for a simple problem. Unfortunately, the Federal Government seems to be in the way again. In 1975, the Energy Policy and Conservation Act was passed, making it illegal to export United States crude. It was at the height of the Arab oil embargo. Congress wanted to insulate Americans from global price shocks and conserve domestic oil reserves. In reality, this ban achieved neither of those goals. The ban has not insulated United States consumers from the world market.

Domestic gasoline prices are largely set by the global crude price, not domestic price, since crude is a globally traded commodity. The United States still has to import about 46% of our crude. These imports face market uncertainty just like every other traded good. Lifting the ban is what would actually protect domestic consumers. U.S. crude on the world market decreases the market share of bad actors like Iran and unstable countries like Algeria.

For producers to want to drill they have to have a profit or make a profit. The crude export ban has driven the domestic price of crude so low that producers will not be able to make money off the drilling. If something isn’t done, economists predict the drilling will slow in the next 18 to 36 months. Perfectly good oil will sit in the ground because the government restrictions are in the way.

So domestic production companies are forced to cut back on drilling and they are going to also be forced to lay off American workers.

Brad Sherman, California. We have had several hearings on the export of natural gas both in the subcommittee and at the full committee. I believe this is the first to focus on the export of petroleum. These are dramatically different economic situations.

You can ship a barrel of oil most of the way around the world for maybe 1% of its value whereas natural gas, to liquefy, transport and then re-gasify you are talking about 40% of its value.

There are some bottlenecks because every barrel of oil produced in the United States with the exception of some on the Alaska North Slope and 25,000 barrels of heavy crude oil from California has to find its way to the U.S. market and so there could be problems of a short-term nature and you could see 1% wasted effort as we transport Alaskan crude to U.S. markets when it might be more efficient to transport Alaskan crude to Asian markets and import more from Africa or the Middle East. As we focus on the possibility of exports, I think a number of questions arise.

First, what it will do to jobs, particularly in the shipping industry. We now have a requirement that domestically shipped oil has to be shipped on U.S. flagged, U.S. crewed—that is to say U.S. staffed ships but not necessarily ships built in the United States. Do we want to go further and require that the ships be built here and how important is that for our national security to have the infrastructure of U.S. shipbuilding and a merchant marine? We also have to look at whether we can require U.S. ships be used for the export of oil to Asian markets. Another issue that comes up is the federal—is the possibility of free trade agreements. We already see that free trade agreements with regard to natural gas indicate that it is automatically considered in the national interest to allow exports of natural gas to countries that we have free trade agreements with. Will the same apply to petroleum? Will the same apply to the Trans Pacific Partnership currently under negotiation? And under those trade agreements will we be able to require U.S. flagged ships, ships with U.S. crews, and U.S. built ships? To me, the most important thing in allowing export is what will happen if there is a worldwide shortage or a market disruption. Why do we ban the export of U.S. crude? We did it in 1975 because we lived through 1973, and I think that we want to be in a situation where it is both legal and practical to require that U.S. crude be used only in the United States during a period that resembles 1973—when there is a shortage, a market disruption, a boycott or gas lines from some other source.

We can put that in law so it is legal and if the President declares a disruption of world petroleum markets but it also has to be practical. What will be the effect on our foreign relationships if in the middle of a worldwide shortage we stop oil tankers in the middle of the Pacific and require them to return to U.S. ports? What will be the practical effect of bringing that oil back, knowing that we will have built infrastructure on the idea that the U.S. will both export and import petroleum and now all of a sudden we are hoarding our own production for our own purposes? So I look forward to trying to resolve these problems because it is bad for our economy and bad for the environment to transport oil further than it would otherwise need to go or to mismatch produced oil with the refinery capacity, and I think it is in the interests of the environment not to have to transport oil further than it would otherwise have to go. Every ship is producing greenhouse gases.

Edward R. Royce, California, Chairman. I think you are holding a very important hearing at a very important time here as we start to think strategically about what it means in a world in which the United States increasingly has the capacity to ship oil to allies that are really under a great deal of pressure and how that could be used as part of our diplomatic efforts, for example, with Iran to maintain sanctions.

One of the things that I think should give us pause is that in our efforts to deny the regime in Tehran nuclear weapons capability the United States and our European allies levied devastating sanctions against Iran by doing one thing primarily in the original bill and that was targeting their ability to export oil and that severely limited their crude oil sales and denied them the ability to repatriate hard currency from those sales. Now, the sanctions against Iranian crude are often described as Iran’s Achilles heel, yet we are imposing the same kinds of sanctions on our own country since without a crude export relief valve oil companies will pull back on what will be increasingly uneconomic production. And the relief valve here is one that we could have used more effectively with respect to our allies because there were five of our allies that were still taking oil shipments from Iran. We could have supplied that differential. We could have brought additional pressure to bear, and should again this situation in Iran not be—not be solved in ensuing months or years, my hope is that we will have the capacity to think about what we could do in order to step in.

At the same time, the Russian annexation of the Crimean Peninsula was made easier by its energy grip over Eastern Europe and especially over Ukraine. Russia has large oil and gas reserves, not as large as ours. They don’t produce as much as we do but they do—but almost as much, and it accounts for 70% of their trade and 52% of the budget for Russia that goes to support their military and their government. The crisis in Crimea has done little to dampen Russian oil sales and Putin is freely selling oil and gas around the world and especially in Eastern Europe at monopoly prices and thus has unfortunately a tremendous amount of influence there. As we look at our strategies for the future, and I am going to quote General Martin Dempsey here, Chairman of the Joint Chiefs of Staff, he says, ‘‘As we look at our strategies for the future I think we have got to pay more and particular attention to energy as an instrument of national power, and I think that has to be factored in to the equation here. ‘‘If we increase our supply of oil, especially into Eastern Europe, we will dent Russia’s leverage on other countries and reduce the revenues that fund Russia’s aggression.’’

Lisa Murkowski, Alaska. In the Energy Committee we held a hearing on this issue several weeks ago. It was the first time in 25 years that there has been a hearing in the United States Senate on the issue of oil export. And put that into perspective. We haven’t had the opportunity to talk about it because we have been evaluating our energy portfolio truly from one of scarcity rather than one of abundance and how the landscape has changed. So this debate—this dialogue that you are beginning here in your committee is greatly appreciated and, again, very, very timely. Let there be no mistake that today’s issue—the ban on crude oil exports—is truly one in the national interest. In an area of doubt—of debt and deficits, the North American energy renaissance presents us with an opportunity to strengthen our position and resolve on the global stage while generating wealth, creating jobs, reducing our deficits and enhancing our national security.

Michael Jennings, CEO & President, Holly Frontier Corporation. We are a domestic independent refining company. We operate five petroleum refineries in the Central and Rocky Mountain states. We employ about 2,600 people directly and indirectly, a number that is probably 10 times that many associated with our contracted maintenance work. Our company is a merchant refining company. That means that we buy crude oil from those that produce it. We also have a wholesale marketing strategy so our products are distributed through convenience stores and big box retailers, none of which bear our name. But our products go out to a market that is in the center of the United States. We produce about 2.5% of the nation’s gasoline, diesel and related petroleum products through our plants each day.

As a merchant refiner, the key messages that I hope to convey to the committee today are as follows. Crude oil exports by the United States are likely to raise domestic crude prices and increase retail gasoline prices in the markets that our company serves by an estimated 10 to 15 cents per gallon of gasoline. Crude exports on the part of a country that imports nearly half of its crude oil requirements are, in our view, very unlikely to improve energy security or advance national interest as we will simply make ourselves more dependent upon crude oil imports as we export our own crude, and we need to be thoughtful about the nations from whom we would be importing that crude. Those with surplus are the OPEC producers and Russia.

The U.S. refining and petrochemical sector is a major employer and is making hundreds of billions of dollars of new investments over the next 10 years to increase manufacturing processing capacity along the Gulf Coast and in other places in order to manufacture and convert this wealth of new raw material that is being produced in the upstream.

We believe that this expanded production has helped in terms of our nation’s energy security. But though great strides have been made, the United States remains very dependent upon imported crude. This is not my opinion or the opinion of our company, simply a statement of the facts.

Current refining requirements are approximately 17 million barrels a day while domestic crude production was about 7.5 million barrels per day in 2013. That is projected to increase by a million barrels per day in 2014 but we are still importing at about 50% of our requirements. Supporters of lifting the ban on the crude exports argue that such a decision would make a move toward a freer global supply function, and certainly our company supports the development of freer energy markets. However, we have to be conscious of the fact that the global crude market is not occupied by free trade. It is dominated by OPEC, which is a cartel, and the country of Russia. Neither of these entities have free trade at their hearts. They are protecting their own domestic interests in cartel-setting volume requirements and other behavior.

I spoke earlier about the impact of pricing on U.S. gasoline in the face of potential crude oil exports, and our company’s view of that is there is probably a 10 to 20 cent per gallon uplift in the cost of gasoline, again, in the markets that we serve which would result from this policy decision. We take that by observing markets that are served by waterborne crude, principally New York Harbor, southern California and northwest Europe, and if we look at those gasoline prices wholesale pre-taxed against the prices that are traded in our markets supplied by domestic crude, we are seeing a 10 to 20 cent differential, with customers in Kansas, Oklahoma and Texas paying the lower number. We think that is something that the committee should take into consideration.

Government run national oil companies control approximately 85% of the world’s crude oil and 58% of production. In addition to these figures, and equally important to global prices, oil exports by the Organization for Petroleum Exporting Countries, or OPEC, constitute approximately 60% of the total petroleum traded internationally. EIA notes: “Due to the diverse situations and objectives of the governments of their countries, these national oil companies pursue a wide variety of objectives that are not necessarily market-oriented.” The level of control of the global crude oil market by national governments and a global cartel belies any claim that the market is free and open. With its market power, OPEC effectively influences crude oil production, supplies and pricing throughout the world through quotas and other controls. The facts make clear that OPEC controls supply to maintain prices where the member countries (including Iran, Iraq, Saudi Arabia and Venezuela) want them to be. OPEC is a cartel, and its existence is designed to control crude oil prices and preserve is members’ own domestic economies. Though American production has increased dramatically, it has not yet matured to the point at which it could significantly impact the price of crude in the global market.

The bottom line is that cheaper domestic crude means cheaper gasoline for consumers. This differential in pricing also means that consumers pay less for heating oil, propane and other critical petroleum products. As I have already stated, there exists a robust domestic demand for gasoline and other refined products in the region in which our company does business. 26 of the nation’s 139 refineries are located in the Midwestern and Plains states.

These plants process 3.7 million barrels per day of crude oil and produce 78 million gallons per day of gasoline and provide stable and high paying jobs for our workers. In this same region, gasoline demand is approximately 100 million gallons per day, a demand that is not readily shifted to other fuels or transportation sources given the predominantly rural and agricultural geography that comprises our market place. Exports could potentially raise costs and slow growth in an area of the country that is driving the American economy. In closing, we believe that any discussion of crude oil exports must be had in the broader context of developing a comprehensive 21st century energy policy for our nation. Though the expansion of production of crude oil in the United States has positively impacted consumers and our overall energy security, it does not tell the whole story. A meaningful discussion requires not only consideration of crude oil exports; but a consideration of the mandates created by the renewable fuel standard, completion of the Keystone XL pipeline and other infrastructure to support free flow of petroleum and products, a review of the EPA’s onerous Tier 3 gasoline rule, and a robust discussion on the future of domestic energy infrastructure. A holistic view is necessary in making decisions that will both shape energy policy, and help drive economic growth for decades to come.

A specific area of focus must be the renewable fuel standard. Insofar as our country has reached a point of security and independence in our crude supply to lift the export restrictions, it would be clear that we have no further need for the costly and inefficient crop-based fuel mandates created by the RFS to promote energy security. These bio-fuel mandates have and continue to drive up prices at the pump for American consumers and distort the price of refined petroleum products. Accordingly, I would encourage Congress to keep the RFS in mind as it debates issues associated with potential export of domestic crude.

Erik Milito, Upstream Director at the American Petroleum Institute. API has more than 580 member companies, which represent all sectors of America’s oil and natural gas industry. Our industry supports 9.2 million American jobs and 7.7% of the U.S. economy. The industry also provides most of the energy we need to power our economy and way of life and delivers more than $85 million a day in revenue to the federal government.

Today, America is producing nearly 50% more oil than we did in 2008. By 2015, International Energy Agency predicts the U.S. will surpass Saudi Arabia and Russia to be the world’s top crude oil producer. This is a new era for American energy, but our energy trade policies are stuck in the 1970s. The U.S. and China are the only major oil producers in the world that don’t export a significant amount of crude. It’s time to unlock the benefits of trade for U.S. consumers and further strengthen our position as a global energy superpower.

There also are strategic reasons to increase U.S. energy exports. As General Martin Dempsey, Chairman of the Joint Chiefs of Staff, recently said, “An energy independent and net exporter of energy as a nation has the potential to change the security environment around the world – notably in Europe and in the Middle East.” As we grow as an exporter, U.S. energy leadership has the potential to bolster America’s allies, expand our geopolitical influence, and our own self-imposed restrictions.

Kenneth B. Medlock III James A. Baker, III, and Susan G. Baker Fellow in Energy and Resource Economics, and Senior Director. Center for Energy Studies James A. Baker III Institute for Public Policy Rice University

During the past decade, innovative new techniques involving the use of horizontal drilling with hydraulic fracturing have resulted in the rapid growth in production of natural gas, crude oil and natural gas liquids from shale formations in the United States. This has transformed the North American gas market, generating ripple effects around the world and setting the stage for a period of global market transition. It has also contributed to the benchmark US domestic crude oil price West Texas Intermediate (WTI) becoming substantially discounted to global benchmark crudes. While this discount arose largely due to constraints on the ability to move crude oil away from Cushing, OK, it has triggered concerns that it is a harbinger of broader discounts of US crude oil prices relative to global market prices. Specifically, if a constraint on the ability to arbitrage a price differential drove the discount of WTl, then it stands to reason that a constraint on the ability to arbitrage US crude will more broadly emerge as the existing constraint banning US oil exports becomes binding. As a result, there has been significant interest in changing the long-standing laws banning oil exports.

Global crude oil demand is projected to increase to just short of 120 million barrels per day by 2040. The majority of the projected growth will come from developing Asian economies, particularly China and India, but also several other Asia-Pacific countries.

Importantly, demand in the countries of the Middle East is projected to grow among the fastest in the world, attributed to economic growth as well as heavily subsidized domestic energy prices. Of course, a lifting of subsidies would abate the projected growth, but absent a significant shift in domestic energy pricing policy, these countries will be challenged to maintain, much less grow, exports.

This signals a need for new sources of supply, and could move the geopolitical compass toward new supply growth areas, particularly those with abundant, accessible unconventional resources such as Canada and the US.

Of course, declining demand since 2008 has played a major part as well. This is particularly salient for petroleum product markets, as the US now exports (net) upwards of 3.5 million barrels per day of petroleum products, in fact, the combination of discounted crude oil, low cost natural gas, lower demand, and no policy-directed constraint on exporting refined products has allowed the U.S to effectively become a refining hub over the past few years, providing petroleum products to the global market place.

A Comment on Energy Security

The concept of energy security really began to take hold as a matter of national interest following the oil price shocks of the 1970s. In fact, every recession since World War II, except one, has been preceded by a run up in the price of oil. This strong correlation has prompted many policies aimed at mitigating the impacts of rising oil prices. As such, “energy security” generally refers to policies that aim to ensure adequate supplies of energy at a reasonable price in order to avoid the macroeconomic dislocations associated with energy price spikes or supply disruptions. So, how exactly do high oil prices negatively impact the economy? The literature on this matter is fairly deep, and there have been many proposed channels to convey the correlation, some of which carry a causal overtone.

… inflationary effects

  • Increases in the price of oil (energy) lead to inflation which lowers the quantity of real balances in an economy thereby reducing consumption of all goods and services.
  • Counter-inflationary monetary policy responses to the inflationary pressures generated by oil (energy) price increases result in a decline in investment and net exports, and consumption to a lesser extent.
  • trade balance effects Oil (energy) price increases result in income transfers from oil (energy) importing countries to oil (energy) exporting countries. This, in tum, causes rational agents in the oil (energy) importing countries to reduce consumption thereby depressing output.

… industrial influences If oil (energy) and capital are compliments in the production process, then oil (energy) price increases will induce a reduction in the utilization of capital as energy use is reduced. This, in turn, suppresses output.

If it is costly to shift specialized labor and capital between sectors, then oil (energy) price increases can decrease output by decreasing factor employment. If a recession is not unreasonably long, the high costs of training will cause specialized labor to wait until conditions improve rather than seek employment in another sector.

… and investment impacts In the face of high uncertainty about future price, which may arise when a price shift is unexpected, it is optimal for firms to postpone irreversible investment expenditures. Investments are irreversible when they are firm or industry specific.

Deborah Gordon Senior Associate, Energy and Climate Program Carnegie Endowment for International Peace. I began my career with Chevron as a chemical engineer and then spend over two decades researching transportation policy at Yale University, the Union of Concerned Scientists, and for a wide array of non-profit and private sector clients. I have authored books and many reports on transportation and oil policy making.

The U.S. is the major energy nation that is closest to being equal parts oil producer and oil consumer. Our energy situation stands in stark contrast to other nations. For example, China and Japan are majority consumers and Saudi Arabia and Russia are majority producers. America is in an enviable energy and economic position. We won’t want to either hoard or hand over all of our resources without first establishing policy goals and strategies. The challenge will be to determine what policy frameworks will balance the nation’s long-term oil trade objectives, national security, and global climate concerns.

Question #1: Given that the u.s. can already export unlimited volumes of petroleum products, under what conditions should if also be allowed to export crude? American crude generally cannot be exported, but there is no legal limit to exporting certain raw ultra-light oil components (natural gas liquids and condensates) and refined oil products. As of January 2014, product exports have increased 4-fold over the past eight years to 3.6 million barrel per day. Today’s oil trade is increasingly driven by valuable diesel, gasoline, jet fuel, and petrochemical feed stocks than crude oil. In 2013, the U.S. exported at least $150 billion in petroleum products, scoring the largest gain for any commodity in the U.S. economy.

A go-slow policy, will allow other nations to adjust to North America’s increased oil capacity. Those oil-rich nations that have built their economies on oil revenue are increasingly vulnerable to disruption. While reversing the export ban could increase global energy competition, it is also likely to change market dynamics and redirect refined product trade flows. It is unclear how the oil value chain will adjust in response to changes in upstream production and downstream refining factors. U.S. oil export policies must take these dynamics into consideration. Fostering market stability should be a primary consideration in deciding what conditions should apply to the U.S. in terms of future crude and petroleum product exports.

Question #2: Who would benefit most from reversing the U.S. oil export ban? Answering this question is not straightforward. It is unclear where exactly American light tight oil (LTO) fits into today’s oil value chain. Fracking in the U.S. is producing a different type of oil than Canada and increasingly OPEC are producing. And not all LTO, arc alike. Despite their generally high quality (light and sweet), U.S. LTO gravity ranges widely from 30 to over 70 degrees API-a huge spread. The Lightest of these oils are more like natural gas than conventional oil. Many U.S. and overseas refineries, have been retrofitted to handle heavy, sour oils, and cannot be fed a steady diet of LTO. In order to process Eagle Ford and Bakken oils, significant volumes of heavy oil must be imported and blended into LTO feedstocks. Depending on their quality, some LTOs may be better suited to petrochemical manufacturing.

Determining who benefits from exporting LTO is not simple. Oil producers (IOCs and independents), refiners, manufacturers, and the public each have different objectives that relate back to price spreads and uncertainty, and may not align with U.S. policymaker’s goals.

Figure 3: Price History for Selected Crude Types Oil producers and LTO leaseholders strongly advocate lifting the export ban. These stakeholders are responding to the potential for domestic LTO saturation in the Gulf Coast, widening price differentials between WTIILLS and Brent benchmarks, and an overly-simplistic view that easing the export ban would facilitate selling off more of the crude at a higher price from the Bakken, Eagle Ford, and o!her LTO oilfields. Industry analysts like Woodmac argue, however, that elude markets are complicated with different prices for various transportation mode and oil qualities. As such, relaxing the oil export ban may not necessarily eliminate the LTO discount to Brent. Instead it could invite cost-cutting arbitrage of U.s. and international crudes with unpredictable outcomes.

Refiners are split on whether or not to lift the ban depending on numerous operational and geographic factors that determine their bottom line. To the extent the ban discounts U.S. crude to Brent, large U.S. refiners enjoy higher petroleum produce profits. Other U.S. refiners that can preferentially handle LTO also favor the export ban. Those refiners who cannot handle U.S. LTO feedstock because their infrastructure is designed for on low-quality oil imports from Canada, Mexico, and Venezuela are in favor of free trade and do not oppose ending export restrictions. European refiners who can better handle L TO and desire greater competition to moderate Brent pricing are in favor of loosening the U.S. oil export ban.

Manufacturers may not yet have a unified position. Chemical companies took a strong position on LNG exports. But major manufacturers have yet to do so on oil exports. Petrochemical companies worry that lifting the ban could increase the price of domestic crude, which now trades for less than its international counterpart. Still others believe that more oil in the global market will drive down energy prices and create jobs in the United States.

American consumers are concerned about what exporting U.S. oil will mean for gasoline prices. Simple assumptions-more oil at home means energy independence that will lower gasoline prices-lead to misperceptions. Prices are greatly influenced by global factors. Market volatility could be a real challenge in the future. And, in order for LTOs to be produced, global oil prices must remain high. The end of cheap oil and gasoline is over despite the U.S.’s new oil bounty.

GORDON. So about 10 years ago, 8 years ago, before light tight oil was really on anyone’s radar screen and even EIA missed it—everyone missed it, and there are reasons why separately I can discuss—but the move was made to change the entire refining sector to deal with what oil we thought was going to be the last oil on earth, this heavier barrel. And so now we have a situation where billions have been put into U.S. refineries up and down the Mississippi and into the Gulf that handle selective oils best—they are complex refineries and they handle the extra heavy oil. These refineries make diesel. They make more diesel, and diesel goes to your question—has a very high export value. We are exporting a tremendous amount of diesel. The light tight oils that now we found out we have and we don’t really yet have the refining capacity for make, preferentially, gasoline, which is the product we use, so you can imagine ships crossing in the night, you know, with all of this global trade where oil would go one way. It will get refined someplace else. The product will come back.

Mr. PERRY. Thank you, I just want to maybe go back to this last question about refined as opposed to unrefined. It seems to me that the refined product would be more dangerous maybe to the environment if it would spill as opposed to crude oil that comes from the ground—comes from the earth. But if I am wrong—am I wrong or—makes no difference whatsoever. We don’t care whether we spill gasoline or oil or crude. It is all the same?

Mr. JENNINGS. The refined product will evaporate if spilled and crude oil will not. So there is a difference. Worse to the water would be the crude oil, which would be residual in the water, where as to the air would be

Mr. MEDLOCK. But there is a difference between a naturally occurring seep and a spill. A naturally occurring seep is actually part of the local ecosystem that has evolved over thousands of years typically, whereas when you talk about a spill it is an introduction of a raw crude into an area that is not equipped to cope with it. So it is different.

Ms. GORDON. And I just wanted to add, because oils are now so different from each other—we still talk about it as oil coming out of the grounds—but the light tight oils, some of them, especially coming out of the Eagle Ford in Texas, are so light they are condensate and that is what Senator Murkowski was talking about maybe trying to change the definition of oil, and some of the oils coming out of the ground in Venezuela and Canada are so heavy they are on their way to coal. So we are talking about the definition of oil, hydrocarbons, really changing where it is not necessarily one thing anymore. It is a collective of a lot of different hydrocarbon arrangements.

Mr. JENNINGS. The refining system in the United States is, obviously, capable of making the different boutique fuels that are required in different markets throughout the country. They relate principally to vapor pressure, how volatile the material is, octane and now sulphur content is a big focus. The international standard often requires the tighter end of those specifications and so the export barrels typically will be those that would qualify for the most stringent U.S. markets as well.

Mr. PERRY. At what point in this discussion are producers going to leave the oil in the ground? Are we already doing that because refining capacity doesn’t exist? Is that already occurring now and if it isn’t at what point would that occur or will it never occur?

Mr. MEDLOCK. It will certainly occur if the discounts actually get to be sufficient enough. Currently there are a couple different things that are working against this. It is not just an export issue. It is also an infrastructure issue because currently in the Bakken, for example, in North Dakota we move a lot of that crude by rail, which is an order of magnitude more expensive than moving it by pipeline. And this goes back to, you know, getting the appropriate infrastructure in place and there is, obviously, a policy overlay here. But if you were to actually have the pipeline infrastructure in place to move that crude effectively, the netback to the wellhead would be priced $18 to $20 higher. And so that buys a lot more activity in the field. So it is, you know, I hate to focus this only on the export issue because it is broader than that. It actually is—it matriculates down in the infrastructure to move away from the wellhead. And moving crude by rail is a lot more expensive than moving it by pipe.

Ms. GORDON. I was just going to add because it came up, the, you know, consumers and the economy, of course, with oil and gasoline comes up all the time. These oils, if they are stranded in the ground, it will be because the price is too low. It will—it will take a much higher price. So we are talking about more abundance at a high price. This is so different than the 1970s where we were talking very low prices and then supply was getting stuck. This is a lot of capacity—physical capacity of hydrocarbons in the earth that can get out of the ground if the price gets really high. So we are not really—we will see volatility in the market but it is going to have to trend upward to get these oils into the market and move them around and refine them.

Mr. JENNINGS. The Middle East is still producing and exporting 10 to 15 million barrels per day of oil. Even with what we and our North American allies could do, I don’t believe in the near future in our lifetimes we are going to offset that effect.

Mr. YOHO. But it is possible. We can’t use oil or the petroleum products as a strategic diplomatic tool if we do not update our export oil policies and I for one will support the repeal of this policy to increase the ability for us to export so that we can use that as a bargaining chip.

Mr. Milito and Dr. Medlock, do you feel it is possible for us to achieve energy security in the U.S.?

Mr. MILITO. I think we are doing that right now with this tremendous advance in production that we are seeing. Going from 5 million barrels a day to 10 million barrels a day in just a few years is incredible. Nobody would ever have imagined that. Same on the natural gas side. We are expected to import $100 billion a year in natural gas and now we are looking to export.

Mr. YOHO. Well, I mean, that is just it. I mean, 10 years ago we were going to have to export all this but through technology and better techniques we are going to be a net exporter. Do you feel that we could be a net exporter on petroleum products too?

Mr. JENNINGS. First, I want to dispel the myth that it is just light or just heavy. Inside every heavy refinery is a light plant where you are going to not use the full kit. So these plants can refine light crude but not on an optimized basis. They don’t fully use all the capital. Probably half to five-eighths of our country’s refining capacity has capability to cut deeper into the heavy and sour barrel and make gasoline and diesel out of it and the remaining 30, 40% doesn’t have that capacity. What I would say, though, is that this is a snapshot at a point in time. There is a lot of investment being made—condensate splitters, and other things that refining plants are doing. We had one in Cheyenne, Wyoming, that was almost 100% running heavy Canadian. Now we run 50% Canadian, 50% light Bakken.

Currently, the United States is exporting about a million and a half barrels per day on a net basis of refined petroleum products.

Mr. SHERMAN. I would point out on the idea of Ukraine they can’t afford to pay Russia $10 a unit. Japan pays us or is paying $16 so if we were exporting natural gas the Japanese would be offering far more than the Ukrainians could afford to pay unless we want to tax the American people more so that we can provide $6 a unit.

The dream of the—of environmentalists I know is that the tar sands of Canada are never exploited. There are those who say they will build the pipeline—the Keystone. The environmentalists think they can stop that. There are those who say the Canadians will go east or west. There are Canadian environmentalists who are in touch with my California environmentalists who think they can stop that. How uneconomic is it to put that Canadian oil into tanker cars, take it on railroads to a U.S. domestic pipeline and then have it proceed? In other words, if we—if the environmentalists stop the Keystone—stop any pipeline—any Canadian pipeline and they stop any international-U.S. pipeline, can domestic U.S. pipelines bring that oil to the market economically although at lower profits to those who own the tar sands?

Ms. GORDON. Well, it is pretty powerful. You know, the investments up there, at least for the mined bitumen, which has all been invested, it wants to get out and it will do so at a lower profit if it means, you know, mothballing everything that is ready to get out there. So right now, it is moving by rail. There is—I think it is Valero, can’t remember who—someone has put in a variance actually that would take rail bit, which is the diluted—slightly diluted bitumen that you put on rail and then it would just put it right onto a tanker so it would come through—the question would be, is this even U.S. oil? I mean, are we just exporting foreign oil out of Texas by putting Canadian oil on bunkers?

Mr. SHERMAN. So bottom line, that Canadian oil—those tar sands will be exploited. If it is inefficiently on tanker cars it is still more economic than leaving that tar sand in the ground and—do I have that right?

Ms. GORDON. Yes, for the mined bitumen, which is about 20% of the resource, because all of that investment has been made. Big question mark for the in situ, the really deep bitumen that they have to heat out of the ground. It might be that investments aren’t made if it is difficult to move it to market. And then the big question about the oil sands is what do you do with the bottom of the barrel. If we could think of a way to get rid of that pet coke—the bottom of the barrel—they really wouldn’t be that different from any other oil. It is just that they have a very large bottom of the barrel.

Mr. JENNINGS. The difference in price to ship crude by rail versus pipeline from Canada to the Gulf of Mexico is only about $6 a barrel—$5 or $6 a barrel. That isn’t going to go into the producer’s decision making of whether or not to develop incremental oil sands capacity.


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Yet another 2013 house hearing about U.S. energy independence

House 113-1. February 5, 2013. American energy security & innovation: an assessment of North America’s energy resources. House of Representatives. 202 pages.

[Excerpts from the 202 page transcript of this hearing]

Representatives and speakers declaring the U.S. energy independent:

  1. Ed Whitfield, Kentucky
  2. Fred Upton, Michigan
  3. Joe Barton, Texas
  4. Daniel Yergin, Vice Chairman, IHS
  5. President Obama
  6. Harry Vidas, Vice President, ICF International

ED WHITFIELD, KENTUCKY: The title of today’s hearing is ‘‘American Energy Security and Innovation,’’ and we are going to focus on an assessment of North America’s energy resources. Certainly, one of the primary factors that affects the economy is energy policy, and certainly there are other factors as well but that plays a vital role.

I was reminded as I read the testimony last night that it wasn’t too many years ago when people throughout the country, experts and otherwise, were talking about the United States fossil fuels, for example, their resources were being depleted. We were running out of oil, we were running out of natural gas and we were going to have to be importing more. As a matter of fact, in January 2007, a CEO of one of our largest utility companies made the comment that we were running out of natural gas, production was declining and demand growing so he expected that imports would go from 3 percent of our national needs to 24 percent in 2020.

And then of course, we know what has happened. We have had all sorts of new discoveries—the Bakken field, the Eagle Ford, developments in Colorado—and most of these shale fields have been discovered on private lands, and even though the number of permits on public lands has gone down, the production on private lands has increased dramatically. So this is a real game changer. We have heard the term for many, many years, we have the opportunity to be energy independent, and that is actually the reality today, we have abundant resources that can meet the needs of this country on the electricity side and the transportation side for years and years to come.

We have seen increases in domestic oil production since 2007 and natural gas production since 2006, according to the Energy Information Administration. And EIA predicts that these upward trends will continue for years to come. At the same time, Canadian oil production is growing so fast that we will need the Keystone XL pipeline expansion project to bring the additional output to American refineries in the Midwest and Gulf Coast. In fact, the news is so promising that some analysts are talking about the possibility of achieving North American energy independence by the end of the decade. Of course, experts may disagree as to just how much energy potential is out there, but none would have claimed just a few years ago that our nation would reverse course and have the potential to become a true global energy supplier and powerhouse.

We are seeing a truly dramatic shift away from long-held beliefs about domestic oil and natural gas supplies. So much of our existing legislation is rooted in the assumption of domestic energy scarcity, not energy abundance. Needless to say, a wholesale rethinking of energy policy is in order, and today’s hearing is the first step in that process.

We will soon hear from one of our witnesses, Mary Hutzler of the Institute for Energy Research, America possesses nearly half of the entire world’s coal reserves. This is enough coal to continue its use at current rates for 500 years.

The good news is that a future of plentiful, affordable, and reliable supplies of North American energy is no longer just a dream.

BOBBY L. RUSH, ILLINOIS: The EIA reporting that U.S. crude oil production has increased from 5.1 million barrels per day in 2007 to 6.4 million barrels per day in 2012, the highest level since 1997. The EIA reports that in 2005, the United States imported 60 percent of the petroleum it consumed, and by 2012, that number had dropped to about 41 percent, the lowest level in decades. This decline can be attributed primarily to increased domestic oil production, the additional use of biofuels as well as the adoption of higher fuel efficiency standards for vehicles.

The EIA also projects that the United States will reduce its reliance on imported oil to less than 30 percent of consumption by 2035, and U.S. natural gas production will increase by 44 percent by 2040 due primarily to the projected growth in shale gas production.

FRED UPTON, MICHIGAN. Certainly, this hearing is a welcome one to examine the positive developments resulting from advancements in innovation and technology, the game-changing potential for North American energy independence. What was once believed to be unthinkable is certainly now within our grasp. For 3 decades, 30 years, the American people have been told that we are a Nation of declining resources at the mercy of OPEC. The story was nearly as gloomy with natural gas with forecasts of dwindling domestic supplies, higher prices, and rising imports from the Middle East.

In fact, in this committee, many may remember when we crafted a new title in the Energy Policy Act of 2005 to facilitate what we thought would be the new norm: pending reliance on imported gas from geopolitically unstable regions of the world, to add to our growing reliance on OPEC oil.

But thanks to American ingenuity and advanced technologies, the trends in domestic oil and natural gas production have in fact been turned upside down. In fact, the United States is now the world’s leading producer of natural gas, and the IEA is predicting that by 2020, U.S. oil production will exceed Saudi Arabia. 2020, let me repeat that, we are going to exceed the production in Saudi Arabia. Our overall energy landscape has changed dramatically in just a short period of time, and it is not only rewriting the economic outlook that we have as a Nation, but also beginning to change the geopolitical nature of global energy economics.

JOE BARTON, TEXAS. As we speak today, in the Barnett shale, there are over 16,000 producing natural gas wells, and last year they produced in the neighborhood of 2 trillion cubic feet of natural gas in that one field. With the miracle of hydraulic fracturing, we have unleashed a drilling and production revolution in this country, not only in natural gas but now that technology is being used in oil, and the State of North Dakota, which less than 10 years ago had probably fewer than 200 or 300 oil wells, is on track in that one State to produce over a million barrels of oil in the very near future, possibly this year. We can be energy independent if we want to. It is not a question of can we.

HENRY A. WAXMAN, CALIFORNIA. These are all positive developments. The question we must ask is whether we are on a sustainable course for the years to come. As we debate our energy future, this committee has a choice. It is an energy choice and a climate policy choice, and ultimately it is a moral choice.

Every decision to build a new fossil fuel-fired power plant, or construct a pipeline to transport tar sands, or drill for more oil off our Nation’s coasts has climate risks. We need to understand and weigh those risks before we lock in infrastructure that will produce carbon pollution for decades to come. There is an appeal to the energy resources we are discovering. We are stronger when we produce oil in the United States than when we import it from Saudi Arabia. We are better off when we produce our own natural gas than when we import LNG. But we also must recognize that the world has far more proven reserves of oil, gas and coal than we can ever safely use. The atmosphere has a rapidly shrinking capacity to safely absorb carbon.

STATEMENT OF ADAM SIEMINSKI . Drilling in tight oil plays in North Dakota, Montana, and Texas are expected to account for the bulk of the forecast production growth over the next 2 years. U.S. crude oil production could reach 8 million barrels a day in 2014, and we could get as high as 10 million barrels a day but that is not currently in our reference case. U.S. dry natural gas production has increased consistently since 2005, mainly because of the production of shale gas resources. Total marketed production averaged about 69 billion cubic feet in 2012, and EIA expects production will remain close to that level this year and next year. Crude oil and natural gas proved reserve additions

Demonstrated Reserve Base. The largest category of reserves is the demonstrated reserve base (ORB), which represents coal reserves in the ground that have been identified to specified levels of accuracy and are in thickness ranges and at depths that are considered minable. As of January 1, 2012, the demonstrated reserve base was estimated to contain 483 billion short tons. The ORB was originally estimated in 1974 by the U.S. Bureau of Mines

STATEMENT OF DANIEL YERGIN, Vice Chairman, IHS. The United States is in the midst of an unconventional revolution in oil and gas that fits that all-of- the-above strategy that Congressman Rush talked about

Those of you who participated in hearings in 2008 remember those dark, dire days when, I think as Chairman Whitfield reminded, the world was going to run out of oil and the United States was going to run out of oil even more quickly. How that has changed. Shale gas now has gone from 2% of our supply to 37% of our supply, and what is really dramatic is what has happened on oil, which instead of continuing its long decline has increased dramatically by almost 39% since 2008.

It is sobering to consider that without these technologies, and the oil output that has resulted from them, the sanctions on Iran might well have failed.

Certainly expanded domestic supply will add resilience to shocks and add to our security cushion. Moreover, prudent expansion of U.S. energy exports will actually add an additional dimension to U.S. influence in the world. However, there remains only one world oil market, and a disruption anywhere will be a disruption everywhere.

Owing to the scale and impact of shale gas and tight oil, it is appropriate to describe their development as the most important energy innovation so far of the 21st century. That is said with recognition of the major technological advances in wind and solar since 2000; but, as is described in The Quest, those advances are part of the “rebirth of renewables”. As actual innovations, solar and wind emerged in the 1970s and 1980s.

So far, this unconventional revolution is supporting 1.7 million jobs – direct, indirect, and induced. It is notable that, owing to the long supply chains, the job impacts are being felt across the United States, including in states with no shale gas or tight oil activity. For instance, New York State, with a ban presently in effect on shale gas development, nevertheless has benefitted with 44,000 jobs. Illinois, debating how to go forward, already registers 39,000 jobs.

In March, 2011, President Obama spoke about how “recent innovations have given us the opportunity to tap” large reserves of natural gas – “perhaps a century’s worth of reserves.” 

The question as to how the unconventional revolution will affect U.S. involvement in the Middle East is moving to the fore. Current net U.S. imports from the Persian Gulf are equivalent to 8% of total consumption. Even if that number goes down, the nature of U.S. interests in the region go well beyond direct oil imports to the importance of the region for the global economy and global security.

STATEMENT OF JENNIFER MORGAN. Directly relevant to this subcommittee are electric infrastructure and reliability are already being affected and are increasingly vulnerable to droughts and other disruptions caused by climate change. Current impacts on energy production are just the beginning. Unless we change course, these impacts will become more extreme, placing our energy infrastructure and our country at great risk, which brings me to my second point, which I think is very important. To avoid the most serious climate change impacts, our energy policy must drive low-carbon technologies forward now and build them out at a much larger scale.

Sea-level rise and associated storm surges and coastal flooding have significant economic implications. For example, damage estimates from Hurricane Sandy have ranged from $30 to $50 billion. In Florida, already occurring sea-level rise impacts are forcing Miami Beach to spend more than $200 million to overhaul its storm drainage system, and Hallandale Beach to spend $10 million 15 on new wells because of saltwater intrusion. Sea-level rise will require increased energy usage in the form of additional pumping for drainage and water supply, as well as for the energy-intensive process of desalinization. The vulnerability of the U.S. economy to sea-level rise is significant, with 41 million Americans living in coastal counties along the East Coast.

According to the National Oceanic and Atmospheric Administration (NOAA), over 65% of the contiguous United States experienced drought last September, causing widespread damage to the nearly $300 billion in annual agricultural commodities within the United States. Recent scientific findings have strengthened our understanding of the link between climate change, heat, and drought. For example, the heat wave leading to the Texas drought was found in a recent study” by NOAA and other institutions to be 20 times more likely to occur now than in the 1960. According to the recent draft National Climate Assessment, disruptions to agricultural production from climate change have increased in recent years and are expected to increase further over the next 25 years.

Extreme weather and climate events. According to NOAA, in 2012 the United States experienced 11 extreme weather events causing more than $1 billion in damages each? The economic losses from extreme events increased in part by the impacts of storm surge exacerbated by climate change are significant. For example, hurricanes have cost the U.S. Gulf Coast alone an average of$14 billion in damages per year, and the region could accumulate $350 billion in cumulative hurricane-related damages over the next 20 years. The 150-percent increase in population along the Gulf Coast over the last 50 years, to 14 million inhabitants, has further increased the potential for costly impacts from storm surge and associated hurricanes. The increase in frequency and cost of extreme weather events has caused ripple effects throughout the insurance industry, which recent research shows has experienced steadily increasing weather-related losses over the last two decades. Aggregate economic losses in 2011 attributed to extreme weather events were $55 billion,”and storms such as Tropical Storm Lee and Hurricane Irene were responsible for a combined $8.3 billion in damages that included coastal flooding. With the expectation that sea-level rise and future threats of storms such as Sandy will increase property losses, the financial risk will be transferred more to the public sector as the private sector cannot cover “high-risk” coastal properties.

Energy facilities will also likely be affected by sea-level rise. The contiguous United States has more than 280 electric power plants, oil and gas refineries, and other energy facilities which are situated on low-lying land and thus vulnerable to sea-level rise and episodic coastal flooding. Sea-level rise poses especially substantial challenges for sustaining reliable energy infrastructure in states such as Florida, where 26 energy facilities are located in especially vulnerable areas. In addition, power sector reliability is affected by extreme weather events. For example, in the aftermath of Hurricane Sandy and the Nor’easter that immediately followed, more than 8 million customers lost power. Refineries, natural gas distribution systems, and petroleum terminals were also affected by these storms. Meanwhile, because the majority of U.S. oil production and refining occurs in the Gulf Coast, hurricanes can impact national energy availability and price, as Hurricanes Katrina and Rita demonstrated in 2005. The nation’s power sector is also highly vulnerable to extreme drought. Water scarcity has emerged as one of the defining challenges of this century, yet a significant amount of water is needed to extract energy resources and use them to generate electricity. Limits on availability of ground and surface water are shaping the current operation and future location of America’s power plants. In 2011, over 85% of total electricity generation in the United States was produced by thermos-electric power plants fueled by nuclear and fossil energy sources, most of which rely heavily on substantial water resources for cooling, As fossil energy extraction trends toward unconventional resources and “enhanced” production, more water is needed relative to extracting the same amount of energy using conventional methods, According to the National Energy Technology Laboratory, there are 347 coal-fired power plants in 43 states vulnerable to water supply and/or demand concerns. In a future with increasing likelihood of droughts, our nation’s ability to meet growing energy needs through thermoelectric power generation will be highly vulnerable to climate change.

The U.S. power sector will require as much as $828 billion in capital investments and expenses before the end of this decade. Many of these investments will be for very long-lived assets from power plants to transmission systems. U.S. energy companies making investments today are considering 40+ year operational horizons and cannot ignore the potential for a future where climate policies and environmental risks influence the bottom line. One of the surest ways to saddle customers with higher costs from major stranded investments is to ignore the need to factor climate impacts into today’s decision-making processes. As a society, delaying the decision to act on climate change increases the overall cost of mitigating greenhouse gas (GHG) emissions. A recent study by KMPG found that the costs of environmental impacts for a wide array of industries are doubling operational costs every 14 years. The cost resulting from climate change, specifically, was estimated at 1% per year if early action is taken, but 5% per year of delay in establishing climate policy certainty. Other studies have found that climate change could put trillions of investment dollars at risk through 2030.

MARY J. HUTZLER. The Institute for Energy Research is a nonprofit think tank that conducts research and analysis concerning global energy issues.

But today’s hearing is focused primarily on the resource availability and the potential under our feet and off our shores to achieve domestic energy goals, almost unthinkable just a few years ago. In fact, for decades Americans were asking the question, where we will get the energy we need to heat our homes, fuel our cars and meet the demands of a strong 21st century economy. Due to hydraulic fracturing and horizontal drilling technologies, we no longer question whether we have the resources.

The myth of energy scarcity that has plagued our national conversation has been exposed. Just in the last year, the misleading refrain that the United States only possesses 2% of the world’s oil reserves has been replaced by the mounting evidence of our Nation’s resource abundance.

Increased oil sands imports from our neighbor Canada could free the United States from energy dependence on foreign countries where American workers face increasing threats of kidnapping by terrorists and even murder.

The United States has vast resources of oil, natural gas, and coal. In a few short years, a 40-year paradigm-that we were energy resource poor-has been disproven. lnstead of being resource poor, we are incredibly energy rich.

The amount of technically recoverable oil in the United States totals almost 90% of the entire oil reserves in the world. Technically recoverable resources are not equivalent to reserves, but comparing their magnitudes provides a way to measure size. IER’s estimate of technically recoverable oil in the United States is 1,422 billion barrels. That amount of oil can satisfy U.S. oil demand for 250 years at current usage rates or it can fuel every passenger car in the United States for 430 years. It is also more oil than the entire world has used in all human history. The technically recoverable natural gas resources in the United States total 40% of the world’s natural gas reserves. At 2,744 trillion cubic feet, it can fuel natural gas demand in the United States for 175 years at current usage rates, or selectively, it can satisfy the nation’s residential demand for 857 years or the nation’s electricity demand for 575 years.

Technically recoverable coal resources in the United States are unsurpassed and total 50% of the world’s coal reserves. At 486 billion short tons, it can supply our country’s electricity demand for coal for almost 500 years at current usage rates.

Natural Gas Replenishment

The Myth of Peak Oil, Natural Gas, and Coal For many years, we have heard of fossil fuels reaching their peak production levels or at the verge of being depleted.

The same is true for the myth of ‘peak’ coal. In 2007, David Hughes, Geologist for the Geological Survey of Canada, stated, “Peak coal looks like it’s occurred in the lower 48.” And yet, the United States still has the largest coal reserves in the world. Rather than depletion effects, our coal industry is faced with overly broad and restrictive regulations on the use of coal and increasing restrictions on coal production from the U.S. Environmental Protection Agency.

Harry Vidas, Vice President, ICF International. ICF estimates that the remaining technically recoverable U.S. natural gas resource base is 3,850 trillion cubic feet, which represents 155 years of current consumption. The U.S. shale gas resource is almost 2,000 TCF, 52% of the total.

Our current assessment of the U.S. oil resources in terms of technically recoverable resources is 264 billion barrels. This represents 110 years of production at current production rates.

Mr. SIEMINSKI. We took at look at how quickly natural gas could grow in transportation, and it is a very small number, a rounding error in terms of percentages. We use 3% of our natural gas to move natural gas in the pipelines, but when most people think about transportation, they are thinking about trucks or cars and so on. We believe that LNG in freight trucks and then eventually natural gas being turned into liquids like a high-quality diesel fuel—there is a plant under consideration down in Louisiana to do just that [my note: this project was cancelled]—could actually almost double the amount of total natural gas in transportation so that we could get up from 3% now to easily 6% and possibly as high as 8 or 9%. A lot of that is because natural gas, from a pricing standpoint, looks really, really attractive compared to global oil prices. So there is a lot of effort underway there.

Infrastructure issues take time. You can often get some production going and a lot of wells being drilled. Whether or not companies can then afford to build the pipeline infrastructure to move those products, oil and gas, around depends on their own view about how long the production activity will last. Because most of the pipeline infrastructure now is based upon traditional oil and gas and refineries and the like, not all these new plays are in areas where there is access to pipelines.

Mr. YERGIN. I think we have pretty much the same view as EIA, that, you know, it does now appear that natural gas will become an important fuel for large trucks, for railroads and so forth. At this point we don’t see it becoming a major fuel for private automobiles because of the nature of the infrastructure and so forth that would be needed.

Our thinking needs to catch up with reality. Our logistics need to catch up with new production. Everything has been turned upside down. Instead of going south-north, it is going north-south.

Mr. VIDAS. The analysis that we have done is very similar, that although we expect natural gas and liquefied natural gas vehicles to triple their use over the next 20 or 25 years, it still represents a relatively small part of the overall sector. The more likely way that natural gas could be used to displace oil would be through gas- to-liquids technologies or even using natural gas to generate electricity and then using electricity in battery cars.

Mr. BURGESS. the State of Texas has added almost a half million people over the past years from last summer to—the summer of 2011 to the summer of 2012, and the reason for that of course is the availability of energy and the cost of energy, and while energy in and of itself cannot be its own end, it does help drive our economy. So when we talk about not wanting to betray our children and future generations, I think we have a responsibility to the economy, and part of that responsibility is the energy supply that is available to our economy. Dr. Christensen talked about tipping points. I will just ask an open-ended question. I know you guys don’t like to speculate, but what kind of tipping point would we have seen with the economy in the last 4 or 5 years in the absence of shale?

Mr. YERGIN. If we had remained on the track that we had been on prior to when we were going to build all of those LNG receiving stations, we would probably be spending $100 billion a year now to import LNG into the country, so that would have been a big burden. Secondly, had we not seen this increase, this substantial increase in oil production, we would be paying a lot higher prices for oil, and it would be a much, much tighter and more vulnerable market and we would not have had what we have seen is that these supply chains are so long in our economy, these are dollars that stay here. They are going to jobs here rather than going into a sovereign wealth fund somewhere else in the world. So in that other universe, it would have been a much more difficult picture and more congruent with what seemed to be the picture in front of people in 2008.

Mr. SIEMINSKI. Virtually every economic study that I have seen suggests that higher domestic production of fuels leads to greater GDP, and when you get to the import issue you obviously have lower trade deficits. All of that helps the economy, leads to greater job creation, as Dr. Yergin said. I think one of the things to keep in mind is that the availability of relatively low-cost natural gas has actually helped to sustain some of the growth in wind and solar on the renewable side because those are intermittent sources. They need a backup supply and it is often natural gas that provides the backup for these rapidly growing renewables that are going to become a fairly significant part of U.S. energy production and consumption.

Mr. BURGESS. We have peaking demands in north Texas where in the summertime when the air conditioners are all cranked down low, even if you had a substantial wind component, you would never be able to keep up with that peak demand.

Mr. CASSIDY. Mr. Yergin, there are those that say that we shouldn’t export liquefied natural gas because in some way by doing so we will promote the production of more natural gas and therefore contribute to global warming, but what you are saying is that is absurd because if we don’t do it, Australia or Canada or some other country will export liquefied natural gas. Is that a fair statement?

Mr. YERGIN. Yes, I think people will fill the market and fill the need, and in fact are racing ahead to do that.

Mr. CASSIDY. Now, as they race ahead, it is fair to say that if is a $5 billion or $10 billion project to create one of these export terminals, those are a heck of a lot of jobs that will be sacrificed because of an absurd premise? Again, is that a fair statement? Being that if we don’t export liquefied natural gas, then natural gas will not be mined.

Mr. YERGIN. Well, I think in fact if you take a country like China, which as Adam Sieminski pointed out, it is very heavily oriented towards coal and wants to reduce its use of coal and use more natural gas to produce electricity to reduce pollution, they will look in one direction or another, and if we are sending natural gas we would be contributing to their reducing their pollution.

Mr. CASSIDY. So if we can create those jobs, we will simultaneously improve our economy, but too, improve, decrease carbon release worldwide potentially?

Mr. YERGIN. Yes. I think what is happening now is——

Mr. CASSIDY. I am going to let you hold that. If we don’t send energy to Japan, their economy will tank. That is on my mind when I go around to the exporters in Louisiana. I say what do you need to create more American jobs. They say more robust markets to export to. Right now Japan and Europe are in the doldrums. We need those economies to do better so we can create more American jobs. It is in our self-interest to make sure that they have adequate energy supply.

Mr. YERGIN. That is right, and it is in our political interest and it is in our economic interest.

Mr. DOYLE. I hear this a lot, that there is all this development that could be taking place on federal lands but the permitting process is so bad, and I think the map pretty graphically illustrates that there is just not much federal lands where the oil and gas shale plays are in the United States. I just wanted to provide that for clarification.

Mr. GARDNER.   That red spot on the map is in my district in northern Colorado. But there is tremendous opportunity for development in the gray spots, and a lot of that gray spot that you see in Colorado with the Rocky Mountain areas, it is BLM land, it is U.S. Forest Service land. They are unable to get permits through the BLM because of various bureaucracies. In fact, according to the Western Energy Alliance, over 100,000 jobs could be created in the western United States, primarily on those gray lands, if the permitting delays were simply lifted. Over 100,000 jobs could be created in the western United States. That is not because all the development is taking place in the red areas or the pink areas. That is because Bureau of Land Management and other agencies have been so slow in their permitting that we can’t get those permits through to create those kinds of jobs. So I think you would see a lot more red areas if we could actually get a government that was willing to allow us access to those resources in a responsible manner, and so I for one would like to see over 100,000 jobs being created in the western United States.

Mr. TONKO. And we are experiencing this period of relative abundance but we have been there before in our recent past history, so oil and gas markets are volatile and have led us to a false sense of energy security in the past. So how do we develop a national energy policy that is less shortsighted and more strategic? Basically, how can we best use these reserves to maximize——

Mr. GRIFFITH. So this is of great concern in my area because we have railroads, coal and utility companies. I would point out also that it is kind of interested that your written testimony indicates that the Chinese are using about 4 times as much coal as we are and that while they are building cleaner plants, they are not putting their older, less clean plants out of existence in the meantime, are they?

Ms. HUTZLER. No, they are not. With their GDP growth, they need all the power they can get, and in fact, according to the National Energy Technology Laboratory, they are building 60 to 80 gigawatts of coal-fired plants a year, and they think that will happen easily through 2016 and maybe further.

Mr. GRIFFITH. And so they are relying on coal including maybe some of our coal to generate their energy and the growth in their economy. Isn’t that true?

Ms. HUTZLER. Yes. They have to import coal now. They can’t produce enough themselves to satisfy their demand and we are exporting coal to them.

Mr. GRIFFITH. And so when I tell my constituents that not only are we damaging coal but we are also damaging jobs in the United States, we are allowing the Chinese to grow their economy while retarding our economy by not using our clean coal technology. Isn’t that correct?


Mr. GRIFFITH. And so for all intents and purposes, at least at this point in history, there is not the technology available for the United States to build any more clean coal plants, coal-fired electric generation plants, and we are really handicapping ourselves in relationship to our competitiveness with the Chinese. Isn’t that also true?

Ms. HUTZLER. Yes. Currently, CCS technology is not commercially available for these plants.

Mr. MARKEY Just a point. In 2009 in this committee and on the House Floor, Mr. Waxman and I built in $60 billion for clean coal technology, carbon capture and sequestration. We voted it out of this committee with no Republican support. Over the last 5 years, unfortunately, coal has dropped from 51% down to 35% of all electrical generation in the country, and what has gone up? Natural gas. It is less expensive and it is cleaner. So coal is being attacked but it is by the natural gas industry, so let us just get that clear, and we put the $60 billion in and the coal industry opposed the Waxman-Markey bill. They opposed now, and now they suffer from not having the investment in technology to make it cleaner. So don’t blame us, blame the coal industry for not wanting the funding and blame the natural gas industry for their technological breakthroughs that have allowed for the production of more and cheaper and cleaner sources of energy.

Mr. Sieminski, recently the Department of Energy released a study of the economic impacts associated with exporting large quantities of natural gas that was performed by NERA Consulting. The study used outdated 2010 EIA projection data and concluded that while exports would lead to higher domestic energy prices and adverse impacts to American manufacturing, the overall economic impact would be positive. Isn’t it true that EIA’s 2010 data predicted that domestic natural gas use in the power sector would decline between 2010 and 2020, though its use in the power sector has actually ended up growing by 27% just since 2010?


Mr. MARKEY. OK. That is all I needed to know. So way off. EIA was way off. Natural gas and the utility sectors not only did not go down, it has now gone up 27% since that report. Isn’t it true that EIA’s current projections of natural gas use in the transportation sector are seven times as high as the 2010 data used in the NERA study?

Mr. SIEMINSKI. And our supply estimates are also higher.

Mr. MARKEY. I am asking you to just go back to this study that is being relied upon. Is it not seven times higher in the transportation sector than NERA projected in just 2010?

Mr. SIEMINSKI. Yes, sir.

Mr. MARKEY. OK. Thank you. So this data was released in 2010, and since then 100 major manufacturing projects totaling $95 billion in investment have been announced. These are manufacturing facilities that would produce chemicals, fertilizer, steel, aluminum, gas, tires, plastics and other goods, all of which rely on cheap natural gas. That is what is driving this manufacturing. These announced projects alone would push U.S. industrial demand for natural gas 30% beyond the estimates used in the NERA study. Just yesterday, the Wall Street Journal described decisions made by German and Canadian companies to locate new facilities in the United States because of low natural gas prices. The Germans, the Canadians are coming to the United States with their manufacturing facilities. Do you believe that we should be making decisions about what to do with domestic natural gas in 2013 and beyond using data that reflected what was going on in that sector 3 years ago that vastly underestimated what is happening today?

Mr. SIEMINSKI. I think it is always better to have recent and accurate date in making forecasts but——

Mr. MARKEY. Especially since the data we are talking about is like a Frankie Avalon record except it only took 3 years to turn it into completely outdated information that was totally wrong about where we would be 3 years later. Last year your agency found that exporting 12 billion cubic feet per day of natural gas could lead to a 54% increase in domestic prices but today companies are applying to export nearly 3 times that amount. It seems to me that before we permit more natural gas exports to occur, we should have an understanding of the potential economic impacts on consumers, on the manufacturing sector and on the transportation sector in the United States in terms of our own internal domestic growth in those sectors of our economy and have it based upon real data, not old data that bears no resemblance to what is happening in the natural gas sector today.

This panel led by the Republicans voted in 2012 to repeal the ability of EPA to increase fuel economy standards for the vehicles which we drive. Let me just go down the line here and just ask each of you, do you support the repeal of the ability of the EPA to increase fuel economy standards or do you oppose repealing the authority? Can we just go down and we will just get your views on that way in which we deal with oil consumption in the United States?

Mr. KINZINGER. Last week’s Wall Street Journal, there was an article titled ‘‘Can Gas Undo Nuclear Power?’’ which discusses how low natural gas prices are problematic for our baseload energy production, and I would like to know your thoughts on low gas prices as it impacts fuel diversity into the future and existing domestic resources like nuclear.

Mr. YERGIN. I think what has happened with natural gas prices, remember, when people went out to start developing shale gas, it was—the incentive was very great for these independents. It was like $12 and now we know we are talking around $3, and that is really changing the marketplace, the electric power marketplace for everything, certainly including nuclear.

Mr. KINZINGER. So does that give you concerns for maybe the viability of nuclear in the future if this continues? And also, what do you think is going to happen? Do you think in 10 years if you can magically look forward that we will have a diverse energy supply or do you think we will have too many eggs in one basket?

Mr. YERGIN. Well, I think it is the—we have 4 reactors that are under construction, two projects now. I think that in this cost environment it is very hard to see anybody committing to a current generation of new power plants. The Secretary of Energy Advisory Board, the last session was partly devoted to small modular nuclear reactors, in other words, where there is technological innovation. And I think the other question about our nuclear fleet is, it is about 20% of our electricity. Lives have been extended. What happens after another 20 year and does that shrink away then.

Mr. POMPEO. I was reading an article about renewable energy, and in Eastern Europe they subsidized it even longer than we have and even more than we have, and they have had some power blackouts. There is an article in Bloomberg on October 25 that I would also like to submit for the record that talks about these energy blackouts. [The information appears at the conclusion of the hearing.]

You know, our grid could suffer the same kinds of things, in my view, if we have non-storable, non-reliable energy source. Do you have a view of the risk of us subsidizing this at such a rate that we get to a place where we have got less reliable electricity in America?

Ms. HUTZLER. Yes. Germany is a good example because they are phasing out their nuclear units and turning to renewable energy in its place, but obviously it has to be backed up, and it has caused instability to their grid. Neighboring countries are not allowing them to export their renewable energy, their wind energy, to them such as Poland, and in fact, industrial users are seeing some disruptions in their service that is causing them hundreds of thousands of dollars in equipment and they have already told the German government that either you fix this problem or we are going to leave.

Mr. POMPEO. Mr. Sieminski, you talked about renewables growing at a huge rate. It is easy to grow at a huge rate off a small base. It is still not a hugely important part of our energy resource base. When you made these assumptions about its economic growth, what did you assume for federal policy? Did you believe that we would continue our current—somebody on the other side of the aisle called it creative financing. But what assumptions did you make about state RPSs and these kinds of non-economic policies remaining in effect?

Mr. SIEMINSKI. Renewables go from about 13% to 16% of total electricity generation, so there is a lot of growth but it is still a small portion.

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It’s official – the U.S. is energy independent! House Hearing 2013

House 113-88. October 29, 2013. North American Energy Infrastructure act. House of Representatives.

[Excerpts from the 195 page transcript of this hearing] 

ED WHITFIELD, KENTUCKY. Over the last several months, this committee has received compelling testimony detailing how the United States has entered a new era of energy abundance. New technologies and American innovation are unlocking vast amounts of previously untapped domestic energy resources, meaning greater access to affordable and reliable energy for all Americans. In fact, the Energy Information Administration recently reported that the U.S. will be the world’s top producer of petroleum and natural gas in 2013, surpassing both Russia and Saudi Arabia. And we continue to be one of the world’s leading producers and exporters of coal.

GENE GREEN, TEXAS. The energy revolution bodes well not only for U.S. economic and security interests, but it also offers significant advantages for our North American allies: Canada and Mexico. Based on current projections, many analysts believe that the U.S., Canada, and Mexico could finally achieve North American energy independence by the end of the decade.

But energy supply alone is not sufficient to achieve North American energy independence. We must also have in place the energy infrastructure necessary to deliver affordable and reliable energy across our northern and southern borders. The legislation before us today will modernize and reform the approval process for energy infrastructure projects that cross the borders of the United States.

JAY MCNERNEY, CALIFORNIA. I do have significant concerns about the bill. I don’t think the case has been made for why projects that are not in the public interest should be approved. We should make sure that cross-border energy projects are in the broad public interest, receive a thorough environmental review, and provide adequate opportunities for public comment and participation. We shouldn’t have a rushed process that isn’t going to provide meaningful review.

HENRY A. WAXMAN, CALIFORNIA. Climate change is the biggest energy challenge we face. Before approving a multibillion-dollar energy infrastructure project that will last for decades, we need to evaluate its climate impacts. That is the standard the President rightly set in June. But this test is a significant obstacle for tar sands pipelines because they would carry the dirtiest fuel on the planet. Over the last few years, House Republicans have repeatedly tried to short-circuit the process and mandate approval of the Keystone XL tar sands pipeline. The bill we are considering today goes even further. It creates a new process to rubberstamp every pending and future tar sands pipeline. The premise of the Upton bill is that tar sands pipelines should be approved quickly with no Federal environmental review, no public comment, and no consideration of important factors like climate change or even safety. Under this approach, legitimate concerns cannot even be raised. Mr. Chairman, not only is your voice strained and hard to come forward, everybody’s voices will be restrained. That is the wrong approach for making decisions about controversial projects. Keystone XL is a multibillion-dollar pipeline that will carry tar sands sludge. The oil industry financial analysts and Canadian Government officials say this pipeline is critical to realizing the oil industry’s plan to triple tar sands production. Well, environmental groups say the pipeline will lead to a massive increase in carbon pollution. Over one million Americans filed comments. One million Americans had their voices heard, Mr. Chairman. In a democracy, we need a permitting process that allows for public input. This bill does exactly the opposite. The July 2010 Enbridge pipeline spill in Marshall, Michigan, taught us that tar sands spills are much harder to clean up than regular oil spills. Almost $1 billion has been spent and they are still cleaning up the Kalamazoo River over 3 years later. Enbridge wants to expand another tar sands pipeline from Canada through North Dakota, Minnesota, and Wisconsin.

But if this bill becomes law, the permitting agency couldn’t even consider pipeline safety issues when deciding whether to approve that controversial pipeline.

In the Northeast, another divisive pipeline project would carry tar sands oil from Canada through New Hampshire and Vermont to Portland, Maine, where it would be loaded onto tankers. The project wouldn’t require any approval at all under this bill’s new permitting process. This bill virtually guarantees that Keystone XL and the other controversial pipelines with pending applications are approved within 2 years. It should really be called the Zombie Pipeline Act. Under this bill, even if the administration rejects KXL because it is not in the public interest, KXL could rise from the grave and reapply. It would then be rubber-stamped under the new process.

The Upton bill is not limited to oil pipelines. It also applies to cross-border natural gas pipelines and electric transmission lines. This bill would prevent permitting agencies from considering factors such as safety, electric reliability, engineering, and environmental impacts when deciding whether to approve these projects. Energy projects that are not in the public interest would be rubber-stamped.

And the bill would allow for unlimited exports of liquefied natural gas through Canada and Mexico with absolutely no controls or conditions. That is why domestic manufacturers like Dow, Alcoa, and Nucor have criticized the bill.

Mark P. Mills, Senior fellow, Manhattan Institute for Policy Research

Let me just present first a thought experiment. Imagine what would have happened over 7 years but for the extraordinary expansion in the oil and gas sector. I think the United States would have faced not a recession but a depression. If you consider the numbers as a context that the increased domestic production of hydrocarbons has contributed over $400 billion a year to the U.S. economy. It has attracted something like $200 billion plus and growing in foreign direct investment in the United States. It has driven down imports of oil by 45%, which has radically decreased the GDP-robbing trade deficit. We are, as others have noted, now a net exporter of hydrocarbon products for the first time since 1949 and on track, God willing and permit willing, to becoming a net exporter of significant amounts of natural gas, in our own EIA forecasts, about $2 trillion of additional private investment over the next decade in this sector.

It is already well recognized that the manufacturing sector directly related to oil/gas exploration, production, transport, and refinement has seen a growth and also has been recognized that the energy-intensive sector of the U.S. manufacturing economy is under a massive revival. In fact the American Chemical Council has pointed out that there is about $70 billion in investments underway now and about 100 projects in the United States that will come online in just the next few years that will yield about a million jobs and add about $300 billion to the GDP. These are astounding changes but they are frankly only part of the story and not enough. The revitalization of that ecosystem will spill over into the rest of the manufacturing ecosystem because of the proximity of high- quality, low-cost, high-reliability supplies and suppliers, because of the proximity of a revitalized labor source and also, frankly, the proximity of reinvestment in the American educational entrepreneurship and venture community that arises from this wealth that occurs.

It is obviously clear the United States could become economically energy independent and will be doing so very quickly. What is more interesting is the question of whether North America, the United States in combination with its two allies, could be, and will become the single-largest supplier of hydrocarbons to the world. This is a profound change in geopolitics, but more importantly, from a domestic perspective it is a profound change in the fortunes of U.S. companies across the entire industrial ecosystem and for high-paid permanent jobs in the middle markets and middle class.

This won’t come about easily because there are so many forms of legislation and regulations that are locked into a historical way of thinking, the paradigm of shortages, the paradigms of disappearing resources that we all know has now evaporated and no longer is the ruling paradigm. And it is in fact a permanent secular shift in the structure of the U.S. energy economy and the world energy economy. We can now become suppliers to the world in combination with our allies, not consumers of the world’s resources.

The North American Energy Infrastructure Act comes at time of a transformation in the energy landscape that almost no one anticipated. Only a few short years ago everyone was talking about peak oil and gas and about the imperative to find energy resources beyond hydrocarbons.

Instead, we find ourselves today in a world awash in the potential to produce enormous new quantities of oil and natural gas. And the epicenter of that transformation is North America. In a stunningly short time the U.S. has emerged to become the world’s fastest growing producer of oil and natural gas, vaulting North America to the absolute dominant global position in hydrocarbon energy production.

Imagine what our nation would look like today in the counter case — if the new technologies of oil and gas, and the tens of thousands of small and mid- sized businesses had not deployed that technology to release the hydrocarbon riches locked up America’s vast shale fields. The numbers make it clear that but for the hydrocarbon shale revolution, America may have slipped into Depression. Consider the facts.

The U.S. is now a net exporter of refined hydrocarbons for the first time since 1949, and is on track to become a major exporter of natural gas.

This is a total reversal of fortunes from a continent condemned to energy dependence to one awash in production. It is epitomized by the literal physical reversals in the direction of flows in oil and gas pipelines that now carry fuel from the heartland to the coasts, instead of vice versa. We have also seen the mission of liquid natural gas terminals reverse from import to export, a reversal in refineries from retirements to expansions, a reversal in shipyard construction, and reversal in a dozen-plus states from shrinking to expanding tax receipts and jobs.

The hydrocarbon sector is the single most dramatically expanding part of the entire U.S. economy and has been a shining light of growth and high-value full-time job creation – growth that has come without federal stimulus or new subsidies or preferences. This stands in stark contrast to slow or stagnant growth across nearly every sector of the economy reflected in the extraordinarily slow recovery in jobs and especially for well-paid middle- class full-time jobs.

The U.S. is now on track to become energy independent in economic terms. But that is only part of the story and only a first step towards a far more valuable opportunity. In combination with our North American allies, Canada and Mexico, this continent can quickly become the world’s largest supplier of hydrocarbons. The economic and geopolitical implications are far-reaching.

All this begs the obvious question: why wouldn’t we be doing everything possible to encourage and accelerate the North American hydrocarbon revolution? Especially in the context of the role of hydrocarbons in high- value manufacturing jobs — a sector at the very core of the kinds of employment growth so eagerly sought by citizens and their elected representatives.

And the energy-intensive manufacturing ecosystem’s expansion will spill over into and catalyze other manufacturing both upstream and downstream where other businesses will take advantage of the proximity to low-cost high-reliability supplies and suppliers, of the growth in local labor force skills, and benefit from the collateral advances and investments in new underlying technologies. That’s how industrial and economic ecosystem’s work. This is precisely what policymakers hope will happen when they try to “stimulate” such outcomes.

It bears noting that the dramatic growth in American oil and gas production has not arisen from new discoveries or the opening up of off-limits federal lands, but from new technologies and techniques that manufacture liquid and gaseous hydrocarbons from solid shale rock. Widely reported as “fracking” – hydraulic fracturing – the story is one of deep industrial innovation, digital technologies and software, driven and deployed largely by small businesses not Big Oil. It is a quintessentially American success story and a permanent secular shift in the energy landscape.

Imagine what would be possible with a bold North American initiative to optimize and rationalize each nation’s projects and infrastructure. The North American continent has more than double the oil and gas resources of the entire Middle East. Unleashing North America’s capabilities would ignite jobs and growth from the Yucatan Peninsula to the Arctic Circle. In less than two decades North America could surpass Middle Eastern production and become the dominant player in global energy markets.

But the American hydrocarbon sector not only contributes more to the GDP than does Silicon Valley, it has also contributed more to the reduction in the trade deficit, added more jobs, and generated more widespread wealth in more states and thus contributed more revenues and economic recovery.

Economic growth is the solution to essentially every problem facing the nation faces today from deficits to entitlement funding, from housing to political dysfunction.

MARY J. HUTZLER, Distinguished Senior Fellow, Institute for Energy Research


Oil. Total recoverable resources 1.79 trillion barrels – enough to fuel every passenger car in the U.S. for 430 years. Almost twice as much as the combined proved reserves of all OPEC nations.

Natural Gas. Total recoverable resources 4.244 quadrillion cubic feet. Enough to provide the U.S. with electricity for 575 years at current leves, enough to fuel homes heated by natural gas for 857 years, more than the next 5 largest national proved reserves (more than Russia, Iran, Qatar, Saudi Arabia, and Turkmenistan).

Coal. Total recoverable resuorces 497 billion short tons, enough to provide 500 years of electricity at current levels of consumption, more coal thanany other country in the world, more than the combined total of the top 5 non-north American countries reserves (Russia, China, Australia, India, Ukraine).

The vast energy riches of North America mean that our economic future can be bright, and we can choose to chart our own course to a greater degree than we have been led to believe during the past four decades of the myth of energy scarcity.

While Presidents have sought “energy independence” as a goal from President Nixon on through President George W. Bush, that elusive goal may finally be within reach according to many forecasters. The energy revolution that is going on in North America is historic, and since the resource base is so enormous, we are not limited by a shortage of energy.

Due to hydraulic fracturing and the shale oil and gas revolution, the United States is already the world’s largest natural gas producer and the world’s largest liquid fuels producer.

The energy pipeline transportation network of the United States is vast. It consists of over 2.5 million miles of pipelines, which could circle the earth about 100 times. These pipelines are operated by approximately 3,000 companies, and are regulated by the U.S. Department of Transportation. There are over 2 million miles of natural gas pipelines in the United States and over 180,000 miles of oil pipelines

Oil pipelines consist of crude oil pipelines and refined petroleum product pipelines that carry gasoline, jet fuel, home heating oil, diesel fuel and other petroleum products. Crude oil pipelines consist of gathering lines and trunk lines. Gathering lines are small pipelines generally from 2 to 8 inches in diameter that gather the oil from the wells and connect to larger trunk lines that are generally 8 to 24 inches in diameter. There are between 30,000 and 40,000 miles of small gathering lines located in Texas, Oklahoma, Louisiana, Wyoming, and other oil producing states. The crude oil trunk lines or transmission pipelines to which the gathering lines are connected carry crude oil from producing areas to refineries. The Trans Alaskan Pipeline System, which is 48 inches in diameter, is an example of such a pipeline. There are about 55,000 miles of transmission pipelines in the United States.

Refined product pipelines deliver petroleum products to large fuel terminals with storage tanks, from which tanker trucks make local deliveries to gas stations. These refined petroleum pipelines vary in size from relatively small at 8 to 12 inches in diameter to 42 inches in diameter and are found in almost every U.S. state. There are about 95,000 miles of refined product pipelines.

The natural gas pipeline system is organized somewhat differently because unlike oil, natural gas is delivered directly to homes through pipelines. There are about 20,000 miles of natural gas gathering lines that move natural gas to large cross8country transmission pipelines. These large distribution lines, of which there are about 305,000 miles, move the natural gas close to cities where much smaller lines carry it under streets to homes and businesses in almost every city and town in the United States, accounting for the vast majority of the pipeline mileage–over 1.8 million miles.

Forty years ago, the United States faced the 1973 Arab oil embargo setting off a series of policy initiatives in Washington designed to reduce our dependence on foreign oil. Despite them, domestic production of oil had declined and oil imports had increased until recently. Thanks to American innovation, new drilling technologies have allowed us to tap our vast shale resources and make the United States the largest liquid fuels and natural gas producer in the world. And with Canada’s vast proven oil reserves, the prospect of North American energy independence is no longer political rhetoric but a promising reality.

Pipelines have been used for 3/4 of a century providing the safest, most-efficient, and least-cost transport of oil and natural gas, but due to existing pipelines reaching near full capacity, oil transport by rail has increased dramatically. Last year, oil carried on trains from Canada to the United States increased 46 percent. EIA estimates that 1.37 million barrels of oil and petroleum products per day were moved by train during the first 6 months of 2013, up 40 percent in just one year.

The United States imported almost 3 trillion cubic feet of natural gas from Canada in 2012, 12 percent of our consumption that year. The United States gets 94 percent of its natural gas imports from Canada. The rest comes from Mexico and from overseas as liquefied natural gas. Canadian natural gas imports to the Northeast and Midwest, areas that also benefit from increased domestic production of the Marcellus Shale, are slightly declining, while Canadian natural gas imports into the Northwest are increasing. Four U.S. States, Minnesota, Montana, Idaho, and North Dakota, account for 75 percent of all the natural gas brought into the United States via pipeline. The border States serve as critical links for gas-dependent States like California where over 55 percent of electric generation comes from natural gas.

On the East Coast, Vermont, the first State to ban hydraulic fracturing, is entirely dependent on natural gas from Canada. On our southern border, the United States is a net exporter of natural gas to Mexico where exports have been on an upward trend since 2000 and have more than doubled since 2007. Mexico is also our third-largest supplier of oil and petroleum products supplying almost 400 million barrels in 2012, though this is down from its peak in 2006.

Steve Scalise, Louisiana. I want to ask Mr. Mills about some of the things that a lot of us on this committee have advocated for a long time, and that is North American energy independence. Of course we advocate an all-of-the-above energy strategy and of course we have seen a revolution, especially as it relates to natural gas, oil, and other technologies that have allowed us to access so much more natural resource here in America that allows us to be energy independent.

Mr. DINGELL. I have concerns about the bill as written and I hope that the changes can be made to ensure proper diligence is given to protect the public interests and our tremendous natural resources and that we can do this by using the review processes that are now in the law wisely and not by eliminating the NEPA environmental review process from the cross-boundary permit or from other things which appear to be important because what may be necessary for the situation on the Keystone pipeline may be quite different in other matters and may lead to some very significant regrets if we go the wrong direction. So I would like to see that we preserve an intelligent and reasonably expeditious review process. Mr. Blackburn, in your testimony you said if this bill were in effect for the Keystone XL pipeline project that only the State of Montana has an environmental review process. Would the Montana environmental review have been required to examine the pipeline siting over aquifers, wetlands, rivers, and other sensitive areas in other States?

Mr. BLACKBURN. No, Representative.

Mr. DINGELL.   I happen to have the privilege to live in the Great Lakes region, home for some 20% of the world’s freshwater supply, as well as a tremendous resource for hunting, fishing, recreational use, for industrial and transportation. Not too long ago we had a serious problem with an oil pipeline leaking approximately a million gallons into the Kalamazoo River. My concern is what would have happened had this pipeline been crossing the Detroit River, the St. Clair River, or some of the waters in the Great Lakes? If a pipeline were to leak oil into one of these rivers, it would flow into St. Clair down the Detroit River, past my district into Lake Erie. All the way the spill would affect vast private areas and State and Federal lands of Michigan, possibly Ohio, Canada, and the rest of the Great Lakes basin. Now, Mr. Kyles, this question to you. Your company operates pipelines across the St. Clair and Detroit Rivers. If you were to build a new liquefied petroleum gas pipeline under either of these rivers and this bill were in effect, would a Federal NEPA review for that pipeline be required? Please answer yes or no.

Mr. KYLES. Yes, it would be required but——

Mr. DINGELL. NEPA would be required if this bill were in effect?

Mr. KYLES [continuing]. Not according to this bill.

Mr. GREEN. You mentioned that the expansion of international power lines would support the development of clean non- emitting energy sources, including projects located in the United States. Can you elaborate further on how U.S. renewable projects benefit from the construction of transmission connections with Canada and why is cross-border infrastructure essential in maximizing North American clean energy potential?

Mr. BURPEE. Within Canada, there is a large amount of large hydro storage. There is a lot of wind being developed in both Canada and the U.S. The marriage of large hydro for storage and wind is ideal. Anything that is non-dispatchable or intermittent needs some form of storage. The cheapest, most efficient form of storage is large storage hydro, so they fit. As the systems evolve and we move away from carbon,

Mr. BLACKBURN. Yes, the environmental review process is critically important to landowners and other citizens throughout the pipeline routes. It, for example, allows them to understand something about economics for pipelines, which are critical to the national interest and allows them to understand the impacts to their own particular properties and the ways that those impacts can be limited. If we are going to ask landowners to take a bullet for the country, they should at least know that the pipeline is needed and what can be done to limit the harm.

JEFF C. WRIGHT, Director, Office of Energy Projects, Federal Energy Regulatory Commission.  

The Commission is responsible under the Natural Gas Act for authorizing the construction and operation of interstate natural gas pipeline and storage projects and for the construction and operation of facilities necessary to permit either the import or export of natural gas. The Commission conducts both a non-environmental and an environmental review of the proposed facilities. The environmental review, pursuant to the National Environmental Policy Act of 1969, or NEPA, is carried out with the cooperation of numerous Federal, State, and local agencies, and with the input of other interested parties.

Section 3(b)(1) of the bill states that the Commission shall approve a project within 120 days of receipt of a request to construct and operate border facilities unless the project is not in the national security interests of the United States, and that under proposed Section 3(b)(3), approval will not be a major Federal action under NEPA. This would differ substantially from the Natural Gas Act in that the proposed Act does not make any provision for procedures such as public notice, public comment, issuance of an order supporting a Commission decision, rehearing, or judicial review in conjunction with the Commission’s consideration of an application. A 120-day deadline would not permit construction of an adequate record, enable important agency consultation, or allow for meaningful public interaction in arriving at a decision. The proposed language could be read as giving the Commission no discretion in the issuance of an authorization unless there are national security concerns.

The Commission, by statute, is the lead agency in the approval of interstate pipeline facilities in the U.S. and at its borders. However, depending upon the location of the proposed facilities, there are other Federal statutes that are administered by Federal and State agencies that require authorizations prior to the Commission’s approval. Even if the Commission issues conditional approval, construction cannot begin until the other Federal authorizations are issued.

Further, border facilities, when considered on their own, do not usually constitute a major project. Nevertheless, a finding of no significant environmental impact still requires the Commission staff to conduct a NEPA analysis to be able to make such a conclusion. In addition, many border facilities require Commission-jurisdictional upstream pipeline facilities to be constructed.

Typically, Greenfield pipeline construction requires an environmental impact statement since there will be significant environmental disturbance. Under NEPA, an agency is charged with reviewing the cumulative impacts of a project. The related upstream facilities cannot be considered apart from the related border facilities. Separate consideration would invite charges of project segmentation and could result in a court reversal of a Commission decision. Therefore, the proposed 120-day approval process would hinder the ability of the Commission to consider stakeholder concerns and prevent the Commission from conducting a thorough analysis of a project involving border facilities, resulting in a decision whose sustainability is questionable.

DAVID K. MEARS, Commissioner, Department of Environmental Conservation, Vermont  

We do have concerns, however, about this legislation which takes a piece of the approval process for international transboundary projects and breaks it out of the traditional process that we have had and removes the environmental review under the National Environmental Policy Act. Our concerns are specific to this specific project that is under consideration in Vermont but also more broadly with the concept in general. The specific project in Vermont that we are concerned about is a pipeline that currently runs from Portland, Maine, to Montreal transporting light sweet crude for the most part. And the proposal that is actively under consideration is if it ends up being that Montreal becomes the Locust point for the transmission of tar sands oil, that that oil will in turn be transmitted through the pipeline, the pipeline would be reversed and transmitted from Montreal through Vermont to Portland. The pipeline is decades old. It has not experienced this type of crude oil in the past, which presents greater risks to the environment. The pipeline flows through an area of pristine and natural beauty in the area. It flows past drinking water supplies, over water supplies, wetlands, State parks, et cetera. Vermont is a State that is critically dependent upon its tourism, recreation-based economy for its economic livelihood. And so our concerns are that if this project is exempted from review, that those kinds of considerations, whether or not the pipeline needs to be upgraded or additional considerations around how to ensure safety will not be given proper consideration. Also, our concern relates to the exemption of this project from the NEPA environmental impact statement requirements, which provide for the opportunity for public involvement and participate in. That is a critical aspect for Vermonters. We have a strong tradition of participatory democracy. It is critical to us that our citizens and communities have the chance to fully understand what the risks and impacts are both to their communities in terms of the direct impacts of the pipeline but also the broader impacts of an international transboundary pipeline such as this one that has implications in terms of climate change and the broader energy markets.

We acknowledge and I agree with many of the concerns raised today with the existing process for transmission projects particularly in the oil pipeline context, but simply exempting them from the environmental review and placing a time constraint on to the Federal agencies that are involved in limiting the scope of their review will not achieve the purposes of achieving, as Mr. Mills has suggested we all would like to see, a more robust, efficient North American energy system. I think we all share that goal. I think we can do it in our current system of environmental laws without exempting transboundary projects such as this one, the pipeline reversal that I was referring earlier, from an environment to review.

Paul Blackburn and I have represented landowners threatened with condemnation by TransCanada and citizens concerned about oil spills and climate change resulting from proposed Keystone XL pipeline. I also plan to represent citizens of Minnesota on the Alberta Clipper pipeline expansion, which would probably be directly affected by this legislation. Various citizens of Minnesota might think about this. I would say that the citizens have a stake here and their rights and freedoms must be respected. One hundred and twenty days is simply not long enough, simply not long enough to allow citizens to be involved in these particular decisions, and this needs to be looked at in a broader context. The government offers pipelines a really sweet deal. First off, they get to condemn thousands of parcels of private property and property owners like the farmers and ranchers that I represent in South Dakota take this very personally. Also, once the pipeline is built, FERC guarantees the pipeline company profits forever as long as that pipeline operates, regardless of how much or how little it is used.

In contrast, landowners and citizens get a raw deal because they receive little benefit and shoulder many adverse financial and economic impacts.

As I noted, the Alberta Clipper pipeline is currently pending and it is critically important to recognize that the crude oil pipeline regulation process is radically different from the process for natural gas pipelines and for electric transmission lines. You know, applying this law to all three of them the same way doesn’t make a lot of sense. FERC does an extensive amount of review in natural gas pipelines, as the prior witness talked about, and the Department of Energy does a great deal, as well as all the regional transmission system coordinators do a lot of work for the transmission line planning. In contrast, the crude oil pipeline regulatory process is kind of the Wild West.

Congress should not allow crude oil pipelines to be built until a need for those pipelines is proven. Most regulative utilities have to do this before they get their tariffs guaranteed. This is a real problem, as shown by 2010 FERC petition filed by Suncor, one of the largest tar sands producers. Suncor argued that Enbridge should not have started construction of the Alberta Clipper pipeline because it was not needed and may never be needed, something that the public doesn’t know. Suncor stated—and I will cut to the quote—by the time the Alberta Clipper is finished, Suncor argued ‘‘shippers will have paid Enbridge hundreds of millions of dollars before they reach the point, if ever, where the operational benefits the Alberta Clipper justify their cost.’’

These kinds of economic issues are the kinds of things that the Federal Government should look at, and yet in 120 days it is something not possible to look at this economic analysis. The kind of analysis done in Canada by the National Energy Board and the kind of analysis done at States for need is critically important to determine if citizens are really protected. One hundred and twenty days is not enough. I would say that the Congress should really try to amend this entire system and make it rational for citizens so that we aren’t just simply building pipelines without a clear understanding of why and whether they are really in the citizens’ economic interests.


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House hearing on achieving North American energy independence

House 112-176. September 13, 2012. The American energy initiative part 28: A focus on the outlook for Achieving North American energy independence within the decade. House of Representatives. 167 pages.

Proclaimers of energy independence:

  1. Ed Whitfield, Kentucky
  2. Fred Upton, Michigan
  3. Joe Barton, Texas
  4. Mr. Harold Hamm, Chairman and CEO of Continental Resources and energy policy advisor to Governor Romney
  5. Daniel Ahn, Chief Commodities Economist at Citigroup in New York
  6. John Freeman, Energy Research Group at Raymond James
  7. Mark P. Mills, Senior Fellow, Manhattan Institute
  8. Steve Scalise, Louisiana

ED WHITFIELD, KENTUCKY. Today we are going to talk about what I consider some very good news, and that is the achievability of North American energy independence and particularly oil independence within the span of a mere decade.

So after many decades of hearing that the United States basically reached the end of its reserve, as a matter of fact, as recently as 2010 President Obama stated in a national address that we are running out of places to drill, and he still cites the outdated and misleading claim that we possess only 2 percent of the world’s oil reserves. But this pessimistic view is being blown away by reality.

The global implications are tremendous because the one thing that has not changed is the instability in the Middle East and the hostility of several major oil-producing nations towards the United States. However, the more oil that is produced in the United States and Canada, the less leverage OPEC or any of its individual member nations can exert over us. And now we have the chance to reduce that leverage virtually to zero with North American oil independence.

The geopolitical benefits alone are enough to make this goal worthwhile, and the economic benefits are simply icing on the cake. North American energy independence would bring with it hundreds of thousands, if not millions, of new jobs in a rejuvenated energy industry. Indeed, it would succeed where unfortunately our stimulus package failed, and rather than cost over $800 billion, it would actually add revenues to the Federal Treasury. And when you compare the real oil-industry jobs already being created in States like North Dakota, and as you know, in North Dakota right now, the unemployment rate is less than 3 percent, and all the experts agree that that primarily comes from the fact of the new oil fields that have been hit there, the jobs that are being created. And not only can we talk about oil but we also could talk about independence in natural gas because of the tremendous finds that we are finding.

Today, we are going to talk about some very good news – the achievability of North American energy independence, and particularly oil independence, within the span of a mere decade. However, in order for this potential good news to become reality, the federal government has to take certain steps to allow it to happen. I might add that it was not long ago that we were repeatedly told that we would have to live with declining U.S. and North American oil production.

Even more troubling is the fact that the president has blocked access to many energy-rich federal lands and offshore areas. Indeed, the increase in American oil production is especially impressive given that we have done it with one hand tied behind our back. According to the Congressional Research Service, fully 96% of the increase since 2007 has occurred on non-federal lands, where the Obama administration doesn’t have the power to block leasing or impose permitting delays. But on federally controlled lands and offshore areas, production has actually declined by two percent.

BOBBY L. RUSH, ILLINOIS. Unlike the simplistic Sarah Palin ‘‘Drill, baby, drill’’ Romney-Ryan energy plan, President Obama has put forward a comprehensive energy policy that encompasses concrete proposals to not only make us less reliant on imported oil from overseas but which also takes into account the serious issue of climate change. While my Republican colleagues are loathe to even mention the words ‘‘climate change’’ and have claimed it to be a hoax, I can assure you, Mr. Chairman, that most of the farmers across this Nation will disagree with that position as we have witnessed the worst year of record temperatures, drought and crop loss in modern American history.

FRED UPTON, MICHIGAN.   The advances in drilling technology that we will hear about today have accomplished more for the American people than all of the Solyndras and other federal stimulus giveaways combined. They have already rewritten the conventional wisdom that America’s natural gas production is declining, and are now doing the same for domestic oil production. In fact, predictions of dwindling North American oil supplies have been replaced with very realistic predictions of North American oil independence within a decade.

JOE BARTON, TEXAS. We have a possibility to be energy independent almost at any time we want to be in the next 10 to 15 years.

HENRY A. WAXMAN, CALIFORNIA.   Today’s hearing presents two different visions of an energy policy for America.

One vision doubles down on the energy policies of the past. Its mantras are ‘‘drill, baby, drill’’ and tax breaks for the oil industry. The other vision recognizes that energy is key to America’s economy, national security and environment. It supports a mix of energy sources to provide American consumers with affordable, clean energy. The choice is all of the above or oil above all, and the answer will affect the lives of every American.

Not so long ago, we actually implemented an energy plan written by and for the oil industry. In 2001, President Bush and Vice President Cheney unveiled the Bush administration’s energy plan, written in secret with oil, coal and other energy-industry interests.

So in 2005, I examined what had happened to energy prices and dependence on foreign oil under the Bush energy policy since 2001, using data and analysis from the EIA. Under the Bush-Cheney oil industry energy plan, gasoline prices more than doubled. Crude oil prices more than doubled. The average American family spent $2,000 more each year on energy costs. And the oil companies reaped record profits. This energy plan did not benefit America’s families. It did not boost our economy or improve our national security, and it certainly did not clean up pollution or address the threat of climate change.

Today we are discussing another Republican energy plan that was drafted with industry, especially the oil industry. And it is a backwards-looking plan that resurrects the Bush-Cheney policies. It calls for more tax breaks for oil companies, opening new areas to drilling, and putting the States in charge of issuing drilling permits on Federal lands.

The Obama administration’s energy policy is fundamentally different. President Obama hasn’t just promised to reduce our dependence on foreign oil; he has actually done it. For the first time in decades, we are importing less than half the oil we consume. His administration’s new motor vehicle standards will save more than 2 million barrels of oil per day. And U.S. domestic oil and natural gas production has reached record highs. Perhaps most important, the Obama administration has also made investing in clean energy technologies a national priority.

GENE GREEN, TEXAS. I think it is misleading to debate our energy independence based on geology, technological or economically achievable in the absence of other constraints. There are always external factors that affect the level of production.

Mr. Harold Hamm, Chairman and CEO of Continental Resources and energy policy advisor to Governor Romney. I’m here today to talk to you about the viability of American energy independence. I am here to testify to the policies needed to insure North American Energy Independence in the next decade. There are three basic policies needed to continue the march towards North American energy independence.

  1. Reasonable and consistent environmental regulations
  2. Encouraging development of federal lands
  3. Maintain tax policies that let us keep our own money to drill.

America is endowed with an estimated 139.6 billion barrels of recoverable oil-enough to replace Persian Gulf imports for the next 50 years. We also have undiscovered technically recoverable natural gas of 1445.3 trillion cubic feet.

We now have natural gas reserves of over a century.

With this extraordinary advance in technology we can now access the immobile oil

The tax provisions in place for over 50 years that let us keep our own money to reinvest in drilling are crucial to keep this energy revival going. We support comprehensive tax reform. When that process begins we should all be willing to make the case as to why provisions in the code are beneficial to all Americans. We will make the case that the repeal of these tax provisions would result in as much as a 40% decrease in drilling activity and stop this American energy renaissance.

Some call this expensing of ordinary business expense a “subsidy”.

Sixty-Two Percent of the known Oil Resources on Federal lands Are Off-limits. Based on resource estimates, these lands contain about 62 percent of the oil on federal land (19.0 billion barrels) and 41 percent of the natural gas (94.5 trillion cubic feet).

Daniel Ahn, Chief Commodities Economist at Citigroup in New York. Earlier this year, my colleagues and I published a report entitled ‘‘Energy 2020: North America, the New Middle East,’’ and I would like to take the opportunity to share and update its conclusions. North America has recently become the fastest-growing hydrocarbon producer and exporter in the world, and this trend should accelerate to the end of the decade. This energy renaissance has been driven by both declining domestic consumption and the successful deployment of new technologies to extract hitherto inaccessible oil and gas resources, particularly in tight and shale rock formations using horizontal drilling and hydraulic fracturing techniques. These two trends, declining demand and burgeoning supply, should have dramatic consequences for national energy security and for the domestic and global economy.

American dependence on imported oil outside of North America should shrink or even be eliminated entirely.

Global oil prices could fall by 15 or even 20 percent. Energy-intensive manufacturing industries such as petroleum refining, petrochemicals, fertilizers, iron, steel, aluminum smelting, all should strategically benefit. Natural-gas-fueled vehicles could proliferate on American roads. Distinguished committee members, a minor industrial revolution is in the making in our heartland. This is testament to the technical ingenuity and flexibility of American workers and enterprises and the bounty of our natural resources.

The United States was once the world’s largest oil producer for much of the 20th Century, after Russian production collapsed during the Revolution of 1917. The United States maintained this status for half a century, notably providing the oil necessary to fuel the critical Allied war effort throughout the two World Wars. However, faced with aging fields, American production peaked in 1970 and subsequently declined despite new production from Alaska. Increasing reliance upon imported oil proved a critical economic vulnerability during the oil shocks of the 1970s, fueling a painful period of economic malaise and high inflation. But 2007 proved a turning point, with record-high oil prices above $100 per barrel triggering two transformative factors that proved the “peak oil” pundits wrong again.

The United States and North America more broadly, is in the throes of a historic energy revolution, driven by two factors: declining consumption and growing production. Gasoline and other refined petroleum consumption in the US have been in decline since 2007, in part due to cyclical economic weakness but also structural factors. This structural trend is expected to continue due to demographic shifts, higher vehicle efficiency standards, and other energy efficiency savings. Meanwhile, North American production of hydrocarbon liquids and gas has skyrocketed. Most notably, new production from unconventional sources such as tight and shale rock formations have been made possible thanks to the deployment of hydraulic fracturing and horizontal drilling technologies. Given the confluence of declining consumption and growing production, and what is geologically, technologically, and economically feasible, we project that North America can potentially achieve energy independence (i.e. oil/gas net self-sufficiency) by 2020.

John Freeman, Energy Research Group at Raymond James.

America is already a major exporter of coal, and together with Canada, we are already self-sufficient when it comes to natural gas, and for the first time in over 50 years, there is clear visibility on how oil independence can be achieved.

Many of the themes I am going to describe today are sustainable trends driven by the private sector, and they can continue for a long time, even without additional policy steps.

The Nation’s all-time peak for petroleum imports was in 2005 at 13.5 million barrels a day. By 2011, imports were down to 9.7 million barrels a day. That reduction in imports was almost evenly balanced between rising domestic production and declining consumption, and we believe imports can disappear entirely by as early as 2020.

The nation’s oil demand began to fall well before the onset of the financial crisis in 2008. Between 1992 and 2005, demand was up every single year except one. Since 2005, demand has fallen every year except one. There are four long-term drivers, and in our view will result in a sustained decline in U.S. oil demand. The first driver is ongoing improvement in fuel economy. Between 2006 and 2011, the increase in average fuel economy of actual passenger car sales improved more in absolute terms than it had in the 15 years combined prior to that. Second, there is an ongoing decline in vehicle miles traveled. The use of public transport, greater reliance on Internet commerce, the fact that the number of automobiles per household peaked in 2007, due in part to demographics, are just some of the factors driving this trend.

In conclusion, America is blessed with an abundance of natural resources. We are the largest producer of natural gas in the world, the second largest producer of coal, and in the next several years will become the largest oil producer in the world. The future has never been brighter for achieving energy independence.

Summary of Testimony – John Freeman, Energy Research Group, Raymond James & Associates, Inc. Supply: • U.S. can become energy independent by 2020 • Before the end of this decade the U.S. will become the largest oil producer in the world • Three areas (Bakken, Eagle Ford, Permian) will drive 80% of the production growth

Daniel J. Weiss, a Senior Fellow at the Center for American Progress Action Fund, a tax exempt organization dedicated to improving the lives of Americans by transforming progressive values and ideas into policy. The question posed for this hearing is “A Focus on the Outlook for Achieving North American Energy Independence Within the Decade.”

Giving states the authority to allow drilling in National Park Service units and other public lands within their borders tempts them to seek oil revenues rather than safeguard health and natural resources. The New York Times noted “States, as a rule, tend to be interested mainly in resource development.” Yesterday the Center for American Progress released data highlighting 30 National Park units that face the prospect of future oil and gas drilling, including the Flight 93 Memorial and Everglades National Park. These places would be vulnerable if federal oversight of energy on public lands is eliminated in favor of more relaxed state regulations.

Parks with possible drilling

  •    San Antonio Missions National Historical Park — Texas
  •    Guadalupe Mountains National Park — Texas
  •    Palo Alto Battlefield National Historical Park — Texas
  •    Bluestone National Scenic River — West Virginia
  •    Cane River Creole National Historical Park — Louisiana
  •    Carlsbad Caverns National Park — New Mexico
  •    Chaco Culture National Historical Park — New Mexico
  •    Dinosaur National Monument — Colorado, Utah
  •    Everglades National Park — Florida
  •    Flight 93 National Memorial — Pennsylvania
  •    Fort Necessity National Battlefield — Pennsylvania
  •    Fort Union Trading Post National Historic Site — North Dakota, Montana
  •    Friendship Hill National Historic Site — Pennsylvania
  •    Glen Canyon National Recreation Area — Arizona, Utah
  •    Grand Teton National Park — Wyoming
  •    Great Sand Dunes National Park and Preserve — Colorado
  •    Gulf Islands National Seashore — Florida, Mississippi
  •    Hopewell Culture National Historical Park — Ohio
  •    Indiana Dunes National Lakeshore — Indiana
  •    Johnstown Flood National Memorial — Pennsylvania
  •    Jean Lafitte National Historical Park and Preserve — Louisiana
  •    Little River Canyon National Preserve — Alabama
  •    Mammoth Cave National Park — Kentucky
  •    Mesa Verde National Park — Colorado
  •    Nicodemus National Historic Site — Kansas
  •    Santa Monica Mountains National Recreation Area — California
  •    Steamtown — Pennsylvania
  •    Upper Delaware Scenic and Recreational River — New York, Pennsylvania
  •    Theodore Roosevelt National Park — North Dakota
  •    Washita Battlefield National Historic Site — Oklahoma

Parks with current drilling

  •    Alibates Flint Quarries National Monument — Texas
  •    Big Thicket National Preserve — Texas
  •    Lake Meredith National Recreation Area — Texas
  •    Padre Island National Seashore — Texas
  •    Aztec Ruins National Monument — New Mexico
  •    Big Cypress National Preserve — Florida
  •    Big South Fork National River & Recreation Area — Tennessee, Kentucky
  •    Cumberland Gap National Historical Park — Kentucky
  •    Cuyahoga Valley National Park — Ohio
  •    Gauley River National Recreation Area — West Virginia
  •    New River Gorge National River — West Virginia
  •    Obed Wild & Scenic River — Tennessee

Earlier this week the Washington Post reported that drought and rising temperatures are forcing water managers across the country to scramble for ways to produce the same amount of power from the hydroelectric grid with less water, including from behemoths such as the Hoover Dam. Hydropower is not the only part of the nation’s energy system that appears increasingly vulnerable to the impact of climate change, as low water levels affect coal-fired and nuclear power plants’ operations and impede the passage of coal barges along the Mississippi River. Drought conditions can also interfere with the hydraulic fracking employed to produce shale gas. Citi GPS found that Fracking is a water-intensive process. The EPA estimates that 1.2 to 3.5 million gallons of water is used to frack a well. Water is the very component in hydraulic fracking that makes the current shale gas and oil boom possible by creating fractures in the oil and gas-bearing shale gas rock thousands of feet below ground. Some of the largest tight oil and shale gas fields are in Texas plagued by drought in 2011 and 2012. NOAA predicts that the nationwide drought conditions will remain mostly unchanged through the end of November.

Giving states control of resource development on federal lands is a real threat to some of America’s most special places for hunting, fishing, hiking, and recreation. They could permit controversial projects near national parks such as uranium mining around the Grand Canyon, oil and gas drilling near Arches National Park in Utah, and coal mining 10 miles from that state’s picturesque Bryce Canyon National Park.

Oil companies not using federal leases

Despite their demand to open fragile, previously protected places for oil and gas production, oil and gas companies are not developing many of the leases that they already hold. A huge portion of leases held for public lands and waters lack exploration or development plans according to Department of Interior data. The department found that 56 percent of the leased acres onshore in the lower 48 states are not in production or exploration. The percentage is even larger offshore, where 72 percent of leased acres are dormant. This simply means that big oil companies currently hold the keys to vast amounts of publicly owned resources but have chosen not to develop them right now. As of the end of fiscal year 2011, there were more than 38 million onshore acres under lease, but the industry was only actively producing on just more than 12 million acres. The story holds true down the line, given that as of the end of fiscal year 2011, the industry was holding more than 7,000 authorized permits to drill with parcels that were unexplored or undeveloped. Idle leases in the Gulf of Mexico contain large amounts of oil. The tracts that are not producing oil or subject to pending or approved exploration and development plans are estimated to contain 17.9 billion barrels of “undiscovered technically recoverable resources” oil and 49.7 trillion cubic feet of UTRR natural gas. According to the same report from the Department of Interior, “More than 70% of the tens of millions of offshore acres under lease are inactive.” This includes almost 24 million acres that do not have “approved exploration or development plans” in the Gulf of Mexico. This area has an estimated 11.6 billion barrels of oil and 50 trillion cubic feet of natural gas.

the Energy Information Administration said a rapid increase in natural gas production from shale resources over the last 5 years has significantly affected natural gas prices and the relative attractiveness of Federal and Indian lands as areas for development of conventional natural gas resources.

As the price of natural gas dropped, there was a dramatic decline in the amount of public land nominated by the industry for leasing. Since fiscal year 2006 there has been nearly a 67% decline in the amount of onshore public land nominated by the industry in the Rocky Mountain States. As one industry expert told The Wall Street Journal, “It is safe to say that there will be fewer natural gas wells drilled in 2012.”

Given the current low price of natural gas, there is simply less demand from industry to drill at all, let alone on public lands. In addition, the oil and gas industry has been less focused on public lands and waters, since many of the best resources are currently located on private land. And oil companies drill where the best resources are.

John Purcell, Vice President of Wind Energy for Leeco Steel. Leeco Steel first began delivering steel plates and fabricated plate products to the wind industry in 2004. Revenue from the wind industry now accounts for nearly 40 percent of our company’s revenues. Leeco Steel has provided over 500,000 tons of steel plates to 12 tower manufacturing facilities in 12 States across the United States,

Mark P. Mills, Senior Fellow, Manhattan Institute. The United States is the largest single supplier of grains, accounting for about 40 percent of global exports. We enjoy the associated trade, jobs, and revenue benefits that come from being the world’s breadbasket. Technology is now doing for the American energy and fuel sectors what it previously did for the agricultural sector. In a complete reversal of the widely accepted energy paradigms of declining domestic hydrocarbon production, dependence, and shortage, it is now realistic for America not just to feed the world, but to fuel it as well. Last year the United States exported almost $140 billion in agricultural goods – and about $120 billion in hydrocarbons. Within a year or so, we will likely export more fuel and petroleum products than food. Shortly after that, hydrocarbon exports will exceed those from information technology equipment, and then quickly exceed automotive sector exports. This is only the beginning of what is possible. Policies that accelerate hydrocarbon production could create at least 3 million jobs and $3 to $7 trillion worth of economic benefits, and would completely reset energy geopolitics. I have outlined the staggering magnitude of the jobs and economic benefits in a Manhattan Institute report this past summer titled Unleashing the Energy Colossus, work that expands on similar bullish analyses from organizations like Citi bank, Wood McKenzie, HIS CERA, Deloitte, and industry insiders like Bentek Energy.

The United States can, quite literally, drill, dig, build, and ship its way out of the current economic and jobs malaise. The new reality of hydro carbon abundance makes possible not only energy independence, but also a credible scenario in which the Middle East is displaced as the world’s primary energy exporter.

Hydrocarbons currently supply 85% of the world’s energy and every forecast sees them as central for the foreseeable future. Essentially all growth in global energy demand is now outside of the United States.

When asked what constrains expansion, businesses across the country universally cite the crushing weight of the existing regulatory system. Policies and regulations have evolved unintentionally to become complex, over-reaching, and often capricious. Regulations are suppressing American energy productivity.

Peter Howard, President and CEO Canadian Energy Research Institute.

Western Canada:

  • Conventional light Crude 562,000 bbls/day
  • Condensate (C5+) 128,000 bbls/day • Conventional Heavy Crude 422,000 bbls/day
  • Upgraded Bitumen (SCO) 846,000 bbls/day
  • Non-Upgraded Bitumen 759,000 bbls/day

From Eastern Canada:

  • Conventional light Crude 272,000 bbls/day Total 2,989,000 bbls/day

In 2011 Canada’s average daily exports were 2,138,000 bbls per day with 98% of those volumes going to the United States.


Canada’s conventional oil production (light and heavy) peaked in the mid-70s at 2,200,000 bbls/day and has been on a steady decline since that point in time until recently. In 2010/2011 the year over year production rate increased. The reason: applying horizontal drilling technology to old oil fields to access bypassed oil and increase the recoverable oil percentage. During those years the number of oil directed wells increased from 1,647 wells in 2008 to 3,109 in 2010 and 4,339 in 2011 with horizontal wells accounting for 60% of the total. CERrs conventional oil model is forecasting a conservative increase in conventional oil of 200,000 bbls/day by 2015 and an optimistic increase of 300,000 bbls/day.

Oil sands currently produce, on average, 1,618,000 bbls/day (2011) with 60% sourced from mining operations and 40% from in situ operations. Production ramp-ups and debottlenecking efforts over the next 2 years will expand production to 2,200,000. By 2013, an additional 408,000 bbls/day is scheduled to be connected from projects that are currently under construction and due on stream prior to 2015. Additional volumes of 1,300,000 bbls/day have been approved by the regulator and are awaiting start of construction. Also, there is another 1,300,000 bbls/day from projects that are waiting for approval by the regulator and a further 1,000,000 bbls/day from projects that have been announced. Total potential from the oil sands is 5,300,000 bbls/

The current capacity of the export pipelines from the WCSB from an operational point of view is 3,450,000 bbls/day.


Mr. POMPEO. Mr. Hamm, it wasn’t very long ago that there was peak oil, we are about out of the stuff. All of American energy policy really for the last 25, 30 years under both parties was premised on that notion. Any validity to the fact that you are wrong, that what we have heard from these economists today is wrong and that we do have this challenge in front of us in the near term?

Mr. HAMM. There are several believers in peak oil. I wasn’t in that group. You know, there are still some people, I guess, that maybe are talking about peak oil. But, you know, frankly it is supply and development and we are seeing so many other oil plays across the United States today that, you know, it is almost too many to quantify at this time. But the big ones that we have, of course the Bakken and Eagle Ford, and that is adding so much supply here in the United States, plus natural-gas production across the United States brings a lot of liquid with it as well.

Mr. MILLS. If I might just briefly add on your question about peak oil because it is a very interesting one, the abundance of oil production and natural gas in the United States is not a consequence of us suddenly discovering that there is oil or gas here. We didn’t find a new planet or a country; we got new technology. And what is interesting with the technology aspect of this is, technology unleashes the resources, not finding the resources per se, and it is an indicator of what the future holds, the idea whether this is a peak or not. We can look at patents as sort of a forward-looking indicator of what is emerging. So we did some research and looked at the last 5 years the numbers of patents issued in non-hydrocarbons, about 60,000. The number of patents issued in the same 5 years in the hydrocarbon fields is 150,000. So this is a permanent shift in the technological revolution.

Steve Scalise, Louisiana. I think a lot of us have been pushing to get North America energy independence within a decade. It is clearly a goal that we can achieve, but it is also clearly a goal that can’t be achieved under the current policies of President Obama,



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Dennis Coyne predicts world coal production peak in 2025-2030

See Coyne’s article at:

Dennis Coyne. March 11, 2016. Coal Shock Model. peakoilbarrel.com

[ The IPCC has not invited geologists to estimate fossil reserves, and sides with the “no limits to growth” economists.  The IPCC believes that too expensive or technologically unavailable energy resources will be exponentially available in the future out to 2100 because of magical thinking, not geology, because homo sapiens are so clever we can do anything, regardless of the laws of physics, and that if enough money is printed, anything is possible. 

But if peak oil, peak coal, peak natural gas, and peak electricity have already happened or will soon, then IPCC  projections are far too high, and we ought to be more concerned with reducing our use of fossil fuels, especially oil (the master resource), rather than greenhouse gas emissions.  After all, reducing the use of fuel reduces greenhouse gases!  Energy efficiency is not a solution, we need to actually reduce the amount of oil used every year to stay under the depletion curve.  It isn’t clear whether or not our economic system could handle that, since it is based on endless growth.  Alice Friedemann   www.energyskeptic.com ]

Posted in But not from climate change: Peak Fossil Fuels, Coal, Fossil Fuels, Peak Coal | Tagged , , | Leave a comment