[Senate Hearing 112-378]
[From the U.S. Government Publishing Office]





                                                        S. Hrg. 112-378

                  U.S. GLOBAL ENERGY OUTLOOK FOR 2012

=======================================================================

                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                      ONE HUNDRED TWELFTH CONGRESS

                             SECOND SESSION

                                   TO

          RECEIVE TESTIMONY ON THE U.S. GLOBAL ENERGY OUTLOOK 
                                FOR 2012

                               __________

                            JANUARY 31, 2012









                       Printed for the use of the
               Committee on Energy and Natural Resources

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               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                  JEFF BINGAMAN, New Mexico, Chairman

RON WYDEN, Oregon                    LISA MURKOWSKI, Alaska
TIM JOHNSON, South Dakota            JOHN BARRASSO, Wyoming
MARY L. LANDRIEU, Louisiana          JAMES E. RISCH, Idaho
MARIA CANTWELL, Washington           MIKE LEE, Utah
BERNARD SANDERS, Vermont             RAND PAUL, Kentucky
DEBBIE STABENOW, Michigan            DANIEL COATS, Indiana
MARK UDALL, Colorado                 ROB PORTMAN, Ohio
JEANNE SHAHEEN, New Hampshire        JOHN HOEVEN, North Dakota
AL FRANKEN, Minnesota                DEAN HELLER, Nevada
JOE MANCHIN, III, West Virginia      BOB CORKER, Tennessee
CHRISTOPHER A. COONS, Delaware

                    Robert M. Simon, Staff Director
                      Sam E. Fowler, Chief Counsel
               McKie Campbell, Republican Staff Director
               Karen K. Billups, Republican Chief Counsel









                            C O N T E N T S

                              ----------                              

                               STATEMENTS

                                                                   Page

Bingaman, Jeff, U.S. Senator From New Mexico.....................     1
Burkhard, James, Managing Director of IHS CERA, Cambridge Energy 
  Research Associates, Cambridge, MA.............................    19
Diwan, Roger, Partner and Head of Financial Advisory, PFC Energy.    23
Gruenspecht, Howard, Acting Administrator and Energy Information 
  Administrator, Department of Energy............................     5
Jones, Richard H., Deputy Executive Director of the International 
  Energy Agency, Paris, France...................................    10
Landrieu, Hon. Mary L., U.S. Senator From Mississippi............     2
Murkowski, Lisa, U.S. Senator From Alaska........................     3

                                APPENDIX

Responses to additional questions................................    49

 
                  U.S. GLOBAL ENERGY OUTLOOK FOR 2012

                              ----------                              


                       TUESDAY, JANUARY 31, 2012

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 10:02 a.m. in 
room SD-366, Dirksen Senate Office Building, Hon. Jeff 
Bingaman, chairman, presiding.

OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW 
                             MEXICO

    The Chairman. OK. Why don't we get started? The hearing 
will come to order.
    Thank you all for being here. This is an oversight hearing 
on the U.S. and global energy market outlook for 2012. As many 
of you know we often start the year by holding a broad overview 
hearing such as this.
    Obviously a lot has happened since last year. Since the 
last time we had an overview hearing of this type many 
countries, the Middle East and North Africa, the key oil 
producing region of the world, had popular uprisings resulting 
in new governments taking charge in what is now referred to as 
the Arab Spring of 2011. As a result, Libya, an important OPEC 
member and exporter to Europe, spent much of 2011 with oil 
production and exports near zero.
    With Libyan production and exports now almost totally 
restored or mostly restored, our focus on that region of the 
world has a new complexity because of the multi-lateral 
sanctions against Iran which also is one of the world's largest 
oil exporting Nations. Although the U.S. has sanctioned Iran 
since 1980 and has not imported Iranian oil since that time, 
Iran remains an important source of Asian and European oil 
imports. So as Europe now works to implement its own sanctions 
against Iran we can anticipate some dislocation in crude oil 
flows as the world adjusts to this new situation. These geo-
political uncertainties serve as a reminder that oil markets, 
and to be more specific, oil prices, are a very important 
factor in our country's economic security. That's why it's so 
important to fully understand the connection between U.S. and 
global oil markets.
    The oil market outlook in the U.S. is brighter than we 
would have thought possible even a few short years ago. Our oil 
production is up. Our production of alternative liquid fuels is 
up by about the same amount. Our reliance on imported petroleum 
is down.
    At the same time our cars and trucks are using that oil 
more efficiently than before. The United States has 
successfully reversed what seemed to be an inevitable trend of 
becoming ever more dependent on imported oil. So this is an 
accomplishment that we can all be grateful for.
    However it's important to note that in part because of this 
enhanced U.S. security, we, the United States, are no longer 
the primary driver behind the world oil markets and prices. As 
our oil production has gone up in the past few years, oil 
prices have gone up as well. The U.S. became a net exporter of 
refined products in recent months, yet consumers are still 
paying higher prices at the pump. That's why, I hope, we can 
use today's discussion to understand broad energy trends in 
both the U.S. and around the world. My view is that we need to 
understand not only how to make the U.S. less vulnerable to oil 
disruptions but understand what events and actions actually 
affect world oil prices.
    We have a panel of 4 expert witnesses today who can help us 
understand the interrelated markets for oil and for all of our 
energy sources.
    We'll start today's discussion with Dr. Howard Gruenspecht, 
who is the Acting Administrator of the Department of Energy's 
Energy Information Administration. He will share the highlights 
of EIA's latest short and long term energy market forecasts.
    This committee is a heavy consumer of EIA products. We 
always appreciate having EIA share its data and analysis with 
us. I note President Obama has nominated an impressive 
candidate, Adam Sieminski, to become the next Administrator of 
the EIA. In the meantime we very much appreciate Dr. 
Gruenspecht being here to present the EIA's position.
    Next we'll hear from Ambassador Jones, the Deputy Director 
of the International Energy Agency in Paris. We look forward to 
discussing IEA's forecast of total world energy supply and 
demand outlook through 2035. I'll also note that the IEA was 
founded as a forum for responding to oil supply disruptions and 
still has an important role to play in that capacity. Given the 
current geo-political environment we are especially grateful to 
be able to have Ambassador Jones here today.
    We also are pleased to have with us 2 leading energy 
analysts, both of whom have been before our committee on 
several other occasions. Both Mr. Diwan and Mr. Burkhard can 
offer their own thoughts and insights on where the oil markets 
are headed. They also each have considerable expertise in the 
geo-politics of oil.
    [The prepared statement of Senator Landrieu follows:]

    Prepared Statement of Hon. Mary L. Landrieu, U.S. Senator From 
                              Mississippi
    Thank you, Mr. Chairman for convening this hearing. It is very 
important that Congress be informed of the expected energy outlook for 
not only the U.S. but for the world so we can make informed decisions 
on the policies we enact.
    Before I get to my questions, I just want to state for the record 
that I have always been a firm believer that we should and must develop 
all of our domestic energy resources here at home to ensure our country 
more energy secure.
    Looking back on 2011, it is clear that political unrest in the 
Middle East, in particular Libya, had a profound impact on the global 
oil supply. Looking forward, it is clear that sanctions on Iran would 
have a similar effect on supply, driving the price of oil higher still.
    As I review the materials for this hearing, I see that 
International Energy Agency predicts that 2012 will be another year of 
increased volatility in the world oil market, due primarily to unrest 
in oil producing states in the Middle East. I see that they advocate 
"investment in new productive capacity, especially in diverse areas 
likely to be less susceptible to geopolitical risks" as a way to ensure 
our energy security into the future.
    I would point out that one area `less susceptible to geopolitical 
risks' is our own Gulf Coast, yet the issuance of permits for new 
drilling permits still lags behind pre-Macondo levels, which will 
continue to discourage producers from investing in increased 
capabilities in the Gulf. In addition, the slow pace of permitting has 
devastated the essential industries that support drilling- industries 
like deep sea tugs, helicopter services, and even catering.
    According to recently released study from Greater New Orleans Inc., 
42% of support businesses along the Gulf Coast are not making a profit, 
50% have laid off workers, and 46% have moved operations away from the 
Gulf Coast.
    If we are to continue to take advantage of the bountiful resources 
in our Gulf, we need these industries which form the ecosystem of 
support necessary to continue drilling in the Gulf. If we are to have a 
drilling industry in the future, it is necessary to increase the pace 
of permitting now to ensure that these businesses can afford to stay in 
the Gulf Coast.
    In addition, the Keystone XL pipeline project, which would have 
provided both additional cross-border pipeline capacity and essential 
pipeline capacity from the Midwest to the Gulf Coast, has been rejected 
with no clear plan to move forward. This rejection threatens to stall 
the development of Canadian imports and could threaten an essential 
source of North American oil.
    Despite these slowdowns, I am pleased to see that domestic 
production is projected to increase in 2012, but this enthusiasm is 
tempered by the thought that we could be producing still greater 
amounts of the energy we use here at home rather than importing it.
    It is clear from reading the materials presented for the hearing 
today that we are on the cusp of possibly another tumultuous year in 
the oil market, and that increased investment in domestic production is 
required to ensure a steady and affordable supply to ensure that 
consumers are not faced with increased energy costs in these tough 
economic times.

    The Chairman. Let me defer to Senator Murkowski for any 
opening statement she has.

         STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR
                          FROM ALASKA

    Senator Murkowski. Thank you, Mr. Chairman. I appreciate 
you convening this very important hearing. It's really a scene 
setting hearing for us here on the Energy Committee.
    In looking at the panel before us, I welcome you all back. 
I recognize that this is a welcome back. We're almost onto 
Groundhog's Day here. I would suggest that this is not going to 
be a repeat of what we heard from last year.
    As the chairman has noted there has been a lot that has 
changed from the last time we convened. The conventional wisdom 
here is that this Congress cannot accomplish any major energy 
legislation now that we are into, full on into, an election 
year. I think that that would be a disappointing finish for us. 
But it doesn't mean that the rest of the energy world is going 
to be grinding to a halt.
    Decisions are still being made or perhaps not being made on 
a daily basis about where energy can be developed, who is going 
to buy it, how it will be transported. All of those decisions, 
of course, have consequences for jobs, for our economy and for 
the prices that we pay for our energy needs. Those of you who 
have joined us today will help us understand the major trends 
and events taking place in both the U.S. and global energy 
policy.
    Whether we're talking about China taking its first steps 
toward proving up its shale gas resource, which by some 
estimates is even larger than our resource here in the United 
States. Or whether we're talking about the Strait of Hormuz 
where there are a number of somewhat unforeseen circumstances. 
I think we would all acknowledge that they could have impact on 
the everyday lives of Americans.
    So I'm interested in whether there's a challenge to 
conventional wisdom before us today. I can tell you that when 
oil prices peaked at $147 per barrel back in 2008, we here in 
Congress talked a lot about it but you didn't see much in terms 
of policy changes. We should take a lesson from that experience 
and recognize that times of relative stability are an 
opportunity to recall what we said in times of crisis. It's 
times like now when we're able to have a more reasoned 
discussion that, I believe, we should see to develop a coherent 
policy and then act on it.
    I'm particularly interested in whether the U.S. can hold it 
together and truly see through this natural gas revolution 
that's risen to the top of our energy discussion. Technology 
developed here at home has allowed us to tap the abundant 
resources that we have. We're faced with some pretty good 
problems actually.
    What to do with all the gas?
    How to handle its rapidly expanding development in a 
sustainable way?
    How to keep growing in this space without self destructing 
through the misguided regulatory or fiscal policy reactions.
    So for obvious reasons I'm going to be asking this morning 
where Alaska fits into this picture. Our very unique 
geographical position, our huge resource base, is well placed 
to satisfy some of the export demand for U.S. gas. So I want to 
understand the context of this against the concerns that many 
others, including some on this panel, have regarding the lower 
48 scenarios.
    I think it is appropriate. Timing is everything. But it's 
interesting to talk a little bit about what we know about this 
resource.
    The President in his State of the Union address just last 
Tuesday indicated that this country has potentially a hundred 
years supply of natural gas. In your new estimates the 
Marcellus shale which we previously thought held enough gas to 
meet the entire Nation's demand for 17 years at current 
consumption rates, has now been revised downward to a 6 year 
supply. So it seems like, you know, the numbers are all over 
the place. I think it speaks to fact that you've got changing 
technology, you have increased exploration that allows us to 
understand a little bit more about what we're looking at in 
terms of the reserves. But it does go to the heart of what you 
all deal with and that is understanding the numbers, 
understanding what we're dealing with in terms of supply.
    A long time before the President agreed with those of us 
calling for an all of the above energy policy, it became 
evident that the U.S. still really does matter in terms of 
influencing world energy trends and truly determining our own 
fate. If an emergency or a disaster does occur there's a strong 
likelihood that the rest of the world will look to us for 
leadership. We've got to be ready for that.
    So I'm hopeful that this hearing will help inform, not only 
this committee, but others of patterns developing and help us 
to see where we could act, where we should act and where the 
best investments for our very limited Federal resources might 
be. I look forward to hearing from each of you this morning and 
the discussion that will follow.
    The Chairman. Alright. Why don't we go ahead?
    Dr. Gruenspecht, why don't you take what time you need to 
summarize your annual report, your new outlook and then we'll 
hear from Ambassador Jones?

   STATEMENT OF HOWARD GRUENSPECHT, ACTING ADMINISTRATOR AND 
    ENERGY INFORMATION ADMINISTRATION, DEPARTMENT OF ENERGY

    Mr. Gruenspecht. Thank you, Mr. Chairman and members of the 
committee. I appreciate the opportunity to appear before you 
today.
    The Energy Information Administration is the statistical 
and analytical agency within the Department of Energy. EIA does 
not promote or take positions on policy issues and has 
independence with respect to the information and analysis we 
provide. Therefore our views should not be construed as 
representing those of the Department or other Federal agencies.
    Starting with the short term outlook, EIA expects that the 
global market will rely on both increases in production of 
crude oil and non crude liquids and a draw on inventories to 
meet world demand growth this year. The price of West Texas 
Intermediate crude oil is forecast to average about $100 per 
barrel in 2012, roughly $5 above last year's level. 
Uncertainties such as surprises in economic growth or geo-
political issues affecting Middle East suppliers that, I think, 
were mentioned in the opening statements could push oil prices 
higher or lower than projected. Based on recent futures and 
options data the market believes that there is about a one in 8 
chance that the average WTI price in June 2012 will exceed $125 
per barrel and about a 1 in 25 chance that it would exceed $140 
per barrel.
    On a related matter to geo-political issues, EIA is working 
diligently to meet the February 29th deadline to submit to 
Congress a report on the availability and price of petroleum 
and petroleum products produced in countries other than Iran as 
required under the National Defense Authorization Act. This is 
a report that we are to prepare every 60 days and the first one 
is due February 29th.
    Turning to consumer prices and expenditures EIA has lowered 
its forecast of average household heating expenditures this 
winter due to warmer weather. Our baseline forecast for average 
gasoline prices in 2012 is slightly below last year's level, 
about a nickel a gallon. Although recent options and futures 
price data imply that the market believes there is about a one 
in 5 chance that the U.S. average pump price of regular 
gasoline will exceed $4 in June of this year,the idling of 3 
refineries on the east coast could have an impact on regional 
prices, especially as the market transitions to new supply 
sources. This is another issue that we are watching closely and 
I know there's a lot of interest in Congress.
    I will now turn to the longer term projections from our new 
Annual Energy Outlook. The reference case represents an energy 
future reflecting current market and technology trends, current 
consumer behavior and existing laws and regulations. EIA 
certainly recognizes that projections of energy markets, 
whether short term or long term, are highly uncertain and cases 
addressing a variety of alternative market, technology and 
policy scenarios will be released this spring.
    In the new reference case increased domestic oil, natural 
gas and renewable energy production coupled with energy 
efficiency improvements reduces U.S. reliance on imported 
energy sources. In the outlook domestic crude oil production is 
expected to grow by more than 20 percent over the coming 
decade, again, as alluded to in the opening statements.
    Net petroleum imports as a share of total U.S. liquid fuels 
consumed drop from 49 percent in 2010 and they had been as high 
as 60 percent in recent years, to 36 percent in 2035. I should 
note that proposed fuel economy standards covering model years 
2017 through 2025 are not included in the reference case and 
would further reduce projected liquid fuels demand and net 
petroleum imports.
    U.S. production of natural gas is projected to exceed 
consumption early in the next decade. We expect reliance on 
renewable energy and natural gas for electric power generation 
to rise. Putting all of this together, total U.S. energy 
related carbon dioxide emissions are more than 7 percent below 
their 2005 level, the 2005 level is something that policymakers 
look at often, in 2020 and remain below their 2005 level 
through 2035.
    Shifting to the outlook for global energy use. Our latest 
international reference case projects worldwide energy 
consumption growing about 53 percent by 2035 with China and 
India accounting for half of the increase. While fossil fuels 
continue to dominate, renewable energy is projected to be the 
fastest growing source of primary energy. Natural gas has the 
fastest growth rate among the fossil fuels. Developing 
countries really dominate the growth in all categories of 
energy use.
    There are both similarities and differences in the 
international energy outlooks developed by the EIA and the IEA, 
my colleague here.
    Starting with similarities in both EIA's reference case and 
IEA's current policy scenario to which it's most directly 
comparable, world liquid production reaches similar levels over 
the next 25 years and developing countries account for the vast 
majority of the growth in global energy use.
    Turning to differences, the IEA projects that the OPEC 
share of world liquid supply would increase to over 50 percent 
by 2035. Under similar price assumptions EIA anticipates that 
the OPEC market share would remain near its current level of 
about 42 percent and that conventional and unconventional oil 
production, outside of OPEC, will continue to increase. A big 
wild card is certainly what happens with tight oil or shale 
oil, as it's called. Will that become a worldwide phenomenon?
    Also the gap between projected U.S. natural gas prices in 
the latest EIA and IEA outlooks has narrowed as the IEA has cut 
its price projection for the U.S. market over the last several 
years. But IEA's U.S. natural gas import prices are still more 
than 40 percent above EIA's reference case price at the end of 
the projection. Our price remains under $7 per million BTU in 
today's dollars in 2035.
    This concludes my testimony, Mr. Chairman and members of 
the committee. I would be happy to answer any questions you 
might have.
    [The prepared statement of Mr. Gruenspecht follows:]

  Prepared Statement of Howard Gruenspecht, Acting Administrator and 
        Energy Information Administration, Department of Energy
    Mr. Chairman and Members of the committee, I appreciate the 
opportunity to appear before you today to discuss the U.S. and global 
energy outlook.
    The U.S. Energy Information Administration (EIA) is the statistical 
and analytical agency within the U.S. Department of Energy. EIA 
collects, analyzes, and disseminates independent and impartial energy 
information to promote sound policymaking, efficient markets, and 
public understanding regarding energy and its interaction with the 
economy and the environment. EIA is the Nation's premier source of 
energy information and, by law, its data, analyses, and forecasts are 
independent of approval by any other officer or employee of the United 
States Government. The views expressed in our reports, therefore, 
should not be construed as representing those of the Department of 
Energy or other federal agencies.
    The energy projections that I will discuss today are widely used by 
government agencies, the private sector, and academia as a starting 
point for their own energy analyses. EIA prepares both short-term 
energy outlooks, examining monthly trends over the next one to two 
years, and long-term outlooks, with annual projections over the next 
20-to-25 years. Copies of the most recent outlooks are included as part 
of my testimony. While I will be focusing primarily on the long-term 
outlooks in my remarks today, I would like to first summarize some key 
findings from our January Short Term Energy Outlook (STEO), which 
includes monthly forecasts through the end of 2013.
The short-term energy outlook
    EIA expects the price of West Texas Intermediate (WTI) crude oil to 
average about $100 per barrel in 2012, $5 per barrel higher than the 
average price last year. EIA expects that the market will rely on both 
increases in production of crude oil and non-crude liquids and a draw 
on inventories to meet world demand growth. There are many significant 
uncertainties, such as changes in expected economic growth or 
geopolitical issues affecting Middle Eastern suppliers that could push 
oil prices higher or lower than projected. The National Defense 
Authorization Act signed by the President at the end of December, 
requires EIA, in consultation with Treasury, State and the intelligence 
community, to submit to Congress every 60 days a report on the 
availability and price of petroleum and petroleum products produced in 
countries other than Iran. We are working diligently to provide the 
requested data within the specified timeframe.
    Mild weather the first half of this heating season has resulted in 
a lower forecast of average household heating expenditures for the 
current winter than published in the October 2011 Outlook. Natural gas 
inventories continue to set new record highs. As of the most recent 
report last week, working inventories were 3.1 trillion cubic feet 
(Tcf), about 20 percent above their level at the same time last year, 
which was close to the historical five year average. Household 
expenditures for natural gas, propane and electricity expenditures are 
now projected to be lower than last winter. While still higher than 
last winter, average household heating oil expenditures are now 
expected to increase by only 4 percent down from the earlier projection 
of an 8 percent.
    EIA expects regular-grade motor gasoline retail prices to be 
slightly lower than last year at an average $3.48 per gallon in 2012, 
and $3.55 per gallon in 2013. There are regional variations in the 
forecast, with average expected prices on the West Coast about 25 cents 
per gallon above the national average during the April through 
September peak driving season each year; nationally prices are forecast 
to average about 5 cents per gallon higher than the annual average 
during the peak driving season. The idling of three refineries on the 
East Coast could have an impact on prices, especially as the market 
transitions to new supply sources. This issue is addressed in a 
December 2011 report ``Reductions in Northeast Refining Activity: 
Potential Implications for Petroleum Product Markets,'' that provides 
information responsive to several Congressional inquiries to EIA on 
this matter. We are working on a more comprehensive follow-on report 
that will be issued in the near future.
Long-term energy outlooks
    Annual Energy Outlook--Turning to the Annual Energy Outlook 2012 
(AEO2012), the Reference case discussed in this testimony was released 
last week and is intended to represent an energy future through 2035 
based on given market, technological, and demographic trends; current 
laws and regulations; and consumer behavior. EIA recognizes that 
projections of energy markets are highly uncertain and subject to 
geopolitical disruptions, technological breakthroughs, and other 
unforeseeable events. In addition, long-term trends in technology 
development, demographics, economic growth, and energy resources may 
evolve along a different path than represented in the projections. The 
complete AEO2012, which EIA will release this spring, will include a 
large number of alternative cases intended to examine these 
uncertainties.
    A copy of the AEO2012 Early Release Overview* is included as part 
of my testimony so I will summarize here.
---------------------------------------------------------------------------
    * A copy of the Early Release Overview has been retained in 
committee files.
---------------------------------------------------------------------------
    Domestic crude oil production is expected to grow by more than 20 
percent over the coming decade--Domestic crude oil production increased 
from 5.1 million barrels per day in 2007 to 5.5 million barrels per day 
in 2010. Over the next 10 years, continued development of tight oil 
combined with the development of offshore Gulf of Mexico resources are 
projected to push domestic crude oil production to 6.7 million barrels 
per day in 2020, a level not seen since 1994.
    With modest economic growth, increased efficiency, growing domestic 
production, and continued adoption of nonpetroleum liquids, net 
petroleum imports make up a smaller share of total liquids 
consumption--U.S. dependence on imported petroleum liquids declines in 
the AEO2012 Reference case, primarily as a result of growth in domestic 
oil production of over 1 million barrels per day by 2020, an increase 
in biofuel use of over 1 million barrels per day crude oil equivalent 
by 2024, and modest growth in transportation sector demand through 
2035. Net petroleum imports as a share of total U.S. liquid fuels 
consumed drop from 49 percent in 2010 to 38 percent in 2020 and 36 
percent in 2035 in AEO2012. Note that proposed fuel economy standards 
covering model years 2017 through 2025 that are not included in the 
Reference case would further reduce projected levels of liquid fuels 
use and net petroleum imports.
    U.S. production of natural gas is expected to exceed consumption 
early in the next decade--The United States is projected to become a 
net exporter of liquefied natural gas (LNG) in 2016, a net pipeline 
exporter in 2025, and an overall net exporter of natural gas in 2021. 
The outlook reflects increased use of LNG in markets outside of North 
America, strong domestic natural gas production, reduced pipeline 
imports and increased pipeline exports, and relatively low natural gas 
prices in the United States compared to other global markets.
    Use of renewable fuels and natural gas for electric power 
generation rises--The natural gas share of electric power generation 
increases from 24 percent in 2010 to 27 percent in 2035, and the 
renewables share grows from 10 percent to 16 percent over the same 
period. In recent years, the U.S. electric power sector's historical 
reliance on coal-fired power plants has begun to decline. Over the next 
25 years, the projected coal share of overall electricity generation 
falls to 39 percent, well below the 49-percent share seen as recently 
as 2007, because of slow growth in electricity demand, continued 
competition from natural gas and renewable plants, and the need to 
comply with new environmental regulations.
    Total U.S. energy-related carbon dioxide (CO2) emissions 
remain below their 2005 level through 2035: Energy-related 
CO2 emissions grow by 3 percent from 2010 to 2035, reaching 
5,806 million metric tons in 2035. They are more than 7 percent below 
their 2005 level in 2020 and do not return to the 2005 level of 5,996 
million metric tons by the end of the projection period. Emissions per 
capita fall by an average of 1 percent per year from 2005 to 2035, as 
growth in demand for transportation fuels is moderated by higher energy 
prices and Federal fuel economy standards. Proposed fuel economy 
standards covering model years 2017 through 2025 that are not included 
in the Reference case would further reduce projected energy use and 
emissions. Electricity-related emissions are tempered by appliance and 
lighting efficiency standards, State renewable portfolio standard 
requirements, competitive natural gas prices that dampen coal use by 
electric generators, and implementation of the Cross-state Air 
Pollution Rule.
Other highlights of the AEO2012 Reference case projections
   World oil prices rise in the Reference case, as pressure 
        from growth in global demand continues. In 2035, the average 
        real price of crude oil in the Reference case is $146 per 
        barrel in 2010 dollars. World liquids consumption grows from 
        87.1 million barrels per day in 2010 to 109.7 million barrels 
        per day in 2035, driven by growing demand in China, India, the 
        Middle East, and other developing economies.
   Total U.S. primary energy consumption, which was 101.4 
        quadrillion Btu in 2007, grows from 98.2 quadrillion Btu in 
        2010 to 108.0 quadrillion Btu in 2035. The fossil fuel share of 
        energy consumption falls from 83 percent of total U.S. energy 
        demand in 2010 to 77 percent in 2035.
   Net imports of energy meet a declining share of total U.S. 
        energy demand as domestic energy production increases. The 
        projected net import share of total U.S. energy consumption in 
        2035 is 13 percent, compared with 22 percent in 2010 and 29 
        percent in 2007.

    International Energy Outlook--Given the interconnectedness of U.S. 
energy markets and the broader global markets, the international 
outlook provides useful context for the more detailed U.S. projections 
outlined above. I will briefly describe some highlights of EIA's 
International Energy Outlook 2011 (IEO2011), which was issued last 
September. I will also discuss some similarities and differences from 
the World Energy Outlook 2011 (WEO2011) developed by the International 
Energy Agency (IEA) that you will also be hearing about today.
    EIA's IEO2011 Reference case develops a projection that assumes 
current laws and policies, but does not anticipate new policies or 
regulations that have not yet been implemented. In the IEO2011 
Reference case, worldwide energy consumption grows by 53 percent 
between 2008 and 2035 with much of the increase driven by strong 
economic growth in the developing nations. China and India account for 
half of the projected increase in world energy use over the next 25 
years. China alone, which only recently became the world's top energy 
consumer, is projected to use 68 percent more energy than the United 
States by 2035. A few highlights follow:

   Renewable energy is projected to be the fastest growing 
        source of primary energy over the next 25 years, but fossil 
        fuels remain the dominant source of energy. The renewable share 
        of total energy use increases from 10 percent in 2008 to 15 
        percent in 2035.
   Natural gas has the fastest growth rate among the fossil 
        fuels over the 2008 to 2035 projection period. Unconventional 
        natural gas (tight gas, shale gas, and coalbed methane) 
        supplies increase substantially-especially from the United 
        States, but also from Canada and China.
   World oil prices remain high in the Reference case, but 
        liquids consumption continues to grow; both conventional and 
        unconventional liquid supplies are used to meet rising demand.
   Electricity is the world's fastest-growing form of end-use 
        energy consumption in the Reference case, as it has been for 
        the past several decades.
   The transportation share of world total liquids consumption 
        increases from 54 percent in 2008 to 60 percent in 2035, 
        accounting for 82 percent of the total increase in world 
        liquids consumption.
   Energy-related carbon dioxide emissions rise from 30.2 
        billion metric tons in 2008 to 43.2 billion metric tons in 
        2035-an increase of 43 percent. Much of the increase in carbon 
        dioxide emissions is projected to occur among the developing 
        nations of the world, especially in Asia.

    The IEO2011 Reference case is most directly comparable to the 
Current Policies Scenario (CPS) in the IEA's WEO2011, and there are 
many similarities in their projections. In both the IEO2011 Reference 
case and the WEO2011 CPS, non-OECD countries account for the vast 
majority of growth in global energy use, which is expected to increase 
by 1.6 percent per year between 2009 and 2035. Non-OECD energy 
consumption growth increases by 2.3 percent per year, while China's 
energy use grows at a somewhat faster rate of 2.5 to 2.7 percent per 
year. World liquids consumption reaches about 112 million barrels per 
day in both projections.
    There are, however, also some important differences between the 
IEO2011 Reference case and the WEO2011 CPS. For example, the WEO2011 
CPS projects that the OPEC share of world liquids supply will increase 
from about 42 percent in 2010 to 51 percent in 2035. Under similar 
price assumptions, the IEO2011 Reference case anticipates that the OPEC 
market share will remain at about 42 percent and that non-OPEC supplies 
from both conventional and unconventional sources will continue to 
increase.
    Another difference concerns the outlook for U.S. natural gas 
markets. The WEO2011 CPS projects that U.S. natural gas import prices 
will more than double over the projection, from $4.40 per million Btu 
(real 2010 dollars) to $9.90 per million Btu in 2035. The IEO2011 
Reference case also anticipates an increase in U.S. natural gas import 
prices, but they rise more slowly, reaching only $6.90 per million Btu 
in 2035.
    I should note that while the IEO2011 Reference case and WEO2011 CPS 
are most directly comparable, it is the New Policies Scenario (NPS) 
rather than the CPS that is featured as the central scenario in the 
WEO2011. The NPS assumes ``recent government policy commitments are 
implemented in a cautious manner, even if they are not yet backed up by 
firm measures.'' It can be a real challenge of course, to determine 
what does or does not constitute a ``policy commitment'' under an NPS-
type scenario. Indeed, there are even questions surrounding the 
definitions of``current policies'' for a CPS or Reference case. For 
example, while the IEO follows the AEO convention that existing energy 
tax credits and related incentives in the United States that have 
statutory expiration dates expire as scheduled for purposes of the 
projections, the CPS appears to contemplate the indefinite extension of 
existing incentives.
Conclusion
    As I noted at the outset, while EIA does not take policy positions, 
its data, analyses, and projections are meant to assist policymakers in 
their energy deliberations. In addition to the work on baseline 
projections that I have reviewed this morning, EIA has often responded 
to requests from this committee and others for analyses of the energy 
and economic impacts of energy policy proposals. This concludes my 
testimony, Mr. Chairman and members of the committee. I would be happy 
to answer any questions you may have.

    The Chairman. Thank you very much.
    Ambassador Jones, go right ahead.

STATEMENT OF RICHARD H. JONES, DEPUTY EXECUTIVE DIRECTOR OF THE 
           INTERNATIONAL ENERGY AGENCY, PARIS, FRANCE

    Mr. Jones. Thank you very much, Mr. Chairman, members of 
the committee. I'm going to keep my remarks short and focus on 
the oil market today. My longer, prepared testimony also 
includes remarks on gas and coal markets as well as the outlook 
to 2035.
    Our base case view for 2012 envisages global oil demand 
growth of just over one million barrels per day. On the other 
hand, we think that non-OPEC oil supply and OPEC gas liquids, 
which are not subject to production restraints will rebound by 
as much as 1.6 million barrels per day combined. At current 
OPEC production levels this would imply some slack in the 
market and a recovery in world oil stocks which are now well 
below 5 year averages after more than a year of steady decline.
    However, it appears more likely that OPEC producers will 
trim supply by around half a million barrels per day to produce 
at 30 million barrels per day. This would hold inventory levels 
roughly where they are now which is, as I said, a pretty short 
supply. Although huge uncertainty surrounds the ability of non-
OPEC supply to rebound from the awful year it suffered in 2011, 
there were a lot of unplanned outages. We, and many of our 
analytical peers, believe it can.
    Libyan production continues to recover. Higher oil prices 
have put some expansion projects elsewhere back on track while 
the application of shale gas technology to light tight oil has 
transformed U.S. upstream oil prospects, as Dr. has said. Tight 
oil alone could grow by 250 thousand barrels per day to reach 
870 thousand barrels per day in 2012. In fact increased supply 
from the United States, Canadian oil stands and Brazilian deep 
water output generates much of the expected one million barrels 
per day growth we see for non-OPEC production in 2012 with 
Russia, biofuels and natural gas liquids also making 
significant contributions.
    While there are, of course, downside risks to this forecast 
of non-OPEC supply growth, oil demand might also fall short of 
our expectations. Recently announced revisions to the IMF's 
world economic outlook posit global GDP growth for 2012 at 3.3 
percent compared to previous forecasts that were nearer to 3.9 
percent. Arguably downside risks for demand and non-OPEC supply 
might balance each other out. If so, OPEC may well try to 
navigate through 2012 producing at or around 30 million barrels 
per day implying underlying spare capacity of between 3 and 4 
million barrels per day.
    Now this estimate of spare capacity will come under 
scrutiny as another looming supply side issue for 2012 unfolds. 
I'm speaking of Iran. The recently announced U.S. sanctions on 
entities having financial dealings with the Iranian Central 
Bank and the new European Union embargo on oil imports from 
Iran will clearly affect the mix of crude oil supply available 
on a regional basis even if absolute levels of global crude 
supply may be impacted to a lesser degree.
    Iran currently exports around two and a half million 
barrels per day of crude oil with 65 percent of this going to 
Asia and some 30 percent into Europe, mostly to refiners around 
the Mediterranean. A significant portion of the 1.3 million 
barrels per day of Iranian crude imported by IEA member 
countries which, of course, include some countries in Asia like 
Japan and Korea, anyway, increasing a significant portion is 
likely to be affected by these majors. Even if refiners will 
have until June or July to source alternative barrels, most are 
already looking for incremental supplies from outside Iran 
which is exactly the intent of course of the sanctions.
    In terms of crude quality buyers are likely to seek extra 
barrels from Saudi Arabia, Russia or Iraq to make up for lost 
sales from Iran. While Saudi Arabia has publicly reassured 
customers that it will meet their requirements analysts have 
raised questions over the extent of the Kingdom's spare 
capacity, the proportion of Arab Medium which is a good 
substitute for the bulk of Iranian exports within that spare 
capacity and the Kingdom's logistical flexibility to reorient 
its exports to European refiners. Ultimately refiners denied 
the ability to import Iranian oil will most likely find the 
extra barrels they need, but perhaps at higher prices than 
might otherwise have been the case.
    Of course, Iranian authorities also have threatened to 
institute an embargo of their own on exports to Europe and to 
impede traffic through the Strait of Hormuz. The latter threat 
is of greater concern to world oil markets. 17 million barrels 
per day, equivalent to some 20 percent of global oil supplies 
pass through the Strait. To a degree such threats have already 
been factored into market prices, we believe. The likelihood of 
a prolonged blockage of Hormuz transits is seen as being fairly 
low.
    Mr. Chairman, in sum, all of this suggests that those who 
are seeking a more tranquil oil market in 2012 may well be 
disappointed. At the IEA we'll continue our monitoring of oil 
market conditions and in particular the availability of 
alternative market supplies. No physical disruption of oil 
supply has occurred yet. But as always, the Agency will remain 
vigilant and stands ready to act rapidly and decisively if a 
major disruption occurs.
    Thank you, Mr. Chairman.
    [The prepared statement of Mr. Jones follows:]

 Prepared Statement of Richard H. Jones, Deputy Executive Director of 
             the International Energy Agency, Paris, France
    Mr. Chairman, and members of the committee, I am grateful for the 
opportunity to come before you today to discuss the views of the 
International Energy Agency (IEA) on recent oil market developments and 
prospects for 2012. I hope that my testimony will help to inform the 
important work of this committee as it begins crafting policies in the 
new year.
    A retired American diplomat with experience on Middle Eastern and 
energy issues, I have served as Deputy Executive Director of the 
International Energy Agency since October, 2008. The IEA is an 
intergovernmental organization that acts as an advisor to 28 member 
countries, including the United States, in their effort to ensure 
reliable, affordable and clean supplies of energy for their citizens. 
Founded during the 1973-74 oil crisis, the central role of the IEA was 
and remains to co-ordinate response measures in times of oil supply 
emergencies. As energy markets have evolved, however, so has the IEA. 
Its mandate today also incorporates work on market reform, energy-
technology collaboration, climate-change policies and outreach to the 
rest of the world, especially major consumers and producers of energy 
including China, India, Russia and OPEC countries.
    I will use my time this morning to focus on the oil market, which 
has become a focus of attention once again amid high prices and 
elevated tensions in the North Africa and Middle East (MENA) region. I 
have also attached a written appendix, covering market movements for 
other sources of energy, and the long term outlook for global energy.
Oil market developments in 2011
    Having steadily risen from a low point of below $40/bbl in February 
2009 to a high of around $120/bbl last spring, crude oil prices have 
shown a degree of stability ever since. A $100-$120/bbl envelope looks 
to have become established, with prices oscillating within that range. 
Of course, as we have noted before, oil prices at these elevated levels 
still pose significant problems for import-dependent countries, 
especially those which subsidise end-user prices heavily. In this 
regard, we estimate that the proportion of total world GDP dedicated to 
oil expenditures was back up above 5% for 2011, as it was during the 
economic slump of 2008 and during several previous periods of severe 
economic downturn. High oil prices may or may not have caused these 
episodes of economic difficulty, but they certainly did not help.
    Many have pointed to the apparent paradox of prices at or above 
$100/bbl when the world apparently faces the prospect of economic slow-
down and therefore diminishing levels of likely oil demand growth. The 
invisible hand of market speculators is often referred to as having 
held oil prices artificially high. And yet detailed research has so far 
failed to identify a smoking gun in the commodities derivatives 
markets:

   there is no clear link between futures market activity and 
        oil price moves;
   market volatility has declined from 2008 highs and is not 
        out of line with historical levels or compared with that in 
        other commodity markets;
   evidence is slim surrounding so-called `excessive 
        speculation';
   and indeed, both price levels and volatility for exchange-
        traded commodities have been less exaggerated than they have 
        for their non- exchange-traded counterparts.

    This is not to say that interactions between physical commodity and 
financial markets have not increased: they have. And short term price 
moves at an intra-day or intra-week level may well be amplified by what 
is happening in the derivatives markets. But there are more obvious 
factors that appear to have held prices high in 2011--the relationship 
between demand and supply, and a steady tightening in OECD inventory 
levels that has resulted from a marked imbalance between global supply 
and demand since early-2010.
    In 2010, world oil demand grew by a near-record 2.7 mb/d as the 
global economy rebounded from recession. Growth was particularly strong 
in the non-OECD economies, which accounted for 80% of the increase. And 
supply was not able to keep up, rising by less than 2 mb/d. So we saw 
an implied global stock draw of 0.8 mb/d in 2010.
    The picture however changed subtly in 2011: In fact, global oil 
stocks still declined by 0.5 mb/d, but this time due to severe 
shortfalls from the supply side, which was unable to keep up even with 
much more moderate oil demand growth of only 0.7 mb/d. Firstly, a spate 
of unscheduled disruptions wiped-out expected growth in non-OPEC supply 
which, in the event, barely held steady in 2011 at 52.7 mb/d. The North 
Sea, Canada, Brazil, Argentina, Malaysia and China all saw a 
combination of technical and industrial-related production shortfalls, 
while political unrest sharply curbed supplies from Yemen, Syria and 
Sudan. All these events however pale into insignificance compared with 
the key oil market development of 2011--the loss of Libyan supply. 
This, you will recall, was an event that prompted the IEA in June of 
2011 to call for a release of 60 million barrels of strategic 
inventories, to act as a bridge to higher supplies from other OPEC 
producers, to add physical liquidity to the market (notably in the form 
of light-sweet crude oil), and to try to prevent a potentially abrupt 
drawdown in OECD inventories during the second half of 2011 if other 
OPEC supplies did not increase to help offset the loss from Libya.
    The agency today feels vindicated. The release of stocks, 
particularly from the US SPR, provided short term liquidity in light-
sweet crude, and allowed the re-routing of export cargoes otherwise 
headed to North America, back towards European refiners who most keenly 
felt the loss of Libyan feedstocks. To date, we estimate the Libyan 
crisis has cost the market 425 million barrels of lost supply, even 
though production has begun to recover in recent months. While other 
OPEC members, notably Saudi Arabia, did step in during the summer to 
raise production, so far their efforts and the IEA stock release 
combined have only managed to fill around 75% of the gap left by 
reduced Libyan volumes. OECD company inventories have continued to 
tighten, but to a much lesser degree than risked being the case back in 
June. We think the coordinated action by IEA members played at least a 
partial role in helping avoid a damaging price spike during summer 
2011. Nonetheless, operating inventories, particularly for crude oil in 
Europe, starved of light-sweet Libyan supplies for much of 2011, stand 
well below the five year average.
    In short, market fundamentals have continued to tighten in 2011, 
yet prices have been stabilized by the countervailing influence of a 
potentially weakening global economy on the one hand, and geopolitical 
instability which is raising questions about supplies from the Middle 
East Gulf region on the other.
 How long can this apparent stability last?
    We note in the latest issue of the Oil Market Report, our monthly 
assessment of recent market fundamentals and short term outlook, that 
this relative price calm could be fragile. While we habitually avoid 
making specific price prognoses, much depends on whether economic 
malaise or supply-side problems predominate in the next year.
    Our `base case' view for 2012 envisages global oil demand growth of 
just over 1 mb/d. We think that non-OPEC oil supply and OPEC gas 
liquids (which are not subject to OPEC's production management system) 
will rebound by as much as 1.6 mb/d combined, leaving OPEC producers an 
opportunity to trim their collective crude supply by around half a 
million b/d to 30 mb/d and still maintain inventory levels roughly 
where they are now.
    But of course huge uncertainty surrounds the ability of non-OPEC 
supply to rebound from the awful year it suffered in 2011. We and many 
of our analytical peers believe it can, continuing the trend of 
reinvigorated growth that was seen in 2009 and 2010. Higher oil prices 
have seen upstream spending increase and have brought a number of 
tentative expansion projects back on track. And not least, favourable 
oil-gas price differentials and the application of the technologies 
deployed in the US's shale gas revolution to light tight oil (LTO) have 
transformed US upstream oil prospects. LTO production alone could grow 
by 250 kb/d to reach 870 kb/d in 2012. Consensus expectations for non-
OPEC growth in 2011 range from around 0.5-1.0 mb/d, with our own at the 
upper end of that range. Either way, supply from the Americas (not only 
the US, but also Canadian oil sands and Brazilian deepwater output) 
generate much of the expected growth, with Russia, biofuels and natural 
gas liquids also expected to make significant contributions.
    There may indeed be downside risks to non-OPEC supply compared with 
our base case, particularly if higher spending cannot offset the type 
of disruptions seen in 2011. But two years in a row dogged by that 
level of outages would be most unusual. Equally likely, oil demand 
might also fall short. Recently announced revisions to the IMF World 
Economic Outlook posit global GDP growth for 2012 at 3.3%, compared to 
previous levels near 3.9%. All other things being equal, this could 
feed through to reduce our own expectation for oil demand in 2012, 
although late-winter weather and the degree to which non-OECD economies 
continue to buck the weakening growth trend of the OECD could 
complicate matters. Arguably, these downside risks for demand and non-
OPEC supply might just balance each other out. So OPEC may well try to 
navigate through 2012 producing at or around 30 mb/d, slightly lower 
than the 30.9 mb/d we think they supplied to the market in December, 
and implying underlying spare capacity of between 3-4 mb/d.
Turning to the Iranian Question
    This estimate of spare capacity may be brought into sharper focus 
as another looming supply-side issue for 2012 unfolds, namely that of 
Iran. Leaving aside the geopolitical merits of measures designed to 
prevent Iran from attaining nuclear weapons capability, the recently 
announced US sanctions on entities having financial dealings with Iran, 
and the upcoming EU embargo on oil imports from Iran, will clearly 
affect the mix of crude oil supply available on a regional basis, even 
if absolute levels of global crude supply may be impacted to a lesser 
degree. 



    Iran exports around 2.5 mb/d of crude oil, with 65% of this going 
to Asia and some 30% into Europe (the bulk of this to refiners around 
the Mediterranean rim). A significant portion of the 1.3 mb/d of crude 
imported by IEA member countries is likely to be affected by at least 
one of these measures, even if refiners will have until June/July to 
source alternative barrels. The extent to which US sanctions are 
actually applied will depend on a Presidential determination in the 
spring, and the precise impact of the EU embargo has also yet to be 
fully assessed. But Mediterranean refiners, together with their IEA 
Pacific colleagues, will likely be looking for incremental supplies 
from outside Iran between now and the measures' implementation in the 
summer. In terms of crude quality, buyers are likely to seek extra 
barrels from Saudi Arabia, Russia or Iraq to make up for lost sales 
from Iran. While Saudi Arabia has tried to reassure customers that 
existing and incremental requirements will continue to be met, analysts 
have raised questions over the extent of the Kingdom's spare capacity, 
the proportion of Arab Medium (a good substitute for the bulk of 
Iranian exports) within the Kingdom's spare capacity, and its 
logistical flexibility to re-orient exports in a westerly direction if 
European refiners in particular need extra volumes. Ultimately, we 
think refiners denied the ability to import Iranian oil will most 
likely find the extra barrels they need, albeit they may need to pay 
higher prices than might otherwise have been the case.
    Conversely, there is a widespread expectation that Iran will try to 
retain or increase sales to non-OECD buyers, potentially making extra 
spot sales into Asia at discounted prices. The success or otherwise of 
the economic measures taken against Iran will therefore depend heavily 
on the response of China and India, which together already purchase 
around 860 kb/d of Iranian oil, or 34% of the country's crude exports.
    Nor have the Iranian authorities been silent as these economic 
sanctions have been deployed. Of greatest concern for the oil market is 
the threat by Iran to impede traffic through the Strait of Hormuz (17 
mb/d, equivalent to some 20% of global oil supplies) if an embargo is 
applied as well as its threat to retaliate against neighbouring 
producers if they try to boost exports. To a degree, such threats have 
already been priced into the market, while the likelihood of a 
prolonged stoppage for Hormuz transits is seen as being fairly low.
In conclusion
    All of this suggests that those seeking a more tranquil 2012 oil 
market than was seen in 2011 may be disappointed. At the IEA we will 
continue our ongoing and detailed monitoring of oil market conditions 
and in particular the availability of alternative market supplies. So 
far there is no physical supply disruption underway. But as always the 
Agency will remain vigilant and it stands ready to act rapidly and 
decisively if a major disruption to oil supply occurs. Emergency oil 
stocks, as their name suggests, are for use only when the market's 
ability to efficiently reallocate supplies in a crisis is compromised. 
Ongoing investment in new productive capacity, especially in diverse 
areas likely to be less susceptible to geopolitical risks, and a 
progressive improvement in energy and oil use efficiency provide longer 
term routes to greater supply security. But, if the mere availability 
of IEA strategic stocks helps calm otherwise jittery market nerves in 
2012, so much the better.
    Thank you Mr. Chairman.
                               appendices
          1. Recent developments in gas, coal and power markets

    Decoupling of world gas markets has reached a new level. In North 
America domestic production growth has accelerated. For the January--
October period US gas production is up by 7-8% (40bcm), compared to 
growth rates between 2-3% in recent years. Abundant supply led to 
persistently low prices under $3.00/Mbtu. So far, there is no sign of 
such low prices leading to a slowdown of production. This is most 
likely due to the financial benefits of natural gas liquids as well as 
the associated gas from light tight oil.
    As a result of low gas prices, gas- fired electricity generation in 
the US has continuously increased its load factor at the expense of 
coal. Gas fired power generation in the US is likely to have exceeded 
1000 Twh in 2011 for the first time in history, and gas is now 24% of 
US power generation, up from 21% in 2008. As a mirror image of 
expanding gas usage, coal-fired power generation in the US is down by 
7% on a year on year basis, leading to declining coal demand. As the 
new IEA publication released in December 2011 (Medium Term Coal Market 
Outlook) emphasized, due to the competition with gas, US domestic coal 
demand, which is dominated by power generation is unlikely ever to 
return to its historical peak seen before the financial crisis.
    Due to the continuously growing availability of cheap gas, there is 
an increasing interest in gas exports from the United States: the 
Sabine Pass project has signed export contracts for around 15 million 
tons of LNG supply for Western Europe (BG and Gas Natural) as well as 
India. The Medium Term Gas Market Outlook, which will be released in 
June 2012, will examine the prospects for US gas exports over the next 
five years in detail.
    In a stark contrast to North America, international LNG markets 
have tightened. This is primarily due to increasing LNG demand in the 
Asia Pacific region, especially Japan. Due to safety reviews and 
regulatory checks affecting a substantial part of Japanese nuclear 
capacity, Japanese nuclear production currently is running at less than 
one third of its pre-earthquake level. So far, Japan has managed to 
avoid blackouts by disciplined demand side management and increasing 
utilization of gas-fired electricity generation, leading to a 
substantial (10 million tons on an annualized basis) increase of its 
LNG imports. LNG spot prices in the Asia - Pacific region rose as well 
and quickly exceeded 16 USD/Mbtu; LNG tanker freight rates have doubled 
since last year. No major new LNG supply will be coming online in the 
next 3 years, so market tightness is likely to endure. More detailed 
IEA analysis of the structure of Asian LNG markets will be included in 
the upcoming Medium Term Gas Outlook.
    High oil prices feeding through oil indexed contracts for natural 
gas as well as the effect of Asia-Pacific demand on LNG markets have 
stabilized gas prices at a high level in Europe. High prices, economic 
weakness and expanding renewable production have led to falling gas 
demand there. This is also partly due to mild weather, but gas 
consumption in the April--September period was down by 7%, suggesting 
structural weakness. A major factor behind this is the electricity 
sector: OECD Europe power generation was down by 1.6% (Jan-Oct) due to 
economic weakness, and thermal power generation was down by 2.4%. The 
disproportionate impact on thermal power was due to renewables rather 
than nuclear: increasing French and UK nuclear production compensated 
for the German nuclear moratorium, leading to stable EU nuclear 
production.
    Meanwhile, falling thermal generation cut the need for carbon 
credits, leading to a price collapse: the CO2 price fell below 7 Euros/
ton, compared to 2010's average of 14.3 Euros/ton. The combination of 
expensive gas and cheap CO2 enhanced the competitiveness of 
coal in Europe: burning coal became considerably more profitable which 
pushed gas to the margin. As a result of low demand levels and 
plentiful excess conventional capacities, European power prices have 
remained low (hovering between 50-60 euro/Mwh) despite the German 
nuclear phase-out. Nonetheless, concerns persist that a combination of 
a colder winter and transmission congestion might lead to a tighter 
situation in certain regions.
    Despite falling demand, EU gas imports were slightly up due to 
declining production and increasing stocks. Libyan gas production and 
exports are coming back online, and the political uncertainties in the 
MENA region have had no major impact so far on LNG supply.
    Ramp up of non-conventional gas will likely be slow in both Europe 
and China in the context of heightened concerns over environmental and 
safety issues. To help address these concerns, the IEA will examine 
``Golden Rules for the Golden Age of Gas'' in detail in a non 
conventional gas workshop in Warsaw in March. This workshop will feed 
into a chapter of the same name in the 2012 edition of IEA's ``World 
Energy Outlook''.
    So far the slowdown in growth of the Chinese economy has not led to 
any measurable slowdown of electricity or coal demand. China still 
faces an electricity shortage and 90 GW coal-fired capacity is under 
construction. The Medium Term Coal Market report projects around 800 
million tons coal demand increase in China till 2016. There is a large 
uncertainty over Chinese domestic production and consequently import 
needs, which could lead to market volatility. On the other hand, the 
increase of Indian coal import needs is almost certain as India 
struggles in vain to satisfy its growing demand with domestic mining. 
There is sufficient new coal production capacity coming to the market, 
but there are persistent bottlenecks in transport infrastructure.
          2. The long-term outlook for global energy

    The IEA's World Energy Outlook 2011 (WEO-2011) identifies key 
medium- and long-term global energy trends based on scenario analysis. 
The report, released annually in November, contains detailed global 
projections for energy supply and demand through the year 2035. Each 
year, the WEO highlights a different region and fuel as well as other 
timely issues (in WEO-2011, special attention was devoted to Russia's 
energy sector, coal markets, energy access and energy subsidies).
Background and assumptions
    WEO-2011 analyses three scenarios and multiple case studies 
differentiated by their respective assumptions about future energy-
related policies adopted by governments. The baseline for our analysis 
is the New Policies Scenario. Its policy assumptions take current 
policies as a starting point and then (cautiously) incorporate the 
broad policy commitments announced by countries around the world to 
deal with energy security, climate change, local pollution and other 
energy-related challenges. These commitments include targets for energy 
production and energy efficiency, phase-outs or additions of nuclear 
power, national pledges to reduce greenhouse-gas emissions and the 
elimination of wasteful fossil-fuel subsidies. For the United States, 
key assumptions in the New Policies Scenario include (1) a shadow price 
for carbon dioxide (CO2) emission in the power sector, 
reaching $35 per tonne CO2 in 2035; (2) extended operating 
lifetimes for nuclear power stations; (3) continued financial support 
for renewable energy; and (4) more stringent heavy-duty vehicle 
efficiency standards. The policy assumptions in the New Policies 
Scenario differ from those in the EIA's Reference Case, which accounts 
for existing policies, and therefore the two sets of results are not 
directly comparable.
    Economic growth, population growth and energy prices are other 
major assumptions taken in the WEO-2011 New Policies Scenario. 
Worldwide, economic growth averages 3.5% per year and that the 
population expands by some 1.7 billion people between 2010 and 2035. In 
real terms, the IEA crude oil import price rises from $78 to $120 per 
barrel over the Outlook period; the North American natural gas import 
price rises from $4.4 to $8.6 per MBtu between 2010 and 2035, but is 
considerably lower than other regions given more abundant supplies; the 
OECD coal import price increases from $99 to 110 per tonne. These price 
paths are not a forecast. Rather, they reflect our judgement of the 
prices that would be needed to encourage sufficient investment in 
supply to meet projected demand over the Outlook period. The New 
Policies Scenario assumes limited CO2 prices for some 
countries, with varying price levels, mechanisms and sectors affected.
    All WEO-2011 projections cited in this testimony, unless otherwise 
stated, are derived from the New Policies Scenario.
Key projections and trends in the WEO-2011
    Global energy demand is projected to increase by one-third between 
today and 2035 as a result of economic growth and shifting demographic 
trends such as population growth and urbanisation. These trends are 
driven by non-OECD countries, which account for more than 90% of the 
increase in energy demand in the Outlook period. Given the 
interdependency of global energy markets, this underscores the critical 
importance of non-OECD energy policies in shaping our energy future.
    Fossil fuels remain the dominant source of energy, however, while 
demand for fossil fuels continues to rise in absolute terms their share 
of global energy consumption declines from 81% in 2010 to 75% in 2035 
as renewable energy technologies make further inroads. Renewables 
growth is concentrated in the power sector, where hydropower and wind 
are projected to account for half of new installed capacity. Natural 
gas is the only fossil fuel that we project to make up an increasing 
share of the energy mix.
    Increasing demand for mobility in non-OECD countries boosts global 
liquids (oil and biofuels) demand to 104 million barrels per day (mb/d) 
in 2035, up from 88 mb/d in 2010. The total number of passenger cars 
worldwide will double, reaching almost 1.7 billion at the end of the 
Outlook period. The rise in liquids use comes despite impressive gains 
in vehicle efficiency, particularly in Europe and the United States.
    On the supply side, oil companies increasingly turn to resources 
that are more difficult to extract and therefore costlier. Conventional 
crude oil in total oil supply declines slightly by the end of the 
Outlook period as natural gas liquids (18 mb/d in 2035) unconventional 
sources (10 mb/d) and biofuels (4 mb/d) make significant contributions 
to meeting increased demand. Iraq, Saudi Arabia, Brazil, Kazakhstan and 
Canada account for the largest incremental gains in oil output. We 
calculate that 47 mb/d of gross capacity additions will be needed to 
replace declining production at maturing oil fields. This necessitates 
huge investments in upstream oil in the Outlook period.
    With increasing dependence on a small number of oil-producing 
countries in the Middle East and North Africa (MENA), a shortfall in 
upstream investment there would have far-reaching implications for the 
global oil market. Such a shortfall may be prompted by higher perceived 
investment risks, deliberate policies to slow the development of 
production capacity or shifting public spending priorities. We find 
that, between 2011 and 2015, if upstream investment runs one-third 
lower in MENA countries than what is required in the New Policies 
Scenario ($100 billion per year), oil prices could rise to $150/barrel 
in the short-term.
    The oil landscape changes positively for the United States over the 
next 25 years, with US oil imports shrinking to 6.2 mb/d in 2035 (lower 
than 1990 levels). This trend underlines the critical role of energy 
efficiency policies, as improved vehicle efficiency causes US oil 
demand to decline by 3.5 mb/d (or 20%). It also reflects the potential 
for expanding supply of US domestic crude oil, natural gas liquids and 
biofuels. US light tight oil production has shown increasing promise. 
Output from the Bakken, Eagle Ford and Niobrara plays alone may exceed 
1.4 mb/d by 2020, with additional light tight oil resources that may 
yet be developed.
    For natural gas, supply and demand factors indicate that the future 
is very bright. This conclusion echoes the main finding in our June 
2011 special report, ``Are We Entering a Golden Age of Gas?''. The 
share of gas in the global energy mix rises to nearly surpass that of 
coal in 2035. About 80% of additional demand comes from non-OECD 
countries, including China, where a major expansion of gas use is 
supported by energy diversification policies.
    In the United States, the combined application of horizontal 
drilling and well-stimulation techniques such as hydraulic fracturing 
has unlocked previously non-commercial resources of unconventional gas 
(including shale gas, tight gas and coal-bed methane). As described 
above, this success has dramatically changed the global supply picture 
and has had positive implications for gas security. Unconventional gas, 
being more geographically distributed around the world than 
conventional resources, now accounts for half of the natural gas 
resource base. We project that it will account for one-fifth of global 
gas supply in 2035. However, this future hinges in part on the ability 
of governments and industry to deal successfully with the environmental 
concerns - air, water and land impacts - associated with unconventional 
gas production. The largest contributions for future gas supply growth 
come from Russia, China, Qatar, the United States and Australia. In our 
special focus on Russia, we note that it could save natural gas 
equivalent to its exports in 2010 if it could just increase its 
efficiency to levels of comparable OECD countries.
    Over the last decade, coal has met nearly half of the increase in 
global energy demand. Going forward, coal use and its implications for 
energy security and the environment will depend largely on policy and 
technology choices. Furthermore, China and India, the two largest 
consumers of coal in 2035, will remain key actors in global coal 
markets. In our New Policies Scenario, we project continued strong 
growth in coal use in the next 10 years, and a levelling off thereafter 
as countries diversify and clean up their energy supply. In this 
scenario, global coal demand grows by 25% in 2035 relative to 2009. If 
instead we assume that current policies are maintained, global coal 
demand increases by 65% through 2035. We also find that deploying more 
efficient technologies could have a major impact on air emissions; if 
the average efficiency of all coal-fired power plants was raised by 
five percentage points in 2035 relative to the New Policies Scenario, 
power sector CO2 emissions would be 8% lower (with local 
pollution benefits). While carbon capture and storage technologies 
might boost long-term prospects for coal use, economic and technical 
hurdles limit its deployment during the projection period in the New 
Policies Scenario.
    Renewable energy experiences impressive growth during the Outlook 
period. The share of non-hydro renewables (primarily wind and solar) in 
power generation rises from 3% in 2009 to 15% in 2035, while hydro 
maintains its share at 15%. Global biofuels supply triples. Cost 
reductions are making renewable energy technologies more competitive, 
but subsidies are expected to play an important role in accelerating 
their deployment and driving further cost reductions. When well-
designed, subsidies to renewable energy can bring lasting economic and 
environmental gains. Even as unit subsidy costs fall, annual subsidies 
to non-hydro renewables and biofuels expand to $250 billion in 2035 as 
deployment scales up. For comparison, global subsidies to fossil-fuel 
consumption are estimated at $409 billion in 2010.
    Nuclear energy production is projected to rise more than 70% 
through 2035, with growth concentrated in non-OECD countries. Despite 
the events at Fukushima Daiichi, our projection for nuclear power 
output is only slightly less than last year. However, to examine the 
possible implications of a major shift away form nuclear power we also 
analysed a `Low Nuclear Case', which assumes that no new OECD reactors 
are built and that non-OECD countries add only half the capacity 
projected in our New Policies Scenario. We find that while there is 
some increased penetration by renewables, the gap is filled largely by 
coal and natural gas. This ultimately tightens markets and worsens 
emissions of CO2 and local pollutants.
    Finally, a few words on the projections in our 450 Scenario, which 
outlines an energy sector pathway for stabilising the atmospheric 
concentration of CO2 emissions at 450 parts per million and 
targets limiting the global temperature increase to 2C. This scenario, 
which the IEA has included in its World Energy Outlooks since 2008, is 
based on policies that lead us to a more sustainable future that 
addresses the threat of climate change. Without new policies we are on 
track for alarming increases in global average temperature: 3.5C in 
the New Policies Scenario and 6C or more in the Current Policies 
Scenario. The key message in the 450 Scenario is that we cannot afford 
to delay tackling climate change if it is to be achieved at reasonable 
cost. Nearly 80% of allowable CO2 emissions up to 2035 are 
already locked in by existing power plants, buildings and factories. On 
current policies, this figure could reach 100% before the end of this 
decade. Moreover, we estimate that for every $1 of investment in the 
power sector avoided before 2020, an additional $4.30 would need to be 
spent after 2020 to compensate for increased emissions.
Conclusion
    Governments have a critical role in setting policy frameworks that 
engender a more sustainable energy future. The data, projections and 
analyses in the World Energy Outlook are intended to assist 
policymakers in that effort. The WEO-2011 New Policies Scenario shows 
that recent global commitments added to existing policies can take us 
part of the way, but more must be done to achieve an energy future that 
balances economic growth, energy security and environmental 
stewardship.

    The Chairman. Thank you very much.
    Mr. Burkhard, go right ahead.

    STATEMENT OF JAMES BURKHARD, MANAGING DIRECTOR OF IHS, 
      CAMBRIDGE ENERGY RESEARCH ASSOCIATES, CAMBRIDGE, MA

    Mr. Burkhard. Mr.--excuse me, Mr. Chairman, Senator 
Murkowski, other members of the committee, thank you for the 
opportunity to share some thoughts with you today.
    Mr. Chairman, as you mentioned, 2011 was quite turbulent in 
the oil market because of the Libyan Civil War, the Eurozone 
crisis, Iran and the slowing global economy. At the same time 
in 2011 we saw the highest annual average oil price ever on an 
annual average basis. But the energy story is not just limited 
to high prices and geo-political concerns. That's very 
important and I'll talk about those in a little bit.
    But the energy story in the United States is also about 
creating jobs and economic growth and more domestic supply. One 
of the most significant stories or developments in energy 
markets in recent years has been what we call the ``Great 
Revival,'' the ``Great Revival'' in U.S. oil production. The 
long decline in U.S. production was never supposed to end.
    But it has come into an end. Between 2008 and 2011 over 
that 3 year period U.S. liquids production, so that's crude 
oil, natural gas liquids, some biofuels. U.S. liquids 
production grew by 1.3 million barrels per day in that 3 year 
period. That was the biggest increase during that time by any 
country in the world. Just for context the No. 2 source of 
growth was Russia which grew by about 500 thousand barrels per 
day.
    North Dakota is an important part of this story. North 
Dakota, a few years ago, wasn't producing much oil. Today North 
Dakota produces about as much as Ecuador. Ecuador is a member 
of OPEC. I don't want to suggest North Dakota is going to join 
OPEC, but it does give you a sense of the context to how big 
that increase has been.
    Looking out, excuse me, over the next decade. When we look 
at the potential for the U.S. and Canada combined. We see the 
potential for U.S. and Canadian production from 2008 to 2020, 
over that 12 year period, to grow by about 4 million barrels 
per day. That's more than what Iran produces today. That's the 
potential. It is quite significant.
    On the demand side we've seen peak demand. We believe U.S. 
demand for liquid fuels peaked in 2005. Given these supply and 
demand trends imports in 2020 are likely to be well below what 
they were as recently as 2005. For illustrative purposes if you 
assume the price of oil is $100 in 2020 and given these demand/
supply trends the U.S. import bill for oil could be about $182 
billion less than what it otherwise would be. That $182 billion 
is about one third of the 2011 trade deficit, entire trade 
deficit.
    These gains, these increases, in U.S. production and 
Canadian production are not guaranteed. Impacts on local 
communities and the environment, obviously, need to be 
addressed appropriately. There are new questions that have been 
raised about the pace of growth in the Canadian oil sands which 
is an important part of this continental growth story. But the 
potential is significant. If it were to be realized and perhaps 
spread to other places around the world it would be a source of 
downward pressure on oil prices.
    Getting to the broader oil market. There's a tug of war 
right now between slowing global economic growth and geo-
political concerns. Oil demand growth is weak.
    The global economy has slowed over the last year which 
would seem to be a recipe for lower prices. Yet, prices are 
high. Why is that? Limited spare capacity and geo-political 
concerns.
    Spare capacity, which is the oil market shock absorber, is 
quite low. Today compared with recent years we estimate it's 
around 2 million barrels per day, roughly, 2 to 2.5. As 
recently as a couple of years ago it was about 5.5 million 
barrels per day. So spare capacity is significantly less.
    In 2012 the Iranian nuclear issue could have a significant 
impact on the oil market. The combination of tighter U.S. and 
European financial sanctions, the European oil embargo on 
purchases of Iranian oil, political infighting in Iran and 
Iran's growing fear of encirclement creates a volatile 
atmosphere where miscalculations could lead to grave 
consequences. An escalation of efforts to disconnect Iran from 
the global economy has increased supply anxiety about the 
reliability and adequacy of oil supplies. It's that supply 
anxiety which is a key support for high prices amid weak 
economic and oil demand growth.
    Assessing the future course of the oil market is always a 
challenge. This year there's a wide spectrum of potential 
outcomes. If the Eurozone crisis were to worsen we can't rule 
out a recession this year which could lead to economic worries, 
overwhelming the geo-political concerns right now.
    So any oil market outlook faces uncertainties. But in 2012 
the uncertainties are perhaps broader than usual and fraught 
with risk. However, the ``Great Revival? and U.S. oil 
production and gas production are sources of growth and secure 
production at a time of heightened anxiety.
    Thank you.
    [The prepared statement of Mr. Burkhard follows:]

 Prepared Statement of James Burkhard, Managing Director of IHS CERA, 
                             Cambridge, MA
                      oil and gas markets in 2012
    It is an honor to speak before the US Senate Committee on Energy 
and Natural Resources of the 112th Congress. One year ago I testified 
before the committee just as political turmoil began to dramatically 
affect a number of countries in North Africa and the Middle East. Oil 
and gasoline prices were rising and creating headwinds for a fragile 
economic recovery and worries for American consumers-and for many 
others around the world as well. In the past year there has been great 
turbulence in the oil market related to the upheaval in Libya, the 
Iranian nuclear issue, troubles in the eurozone, and a slowing pace of 
global economic growth. Today, oil prices are higher than a year ago. 
In fact, in 2011 oil reached its highest average annual price since the 
1860s.
    Developments in energy markets remain a top concern, but the energy 
story is not limited to worries about high oil prices and geopolitical 
tension. Energy investment is also playing a role in fueling growth in 
the United States. A ``Great Revival'' in US oil production is taking 
shape-a major break from the near 40-year trend of falling output.
The Great Revival
    The long decline in US oil production was never supposed to end. 
From 1970 to 2008 US oil (total liquid fuels) production fell by 3.79 
million barrels per day (mbd)--from 11.3 mbd to 7.64 mbd.\1\ But the 
combined power of market signals (namely high oil prices), technology 
advances, and access to prospective acreage has changed the playing 
field. Biofuel policy also played a role. The aggregate impact of these 
forces led to a 1.3 mbd increase in US supply from 2008 to 2011--the 
largest gain by any country during that time. Out of that 1.3 mbd, 
nearly 1.1 mbd was crude oil or natural gas liquids, with the remainder 
coming from biofuels--mainly ethanol. The number two country was 
Russia, where oil production increased 0.5 mbd (see *Figure 1).
---------------------------------------------------------------------------
    \1\ The term ``liquids'' is a broader definition of oil that 
includes crude oil, condensate, natural gas liquids, and biofuels.
    * All figures have been retained in committee files.
---------------------------------------------------------------------------
    The scale of the opportunity to boost oil production in the United 
States is larger than in most other countries over the next decade. 
Indeed, the oil and gas industry has attracted tens of billions of 
dollars of investment capital. In the United States, spending to 
develop oil and gas fields rose 37% from 2009 to 2010--from $50.6 
billion to $69.4 billion. Spending increased further in 2011.
    US oil production growth has materialized at the same time that US 
oil demand has reached a plateau. US oil demand peaked in 2005 and then 
fell; and IHS CERA does not expect demand to exceed the 2005 level 
again. The challenging economic climate of the past several years 
explains part of the decline in demand; but in the longer term, the 
higher fuel economy standards and an aging population will restrain 
demand growth. The combined impact of US oil demand and production 
trends is a decline in US oil imports. By 2020, the net US oil import 
requirement could be around 5 mbd less than it was as recently as 2005. 
At an illustrative oil price of $100 per barrel, this represents an 
annual reduction in the oil import bill of $182 billion-an amount equal 
to about one-third of the entire US trade deficit in 2011.
    The Great Revival is the oily equivalent of the ``shale gale''--the 
revolution in unconventional gas production that emerged several years 
ago. Shale gas now accounts for about 34% of total US gas production, 
up from just 5% in 2006. The shale gale has not only helped to boost 
total US gas production by 28% during this time, but it has also 
created jobs. A new study by IHS Global Insight, The Economic and 
Employment Contributions of Shale Gas in the United States, finds that 
shale gas production supported more than 600,000 jobs in 2010, a number 
that is projected to grow to nearly 870,000 by 2015.
    US natural gas prices have hit 10-year lows recently because of the 
vast amount of relatively low-cost shale gas being produced and the 
warm winter weather, which lowers demand for gas to generate heat. 
Another factor is that many gas producing wells also produce oil--and 
oil sells at a much higher price. Even if gas prices remain low, 
production will continue from these wells because the higher price that 
the oil fetches in the market can offset the lower price of gas.
    Application of advanced technology is critical to the growth in US 
oil and gas production. Horizontal drilling and hydraulic fracturing 
are two technologies at the heart of the growth story. They are also 
part of the debate about the environmental impacts of rising domestic 
oil and gas production. Questions about water availability and quality, 
air pollution, cumulative land use, and the impacts on local 
communities need to be addressed to ensure that oil and gas development 
meets environmental needs and enhances public trust.
    Last summer an Advisory Board to the US Secretary of Energy 
released recommendations related to environmental aspects of shale gas 
production. Increased transparency--particularly through greater public 
access to data on gas-producing operations--and efforts to assure water 
and air quality were among the proposed recommendations. A key point 
made by the Advisory Board was the need for more systematic data 
collection to better measure environmental impacts.
    In addition to addressing environmental impacts, growth in US 
production along with higher output from our neighbor, Canada, requires 
the US pipeline system to catch up with changing supply trends. Canada 
has become, by far, the largest source of foreign oil to the United 
States. In the first 10 months of 2011, the United States imported 2.2 
mbd of oil from Canada, or 24% of total US imports. More than half, 1.2 
mbd, of the supply was from the oil sands of Alberta. In themselves, 
oil sands are now a top source of US oil supply.
    The denial earlier this month of a permit for the proposed Keystone 
XL pipeline project raises the level of uncertainty regarding the long-
term growth and disposition of major sources of world supply growth--
the Canadian oil sands and American onshore output. The project would 
have added 700,000 barrels per day of pipeline capacity between the oil 
sands of Alberta, Canada, and the US Gulf Coast. This is equivalent to 
about one-third of Iranian oil exports.
    If a new application results in a permit by 2013, it is possible 
that sections of the pipeline could be online by late 2014, with the 
entire Keystone XL project in service by late 2015. In this case, the 
January 18 permit denial would have a minimal impact on future crude 
flows from Canada to the United States.
    If no additional cross-border capacity is built, output from the 
Canadian oil sands would eventually hit the limits of existing cross-
border capacity by around 2019. Even before that, however, oil sands 
supply would run up against the capacity limits of Canada's existing US 
customers--refineries in the Mid-Continent--to process oil sands 
production. This could occur as soon as 2015 and is a key reason 
Canadian producers are seeking access to the much bigger refining 
market in the US Gulf Coast. Therefore, Keystone XL would have helped 
to resolve more urgent bottlenecks in the US Mid-Continent. The US 
pipeline system has not yet caught up with growing US Mid-Continent and 
Canadian production, as signaled by the price disconnect between West 
Texas Intermediate-a key US crude oil price benchmark--and similar 
crudes on the global market. If pipeline infrastructure does not keep 
pace with growing oil supply from the US Mid-Continent and Canada, then 
production growth will eventually slow.
    The controversy over Keystone XL means Canada will push harder to 
diversify its oil export markets. The United States is currently the 
sole foreign market for the oil sands. The permit denial highlights the 
risk to Canada of such demand dependence.
    the world oil market--``tug-of-war'' between a weak economy and 
                         geopolitical concerns
    Slow economic growth and modest gains in world oil demand-this is 
the starting point for 2012. We project the world economy to grow 2.7% 
in 2012--well below the 3.7% average over 2010 and 2011. World oil 
demand is expected to increase 0.7 mbd, which is well below the 10-year 
average increase of 1.1 mbd per year.
    This would appear to be a recipe for lower oil prices. Yet oil 
prices are high and spare crude oil production capacity is limited. IHS 
CERA estimates there is about 1.8 to 2.5 mbd of effective spare oil 
production capacity in the world--all of it concentrated on the Arabian 
Peninsula. This is a small ``shock absorber'' for the oil market--
equivalent to about 2% to 3% of world oil demand. As recently as 2010, 
spare capacity was much higher--around 5.5 mbd. Geopolitical fears have 
a more pronounced impact on oil prices when spare capacity is low--as 
it is today.
    Tension over Iran's efforts to develop nuclear technology and 
potentially apply it to military purposes is the most prominent-and 
worrisome-geopolitical issue for the oil market. The decade-long 
nuclear standoff has become a constant feature of the oil market, with 
anxiety fluctuating in response to Iran's volatile posture toward 
negotiations. A threat several weeks ago by an Iranian official to 
close the Straits of Hormuz-the most important oil export route in the 
world-sent a shudder through oil markets.
    In 2012 the Iranian nuclear issue could have a significant impact 
on the oil market. The combination of tighter US and European financial 
sanctions, the European oil embargo on purchases of Iranian oil, 
political infighting in Iran, and Iran's growing fear of encirclement 
creates a volatile atmosphere in which miscalculations could lead to 
grave consequences. Escalation of efforts to disconnect Iran from the 
global economy has increased ``supply anxiety'' and is a key support 
for high prices amid weak economic and oil demand growth.
    The Iranian nuclear issue is not the only geopolitical concern. 
Violence in Iraq threatens the pace of infrastructure rehabilitation 
and expansion of oil production and export capacity. Iraq's potential 
to increase oil supply is enormous, but realizing that potential will 
be difficult. Supply disruptions need not be large scale to have an 
impact. For example, disputes between South Sudan--the world's newest 
country--and Sudan are constraining oil flows from these countries. 
This and other potential difficulties in Africa or other parts of the 
world can collectively have a big impact. This was the case in the 
middle part of the past decade when a series of events removed large 
volumes of oil from the market--what we referred to at that time as the 
``aggregate disruption.''
    Apart from geopolitical concerns, the oil and gas industry 
continues to struggle with rising costs to find and develop new fields. 
As was the case a year ago, costs are on the rise. Indeed, the IHS CERA 
Upstream Capital Costs Index--a type of ``consumer price index'' for 
the global oil industry-illustrates the cost pressure. After a modest 
dip during the recession, costs are likely to approach or set a new 
record level in 2012 (see *Figure 2).
Wide Spectrum of Potential Outcomes
    In early 2012, assessing the future course of the world oil market 
is a challenge because of the wide spectrum of potential outcomes. 
Limited spare capacity, geopolitical concerns, and the risk of 
disrupted supply point toward the possibility of higher prices and even 
a severe price spike. However, the global economy is in a fragile 
state. The eurozone crisis remains unsettled and could worsen. The pace 
of growth in India and China has also showed signs of slowing down. And 
unemployment is still high in the United States.
    IHS CERA has long used a scenario framework to assess the potential 
course of change in the oil market and the broader energy industry. 
Several years ago we constructed a scenario called ``Vortex,'' which 
envisions a member country exiting the eurozone, the United States 
unable to adequately address its fiscal problems, and much weaker 
growth in emerging markets. The outcome in the Vortex scenario is 
another global recession, followed by several years of below-trend 
growth. Oil prices fall below $50 per barrel. We do not believe the 
world has entered such a scenario, but it cannot be ruled out for 2012 
given the concerns emanating from the eurozone.
    Any oil market outlook faces uncertainties. But in 2012, the 
uncertainties are broader than usual and fraught with risk. However, 
the Great Revival in US oil output and further expansion in gas supply 
are sources of growth and secure production at a time of heightened 
anxiety.

    The Chairman. Thank you very much.
    Mr. Diwan, thank you for being here. Please, go right 
ahead.

    STATEMENT OF ROGER DIWAN, PARTNER AND HEAD OF FINANCIAL 
                      ADVISORY, PFC ENERGY

    Mr. Diwan. Good morning. It's an honor to speak again 
before the U.S. Committee on Energy and Natural Resources. I 
will focus today my remark on the state of the oil market in 
the beginning of the year and talk a little bit what's 
happening in the United States.
    The way I'm looking at the oil market and the way to 
summarize what the panelists before me said is really we have a 
bipolar crude oil market where we have significant downside 
risk because of the economic conditions in Europe. On the other 
side we have significant upside risk because of the tensions 
with Iran and the possibility to lose some supply from this 
market. The implication of losing barrels from the Persian 
Gulf.
    If you look at the forward looking balances we are seeing 
that the acute market tightening experience in 2011 is not 
likely to be in store in 2012. Demand is under performing. We 
believe, actually, that demand will be probably smaller than 
what the IEA believe, probably below a million barrel per day 
on average and with significant downside with a few exceptions 
when we look at oil demand globally it's all negative or the 
growth is decelerating, particularly in Asia it's decelerating. 
Growth is only focused on 3 regions: the Middle East, Latin 
America and emerging Asia.
    The bulk of the near-term weaknesses in Europe and also in 
the United States, where we have significant structural trends 
of declining demand.
    On the supply side, we had a very disappointing year last 
year because we had obviously the problems in Libya, but we 
also had a number of problems during the summers which we all 
believe are one off and not recurring. So 2012 we'll see a 
recovery, a lot of these supply and new projects coming online 
mostly from the U.S., Canada and Russia. We don't believe 
actually Brazil will be able to add a lot of barrels this year.
    There is one uncertainty that we haven't talked about which 
is Iraq. Baghdad maintains an optimistic outlook on production 
growth of around 5 to 6 hundred thousand barrels per day for 
2012. In our view the Iraqi government forecast is over 
optimistic given the security condition on the ground.
    We also have to remember we're basically lost 2 small 
countries in the recent months from production, Sudan recently, 
Syria a couple of months ago. We might still have problems in 
Libya and Nigeria that are not solved. So the supply risk is 
still abundant even if we still believe that we can have a 
million barrels per day of growth from non-OPEC crude and 
liquids and OPEC liquids.
    We also need to talk about Iran and the impact of 
sanctions. When we look at the potential countries that Iran 
could divert its European supply to we actually don't see a lot 
of them. We don't see a lot of countries willing to be reliant, 
more reliant, on Iranian barrels.
    So there's a good chance that by the end of the year if you 
move with the sanction that Iran will have to shut down 4 to 5 
hundred thousand barrels per day that need to be replaced by 
other producers. So that--we need to take into account that 
forcing OPEC to produce more, reducing further the spare 
capacity which is not very large to start with. If you add to 
that the supply risk that I talked about, that would make oil 
market pretty nervous.
    Finally from the U.S. perspective the development of oil 
production and the declining oil demand mean that security and 
reliability of supply is rising. Last year when I testified 
here I was asked where do I believe is the best place to 
invest. I answered to many of you were surprised that it's the 
United States. We see that now where we have the full 
revolution, if you want, in the gas being translated to oil.
    We believe that actually by 2020 the United States will 
become again the largest producer of hydrocarbon in the world, 
surpassing Russia. What we have seen between 2004 -2008 in the 
U.S. gas market the increases in prices has allowed the 
industry to crack the share code and to unleash this new golden 
era in the U.S. oil patch. This golden era is really reshaping 
the global oil and gas industry.
    We need to think about that when you look at investment 
globally right now. In the last 3 years the U.S. has been the 
key area of investment flows. If you look at the last 10 years 
a producer in the United States used to produce, make profit 
here and invest abroad because they didn't believe that they 
can make sustainable reinvestment in the United States.
    What we see right now is exactly the contrary. The global 
oil and gas industry is making profit all over the world and 
investing in the United States. The United States is a net 
absorbent of cash. That's a huge change in the industry.
    Thank you.
    [The prepared statement of Mr. Diwan follows:]

   Prepared Statement of Roger Diwan, Partner and Head of Financial 
                          Advisory, PFC Energy
   Tension between geopolitical risks to supply on the one hand 
        and macroeconomic/financial risks emanating from the Eurozone 
        on the other will remain a feature of the market through 2013 
        and will weigh against previously expected price softening.
   Forward-looking balances indicate that the acute market 
        tightening experienced in 2011 is not likely to be in store for 
        2012, and we are believe that the opposite is far more likely. 
        Amid softening oil demand, rising non-OPEC supply will prevent 
        any growth in the Call on OPEC crude until 2013. Without a 
        reduction in OPEC production by some members in order to offset 
        the recovery in Libyan output, commercial inventories are 
        likely to build.
   While significant downside risks to demand persist, the 
        risks to supply will be driving market perception in 2012 and 
        will offset the bearishness inherently embedded in the large 
        projected stock builds over the next two quarters. Furthermore, 
        a significant portion of the projected rise in global 
        inventories will be located in China and India, where the 
        streaming of new refining capacity will necessitate the 
        building up of working inventory in the first half of the year. 
        Both countries' crude imports are expected to accelerate 
        sharply in the months ahead as a result.
   Our 2012 price forecast for Brent stands now at $111.25/b, 
        with the last two quarters of the year being when we anticipate 
        the greatest impact of anti-Iranian sanctions. WTI (Cushing) 
        will average $10/b lower in 2012, a discount to Brent that 
        reflects our belief that improving refinery complexity in the 
        Midwest cuts demand for light sweet crude in the region. Even 
        with the reversal of the Seaway pipeline and its planned 
        expansion, the marginal barrel of US inland crude will still be 
        shipped by rail through much of 2013, and possibly beyond if 
        Bakken production continues to surprise expectations.
             global oil demand is slowing, but by how much?
   With few exceptions, oil demand is expected to either 
        contract or decelerate in most markets: overall, oil demand 
        will effectively grow by 900,000 b/d at most even though our 
        top line demand growth forecast show a higher number: this is 
        due to the anticipated rebound in Libyan demand to near pre-
        civil war levels as well as the post-flood recovery in 
        Thailand.
   Significant downside risks to demand still remain from the 
        unresolved Eurozone debt crisis, but the chances of a world-
        wide recession have diminished due to stepped-up efforts by the 
        European Central Bank to support the banking system.
   Virtually all of the growth in oil demand this year will be 
        concentrated in three market regions: Emerging Asia, the Middle 
        East and Latin America. As in the past decade, Emerging Asia 
        will be the chief oil demand growth region, led by China and 
        India. While world trade has dampened prospects for net exports 
        of manufactured goods from China, economic growth spurred by 
        monetary and fiscal easing will be supportive of higher fuel 
        consumption.
   The Middle East--the second largest demand growth region--is 
        also slated to see accelerated growth this year (rising another 
        250 mb/d compared to 2011's growth of 200 mb/d). The main 
        driver is Saudi Arabia, where residential construction is 
        leading to greater power use.
   The bulk of the near-term weakness is in Europe and the US: 
        Europe is likely to see a decline of 200 mb/d in 2012 with the 
        markets most heavily affected have been those that have 
        undergone some degree of fiscal austerity (Greece, Spain, 
        Portugal, Ireland and the United Kingdom) or have seen a sharp 
        rise in their cost of borrowing (Italy).
   The United States will witness a small contraction in demand 
        by about 90 mb/d for 2012, where tight household budgets have 
        led motorists to cut back discretionary vehicle use and 
        gasoline consumption. Meanwhile, middle distillate consumption 
        remains supported by positive commercial activity.
           supply rising int he west, growth at risk in iraq
   Although non-OPEC supply growth (crude, gas liquids and 
        biofuels) continued to disappoint in 2011, we expect gains to 
        resume in 2012. Final 2011 data for all countries is still a 
        few months away, but our current estimate is for a paltry 
        increase of 0.1 mmb/d after a long list of outages spanning 
        many countries.
   The year 2012 is forecasted to show a recovery in non-OPEC 
        liquids growth and is led by these countries: the US, Canada, 
        Colombia, Brazil and Russia.
   The United States will lead the growth in Liquids growth in 
        2012 led by a rise in oil shale output from the Bakken and the 
        Eagle Ford shale. There are several other shale areas that are 
        just starting to be drilled and if those prove as prolific then 
        our forecast is likely to be raised. We have also penciled in 
        an end to output losses in the Gulf of Mexico after the Macondo 
        spill.
   An area of considerable uncertainty is gas liquids. Volumes 
        have been growing rapidly as drillers turn to exploiting the 
        wet gas parts of the many shale plays, especially the 
        Marcellus. We saw that September gas liquids production reached 
        2,274 mb/d, roughly 73 mb/d above the all-time high of the 
        prior August. This is far higher than what we estimated and may 
        mean a material revision is in order if subsequent months hold 
        to this level.
   A sizeable increase in 2012 liquids is due to the ramp-up to 
        full capacity of Shell's 140 mb/d Pearl GTL project in Qatar. 
        That facility will process 1.6 bcf/d of natural gas that will 
        yield 120 mb/d of gas liquids accounting for nearly all of 
        2012's unusually large gain.
   Iraq's production levels will remain one of the key supply 
        uncertainties over the next 18 months. Baghdad maintains an 
        optimistic outlook on production growth, anticipating a 500-600 
        mb/d increase in output for 2012. In our view, the Iraqi 
        government's forecasts are overly optimistic given 
        deteriorating security conditions on the ground. We believe 
        that . output increases are more likely to be in the 200-250 
        mmb/d range, with risks to this forecast weighted firmly on the 
        downside.
                 a weak economy will drag on oil demand
   Global oil demand growth is forecast to rise 1.1 mmb/d in 
        2012 when accounting for 0.2 mmb/d of growth resulting from 
        year-on-year base effects due to the return of Libyan demand to 
        pre-civil war levels as well as post-flood recovery in 
        Thailand. ?
   In effect, oil demand is slowing down from 2011 levels, and 
        we expected to the growth delta to remain sub-one million b/d 
        in 2013.
   Demand in the advanced economies will continue to be 
        challenged by macroeconomic headwinds, with a mild recession 
        expected for Europe.
   Japanese crude burning is forecast to continue offsetting 
        underlying structural declines in OECD Pacific through 2012. In 
        2013, new gas-fired generating capacity will push liquids out 
        of the fuel stack.
   As international trade cools, key emerging markets will also 
        be affected, especially in Emerging Asia and Latin America.
   Non-OECD demand will nevertheless remain the key growth 
        driver, offsetting recession-related and structural declines in 
        OECD demand. Growth remains concentrated in China and the 
        Middle East.
 in north america, heightened price sensitivity will dampen oil demand 
                                 growt
   The brighter US economic outlook is not expected to support 
        oil demand growth in 2012-13.
   Structural declines in residential heating oil, fuel oil and 
        other products demand are expected to outweigh gains in diesel 
        and jet fuel.
   Gasoline consumption will remain under pressure from tight 
        household balance sheets and high gasoline prices, as seen in 
        2011 with the collapse in discretionary vehicle use.
   The main reason for lower vehicle miles traveled in the 
        United States in 2011 was the sharp increase in retail gasoline 
        prices (reaching $4/gallon) early into the US driving season. 
        This will be repeated this year, and prices will continue to 
        dampen demand.
   Although notable efficiency gains are being made, price 
        elasticity is still expected to play greater roll in reducing 
        near-term demand prospects.
   Given inadequate pipeline capacity from the US Gulf Coast, 
        further reductions in refining capacity planned for the East 
        Coast will tighten regional balances and lead to higher 
        gasoline prices during the peak demand periods of 2012-2013.
   As a result, total final oil demand growth in North America 
        is expected to contract 90 mb/d in 2012 and another 70 mb/d in 
        2013. Risks are on the downside, with prices potentially 
        impacting demand further.

   Slower naphtha and gasoil demand growth together with base 
        effects weighed on year-on-year product demand growth in 4Q11 
        and will continue to depress the first two quarters of 2012.
   But growth should speed up in the second half of 2012 on 
        expected stimulus measures, bringing annual product demand 
        growth to 420 mb/d, a sharp drop from the 610 mb/d seen in 
        2011.
   The longer term effect of the stimulus measures and a ramp 
        up in domestic petrochemical production capacity (which will 
        find a market by backing out imports) will carry total product 
        growth momentum into 2013. Annual demand growth then is 
        expected to average 540 mb/d.
                    non-opec bolsters supply growth
   Gains in non-OPEC supplies last year came in below 
        expectations due to numerous outages as well as delayed project 
        development. The outlook for 2012 and 2013, however, will show 
        marked improvement, posting gains of 0.8 mmb/d and 0.4 mmb/d 
        respectively.
   The year 2012 is forecasted to show a recovery in non-OPEC 
        liquids growth and is led by these countries: the United 
        States, Canada, Colombia, Brazil and Russia. Clearly, our 
        forecast is largely a Western hemisphere story.
   Rapid development of unconventional shale plays in the 
        United States are also yielding high liquids content and may 
        exceed our current forecast
   GLs and condensates will see steady growth as natural gas 
        production expands in the FSU, Asia-Pacific and MENA.
   Partially offsetting these gains will be a deceleration in 
        global biofuels growth.
   Ethanol output will moderate as the United States approaches 
        maximum blend levels for conventional motor gasoline (not 
        helped by the structural decline in demand for the fuel).
   Brazil ethanol growth recedes from poor sugar harvests and 
        lagging investment in distilleries.
   Iran's crude oil exports averaged 2.2 mmb/d in 2011.
   EU embargo has been agreed in principle but details are yet 
        to be worked out. Any implementation would not occur 
        immediately.
   Complete EU embargo would require Iran to find replacement 
        market for about 600 mb/d.

    --Italy is asking for an exception so ENI can continue to receive 
            in kind payments for work performed in Iran.
    --Greece, cut off from normal credit markets, has greatly increased 
            its intake of Iranian crude in recent months. Locating and 
            financing replacement supplies presents a major financial 
            issue for the country, despite reports it will comply.

   India, South Korea and Turkey have increased imports this 
        year as they are less wedded to strict sanction regimes.

    --Supplies will continue but will make the case to the US that 
            efforts have been made to reduce the volume or to find 
            alternate crudes.

   Streaming of new refineries in India and China will see 
        their demand for imports grow by around 600 mb/d so an EU-only 
        embargo could be managed.
   Expecting other Middle East producers to fill void while 
        surrendering market share allowing Iran to sell barrels into 
        Asia--is likely unreasonable.

    The Chairman. Thank you very much.
    Senator Manchin, did you have a question you wanted to ask 
at the beginning? I was told you had to leave and----
    Senator Manchin. As I was walking in----
    The Chairman. OK. Why don't you go ahead?
    Senator Manchin. Thank you, Mr. Chairman. I thank all of 
you for coming here----
    Thank you. I'll get right to the point. It's the XL 
pipeline.
    I'm going to ask all of you to comment. But I have a hard 
time understanding why this has become a political football. It 
makes so much common sense that you want to buy off of your 
friends and not your enemies.
    Also, I think in going down to where we're going to go as 
amount of jobs. I want to hear you alls, just a yes or no, 
maybe comment. There should be jobs created in the United 
States by this building of the pipeline.
    I understand that there's a difference between what the 
State Department has done, the environmental verses the EPA in 
conflict, our own government, if you will is fighting among 
itself for whatever reasons. Next of all the ability that 
Alberta and Canadians are going to produce this no matter what. 
If China becomes a player or the Asia becomes a player, market 
taking this product if we don't. What it does to our security. 
Security should be the most factor, I think, the main factor of 
what we should be concerned about.
    So I would ask, I think the question I would ask. Doctor, 
I'll start with you, if you would. Do you believe the oil sands 
will be developed no matter whether we buy it or not?
    Mr. Gruenspecht. Thank you. At the prices we have in our 
long term projections, the oil sands would likely be--the oil 
sands, tar sands, call them what you will, would likely be 
developed whether or not we purchase.
    Senator Manchin. OK. Does everybody agree?
    Ambassador, do you agree that they're going to develop the 
oil sands?
    Mr. Jones. Yes, I would agree with that.
    Senator Manchin. OK. I'm sure that everybody else agrees 
with that too.
    I would assume that you all think that would be a job 
creator for America if we built it through, into America? Do 
you all agree that there would be jobs? I'm sure it has to take 
jobs of people to build a pipeline, right? So it would be a job 
producer for us?
    Mr. Gruenspecht. Again this goes a little bit beyond what 
EIA does but I guess our view is----
    Senator Manchin. I mean common sense. You're experts. It 
takes Americans to build it, right?
    Ambassador.
    Ambassador Jones. You'd have an initial spurt of 
construction jobs.
    Senator Manchin. Yes.
    Ambassador Jones. Then you'd have some jobs that operate 
the pipeline. I'm not sure what the numbers would be. I don't 
know that it would be a great percentage of increase of 
employment. But there would be some increase, sure.
    Senator Manchin. Mr. Burkhard.
    Mr. Burkhard. Yes, it would create jobs. I think the 
broader point here is the oil sands development in Alberta. 
There are many American companies that are involved in that. So 
the American economy does benefit from further development of 
the oil sands as well.
    Senator Manchin. Which country and government? Which 
country would benefit most if America does not build the 
pipeline and that product does not come? Who would take it? Who 
would benefit most?
    Mr. Diwan. I think it's likely not to be built is the case. 
I think it's very difficult to send that oil outside of the 
United States for Canada to take it to the west coast and ship 
it abroad actually pose even bigger environmental concern.
    So let me try to answer it a little bit differently. I 
think what we're seeing here between the development of the oil 
sands and the United States.
    Senator Manchin. I hate to rush you. I don't have much 
time. They've only given me so much time here. I'm going to 
have to run.
    But you're saying you think they're going to be held 
captive. We're understanding that the Alberta province is 
already meeting right now with China in order to develop this.
    Mr. Diwan. Correct. But from all the economics, if you look 
at it this oil is most likely to come to the United States. By 
the way, we still have capacity for the next 4, 5, 6 years to 
absorb with the present infrastructure, that oil.
    Senator Manchin. Thank you.
    Doctor, if I could I want to switch to the manufacturing 
jobs that insourcing is the new word, is a new buzz word that 
we're all using now. We want to start building things again in 
America. As I'm understanding and Senator Murkowski just talked 
about the now projections as far as what supplies will be for 
the shale and the shale gas.
    West Virginia has been a big player in Marcellus as you 
know. The coal and everything, all the resource we've been 
blessed with. If that's been downgraded now to the point to 
where it could affect the cost of what we would manufacture. Do 
you see the supply having a big impact on pricing and thus 
manufacturing in this country again by not having to 
dependability with the slashing of the reserves?
    Mr. Gruenspecht. I think this reserves or resource story is 
a more accurate way to phrase it because I think the numbers 
we're talking about are total recoverable resources not 
reserves which is a much smaller number. Sometimes too much 
emphasis is placed on the estimates of recoverable resources. 
In fact, despite this downward adjustment that we made in fact 
our natural gas production projections are higher and price 
projections are actually lower in the new outlook than in the 
previous one.
    We rely very heavily on the U.S. geological survey for 
information about geology. They came out with a new assessment 
of the Marcellus after we published our last year's outlook. 
They raised their estimate of Marcellus resources forty fold 
from 2 trillion cubic feet to 84 trillion cubic feet. We had 
been using a number like 400 trillion cubic feet.
    After looking at what they had done and also looking at 
well productivity data which continually comes out we deferred 
to the U.S. GS on geology. But, looking at the latest well 
productivity data we came in somewhat higher than the GS number 
of 84 trillion cubic feet.
    So again, it's lower than what we had in the last outlook, 
but it's higher than what U.S. GS came out with recently. It's 
a lot of natural gas.
    Again our outlook is out there. Our view is that the U.S. 
will become a net exporter our production would exceed our 
consumption. Prices are lower than in the last outlook. I 
understand the desire to focus on one number and changes and 
disputes in that number.
    I think this will be an issue that we face for a long time. 
Total recoverable resource is inherently a squishy concept of 
what's totally under there. But I think the United States has a 
very bright future with natural gas.
    Senator Manchin. Thank you.
    If I may, just 1 second, Mr. Chairman. If I could just--the 
Ambassador really quick.
    I'm concerned about the jobs that we would be capable of 
even producing here manufacturing and so on with the rising 
cost of our energy making it more difficult to use our natural 
resources such as coal to natural gas or the downturn as far as 
the projection of what we have. Do you see that as a long term 
concern and problem?
    Ambassador Jones. Actually right now, I mean, with the 
increasing supply in the domestically, the United States, gas 
prices have fallen. I think oil prices in the United States may 
also be, I mean, right now at WTI, you know, the kind of the 
market crude for the United States is running under Brent by 
about ten bucks a barrel. The differential has been even 
greater. In the last year it was, I think, peaked at 24 or 27, 
something like that.
    So relatively speaking, U.S. prices are relatively low. You 
know, obviously if prices go down that could be a stimulus to 
the economy. But prices in the United States are generally 
lower than in other markets already.
    Senator Manchin. Thank you, Ambassador.
    The Chairman. Thank you.
    Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman.
    Dr. Gruenspecht, just very quickly I want to ask for some 
clarification here. There's an article coming out of a local 
Alaska newspaper from yesterday that indicates that the Alaska 
to Alberta gas pipeline, the proposal that's been under 
consideration for several years has been taken out of the 
outlook reference case because it determined that the project 
would not be economical based on the price forecast through 
2035.
    Then there is another statement that says that the final 
2012 outlook which is to be issued in the spring will in fact 
include some aspect or will include Alaska in its 
determination. Can you help clarify this for me? The statement 
here is, ``EIA's new outlook could bode well for Alaska as the 
state continues to seek a project to bring its national gas to 
market, but the full picture won't be known until this 2012 
outlook.''
    Mr. Gruenspecht. In terms of piping natural gas from 
Alaska--it had already been out of the reference case.
    Senator Murkowski. Right.
    Mr. Gruenspecht. Which again, is just a projection.
    Senator Murkowski. Right. I understand.
    Mr. Gruenspecht. In last year's outlook, and it still is, 
primarily for the same reason that at the prices of natural gas 
that are now being projected the economics are tough to build a 
pipeline.
    Senator Murkowski. The economics are tough for an overland 
route through Canada into the lower 48.
    Mr. Gruenspecht. Right.
    Senator Murkowski. But do you take into account Alaska's 
natural gas potential and the opportunities for it for export?
    Mr. Gruenspecht. We will look closely at that going 
forward.
    Senator Murkowski. Several of you have discussed the issue 
of spare capacity. I think it was you, Mr. Burkhard that 
indicated 2, I think you said $2 billion--excuse me, 2 billion 
barrels per day down from 5 million barrels. Did I say billion 
or million?
    Two million barrels per day is our spare capacity and Mr. 
Diwan, you have mentioned some of the supply risk factors that 
are out there. Some pretty considerable risks whether you're 
talking about Iraq and their ability to move things online. We 
don't know with Nigeria and strikes. You mentioned Sudan, 
Syria, Strait of Hormuz with Iran.
    I mean there--when we're talking about supply risk, it's, 
it is, very, very difficult to predict. So I guess the question 
is is how certain are we that we do have spare capacity in the 
numbers that you have referenced. Given the volatility that you 
have with the supply risk out there how are we dealing with 
this?
    You had mentioned, Mr. Diwan, or excuse me, I guess it was 
you, Mr. Jones. You state that, ``to a degree threats 
surrounding the Strait of Hormuz have already been priced in 
the market by the likelihood of a prolonged stoppage for Hormuz 
transit as seen as being fairly low.'' So when we're talking 
about what is going on with the price of oil, what we have 
available with spare capacity, what we know and perhaps what we 
don't know with supply risk.
    To what degree, Ambassador Jones, has the uncertainty 
already been priced into the market? How do we know that? These 
are some pretty gnarly questions that we're dealing with here 
that go to the heart of the reliability of any kind of an 
assessment that any of you may do.
    So Ambassador Jones, if you want to start first and then 
we'll go down the line here.
    Ambassador Jones. When we look at the situation, the 
market, I mean we basically see actually quite a bit of price 
stability over the last year plus now. Prices peaked around 120 
in April I think it was of last year. They've been oscillating 
between 120 and 100 ever since.
    Senator Murkowski. But if you had price stability last year 
the picture going forward is a little different.
    Ambassador Jones. I'm getting there.
    Senator Murkowski. OK. Alright. I won't----
    Ambassador Jones. So what's been going on? We basically see 
that the concern for the disruptions has put a floor under 
prices that's about at the $100 level. The concern of--yes, at 
the--that's put a floor and a ceiling on prices is put because 
of the fear of economic activity.
    Because we all know that if prices go up it produces an 
external burden on importers. For example, I said last year 
before this committee, that all or several major recessions had 
been preceded by an oil import bill of 5 percent or more. In 
2011 we had an oil import bill for the world of 5 percent or 
more.
    So there has been constant pressure put on the world 
economy. So you can't look at it in isolation. Yes, there are 
risks to the supply. But there's also risk on the demand side. 
So that's--and of course if there's a supply shortage and 
prices go up that puts more burden on the economy which 
increases the likelihood that they'll be a demand shortfall 
because of economic activity.
    So what we're seeing is the interplay of these 2 has kept 
the price within this range. We think it's, basically, we think 
the price is quite high when you consider the availability of 
oil in the market. That's why we think that the market is 
including a premium for this threat of the disruption in the 
Iranian case.
    Senator Murkowski. My time is expired. But Mr. Burkhard, 
Mr. Diwan, anything briefly that you would add to that?
    Mr. Burkhard. Very briefly. Expectations about the future 
play a big role in oil price formation. Wwhen you look at the 
limited amount of spare capacity we estimate it's around 1.8 to 
2.5 million barrels per day, call it 2 for this year.
    There's a reasonable case to be made that Iranian exports 
could have some degree of disruption this year which would eat 
into spare capacity. So it is that limited amount of spare 
capacity. This fear or concern about disrupted oil supplies 
that are keeping prices high. They could even go higher despite 
the weak economy.
    Senator Murkowski. Mr. Diwan.
    Mr. Diwan. I largely agree with Ambassador Jones. I think 
the band will be working between 120 with the floor due to 
politics and the ceiling due the economics is exactly what 
we're in. However, we have really 2 tales and risk going on 
right now.
    One is that the natural crisis in Europe.
    The other is conflict in the Middle East.
    So these 2, in a way, can blow up that range and that's the 
risk we're facing in 2012.
    If neither of which occur we're very likely to stay in that 
band.
    Senator Murkowski. Thank you. Thank you, Mr. Chairman.
    The Chairman. Thank you.
    Let me ask Dr. Gruenspecht. You have in your testimony here 
that net petroleum imports as a share of U.S. liquid fuels 
consumed will drop you project, from 49 percent in 2010, to 38 
percent in 2020 and 36 percent by 2035. That's your projection.
    Then you say that this projection was made without 
including the reference case of any further reduced projected 
levels of liquid fuels as a result of the fuel economy 
standards. Have you calculated if these fuel economy standards 
which have been announced by the Administration and by the auto 
industry and by various others, if those are included, what 
that does to the percentage of liquid fuels that we have to 
import?
    Mr. Gruenspecht. Thank you, Mr. Chairman.
    We are certainly going to include a case like that, in our 
full outlook. It makes a significant difference I'd say in the 
last decade of the projection. By 2035 liquid fuels consumption 
would probably be lower by a million, 1.4 million barrels a 
day, roughly. I'm trying to remember the number. Most of that 
would come out of imports.
    So it's a pretty big deal.
    The Chairman. So instead of it being then 36 percent by 
2035 what percent would it be?
    Mr. Gruenspecht. I would need to calculate that. But I will 
be glad to get back to you with that or maybe one of my 
colleagues will calculate it while we're talking.
    EIA has not yet performed an analysis of the impact of the 
recently proposed fuel economy standards for model years 2017 
through 2025. However, based on information that is currently 
available and preliminary results using the Annual Energy 
Outlook 2012 Early Release Reference case, EIA estimates that 
domestic liquid fuels consumption would be reduced between 1 
and 2 million barrels per day by the year 2035. EIA's Early 
Release Reference case projects that imported petroleum as a 
share of total liquid fuel use declines from about 50 percent 
currently to 36 percent by 2035. Given the estimated reduction 
in fuel use associated with the proposed model year 2017 
through 2025 fuel economy standards, imported petroleum as a 
share of total liquid fuel use would decline several additional 
percentage points by 2035 if other Reference case assumptions 
are unchanged.
    The Chairman. That would be a good figure because I think a 
lot of the effort here in Congress and in the Administration 
has been to try to put in place policies that would reduce the 
amount of petroleum we have to import.
    Dr. Diwan, you referred, I think, in your comments to 
structural trends of declining demand in the United States. 
Could you elaborate on what you're talking about there?
    Mr. Diwan. Yes. There's obviously the gasoline story where 
we have more car efficiencies. But also we're seeing the 
residential heating fuel oil also declining. Another product, 
cheap natural gas, cheaper coal and the extension of the gas 
network will reduce the heating oil consumption too.
    So you have a number of trends here for different fuels 
which are on the decline. But the biggest gain is obviously on 
the gasoline side structurally.
    The Chairman. OK. Let me ask about the closing of 
refineries. We've seen refineries being closed in the United 
States, in Hawaii, in the Virgin Islands, even in Europe.
    What is the impetus for this and for the results that we're 
seeing?
    Are we in a circumstance where we're going to see higher 
prices for gasoline at the pump because of a shortage of 
refined product even while we've got an ample supply of oil 
being produced?
    I mean, what is going on here with refinery closures?
    Dr. Gruenspecht, do you have a perspective?
    Mr. Gruenspecht. I have something of a perspective. We've 
sent a--we put a report on our website right before Christmas, 
a short report on Northeast U.S. refining. We are expecting to 
provide a much more detailed piece probably by February.
    But I guess the short answer is that certain types of 
refineries, you know, in certain regions are not economically 
very attractive. I would point out that in the Gulf there are 
significant expansions of refinery capacity and in the Midwest 
there have been significant expansions of refinery capacity. So 
in the strange EIA speak, it's really PADD One or the East 
Coast and some places in Europe and the Hovensa refinery in the 
Caribbean where refineries are being closed. But there are 
other places where refinery capacity is being added.
    Our concerns, which we expressed in the preliminary report 
released in December, are really about the transition. There 
are a lot of petroleum products in the world. Demand trends, as 
discussed, are in some sense moderating with fuel economy 
standards and with increased use of biofuels which reduce the 
demand for petroleum based products.
    There are potential fuel transportation, bottlenecks, 
logistical issues. It's a challenging environment and something 
that I've asked the people at EIA to dig into a lot more 
deeply.
    The Chairman. Mr. Diwan, did you want to add a comment?
    Mr. Diwan. Yes. I want to add structurally to understand 
what's happening here. In Europe we have declining demand which 
means the refining capacity they have is too big for the market 
they're serving. So everybody has to run at low utilization 
rates which makes a lot of these sectors unprofitable. So the 
smaller refinery, the least profitable ones basically, are 
under tremendous economic pressure to shut down. Their refiners 
are losing money basically.
    The United States is slightly different. We have these 
structural trends and demand which are shifting. If you want 
where demand and which product is in a different region. At the 
same time we have the shift in the crude supply with giving 
certain refiners location advantage and certain refiner 
location disadvantage.
    So what we're seeing here is a shift of utilization rate or 
construction of refineries toward the ones who are better 
positioned than others. It's really location issue which has to 
match the changes in the supply. So you're trying to make sure 
that your infrastructure is adapting to your growth of supply 
in the United States.
    While in Europe in the overall sector is declining and 
needs to shrink.
    The Chairman. Alright. Thank you very much.
    Let me go to Senator Barrasso.
    Senator Barrasso. Thank you very much, Mr. Chairman. I 
graciously appreciate the opportunity to hear from these 
experts today. I want to thank them for sharing their 
knowledge.
    If we're going to grow our economy and get Americans back 
to work we need to have access to affordable supplies of 
American energy. We heard that in this room when we sat and 
visited with Bill Gates not too long ago. To me this means 
coal, oil, natural gas, uranium and renewable energy.
    So I was pleased last week at the State of the Union when 
the President said that, ``This country needs an all out, all 
of the above strategy that develops every available source of 
American energy.'' My concern is that the President's rhetoric 
doesn't match the policies that he pursues. Just a week before 
the State of the Union the President rejected the Keystone XL 
pipeline.
    That's a pipeline that is estimated to create tens of 
thousands of direct jobs.
    Will facilitate oil production in North Dakota and Montana.
    Will improve our Nation's energy security.
    So it's my hope that Congress will reverse the President's 
decision soon and get Americans back on track to a more secure 
and prosperous future.
    So, Mr. Burkhard, in your written testimony you 
specifically talk to the issue of the denial of the permit for 
the proposed Keystone XL pipeline. You said that that raises 
the level of uncertainty regarding the long term growth and 
disposition of major sources of world supply growth including 
the Canadian oil sands and the American on shore output. I 
wondered if you could expand on that and specifically with 
regard to U.S. oil production.
    Mr. Burkhard. Sure. The--Canada over the last decade has 
become the most important source of foreign oil to the United 
States by far. The oil sands has been the principle reason for 
that. So the oil sands are not just an important source of 
supply to the U.S. market. They've been a major source of 
global oil supply growth.
    In fact, if you look at the oil sands alone, the U.S. 
imports about as much oil just from the oil sand as we do from 
Mexico or some other leading suppliers. The denial of the 
Keystone permit does raise a question about the future pace of 
growth of oil sands production where it is sent. It is leading 
many Canadian decisionmakers to put more effort into exploring 
potential export routes to the West Coast of Canada which could 
open up the Asian oil market.
    The more immediate question with regard to the Keystone XL 
pipeline is there is the U.S. midcontinent is the principle 
market for oil sands going into the United States. That U.S. 
midcontinent, the Midwest is nearing a saturation point for the 
oil sands. There's only so many refineries in the U.S. Midwest. 
There's only so much crude oil from Canada that they can take.
    So to expand the reach of Canadian oil into the U.S. you 
need a pipeline to the U.S. Gulf Coast which is the largest, 
most sophisticated refining center in the world. In fact it's 
been an important source of export growth for the U.S. But this 
denial does raise an uncertainty about whether that growth will 
continue as previously thought.
    Senator Barrasso. Thank you.
    Dr. Gruenspecht, I'd like to ask you about diesel prices. 
In my home State of Wyoming this weekend noticed that a gallon 
of diesel is about a dollar higher than regular unleaded 
gasoline. It's my understanding that this difference can be 
attributed in part to a shortage of diesel in the West and the 
upper plains and a lot of diesel is being shipping to North 
Dakota to service some of the oil field work being done there.
    Can you help me understand why diesel prices are so much 
higher than gasoline prices right now in Wyoming?
    Mr. Gruenspecht. Thank you.
    I couldn't specifically speak to Wyoming without doing some 
more research, but I do know that this issue of diesel and 
gasoline prices is a broader phenomenon. There may be special 
circumstances in Wyoming.
    In part, because of some of the issues we've been 
discussing, demand for the petroleum components of gasoline has 
been depressed by fuel economy gains and the switch toward 
biofuels. The developing world is driving a lot of the 
increase, and demand there is much more heavily oriented toward 
diesel than toward gasoline.
    In the world mix of products. The demand growth is in the 
distillates diesel and heating oils, affecting Senator 
Shaheen's constituents and me, personally, since I happen to be 
one of the few people in Washington who uses heating oil. It's 
really with that set of products, the differential between 
gasoline and distillates, including heating oil has grown.
    Heating oil and diesel prices are both much higher than 
gasoline. That's driving some of these refinery changes for 
refineries that produce relatively less of the higher valued 
distillate products. Which refineries are profitable? Which 
ones are not, that have been discussed. So a lot of these 
things do tie together.
    Senator Barrasso. Thank you.
    Ambassador Jones, just my final question. We just talked 
about global issues. I want to ask you about global coal 
demand.
    According to the IEA's world energy outlook you said that 
the importance of coal in the global energy mix is the highest 
since 1971. Port says that for all the talk about natural gas 
and renewables, coal, it says unquestionably won the energy 
race in the first decade of the 21st century. It explains that 
globally coal is the most important fuel after oil and that 
coal is the backbone of global electricity generation alone 
accounting for 40 percent of electricity output in 2010.
    Will you elaborate on the importance of coal to China, 
India and other developing countries?
    Ambassador Jones. Certainly.
    First of all one statistic that you didn't mention in your 
resume which is quite accurate is that in that first decade 
coal accounted for half of the world's growth in energy. It's 
truly an impressive performance.
    Why was this? This was largely the countries you mentioned 
China and India, where they have electrified their countries. 
They have brought electricity service to literally hundreds of 
millions of people in recent years who never had electricity 
before. A lot of that electricity was coal fired electricity.
    At the same time China, in particular, has been wrestling 
with the growing pollution in its cities from these coal fired 
power plants. As a result China is eagerly looking for 
alternatives. They are looking at renewables and they are 
looking at natural gas.
    But like in any country a lot of decisions that are taken 
in China on power are taken on economic basis. Coal has been a 
cheap competitor. That is why it is grown so rapidly.
    Whether or not that will continue in the future is another 
question especially now that China has aggressively decided to 
markedly expand their use of natural gas. But I do think that 
and our projections show that coal has a bright future as well.
    Senator Barrasso. Thank you. Thank you, Mr. Chairman.
    The Chairman. Thank you.
    Senator Shaheen.
    Senator Shaheen. Thank you, Mr. Chairman. Thank you to all 
of our witnesses for being here this morning.
    I think every one of you in your comments and projections 
talked about demand and how that's affecting energy projections 
for the future. You may be aware that Senator Portman and I 
have sponsored energy efficiency legislation that addresses a 
number of sectors of the economy here.
    Can you talk about how energy efficiency is incorporated 
into your projections and what increased use of energy 
efficiency would do to your future projections?
    Dr. Gruenspecht, if you want to begin?
    Mr. Gruenspecht. Sure.
    Energy efficiency obviously plays a very big role in our 
projections. For instance, our economic growth projection for 
the next 25 years for the United States is on the order of two 
and a half percent per year, plus or minus. Our growth in 
energy use is much lower than that, like half a percent a year. 
So energy efficiency plays a very important role in that.
    I've already indicated that in our reference case 
projection we build in existing laws and policies including 
final regulations, but not new ones. In response to a question 
from the Chairman, I indicated that even one very important, 
proposed, likely to become final regulation would have a 
significant impact. There are certainly other policies that 
might be implemented by policymakers, which you are and I am 
not, that would also, potentially have, effect.
    So, yes, there's a lot of the impact of energy efficiency 
in our reference case already with existing laws and policies. 
So, I think I would leave it there.
    Senator Shaheen. Ambassador Jones.
    Ambassador Jones. Yes, we have a variety of scenarios. We 
have a scenario similar to the EIA scenario that's based on 
existing policies. We also have a scenario that we the new 
policy scenario which is based on announced intentions of 
policies. Then we have a climate scenario that is designed to 
limit global warming to 2 degrees centigrade.
    In all 3 of those scenarios energy efficiency plays a very 
important role. In fact we believe that, you know, looking at 
climate change and the need to restrict emissions of carbon 
dioxide. Basically we think that energy efficiency alone with 
currently available technologies can lead to at least 50 
percent of the emissions reductions we need if we're going to 
produce or prevent global warming beyond 2 degrees centigrade.
    But of course energy efficiency isn't just important for 
the environment or for climate change. It's important for 
energy security. It's important for economic success as well 
because the more efficiently you can use your resources the 
more competitive you can be in the international market.
    The more efficiently you use your resources, the less of 
them you need. Therefore the less dependent you have to be on 
imports of foreign energy. So energy efficiency is the one 
thing that we see that serves all of the objectives that are 
important to the IEA.
    We include it in our models. We include, in the base case 
scenario, are the current policies. We include a, you know, a 
relatively small improvement in efficiency, the 2 more 
aggressive policy scenarios that we see a stronger growth in 
energy efficiency. That makes a very big difference.
    I can't emphasize too much how much important we see energy 
efficiency for the world's energy future. I want to distinguish 
this from conservation. Conservation can be important in 
certain ways, but what I'm talking about is getting the same 
services for less energy rather than doing with less services.
    Senator Shaheen. Thank you. I'm not going to ask either of 
you about job projections since you've pointed out that's not 
under your purview. But I would just editorially point out that 
there are a lot of jobs that are also created in energy 
efficiency.
    I don't Mr. Burkhard or Mr. Diwan, if either of you would 
like to add anything to what's been said?
    Mr. Burkhard. Fuel economy standards, we already mentioned. 
Those play a tremendous role in oil consumption in the future. 
We're seeing higher fuel economy standards not just in the U.S. 
but also Europe and China, other markets.
    One more challenging aspect to the energy efficiency 
efforts are buildings and structures. A car is on the road for 
maybe 12 years. A building can be around for a hundred years. 
Encouraging, providing incentives for greater building 
efficiency could go a long ways.
    Senator Shaheen. Yes, Mr. Diwan.
    Let me ask a very quick final question for Dr. Gruenspecht 
since you mentioned heating oil in the Northeast. I, 
personally, am very concerned about PAD-1, as you pointed out. 
You talked about the refineries that are down on the East 
Coast.
    Can you talk about the correlation between that, if there 
is any and what we're seeing increased costs for home heating 
oil in the Northeast?
    Mr. Gruenspecht. Thank you.
    I don't think there's really much correlation. I described 
the broader picture of gasoline.
    Senator Shaheen. Right.
    Mr. Gruenspecht. Distillate and you know, as Senator 
Barrasso pointed out, the distillate prices in Wyoming were 
very high. So I don't think the refinery issue this winter so 
far has been much of the issue. We do a winter fuels outlook at 
the beginning of each winter, I think in October, and we did 
flag the heating bills as being for oil users as being pretty 
significant.
    Senator Shaheen. Higher.
    Mr. Gruenspecht. This upcoming winter.
    Senator Shaheen. Right.
    Mr. Gruenspecht. We've gotten a little bit of a break on 
the weather, which has helped everybody. The projected 
expenditure increases have come down a little bit.
    But I think we're still looking at the average heating oil 
user. It varies a lot depending on what temperature you set the 
thermostat, where you are, how well your house is insulated, 
going back to energy efficiency. But it's still looking like 
$2,400, $2,300, as the winter fuel bills for heating oil 
households. That's much higher than households using other 
fuels.
    Senator Shaheen. Yes. Thank you. Very much higher.
    Thank you, Mr. Chairman.
    The Chairman. Senator Portman.
    Senator Portman. Thank you, Mr. Chairman. I really 
appreciated the testimony. I got a chance to read through some 
of it while I was away and ask the question that I missed 
earlier.
    This is actually, I think, a lot of good news today that 
we're hearing in terms of additional energy supplies. 
Particularly heartened by the comments of Ambassador Jones and 
Mr. Burkhard about efficiency because it's an issue where, I 
think, we can make huge progress. I'm one of those.
    I won't necessarily associate my colleague and co-sponsor 
with this. But, you know, we need to produce more. Also use 
less. Those are not inconsistent.
    But my colleague and I do work very hard on trying to 
promote efficiency. As Mr. Burkhard mentioned, a lot of this 
has to do with buildings. Our focus is really manufacturing 
efficiency and buildings. It's time to deploy, as Ambassador 
Jones said, some existing technologies.
    So we're not as much focused on even the innovative side of 
this. Although we certainly want to encourage that as simply 
taking best practices and the United States, of course, has 
tremendous potential here to even catch up with some other 
industrialized economies namely Japan and some of the European 
countries. We can be, as Ambassador Jones said, more 
economically efficient and therefore, help our economy by being 
more competitive and also, of course, as you said, we can use 
fewer imports by doing so.
    But we also need to produce more. Again, I think, those 2 
are not only not inconsistent, but I think they both help to 
create jobs and economic activity. But again, I found looking 
at your testimony some very good news.
    Mr. Burkhard, you talked about the fact that IHS Global has 
now said that shale gas production has supported more than 
600,000 jobs in 2010. They project 870,000 jobs by 2015. I 
think that's low just based on what's happening in Ohio where 
we have another projection showing another 200,000 jobs from 
Utica alone during that time period which would account for 
almost all that growth.
    So I think there's a lot of good news here.
    What is holding back the natural gas production and 
distribution, Mr. Burkhard?
    Mr. Burkhard. The--on the natural gas side prices are quite 
low because of this revolution and shale gas production. But 
what we're seeing is more companies shift toward liquids or 
producing oil. One of the factors that's influencing the pace 
of investment is that the rising costs, finding the right 
people, the right equipment is not a limitless supply.
    There's, in fact, a missing generation of folks in the 
petroleum industry because from about 1986 to earlier this 
decade oil prices were low. The industry was consolidating. 
There weren't many people entering the industry at that time. 
As prices have risen, oil prices have risen and activity has 
picked up, particularly in this country, there's been a great 
deal of pressure in finding the right people and getting the 
right equipment to the right places.
    So that's a significant challenge.
    Senator Portman. In some of the testimony this morning, 
it's interesting you all talked about the fact that because 
there is both wet gas and oil in some of the shale finds that 
that has encouraged people to go ahead and explore and extract 
even though the natural gas prices are relatively low. Will 
that continue?
    I think of Marcellus where maybe there's less of the wet 
gas or oil. But Utica maybe there's more. Will that encourage 
more development in some of those finds?
    Yes, Mr. Diwan.
    Mr. Diwan. Yes. I mean when you think about the U.S. gas 
market as an island, so if we're in oversupply which we are 
right now and prices are low. On the oil side we don't have the 
same issue. Oil prices are really global and at the present 
prices and the present taxation system in the United States, 
these barrels are very profitable.
    So we will see a continued development of liquid plays. I 
think in the next 2 to 5 years we'll have 3 or 4 new plays 
emerging just because of that price differential.
    Senator Portman. Mr. Burkhard, when I asked you about what 
might hold it back you talked about skills, personnel and just 
resources devoted to oil maybe taking away from natural gas, 
the price of natural gas. You didn't mention infrastructure. 
Although in your testimony you talked about that.
    Can you talk a little about what you see as some of the 
limitations on natural gas use and distribution because of our 
infrastructure challenges?
    Mr. Burkhard. One of the new, really exciting developments 
in energy is the Northeast or from Ohio, Pennsylvania, that 
area becoming a significant gas producer and possibly oil 
producer as well. So there weren't--the U.S. pipeline system 
wasn't set up to ship gas away from those areas it was shipping 
gas to those areas. So the challenge now is forming or getting 
the right pipelines to the right places so that gas and liquids 
can be economically developed.
    What we're seeing is this great revival on the supply side. 
This great revival has showed, illustrated, that our 
infrastructure system, our pipeline system whether we're 
talking about the U.S. Midwest or the U.S. Northeast, has yet 
to catch up with this great revival.
    Senator Portman. You would add Keystone to that as well in 
terms of--as Mr. Diwan said earlier there still is adequate 
capacity now but soon there won't be. That would limit as well 
some of the developments of our North American resources.
    Mr. Burkhard. There is enough cross border capacity for the 
next few years, probably, maybe, until around 2019. But the 
problem in the short term, say in the next 1 to 2 years, excuse 
me, is saturation of the Midwest refining market. There's only 
so much oil that refiners in the Midwest can take from Canada. 
So that's expanding the reach of Canadian oil to other markets 
in the U.S., namely the Gulf Coast.
    Senator Portman. Listen, great testimony. I thank Dr. 
Gruenspecht and all of you. My time is up. But we appreciate 
your continuing to give this committee good information.
    The Chairman. Senator Landrieu.
    Senator Landrieu. Thank you, Mr. Chairman. I really 
appreciate the testimony. As usual it's very, very helpful as 
we try to direct our policies to respond to some of the 
changing reality.
    I'd like to submit first for the record a report that just 
came out from our greater New Orleans ink that talks about the 
hidden job loss along the Gulf Coast. A story that really, in 
my view, hasn't been told because the unemployment numbers 
after the Macondo spill has stayed relatively flat, employment 
and unemployment. But it's because of the shift from South 
Louisiana to North Louisiana with the shale plays.
    But in South Louisiana we still are experiencing tremendous 
downturn because of the slow permitting process. The deep water 
plays are significant. But the shallow water drillers have 
really been hurt.
    According, Mr. Chairman, to this report which is really the 
hidden story of the Macondo spill and the, I thought, 
inappropriate moratorium put down.
    Fourty-one percent of the respondents said that they are 
not currently making a profit. These are the small oil and gas, 
independent, marine operators.
    Seventy percent said they have dipped into their cash 
reserves. So they're not laying off their employees but at 
great hardship to these small and independent businesses that 
are servicing an industry that the top line looks good but 
there's a lot underneath.
    So I'd like to submit that for the record.
    The Chairman. We'll be glad to include that.
    Senator Landrieu. Second in the report, Supply Rising in 
the West, Growth at Risk in Iraq, I think this is--the page is 
not numbered. But this is in your report. You all say that we 
have penciled in an end to output losses in the Gulf of Mexico 
after the Macondo spill. It's in the paragraph where you talk 
about the U.S. will lead the growth in liquids, etcetera.
    Can you help us understand what the output losses in the 
Gulf were after the Macondo spill?
    Yes?
    Mr. Gruenspecht. Yes, I'm not sure that the report you're 
reading from is from EIA, but maybe it is.
    The Chairman. I believe it's Mr. Diwan's report.
    Senator Landrieu. I'm sorry Mr. Diwan's report. I'm sorry.
    Mr. Diwan.
    Mr. Gruenspecht. Yes. I could help you with your question 
anyway.
    Senator Landrieu. But let's get to him and then we'll get 
to you.
    Thank you.
    Mr. Diwan. I mean, the delay in permitting has had an 
impact on our projection for the deep water output. With the 
restart of the permitting process now we do not see the decline 
anymore. We're seeing a flattening before a rise further out on 
the horizons.
    So we passed the bottom of that forecast.
    Senator Landrieu. But I will say as the representative from 
the state that has the most, besides Texas, of offshore 
drilling, it's been a very painful 3 years. I know that Senator 
Portman talked about producing more. We have got to get the 
Gulf back up and operating and producing. Not only is it the 
home to tremendous opportunities for oil and gas, both deep and 
shallow. But the refining capacity for the country is in large 
measure or a large part of it in the pipeline system which is 
much more robust than other pipeline systems there.
    So getting the Gulf back up and operating, Mr. Chairman and 
Ranking Member, is important. It's going to remain a priority.
    Let me ask any of you to further discuss the significant 
increase in liquid fuel production because while climate is 
important and the environment is important, I'm really and my 
constituents are very concerned about the economic vitality of 
the United States going forward. The President talked about 
building an economy to last. People are very interested in 
making America more energy secure.
    You talked about the increase, substantial increase, in 
liquid fuels. Could someone describe in a little bit more 
detail? Are we talking about oil? Are we talking about 
biofuels? Where is the growth potential there?
    What about new fuels created from other agricultural or 
other scientific processes like algae, etcetera? Does anybody 
want to comment on that? Because the combination of increasing 
our liquid fuel production and decreasing our use through 
efficiencies in automobiles is extremely exciting because I 
think, if I'm hearing what you're saying, that we could have a 
major impact on not just job creation but on the economic 
security of the United States.
    Am I reading too much into the possibilities here?
    Starting with you, Mr. Diwan.
    Mr. Diwan. Yes, actually I think you are not reading enough 
in what we're saying. We all believe that actually the 
production of crude oil and natural gas liquid in the United 
States will grow tremendously over the next 10 years. The 
technology is there now. The resources are there. Industry is 
investing to bring them up.
    So we are really talking about a major revival of the U.S. 
oil and gas industry. I don't think we really disagree on the 
magnitude even. So we all believe it's really the biggest thing 
happening in the oil and gas industry going forward.
    The investments are available. The funds are available. We 
have, as Jim described, issues in finding enough people 
actually and costs are rising because of that.
    That development, I think, limit also the growth of the 
other fuels outside of oil and natural gas liquids because we 
have such an abundance now. So much to invest into that area 
that, I think, we all have limited growth in other fuels. I'll 
let----
    Senator Landrieu. We call them drop in fuels, you know, 
alternative fuels that you can drop in to the pipeline without 
having to redo all the pipelines. What are our most significant 
opportunities in drop in fuels?
    Go ahead.
    Mr. Gruenspecht. In the Energy Independence and Security 
Act of 2007, Congress enacted and the President signed a very 
ambitious mandate for increased use of biofuels. Right from the 
start it looked pretty challenging for us.
    The cellulosic biofuels, in particular, are supposed to go 
to 15 billion gallons by 2022. We've always been fairly 
skeptical that you could actually get there. The passage of 
time has not ameliorated that skepticism.
    We do think there was a vision, perhaps in some people's 
minds that a lot of that would be cellulosic ethanol, and that 
a lot of it would be a drop in. What we call, biomass to 
liquids, a diesel type fuel that unlike ethanol would go into 
the normal stream of commerce, if you will, as interchangeable 
with regular diesel fuel.
    Senator Landrieu. That doesn't require as much of a 
subsidy.
    Anything from you, Ambassador Jones?
    Thank you, Mr. Chairman.
    Ambassador Jones. Yes, first of all I agree with all the 
comments that have been made.
    In terms of biofuels worldwide, all types of biofuels, we, 
in our World Energy Outlook, we saw them tripling between now 
and 2035. So that's probably a little bit more than 3 percent 
per year worldwide. In the United States they're fairly 
aggressive policies, although they fluctuate.
    Again I agree that cellulosic biofuels are going to be a 
long time coming. Ethanol is going to be the main source of 
biofuel I think for some time, particularly sugar cane ethanol 
which the Brazilians are trying to spread their experience 
around the world in tropical climates. But other crops can also 
of course be turned into that.
    Senator Landrieu. The one other thing I mentioned that's 
significant. The country first, Mr. Chairman and Ranking 
Member, issued its first permit to build an export facility for 
natural gas, the Chenier Company received its permit. I helped 
to push that and proud of it.
    I know there's a debate about whether we should keep the 
natural gas as an island. The problem is if you don't create a 
market for it you get prices that are as low as they are today 
which is a disincentive to production. So you've got to figure 
out the right price point where you can get people to invest in 
natural gas which is a cleaner fuel. But also, you know, so 
opening up that export, I think, is the right thing to do.
    I just want you all to say yes or no. Do you agree with 
that or not opening up exports for gas?
    Yes or no?
    Mr. Gruenspecht. I don't think I'm allowed to have a 
position on that.
    Senator Landrieu. Ambassador Jones?
    Ambassador Jones. Yes, we believe in the trade. The trade 
should be driven by the market, in the market, if there's 
market demand for it. We don't think there should be export 
restrictions.
    Senator Landrieu. Mr. Burkhard.
    Mr. Burkhard. Developments that foster and enhance global 
trade of energy makes for a more robust system.
    Senator Landrieu. Mr. Diwan?
    Mr. Diwan. I agree with them.
    Senator Landrieu. Thank you.
    The Chairman. Senator Murkowski, did you have additional 
questions?
    Senator Murkowski. I do, Mr. Chairman.
    A couple follow ups, one on Iran sanctions and then the 
second on the issue of reserves that I mentioned in my opening.
    So let me start with the sanctions. This is directed to 
you, Mr. Diwan, dealing with the potential impact of additional 
sanctions there. We know that the Iranian--the Europeans have 
agreed in principle to ban the imports, but reading from your 
testimony it seems that neither Italy nor Greece will comply at 
least to the extent that would have been expected.
    Given your point that you've got India, you've got South 
Korea, Turkey, all increasing imports combined with what we 
know about the strong demand from China. What do you think the 
practical effects of these new sanctions will be?
    Mr. Diwan. Italy, Spain and Greece will have to comply with 
EU sanctions by July 1st. The question is would they do much 
between now and then to try to diversify their source of 
supply. They have long term contracts. I think it's not very 
easy unless the Iranians decide to embargo them.
    The problems are specific for each country which refinery 
gets what from where and there's long term commercial 
relations. But it's likely that over the course of year, by the 
end of the year that will not be allowed or they won't be able 
to import as much as they are right now. So we believe that 
they will have to decrease their supply by around 400,000 
barrels per day combined.
    The question is are there other countries willing to pick 
up that slack from Iran and in a way just shift the barrels, as 
Ambassador Jones has said. When you look at the countries which 
are really potential clients here, Turkey can increase a little 
bit. The question is how much it will face the U.S. side of the 
sanctions.
    It's unlikely that any OECD in Asia, country in Asia, will 
take more Iranian crude. The question is really how much India 
and China are willing to become more dependent on Iran as a 
source of supply. We don't believe actually that China will be 
very aggressive in increasing its imports of Iranian barrels 
because it will make them more dependent and more vulnerable to 
a potential disruption of Iranian barrels.
    They have somehow indicated that they're likely to keep the 
percentage of imports from Iran stable which is around 10 
percent of their crude imports. Their crude imports are rising. 
So that 10 percent means a little bit more barrels than the 
year before but it is not significant.
    The question is really India. But the volume we're talking 
about, 4 to 5 hundred thousand barrels per day from Iran which 
do not have a place to go in Europe. It's unlikely that India 
can absorb that much.
    So in a way Iran is--will have difficulty to be able to 
replace these markets. We believe it's more likely actually 
they will have to shut down some production or at least have 
floating storage for some of that production before they shut 
it down.
    Senator Murkowski. Then following on that can you discuss 
the ways that Iran could possibly circumvent the current 
sanctions both in terms of financial payments or physical 
delivery then?
    Mr. Diwan. They need a client who is willing to circumvent 
the financial sanction. The way to do it is to deposit local 
currencies in the local back that the Iranians can draw from to 
buy whatever they need to import back into Iran. I think they 
will have real difficulty to go through the international 
financial system.
    So it limits, again, here, which countries have the 
capability and the ability to do that.
    Senator Murkowski. So really is going to be incumbent on 
all those that are adhering to the sanctions, some pretty 
robust monitoring and some enforcement there, I would imagine.
    Dr. Gruenspecht, I wanted to follow up with regards to the 
EIA's lower natural gas reserve estimates indicated that 
they've dropped precipitously 40 percent, as I recall. Do you 
expect that this lowering of the estimates may possibly 
discourage further exploration? Is this going to have any 
impact one way or another?
    Mr. Gruenspecht. I would say not. Whether the U.S. has 100 
years of total recoverable resource at current rates or 90 
years of total recoverable resources estimated at current 
rates, I just don't think it has much of an effect. I think the 
thing that would affect development would be the view of 
companies on the ground as to how much it costs them to drill a 
well and what they can recover by drilling the well and the 
price.
    So they care about the quantity they can recover by 
drilling a well, what it costs them to drill a well and what 
they think the price is going be. That's really what they're 
focused on. Whether we have 90 years of total recoverable 
resource or 100 years total recoverable resource.
    Senator Murkowski. I would agree with that, 40 percent 
reduction is noticeable. But as you put it in those contexts.
    Let me ask then how much of the EIA reserve estimate then 
is actually driven by the production data that's out there?
    Mr. Gruenspecht. Again I would say that USGS is the primary 
agency in the U.S. Government that does resource estimates. We 
do the work on reserves primarily. Resources is a larger 
concept.
    The USGS had not done a Marcellus estimate in a long time. 
They had a very, what we considered to be, a very low estimate, 
one that we couldn't use. So we developed our own.
    Mr. Gruenspecht. Then after we did that, USGS came out with 
an updated Marcellus estimate which was the 84 trillion cubic 
feet compared to their prior estimate of 2 trillion cubic feet. 
The 84 trillion cubic feet was significantly lower than the 
number that we had developed internally. We obviously said that 
when they came out we would update our work based on the USGS 
work. We did try to do that.
    Senator Murkowski. So do you think that you will revise the 
estimate again?
    Mr. Gruenspecht. I think that this is a really tough area. 
I think there's too much emphasis really put on that number, no 
matter whose number it is. I think that as we gain more and 
more experience with actual drilling the numbers will always 
tend to evolve on total recoverable resource.
    Again, I don't think it's that material for the 25 year 
horizon that we have been looking at in our projections, long 
term, that the IEA looks at. In fact we have more production 
and lower natural gas prices in this outlook than we had in the 
previous one. That really reflects the lowered drilling costs 
and the well productivity.
    Senator Murkowski. I think this is an important part of 
what it is that we're talking about and understanding what's 
going on. Again, the President's State of the Union that he 
gave last week, he again repeats the fact that--or his--I 
shouldn't say it's a fact, the statement that this country only 
has 2 percent of the world's oil. When we're talking about 
reserves verses resources and recoverable, we all--you all know 
at this table that the number can be all over the board here.
    It's how we define it. I think sometimes it's a pretty 
loose definition that would lead people in this country to 
believe that we really don't have much.
    Senator Murkowski. Of a recoverable resource. So it's 
important that we use the right terminology and try to be as 
accurate as we can recognizing that we're dealing with a very 
fluid assessment again as our technologies and our capabilities 
expand.
    Mr. Chairman, that's all that I have. Thank you.
    The Chairman. Thank you.
    Let me ask one other line of question.
    Dr. Gruenspecht, in your testimony you, in discussing the 
world or the international energy outlook, you say renewable 
energy is projected to be the fastest growing source of primary 
energy over the next 25 years. The renewable share of total 
energy use increases, in your projection, from 10 percent in 
2008 to 15 percent in 2035.
    Do you also have in your report an analysis of what those 
trends would be with regard to renewable energy in the United 
States?
    Mr. Gruenspecht. Yes, we have, particularly in our annual 
energy outlook, there's a lot of information on renewable 
energy. Again, it's very fast growing for two reasons.
    One, in the transportation sector you have the mandates for 
biofuels, which even though we don't believe that the target at 
2022 would actually be met, are certainly driving renewables in 
that sector.
    In the electricity sector the share of generation from 
renewables, I think, grows from 10 percent of generation to 16 
percent of generation. So that's a pretty big increase.
    We have renewables being pretty fast growing in the United 
States. In the electricity side it's mostly driven by the state 
renewable portfolio standards. There's also some interaction 
between the transportation side and the electricity side 
because the plants that produce cellulosic biofuels, there will 
be some, and those plants will throw off some extra 
electricity.
     It's a very interesting story.
    The Chairman. Ambassador Jones, is the analysis that your 
agency has made consistent with this as far as renewable energy 
being the fastest growing source of primary energy over the 
next 25 years?
    Ambassador Jones. It's certainly growing very rapidly. Yes.
    I was just checking my testimony. According to World Energy 
Outlook, the share of non-hydro renewables primarily wind and 
solar in power generation rises from 3 percent in 2009 to 15 
percent in 2035. Hydro, of course, which is a major source of 
power generation, maintains its share at 15 percent.
    So overall we're saying all renewables will be about 30 
percent of world power generation by 2035.
    The Chairman. OK.
    Alright. I think this has all been very useful testimony. 
We appreciate you all being here. We will try to stay in touch 
with you as these trends change.
    Thank you very much.
    [Whereupon, at 11:45 a.m., the hearing was adjourned.]
                                APPENDIX

                   Responses to Additional Questions

                              ----------                              

   Responses of Richard H. Jones to Questions From Senator Murkowski
    Question 1. Your testimony indicated that a ``prolonged'' stoppage 
for Hormuz is a low likelihood. Is a temporary stoppage, by inference, 
much higher of a likelihood?
    Answer. This statement was a reference to comments made by 
political-military analysts that were reported extensively in the 
press. The International Energy Agency (IEA) was created to monitor 
developments in energy markets and respond to physical disruptions in 
oil supply. However, the Agency does not generally analyze the risk of 
a disruption, which would require geopolitical and military expertise 
beyond the capabilities of our market analysts.
    Question 2. While some countries are looking to the potential 
phase-out of nuclear power, others, like China and India, are moving 
forward with new nuclear power plants. Do you see more interest 
internationally for large-scale reactors, or small modular reactors? 
For those countries that might phase-out nuclear, is it opposition to 
all nuclear or just the larger, more visible power plants?
    Answer. The only real life deployment of small and medium modular 
reactors so far has been in the Russian arctic, which has some unusual 
characteristics: It is not connected to the main Russian transmission 
grid and extreme conditions make conventional energy supply very 
difficult and expensive. The vast majority of nuclear investment in the 
countries actively pursuing nuclear power-- China, India, South Korea 
and even in Russia-- is in interconnected central regions and focuses 
on GW scale II+ and III. generation units. In fact, the average size of 
plants under construction is considerably larger than the average size 
of the existing fleet globally. The major nuclear investors have 
massive and growing demand for baseload power as well as national 
transmission systems that can incorporate such large nuclear units.
    The main social and political concern in countries that have turned 
away from nuclear power is nuclear safety risk and nuclear waste 
management. These are not particularly related to reactor size. Even in 
countries that favour new nuclear investment such as the United 
Kingdom, it is considerably easier to gain licensing consent for new 
units on existing sites than for greenfield nuclear plant. This also 
creates incentives for larger units.
    On the other hand, even in a supportive political framework, the 
capital intensity and unusual financial risk profile is a major 
obstacle for private investment in nuclear plants. The initial capital 
investment can exceed $10 billion which is a huge burden on the balance 
sheet of even the largest energy companies. Project management issues 
usually preclude EPC (engineering, procurement, construction) 
financing. Consequently, if smaller scale modular reactors became 
commercially available (they are currently not, the Russian ones are 
prototypes derived from submarine reactor designs of the Russian navy) 
that has the potential to relieve one of the major financial rather 
than political barriers to nuclear investment.
    Question 3. EIA reports consistently show little to no growth in 
the hydropower sector. In 2008, the EIA testified before Congress that 
the Annual Energy Outlook (AEO) forecasts less than 1 GW of new 
hydropower capacity to be added by 2030. In the 2011 AEO, hydropower is 
not even included in the discussion with the forecasts for other 
renewable technologies and the report shows an annual growth rate of 
only 0.1 percent in net summer capacity through 2035.
    Do you believe that the EIA modeling is accurately reflecting the 
hydropower sector? In 2011 alone, FERC received approximately 610 MW of 
conventional hydropower applications for original licenses, exemptions 
and also capacity additions at existing facilities. In my state of 
Alaska alone, work is proceeding on a 600+ MW new hydropower project. 
And these statistics do not even include pumped storage, which would 
double or triple these numbers.
    Answer. The IEA World Energy Outlook 2011 (WEO) has three main 
scenarios: the Current Policies Scenario (CPS), the New Policies 
Scenario (NPS) and the 450 Scenario (450). In each of these scenarios, 
by 2035 the WEO sees hydro output growing from 3252 TWh in 2009: to 
5144 TWh (CPS), 5518 TWh (NPS) or 6052 TWh (450) at a global level. For 
the USA, the output is 276 TWh (2009), and for 2035 the expected 
numbers are 303 TWh (CPS), 306 TWh (NPS) and 310 TWh (450).
    By 2035, world hydro generating capacities would increase from 1007 
GW (2009) to 1509 GW (CPS), 1629 GW (NPS), or 1803 GW (450). Hydro 
power capacities in the USA would increase from 101 GW (2009) to 113 GW 
(CPS), 114 GW (NPS) or 115 GW (450).
    The IEA is currently in the midst of preparing an even deeper 
analysis than appears in the WEO. While full results of this analysis 
are not yet ready, we can already say that we expect significantly 
stronger growth for pumped-hydro power plants (providing storage, not 
additional energy) than for traditional hydro power.
    Question 3b. How does the EIA reporting square with these on-the-
ground numbers? Is the EIA re-examining the NEMS model and other data 
to refine and improve its hydro forecasts? And if not, why not?
    Answer. The IEA cannot speak on behalf of the US Energy Information 
Administration (EIA), its models and ongoing work. We believe the EIA 
could answer this question more appropriately.
                                 ______
                                 
      Responses of Roger Diwan to Questions from Senator Murkowski
    Question 1. Iran: I am really struck by something in your 
testimony, dealing with the potential impact of additional sanctions on 
Iran. We know that the Europeans have agreed in principal to ban 
imports of Iranian crude, but from reading your testimony, it seems 
that both Italy and Greece will find it hard to comply. Given your 
point that India, South Korea and Turkey are all increasing imports 
combined with what we know about strong Chinese demand for Iranian oil, 
what will be the practical effect of these new sanctions?
    Question 1a. How will the new European sanctions affect oil prices?
    Answer. In effect, the imposition of the EU and US financial 
sanctions were behind the sharp increase in oil prices in February and 
March. There was a strong fear that oil market will be disrupted by the 
embargo and large volumes of oil will be missed during the summer 
months when oil demand is strong. We expect that the combined US/EU 
sanctions will cause 700-800 mb/d of Iranian crude to be taken off the 
market this year. Since sanctions and potential retaliations are 
placing a large portion of the world's available liquids supply into 
doubt, precautionary stock building by Asian importers has amplifying 
the effect on prices and so far has largely negated Saudi Arabia's 
efforts to increase market liquidity. Refining turnaround in the second 
quarter, and high OPEC production is filling storage fast and oil 
markets do not show real current shortage of worldwide crude. Would 
that be the case in the third quarter when Iranian barrels are lost? 
Would the drop off anticipated and mitigated in the second quarter?
    Iranian production is quickly moving down. We estimate March output 
at 3.29 mmb/d, down from 3.49 mmb/d in January. With Iran needing to 
use its own tanker fleet to move crude to customers, additional tankers 
would have to be chartered for use in floating storage. However, 
toughened restrictions on tanker insurance by the European Union have 
left fewer (if any) tanker owners willing to engage in this business. 
As a result, we anticipate that Iran's production will simply be shut-
in. The bulk of the losses (roughly 550 mb/d) is attributed to the EU 
embargo, but cuts have or will be made by Japan, South Korea, Turkey 
and South Africa.
    Question 1b. What do you believe is the true Saudi spare capacity, 
and to the extent your answer diverges from EIA's or IEA's, please 
describe what deficiencies you see in those analyses.
    Answer. OPEC production remains at elevated levels as the GCC 
countries provide oil markets with extra liquidity at a time when more 
countries began the process of backing out Iranian import volumes in 
response to the EU embargo and US sanctions. We estimate show OPEC 
March output at 31.2 mmb/d, the highest level since the summer of 2008, 
led by a boost in Saudi production now reaching 9.9 million b/d.
    The Saudis are concerned about high prices destroying demand and 
ultimately cutting the need for their main export commodity. As such, 
Saudi Aramco will do everything it can to keep markets supplied (and we 
do not dispute the company's stated 12.5 mmb/d of capacity). But as 
spare capacity continues to decline over the summer (both because of 
its replacement of Iranian supplies and Saudi Arabia's own summer 
requirements for power generation), market concern over a narrowing 
global supply cushion will become more acute. Indeed, unused Saudi 
production capacity has been trending downward since the Libyan outage, 
from a comfortable 4.0 mmb/d to around 2.5 mmb/d today. That is not 
reassuring in a 90 mmb/d global oil market.
    However, one risk that cannot be mitigated is the perception of 
dwindling spare capacity: with every additional barrel of crude that 
Saudi Arabia will produce to replace missing Iranian barrels, spare 
capacity in the Kingdom declines. This perversely heightens concerns 
about future supply availability and contributes to the risk premium 
currently embedded in prices. That element of the price premium is 
likely to stay alive even if no disruption in physical markets is felt 
on July 1st.
    Question 2. You mention in your testimony that ``non-OPEC supply 
growth continued to disappoint in 2011.'' How does this reconcile with 
the major growth we have seen in U.S. onshore production of both oil & 
gas, particularly from shale plays?
    Answer. The major growth occurring in the US onshore production of 
oil & gas has been counterbalanced by decreases in production in the 
rest of non-OPEC producing countries as well as disruptions in supply 
elsewhere. Decreases in production from South Sudan, Syria, the North 
Sea, as well as minor decreases in Colombia, Russia, and China 
overshadowed the North American growth in 2011. The simultaneous supply 
disruptions in Yemen, Syria, and South Sudan and Sudan while fears of 
the impact of the EU embargo on Iranian oil production stated to start 
on July 1st has had a real effect on crude markets. This effect is 
right now muted as oil markets as well supplied by OPEC, and demand for 
crude are at its seasonal nadir. However, a close look at the data 
shows that the Sudanese conflict has removed over 200,000 b/d in the 
last three months, and the cumulative loss is now over 600,000 b/d and 
expected to last through 2012.
    Question 3. Your testimony indicates that the U.S. will lead the 
growth in global liquids in 2012, owing to a rise in shale oil output 
from the Bakken and the Eagle Ford plays. Please discuss the several 
other shale areas that are just starting to be drilled, and what you 
expect in terms of production from those new plays?
    Will these new supplies coming have an impact on the amount of oil 
that we import from OPEC countries?
    You mentioned that in September, gas liquids production reached an 
all-time high. Do You expect that this level of production is a trend 
that will continue?
    Answer. Within the next ten years, crude production is expected to 
grow significantly, carried mainly by the Bakken and Eagle Ford plays. 
Moreover, other plays will be coming online or be further developed to 
add to the growth. These plays include mainly the revival of the 
Permian basin, the Utica, the Niobrara and the Monterey. The chart 
below shows our expectations for production from shale oil in the next 
decade.
    The new domestic supplies will have an effect on imports of OPEC 
crude. By 2020, oil imports will be just 40% of demand, and when 
including ``Safe'' Canadian crude imports, dependence outside North 
America will drop to below 25%. However crude import demand from OPEC 
and other countries will continue to a certain extent, so while volume 
risk from such countries is diminished, price risk remains. The 
following graph* shows North America's net crude imports throughout the 
next decade.
---------------------------------------------------------------------------
    * All graphs have been retained in committee files.
---------------------------------------------------------------------------
    The increased production of gas liquids is expected to carry on 
throughout the decade. The upward trend is likely to be maintained and 
gas liquid production will increase steadily as a result of growing 
production from the Marcellus, the Utica and the Eagle Ford. The 
following graph shows our expectations for gas liquids trends.
    Question 4. You also mention that Canada will be a leader for 
liquids growth in 2012. Could you discuss the effect of the Keystone XL 
pipeline delay and/or rejection relative to this projection? Please 
explain whether you believe this will have an impact on Canadian 
production, or if you expect the Canadians to proceed ``full steam 
ahead'' without it.
    Answer. Canadian oil production will be rising fast in the next 
decade. There has been jockeying between the different pipeline 
companies to ensure that they gain market share as more oil would need 
to move to the US. Existing pipeline capacity will allow to carry all 
the incremental Canadian crude production until 2016 or even 2017, and 
it would mostly benefit the incumbent companies that have already the 
infrastructure in place. We will need more pipeline capacity by 2017, 
and a number of projects are competing for signing up volumes to 
transport. Keystone XL is one of them. This project had the advantage 
of trying to resolve two bottlenecks (Bakken and Canada) in one 
project, but the same result could be achieved with other options, 
including by separating the two issues: a pipeline from the Bakken 
through the Midcontinent, and added capacity from Canada to the US.
    We don't believe that lack of pipeline capacity at this tstage if 
slowing Canadian developments. A bigger danger down the road would be 
the shear amount of US crude production filling the US system and 
limiting the room for Canadian production in US refineries if neither 
countries can export crude out of the Gulf Coast.
    Question 5. Your testimony indicates that Iraq's production levels 
will remain one of the key supply uncertainties over the next year and 
a half, and pointed to deteriorating security conditions on the ground. 
Can you explain what factors are driving this and to what extent is 
Iran playing a role?
    Answer. Prospects for rising Iraqi oil production are being 
undermined by a series of challenges which are hampering operators' 
ability to achieve contracted output targets. On the political front, 
continued infighting between rival factions and a lack of coherent 
institutional framework has severely hampered effective, strategic 
decision-making. It is also delaying the development of critical 
onshore infrastructure which PFC Energy sees as the key determinant of 
production levels in the future. Bottlenecks around critical pumping 
stations have already effectively capped production in southern Iraq, 
with an estimated 100-200 mb/d shut in at times in 2011; this figure 
will rise as first licensing round investors ramp up production in the 
short term. But PFC Energy sees ongoing risks to production from mid-
stream related problems over the next decade, as infrastructure 
expansion fails to keep pace with proposed production increases due to 
a lack of government institutional capacity, delays of tenders and 
awards, and uncertainty surrounding government funding for pipeline and 
export plans.
    On the level of security on the ground, Iraq has been witnessing 
increased risks, stemming mainly from Prime Minister Maliki's stances. 
His move against senior Iraqiyya faction leaders is indicative of his 
determination to consolidate his power now that US troops have left 
Iraq. Maliki's gambit is extremely high risk, and offers little room 
for compromise should he fail to consolidate his power at the expense 
of his rivals. He has betrayed what little trust remained between the 
different factions. Maliki's position will make him more dependent on 
the Islamist Shia Iraqi National Alliance--especially the Sadrists--and 
on Iran. He is unlikely to make a deal with the Kurds, largely because 
their agendas on federalism are incompatible. The risk of protracted 
communal violence has grown significantly, not just between the Sunnis 
and Shia. If the Kurds overplay their hand, especially by seeking to 
move aggressively in disputed territories, they could open up an 
additional front. Oil and gas infrastructure in the south will be a 
tempting target for Maliki's foes.
    Question 6. Given recent focus on the potential impact of the 
Iranians closing the Strait of Hormuz, could Irans' activities in Iraq, 
particularly as relates to Basra, have a greater impact on global 
supplies?
    Answer. Iran, through some of its proxy could impact Iraqi 
production, and if sustained, these disruptions can certainly impact 
prices as Saudi Spare capacity is running thin.
    Question 7. In your testimony, you indicate that inadequate 
pipeline capacity combined with further reductions in refining capacity 
planned for the East Coast will lead to higher gasoline prices over the 
next year. Can you summarize key drivers causing these refinery 
closures and share your view of how both of these factors, particularly 
with reference to Keystone XL delay and/or rejection, might impact 
gasoline prices over the near to medium term?
    Answer. In 4Q11, two Philadelphia-area refineries, Sunoco's Marcus 
Hook and ConocoPhillips' Trainer facilities, were indefinitely idled. A 
third refinery, Hovensa, located in the US Virgin Islands but a major 
supplier to the East Coast, was shuttered in early-2012. The closure of 
these three refineries, which produced more than 260 mb/d of motor 
gasoline last year, was blamed for the sharp rise in Mid-Atlantic 
gasoline prices this year. In reality, despite the closure of such a 
large portion of regional refining capacity (these three facilities 
collectively accounted for nearly 40% of the gasoline produced in PADD 
1), Mid-Atlantic gasoline prices have not meaningfully deviated from 
those in the rest of the Atlantic Basin.
    The limited impact on regional gasoline prices demonstrates that 
external supplies typically undercut local PADD 1 refinery production. 
If these shuttered facilities were more competitive, the loss of their 
supply would have caused a spike in East Coast gasoline spot prices and 
a divergence from Gulf Coast and Midwest markets. However, New York 
Harbor prices are actually set more by supply from the Gulf Coast and 
(to a lesser extent) European imports. PADD 3 refineries, which 
supplied some 58% of East Coast gasoline demand, are more sophisticated 
and benefit from lower operating costs, greater economies of scale, and 
cheaper crude inputs. Put another way, the NYH gasoline price is often 
cheaper than the breakeven price for many East Coast refineries, which 
is why these facilities are being shuttered in the first place. It is 
also why the loss of these locally-produced volumes has not influenced 
the NYH price so far. Any incremental volumes needed to fill the supply 
gap, whether sourced from PADD 3 or Europe, have a lower price than the 
erstwhile production from these three shuttered refineries.
    Of course, supply/demand factors have also contributed to the lack 
of relative movement in the NYH gasoline price. The closing of these 
three refineries has coincided with the seasonal low point in East 
Coast (and the broader Atlantic Basin) gasoline demand. PADD 1 
consumption during the first nine months of 2011 averaged some 3,150 
mb/d; since then, demand has averaged closer to 3,030, including less 
than 3,000 mb/d in January 2012. This demand destruction alone accounts 
for a large chunk of the 260 mb/d in "lost" supply from Trainer, Marcus 
Hook, and Hovensa. At the same time, PBF Energy's Delaware City 
refinery, closed since late-2009, resumed normal operations in October 
2011, adding as much as 90 mb/d to the East Coast gasoline supply. 
Thus, we believe that the ``extra'' volume of gasoline that must now be 
sourced externally (whether from PADD 3 or abroad) only amounts to 
around 2% of total regional demand, certainly not enough to change the 
price setting dynamics of PADD1.
    The adoption or rejection of the Keystone XL pipeline will have no 
impact whatsoever on gasoline prices on the east coast in the next few 
years. Many more factors will impact prices, but this one certainly 
not.
    Question 8. EIA reports consistently show little to no growth in 
the hydropower sector. In 2008, the EIA testified before Congress that 
the Annual Energy Outlook (AEO) forecasts less than 1 GW of new 
hydropower capacity to be added by 2030. In the 2011 AEO, hydropower is 
not even included in the discussion with the forecasts for other 
renewable technologies and the report shows an annual growth rate of 
only 0.1 percent in net summer capacity through 2035.
    a. Do you believe that the EIA modeling is accurately reflecting 
the hydropower sector? In 2011 alone, FERC received approximately 610 
MW of conventional hydropower applications for original licenses, 
exemptions and also capacity additions at existing facilities. In my 
state of Alaska alone, work is proceeding on a 600+ MW new hydropower 
project. And these statistics do not even include pumped storage, which 
would double or triple these numbers.
    b. How does the EIA reporting square with these on-the-ground 
numbers? Is the EIA re-examining the NEMS model and other data to 
refine and improve its hydro forecasts? And if not, why not?
    Answer. I am not qualified to answer this question since I am not 
an expert on the Hydropower sector.
    Question 9. EIA reports consistently show little to no growth in 
the hydropower sector. In 2008, the EIA testified before Congress that 
the Annual Energy Outlook (AEO) forecasts less than 1 GW of new 
hydropower capacity to be added by 2030. In the 2011 AEO, hydropower is 
not even included in the discussion with the forecasts for other 
renewable technologies and the report shows an annual growth rate of 
only 0.1 percent in net summer capacity through 2035. a. Do you believe 
that the EIA modeling is accurately reflecting the hydropower sector? 
In 2011 alone, FERC received approximately 610 MW of conventional 
hydropower applications for original licenses, exemptions and also 
capacity additions at existing facilities. In my state of Alaska alone, 
work is proceeding on a 600+ MW new hydropower project. And these 
statistics do not even include pumped storage, which would double or 
triple these numbers. b. How does the EIA reporting square with these 
on-the-ground numbers? Is the EIA re-examining the NEMS model and other 
data to refine and improve its hydro forecasts? And if not, why not?
                                 ______
                                 
   Responses of Howard Gruenspecht to Question From Senator Cantwell
    Question 1a. Historical vs. Future Coal Prices: According to Energy 
Information Administration (EIA) data (Annual Energy Review 2011, Table 
7.9), coal prices in the United States rose by more than 5 percent 
annually, on average-- from $18.93 to $32.2 per ton-- between 2000 and 
2010. The EIA's Annual Energy Outlook 2012 Early Release projects 
rising U.S. coal production and exports, but average annual coal price 
increases of just 0.9 percent over the period 2009-2035.
    In EIA's analysis, what factors contribute to this significant 
departure from historical trends in coal prices?
    Answer. The key reason coal prices do not continue to rise as 
rapidly in our projections as they have in recent years is that we 
assume that the coal mining productivity will not continue to decline 
as rapidly as it has in recent years. The sharp increase in coal prices 
from 2000 to 2010 was due to many factors, including declines in coal 
mining productivity and the rising costs of mine equipment, parts and 
supplies, fuel prices, explosives, and, more recently, labor. Between 
2000 and 2010, U.S. coal mining productivity declined at an average 
rate of 2.3 percent per year. However, the recent trend of increasing 
coal prices and declining coal mining productivity is a departure from 
longer term trends in the industry. For example, from 1980 through 2000 
average U.S. coal prices declined 4.5 percent per year in inflation 
adjusted dollars, and coal mining productivity increased 6.2 percent 
per year. We take account of both the short- and long-term productivity 
trends in the industry when preparing our long-term projections. As a 
result, in the Annual Energy Outlook 2012 Early Release Reference case 
we assume that coal mining productivity continues to decline, but only 
1.3 percent per year, just over half the rate of decline seen over the 
last five to ten years. In the full Annual Energy Outlook to be 
released in the spring of 2012, we will include a sensitivity analysis 
that examines the impacts of alternative assumptions about coal mining 
productivity.
    Question 1b. Historical vs. Future Coal Prices: According to Energy 
Information Administration (EIA) data (Annual Energy Review 2011, Table 
7.9), coal prices in the United States rose by more than 5 percent 
annually, on average--from $18.93 to $32.2 per ton-- between 2000 and 
2010. The EIA's Annual Energy Outlook 2012 Early Release projects 
rising U.S. coal production and exports, but average annual coal price 
increases of just 0.9 percent over the period 2009-2035.
    Would environmental regulations that effectively limit U.S. coal 
use to relatively cleaner supplies be likely to increase future coal 
prices?
    Answer. Without details on the environmental regulations envisioned 
it is difficult to assess their potential impact on coal prices. 
Generally, regulations that reduce the supply of usable coal would lead 
to higher coal prices for power plants and other consumers, but the 
size of the increase would depend on the specifics of the regulations. 
Conversely, regulations that would lower the demand (i.e., restrictions 
on power plant use of coal) would decrease the price of coal.
    Question 2a. Baseline Projection: In an investment analysis 
published one year ago (http://www.anga.us/media/180381/
deutsche%20report-%20nov%202010.pdf), Deutsche Bank concluded that coal 
use for electricity production in the United States is likely to 
decline significantly in coming decades--from 47 percent in 2009 to 22 
percent in 2030. Several factors contribute to coal's decline, 
including capital cost increases relative to gas, retirement of aging 
plants, increasingly stringent regulation of criteria pollutants, 
rising ash disposal costs, and financial barriers due to the regulatory 
uncertainty associated with greenhouse gas emissions. In contrast, 
EIA's Annual Energy Outlook 2012 Early Release projects that U.S. 
aggregate coal use will continue to rise and that coal will still 
account for 39 percent of U.S. electricity production in 2035. Does EIA 
believe the Deutsche Bank analysis is credible? If not, please explain 
the stark differences between its conclusions and those of EIA.
    Answer. The Deutsche Bank report Natural Gas and Renewables, A 
Secure Low Carbon Energy Plan for the United States (November 2010), 
provides an analysis that is driven by a policy-oriented initiative, 
specifically the identification of a low cost solution for achieving a 
17-percent reduction in overall U.S. greenhouse gas (GHG) emissions by 
2020 and an 83-percent reduction by 2050 relative to the 2005 level. A 
statement to this effect is made at the beginning of their ``Key 
Research Findings'' section on page 8 of their report. Those policy 
goals were not represented in the Annual Energy Outlook 2012 (AEO2012) 
Early Release.
    In addition, it appears that some of the assumptions used for 
Deutsche Bank's analysis may vary substantially from those used by EIA 
for the AEO2012 Early Release. For example, in their analyses Deutsche 
Bank indicates that natural gas prices will remain in a range of $4.00 
to $8.00 per million Btu in nominal dollars, with perhaps $6.00 being 
their primary natural gas prices assumption. In the AEO2012 Early 
Release, the nominal price of natural gas at Henry Hub increases from 
$4.39 per million Btu in 2010 to $8.98 per million Btu in 2030 and to 
$11.48 per million Btu in 2035. Another important difference between 
Deutsche Bank's analysis and EIA's AEO2012 Early Release is the outlook 
for electricity demand, with Deutsche Bank projecting average 
electricity demand to increase by 0.5 percent per year between 2009 and 
2030 and EIA projecting growth of 1.0 percent per year for this same 
time period.
    In the area of coal-fired generating capacity retirements, Deutsche 
bank projects 152 gigawatts of capacity retirements (most likely 
nameplate) by 2030, which is considerably higher than the amount of net 
summer coal-fired capacity retirements projected in the AEO2012 Early 
Release during the years 2011 through 2030. In the Deutsche Bank 
report, the authors indicate that the costs of some environmental rules 
not represented in EIA's AEO2012 Early Release, such as the EPA's 
recently finalized Mercury and Air Toxics Standards (MATS) and 
forthcoming EPA rules on cooling water intake and ash disposal were 
represented in their analyses. EIA plans to represent the new MATS rule 
in the updated AEO2012 Reference case scheduled for publication later 
this year. In our preliminary modeling runs, the representation of the 
MATS rule does result in some additional retirements of coal-fired 
generating capacity.
    Question 2b. Baseline Projection: In an investment analysis 
published one year ago (http://www.anga.us/media/180381/
deutsche%20report-%20nov%202010.pdf), Deutsche Bank concluded that coal 
use for electricity production in the United States is likely to 
decline significantly in coming decades-- from 47 percent in 2009 to 22 
percent in 2030. Several factors contribute to coal's decline, 
including capital cost increases relative to gas, retirement of aging 
plants, increasingly stringent regulation of criteria pollutants, 
rising ash disposal costs, and financial barriers due to the regulatory 
uncertainty associated with greenhouse gas emissions. In contrast, 
EIA's Annual Energy Outlook 2012 Early Release projects that U.S. 
aggregate coal use will continue to rise and that coal will still 
account for 39 percent of U.S. electricity production in 2035.
    Does EIA concur with the broad consensus that anticipated plant 
retirements, increasing regulatory obligations, and higher hurdles to 
capital finance for new coal plants will have a profound impact on U.S. 
coal consumption?
    Answer. While the factors listed above certainly affect the outlook 
for coal consumption, many other factors also influence the outlook for 
coal consumption. Forecasts of changes in laws and regulations which 
are not reflected in EIA's Reference case but may be included in some 
projections that are part of the ``broad consensus'' cited in the 
question can significantly affect future U.S. coal consumption. Other 
factors such as slow electricity demand growth, competitive natural gas 
prices, increased competition from renewable energy sources, and rising 
cost estimates for new coal-fired generating capacity are also key 
drivers affecting projected coal consumption.
    Question 2c. Baseline Projection: In an investment analysis 
published one year ago (http://www.anga.us/media/180381/
deutsche%20report-%20nov%202010.pdf), Deutsche Bank concluded that coal 
use for electricity production in the United States is likely to 
decline significantly in coming decades--from 47 percent in 2009 to 22 
percent in 2030. Several factors contribute to coal's decline, 
including capital cost increases relative to gas, retirement of aging 
plants, increasingly stringent regulation of criteria pollutants, 
rising ash disposal costs, and financial barriers due to the regulatory 
uncertainty associated with greenhouse gas emissions. In contrast, 
EIA's Annual Energy Outlook 2012 Early Release projects that U.S. 
aggregate coal use will continue to rise and that coal will still 
account for 39 percent of U.S. electricity production in 2035.
    If EIA does agree with the consensus of plant retirements, 
increasing regulatory obligations, and higher hurdles to capital 
finance for new coal plants, what is driving future increases in U.S. 
coal consumption in EIA's modeling and analysis?
    Answer. In the AEO2012 Early Release Reference case, increasing 
demand for electricity leads to increased generation from all fuels, 
except petroleum. Between 2010 and 2035, EIA projects an overall 
increase in U.S. electricity generation of 928 billion kilowatt-hours. 
By fuel, increased generation from natural gas-fired power plants 
account for 42 percent of this increase, renewables account for 39 
percent, coal accounts for 11 percent, and nuclear accounts for 9 
percent. The increase in coal generation comes mainly from increasing 
output from existing coal plants in the later years of the projections 
as natural gas prices begin to increase.
    Question 2d. Baseline Projection: In an investment analysis 
published one year ago (http://www.anga.us/media/180381/
deutsche%20report-%20nov%202010.pdf), Deutsche Bank concluded that coal 
use for electricity production in the United States is likely to 
decline significantly in coming decades--from 47 percent in 2009 to 22 
percent in 2030. Several factors contribute to coal's decline, 
including capital cost increases relative to gas, retirement of aging 
plants, increasingly stringent regulation of criteria pollutants, 
rising ash disposal costs, and financial barriers due to the regulatory 
uncertainty associated with greenhouse gas emissions. In contrast, 
EIA's Annual Energy Outlook 2012 Early Release projects that U.S. 
aggregate coal use will continue to rise and that coal will still 
account for 39 percent of U.S. electricity production in 2035.
    Does EIA work with financial analysts to try to incorporate what 
the private sector predicts will happen to coal usage?
    Answer. EIA considers a wide range of information in formulating 
its projections. In the course of developing our Annual Energy Outlook 
each year, we meet with a wide array of interested groups and analysts 
to discuss assumptions we plan to make, proposed model changes and 
review preliminary results. EIA staff and management also participate 
actively in public meetings and conferences where these issues are 
discussed by analysts from the private sector and non-governmental 
organizations. They also keep up with relevant literature from all 
sources.
    Many private sector analyses incorporate assumptions about policy 
changes that have yet to occur, that are not included in EIA 
projections. EIA's Reference case projections assume continuation of 
current laws and regulations. For example, the Deutsche Bank study 
referred to in an earlier question appears to assume a GHG policy 
objective as a basis for their projections of the U.S. electricity 
market, something that is not included in EIA's Reference case 
analyses.
    Question 3a. Effects of Coal Exports: The 2011 Annual Energy 
Outlook shows U.S. exports of coal increasing annually by 1.8%, from 
1.51 quadrillion Btu in 2009 to 3.24 quadrillion Btu in 2035. In 
contrast, U.S. production of coal is only projected to increase by 0.3% 
annually, from 21.63 quadrillion Btu in 2009 to 23.51 quadrillion Btu 
in 2035. This suggests that exports will account for over 13 percent of 
coal production by 2035.
    Could coal prices increase substantially more than projected if 
world demand increases faster than expected? If exports were to 
increase annually at twice the projected rate such that 20% of U.S. 
coal production was exported by 2035, roughly in what range would coal 
prices be?
    Answer. Increased exports of U.S. coal could lead to higher U.S. 
coal prices, depending on a number of factors including the 
availability of other fuels and/or technologies to generate 
electricity. EIA includes a representation of the international market 
for coal trade in our analyses, but the projected increase in exports 
of coal leads to only a slight increase in regional coal prices.
    Question 3b. Effects of Coal Exports: The 2011 Annual Energy 
Outlook shows U.S. exports of coal increasing annually by 1.8 percent, 
from 1.51 quadrillion Btu in 2009 to 3.24 quadrillion Btu in 2035. In 
contrast, U.S. production of coal is only projected to increase by 0.3 
percent annually, from 21.63 quadrillion Btu in 2009 to 23.51 
quadrillion Btu in 2035. This suggests that exports will account for 
over 13 percent of coal production by 2035.
    As the rest of the world consumes an increasing percentage of U.S. 
coal, will coal act more like a fungible commodity subject to prices 
set by the world market, causing U.S. coal prices to increase? Would 
this also cause more volatility in U.S. coal prices?
    Answer. The relationship between the prices of internationally 
traded coal and domestic U.S. coal prices is not well established, so 
it is difficult to predict how future trends in international coal 
prices will affect U.S. coal prices. The swings in international coal 
prices are a relatively recent phenomenon, with generally flat to 
declining trends in inflation adjusted prices prevailing from the 
1980's through the early 2000's.
    In general, there are two distinct markets for international coal 
trade: one representing steam or thermal coal primarily for electricity 
generation and a second market representing coking coal used in the 
manufacture steel. In terms of thermal coal markets, it is difficult to 
see a strong relationship between international and U.S. domestic coal 
prices at this time because the share of U.S. steam coal exported is so 
small. In the AEO2012 Early Release, U.S. exports of steam coal rise 
from 26 million short tons in 2010 to 51 million short tons in 2035, or 
3 percent and 5 percent of overall U.S. thermal coal production, 
respectively.
    In contrast, there does appear to be a relatively strong 
relationship between the international and domestic prices for coking 
coal. However, for this market the export share of total U.S. coking 
coal production is much higher, amounting to 74 percent in 2010 and 
rising to 85 percent in 2035. Also, while U.S. steam coal faces 
substantial competition from other fuels such as natural gas, 
renewables, and nuclear for electricity generation, substitutions for 
coking coal in steelmaking are more limited.
    Question 4a. Regulations and the Cost of Coal: In 2011 the 
Environmental Protection Agency (EPA) issued a number of new rules. As 
these policies go into effect, the price of coal-fired generation is 
expected to rise. The National Research Council's 2010 report ``The 
Hidden Costs of Energy'' showed that the average additional cost of 
coal generation due to emissions of SO2, NOX, and 
particulate matter was 3.2 cents per kilowatt-hour in 2005 and will 
decrease to roughly 1.7 cents per kilowatt-hour by 2030.
    To what extent are these externalities incorporated into EIA's 
models? How do the costs of reducing these emissions from recent 
regulations compare?
    Answer. It is our understanding that the additional costs per 
kilowatthour that the National Resource Council (NRC) calculated for 
emissions of SO2, NOx, and particulates from coal-fired generating 
capacity refer to the cost of externalities such as the impact on 
health, environment, and security. These types of non-market costs are 
not accounted for in EIA's models because they do not generally enter 
into the dispatch decisions of electric systems operators. We do 
explicitly represent the capital and operating costs associated with 
meeting new environmental regulations, but those are not directly 
comparable to the non-market costs discussed in the NRC report cited in 
the question.
    Question 4b. Regulations and the Cost of Coal: In 2011 the 
Environmental Protection Agency (EPA) issued a number of new rules. As 
these policies go into effect, the price of coal-fired generation is 
expected to rise. The National Research Council's 2010 report ``The 
Hidden Costs of Energy'' showed that the average additional cost of 
coal generation due to emissions of SO2, NOX, and 
particulate matter was 3.2 cents per kilowatt-hour in 2005 and will 
decrease to roughly 1.7 cents per kilowatt-hour by 2030.
    If the additional cost of coal generation estimated by the NRC were 
included in EIA's modeling how would that change the estimate for 
future coal consumption and the price through 2035?
    Answer. Estimating the value of externalities is very difficult and 
often subjective. Externalities exist for the use of most fuel types, 
including natural gas, petroleum, and renewable fuels. EIA does not 
attempt to quantify externalities in its analyses. Generally speaking, 
inclusion of externality values reflecting social rather than private 
costs would result in higher projected electricity prices and lower 
projected coal consumption.
    Question 4c. Regulations and the Cost of Coal: In 2011 the 
Environmental Protection Agency (EPA) issued a number of new rules. As 
these policies go into effect, the price of coal-fired generation is 
expected to rise. The National Research Council's 2010 report ``The 
Hidden Costs of Energy'' showed that the average additional cost of 
coal generation due to emissions of SO2, NOX, and 
particulate matter was 3.2 cents per kilowatt-hour in 2005 and will 
decrease to roughly 1.7 cents per kilowatt-hour by 2030.
    Which regulations, in addition to the Mercury and Air Toxics 
Standards (MATS), will be included in AEO 2012? Will disposal costs due 
to coal ash regulations be included? Which Boiler MACT rule is used? 
The one finalized last year that is currently binding or the proposed 
rule issued in December?
    Answer. The Cross State Air Pollution Rule was modeled in the 
AEO2012 Early Release, but the December enactment of the MATS did not 
leave sufficient time for inclusion. The full AEO2012 to be released in 
spring will include the MATS rule by requiring that all coal plants 
install either a Flue Gas Desulfurization (FGD) scrubber or a Direct 
Sorbent Injection (DSI) system in order to continue operating beyond 
2012. The potential additional costs associated with stricter ash 
disposal requirements that have not yet been established in final 
regulations are not addressed in our Reference case projections.
    The Industrial Boiler MACT Rule was most recently proposed in 
December 2011, after our cutoff date for the AEO2012. In any event, 
EIA's Reference case generally reflects final rules, not proposed ones. 
The prior version of the Boiler MACT finalized and then stayed by EPA 
last year is also not included.
    Question 4d. Regulations and the Cost of Coal: In 2011 the 
Environmental Protection Agency (EPA) issued a number of new rules. As 
these policies go into effect, the price of coal-fired generation is 
expected to rise. The National Research Council's 2010 report ``The 
Hidden Costs of Energy'' showed that the average additional cost of 
coal generation due to emissions of SO2, NOX, and 
particulate matter was 3.2 cents per kilowatt-hour in 2005 and will 
decrease to roughly 1.7 cents per kilowatt-hour by 2030.
    Although regulations on greenhouse gas emissions are forthcoming, 
has EIA attempted to model their effect?
    Answer. EIA has not explicitly attempted analyze the impact the 
forthcoming greenhouse gas rules on new plants. In the past we have 
prepared numerous analyses of legislative proposals to curb emissions 
of greenhouse gases (GHGs) that are available on our web site.
   Responses of Howard Gruenspecht to Question From Senator Murkowski
    Question 1. You mention in your report that EIA recognizes that 
projections of energy markets over a 25-year period are highly 
uncertain and subject to many events that cannot be foreseen.
    What factors impact how these numbers move, and how easy is it to 
predict those factors?
    Answer. The number of uncertainties involved in projecting long-
term energy markets is large, and the degree to which they affect 
energy markets varies. Readers of the Annual Energy Outlook are 
cautioned that Reference case results should not be viewed in isolation 
and are encouraged to review the alternative cases included in the full 
publication. The alternative cases published in the Annual Energy 
Outlook (AEO) provide perspective on the sensitivity of energy market 
outcomes to differing assumptions in key areas. Recent energy market 
developments have strongly reinforced the aphorism, `expect the 
unexpected'.
    The list below categorizes areas of uncertainty and highlights some 
of the alternative cases that are included in each year's AEO.

   The U.S. economic environment is subject to variation in 
        business cycles and to uncertainty about the pace of long-term 
        economic growth. Low and high economic growth alternatives 
        explore the effects of varying rates of economic growth on 
        energy markets.
   Energy prices can fluctuate rapidly and are sometimes 
        influenced by developments beyond the U.S. (e.g., international 
        economic developments, oil embargos, natural disasters, other 
        supply disruptions). The AEO includes a set of alternatives 
        featuring low and high world oil prices.
   The future pace of technological change and the resulting 
        effects on energy markets may diverge from what is expected due 
        to varied success in research and development or the potential 
        for disruptive technologies. The AEO looks at the potential 
        effects of different technological paths through cases 
        profiling differing nuclear power costs and life extension 
        alternatives, differing costs for renewable energy 
        technologies, and a suite of cases highlighting a wide range of 
        assumptions about the rate of improvement in energy-using 
        technologies.
   Energy policy changes that depart from current laws or 
        regulations are not included in the AEO Reference case, 
        allowing the case to serve as a baseline for policy analysis. 
        However, a number of additional scenarios relevant to current 
        policy discussions are included in the AEO.
   Exploration and production often leads to changes in 
        estimates of resource availability and/or drilling productivity 
        and cost. The AEO includes alternatives with differing 
        assumptions for oil and gas supply to explore uncertainties in 
        this area.

    Question 2. In reviewing EIA's most recent report on the impact of 
US LNG exports on domestic energy markets, the build-out scenarios 
appear to be aggressive. Please explain your view on the likelihood of 
these various scenarios:
    a. In all 16 of EIA's scenarios, your findings about the long-term 
impact of exports appear to be somewhat minimal, but the conclusions 
about short-term impact, however, seems quite extreme. I realize that 
EIA's conclusions may be based on the export schedule it modeled, but 
could industry respond to such price increases somewhat quickly by 
producing more gas?
    b. How realistic is EIA's projected short-term price impact given 
that production will likely increase?
    Answer. The scenarios contained in the report, Effect of Increased 
Natural Gas Exports on Domestic Energy Markets, were specified by DOE's 
Office of Fossil Energy. EIA has not performed an analysis of the 
likelihood of these LNG export scenarios. The Office of Fossil Energy 
has indicated that these scenarios were specified to capture a wide 
range of possible outcomes. The shorter-term rapid increase in prices 
shown in the report largely reflects expected increases in production 
costs due to the production of more natural gas, which occurs 
relatively quickly. Domestic production increases, on average, from 4 
to 12 percent when exports are added. Production costs increase due to 
the increased demand for equipment (e.g., rigs) and labor to support 
the necessary drilling, as well as for lease rights.
    The shorter-term rapid increase in prices shown in the report 
largely reflects increases in production costs due to the production of 
more natural gas, which occurs relatively quickly. Domestic production 
increases on average from 4 to 12 percent when exports are added. 
Production costs increase due to the increased demand for equipment 
(e.g., rigs) and labor to support the necessary drilling, as well as 
lease rights.
    The projected price impacts associated with the additional exports 
in the scenarios specified by the Office of Fossil Energy for the study 
already reflect the expectation of higher natural gas production. 
Factors that accelerate the need to produce greater volumes will cause 
prices to rise faster than in the Reference case.
    In reviewing EIA's most recent report on the impact of US LNG 
exports on domestic energy markets, the build-out scenarios appear to 
be aggressive. Please explain your view on the likelihood of these 
various scenarios:
    c. Has Alaska's history of natural gas export significantly 
impacted Lower 48 natural gas prices?
    d. If Alaska were to significantly increase its natural gas 
exports, to the order of 4 bcf/day, would EIA forecast any significant 
impact on Lower 48 natural gas prices?
    Answer. The scenarios contained in the report, Effect of Increased 
Natural Gas Exports on Domestic Energy Markets, were specified by DOE's 
Office of Fossil Energy. EIA has not performed an analysis of the 
likelihood of these LNG export scenarios. The Office of Fossil Energy 
has indicated that these scenarios were specified to capture a wide 
range of possible outcomes. The shorter-term rapid increase in prices 
shown in the report largely reflects expected increases in production 
costs due to the production of more natural gas, which occurs 
relatively quickly. Domestic production increases, on average, from 4 
to 12 percent when exports are added. Production costs increase due to 
the increased demand for equipment (e.g., rigs) and labor to support 
the necessary drilling, as well as for lease rights.
    The Alaska and Lower 48 natural gas markets have not been 
historically linked. Over the years, proposals have been developed for 
building a pipeline to supply natural gas to the Lower 48 from Alaska. 
However, this pipeline is not projected by the EIA to be built before 
2035 under Reference case conditions (although it is viable under some 
side cases with higher prices in the Lower 48 States).
    EIA has not assessed the economic viability of transporting LNG 
from Alaska to international markets or the Lower 48 States markets via 
tanker. Shipment of LNG from the Alaska North Slope may pose 
significant logistical challenges in terms of tanker access. With the 
construction of a West Coast liquefaction terminal or with the eventual 
widening of the Panama Canal, it is possible that exports out of Alaska 
could compete with Lower 48 LNG exports in Asian markets and thus have 
an indirect (and likely limited) impact on Lower 48 prices.
    Question 3. Earlier this week, EIA announced that some of the most 
important data in the latest Annual Energy Review may be flawed and 
would need to be revised. Do you know the source of that potential 
error, and how long it may take to correct if the data is indeed 
inaccurate?
    Answer. We discovered after publication of the Annual Energy Review 
2010, that the data in Table 1.14, Fossil Fuel Production on Federally 
Administered Lands, was incomplete. In reviewing the data, EIA 
identified the underreporting and, in consultation with the Office of 
Natural Resource Revenues (ONRR) of the Department of the Interior 
(DOI), identified further data limitations.

   The fossil fuel volumes are sales and not production. The 
        data sources are the Form 2014 and the Solid Mineral Production 
        and Royalty Report, which collect information on sales of 
        fossil fuels produced on federal leases. The distinction of 
        sales and production is important because sales exclude 
        production such as lease use and storage volumes. Sales volumes 
        are a lower bound on actual production.
   The fossil fuel volumes are assigned to the year in which 
        the royalty was paid and not the year the sale took place. For 
        example, if a sale took place in 2007, but ONRR received the 
        royalty payment in 2010, the volume is included in the total 
        sales in 2010.
   The reported sales volumes are on a fiscal year (FY) and not 
        a calendar year basis. For example, FY 2009 covers the period 
        from October 1, 2008 through September 30, 2009.
   EIA had been using the ONRR source due to the difficulty of 
        obtaining data for onshore federal lands. EIA has been 
        reporting offshore production data in its petroleum navigator 
        and will continue working with ONRR to improve the reporting of 
        the production data for onshore federal lands for the year in 
        which production occurred and on a calendar year basis as with 
        the rest of the production data.

    EIA has worked with ONRR to obtain a complete set of data to update 
and revise the table. A report entitled Sales of Fossil Fuels Produced 
from Federal and Indian Lands, FY 2003 through FY 2011 was published on 
March 14, 2012. We have also confirmed that the reporting problem that 
is corrected in the new report was isolated to Table 1.14 in the AER 
and does not affect any other tables in the AER or any other EIA 
analyses.
    Question 4. Last year, Administrator Newell testified with regard 
to Keystone XL that ``Whether or not that pipeline exists, one question 
is whether or not the oil would be produced. That is one question. That 
study seemed to suggest that it would be produced regardless of whether 
there was a pipeline, and it would likely be exported to the west, to 
Asia, as opposed to south to the United States.'' Does EIA still agree 
with each part of that assessment?
    Answer. In his testimony last year, Administrator Newell was 
referring to a study performed for DOE rather than an EIA analysis. 
However, EIA's Annual Energy Outlook and International Energy Outlook 
both consider the global balance between liquid fuels supply and 
demand. In both of those publications, the world oil price is the key 
determinant of the level of unconventional liquids production, 
including production from Canada's oil/tar sands resource. At Reference 
case oil prices used in recent editions of these publications, 
production of this resource is expected to increase substantially.
    Question 5. In the early release of the latest Annual Energy 
Outlook, EIA projects that biofuels usage will continue to increase in 
the United States through 2035--but only offset roughly 600,000 barrels 
of liquid fuel demand.
    a. How much biofuel does EIA project we will be using in 2035, on a 
gallons-per-year basis?
    b. To what extent does EIA project the mandates within the 
Renewable Fuel Standard will be met? Do you still project a substantial 
shortfall of cellulosic biofuel?
    Answer. EIA projects in the AEO2012 Early Release Reference case 
that 38.3 billion gallons of renewable biofuel will be consumed in 
2035. The 600,000 barrels per day (9.2 billion gallons) refers to a 
statement in the report which says, ``In the AEO2012 Reference case, 
some of the demand for biofuel, which in 2035 is projected to displace 
more than 600 thousand barrels per day of demand for other liquid 
fuels, is as a direct replacement for diesel and gasoline'', (AEO2012 
Early Release Overview, p.6.). This refers to biofuels that can be used 
directly (unblended) in vehicles (e.g., biomass-to-liquids and 
renewable diesel) as opposed to the majority of biofuels that are 
blended with petroleum first (e.g., ethanol and biodiesel).
    EIA projects that the cellulosic biofuel standard will require 
repeated annual waivers until it can be administratively modified in 
2016. The AEO2012 early release projects that the 16 billion gallons 
target for cellulosic biofuels established under the renewable fuels 
standard provisions of the Energy Independence and Security Act of 2007 
will be reached sometime after 2030.
    Question 6. EIA reports consistently show little to no growth in 
the hydropower sector. In 2008, the EIA testified before Congress that 
the Annual Energy Outlook (AEO) forecasts less than 1 GW of new 
hydropower capacity to be added by 2030. In the 2011 AEO, hydropower is 
not even included in the discussion with the forecasts for other 
renewable technologies and the report shows an annual growth rate of 
only 0.1 percent in net summer capacity through 2035.
    a. Do you believe that the EIA modeling is accurately reflecting 
the hydropower sector? In 2011 alone, FERC received approximately 610 
MW of conventional hydropower applications for original licenses, 
exemptions and also capacity additions at existing facilities. In my 
state of Alaska alone, work is proceeding on a 600+ MW new hydropower 
project. And these statistics do not even include pumped storage, which 
would double or triple these numbers.
    b. How does the EIA reporting square with these on-the-ground 
numbers? Is the EIA re-examining the NEMS model and other data to 
refine and improve its hydro forecasts? And if not, why not?
    Answer. We believe that the EIA modeling of hydropower is 
consistent with the very slow growth in the industry that has been seen 
in recent decades. At the end of 2010, conventional hydropower capacity 
was 78,825 megawatts (MW), essentially unchanged from the 78,562 
megawatts in place in 1995. During that same time, although there were 
more than 2000 hydropower license applications, FERC only approved 82 
projects, for 555 MW of capacity. The relatively small number of 
projects approved reflects both applicants who decided not to pursue 
projects, as well as projects that FERC disapproved. While the 
breakdown of these categories is unknown, it is clear that only a small 
number of license applications lead to installed projects.
    The projected hydroelectric capacity additions in the Annual Energy 
Outlook are based on a number of factors, including expected increases 
in demand for electricity, the cost and availability of hydro 
resources, and the cost of alternative sources of generation. State and 
Federal incentives are also accounted for, to the extent possible. 
Current EIA projections show a surplus of generating capacity to meet 
near-term electricity demand, with little need for additional capacity 
of any sort through the remainder of this decade.
    EIA's projections include all reported, in-service electricity 
generators greater than 1 MW in capacity, as well as projects greater 
than 1 MW that are under construction, based on respondent-provided 
completion dates. Projects not yet under construction are not 
explicitly included in the forecast. However, additional hydroelectric 
capacity can be built within the model if it is the most economic 
alternative to satisfy electricity demand.
    EIA is not able to model the electricity markets in Alaska or 
Hawaii, which depend on energy supply resources and market dynamics 
that are unlike the inter-connected grids in the contiguous States. 
Additionally, EIA does not currently project demand for new pumped 
storage projects.
    EIA plans to re-examine and expand its assessment of the cost of 
conventional hydropower on a site-by-site basis during 2012 using 
information developed by the Idaho National Laboratory. If this work is 
completed in time, the results will be incorporated in the AEO2013.
                                 ______
                                 
     Responses of Jim Burkhard to Questions From Senator Murkowski
    Question 1. The President stated this week that the U.S. only has 
2% of the world's oil. Is that accurate? Does it tell the whole story? 
Does the 2% figure include anywhere within US lands or waters where we 
haven't drilled? How are ``reserves'' classified in the United States?
    Answer. Proved oil reserves are a broad indication of oil 
resources. But the lack of a uniform, global standard for estimating 
reserves makes comparisons across countries a challenge. Actual 
production levels are another indication of how oil resources are 
distributed around the world. In 2011, the United States was the 3rd 
largest oil producer in the world behind Saudi Arabia and Russia.
    Question 2. When a country experiences a major oilfield discovery, 
like Brazil's Tupi field or our own Prudhoe Bay, is the impact on 
global oil markets typically significant?
    Answer. Large discoveries of oil generally require many years and 
large sums of capital to develop-particularly if the discovery is in an 
area where infrastructure to ship the oil to market is undeveloped. It 
often takes many years for a discovery to have an impact on physical 
levels of oil supply.
    Question 3. IHS Global Insight recently published a report on the 
economic and employment contributions of shale gas in the U.S. Mr. 
Burkhard, under existing policy, can direct and indirect jobs in 
natural gas also contribute to paying down the national debt?
    Answer. Extraction of oil and gas in the United States has created 
many new jobs in recent years. This has been driven by growth in oil 
and gas production. For example, from 2008 to 2011 US liquids 
production increased 1.3 million barrels per day while demand fell. The 
development of oil and gas in the US has created many new jobs and 
reduced the US oil import bill.
    Question 4. EIA reports consistently show little to no growth in 
the hydropower sector. In 2008, the EIA testified before Congress that 
the Annual Energy Outlook (AEO) forecasts less than 1 GW of new 
hydropower capacity to be added by 2030. In the 2011 AEO, hydropower is 
not even included in the discussion with the forecasts for other 
renewable technologies and the report shows an annual growth rate of 
only 0.1 percent in net summer capacity through 2035.
    a. Do you believe that the EIA modeling is accurately reflecting 
the hydropower sector? In 2011 alone, FERC received approximately 610 
MW of conventional hydropower applications for original licenses, 
exemptions and also capacity additions at existing facilities. In my 
state of Alaska alone, work is proceeding on a 600+ MW new hydropower 
project. And these statistics do not even include pumped storage, which 
would double or triple these numbers.
    b. How does the EIA reporting square with these on-the-ground 
numbers? Is the EIA re-examining the NEMS model and other data to 
refine and improve its hydro forecasts? And if not, why not?
    Answer. I am not qualified to answer this question.


                            

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