[Senate Hearing 112-146]
[From the U.S. Government Publishing Office]




                                                        S. Hrg. 112-146
 
                              NATURAL GAS

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



                                HEARING

                               before the

                              COMMITTEE ON

                      ENERGY AND NATURAL RESOURCES

                          UNITED STATES SENATE

                      ONE HUNDRED TWELFTH CONGRESS

                             FIRST SESSION

                                   TO

  RECEIVE TESTIMONY ON THE RECENT REPORT OF THE MIT ENERGY INITIATIVE 
                 ENTITLED ``THE FUTURE OF NATURAL GAS''

                               __________

                             JULY 19, 2011


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




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20402-0001



               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

Biltz, George, Vice President, Energy and Climate Change, The Dow 
  Chemical Company, Midland, MI..................................    21
Bingaman, Hon. Jeff, U.S. Senator From New Mexico................     1
Gruenspecht, Howard, Acting Administrator, Energy Information 
  Administration, Department of Energy...........................     4
Moniz, Ernest J., Cecil and Ida Green Professor of Physics and 
  Engineering Systems, Director, MIT Energy Initiative, 
  Massachusetts Institute of Technology, Cambridge, MA...........     9
Murkowski, Hon. Lisa, U.S. Senator From Alaska...................     2

                               APPENDIXES
                               Appendix I

Responses to additional questions................................    57

                              Appendix II

Additional material submitted for the record.....................    69


                              NATURAL GAS

                              ----------                              


                         TUESDAY, JULY 19, 2011

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 10:35 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? Thank you all 
for being here.
    In recent years a number of factors have combined to raise 
the prominence of natural gas as a resource. Let me mention 5 
of those factors.
    The first, the new application of technologies such as 
horizontal drilling and hydraulic fracturing have led to an 
increase of domestic natural gas production and a reassessment 
of the size of the U.S. technically, recoverable resource base.
    Second, the international focus on reducing greenhouse gas 
emissions to address climate change has favored the lower 
carbon intensity of natural gas for power generation.
    A third factor is the recent tragedy in Japan at the 
Fukushima Nuclear plant that's led both the Japanese and German 
officials to speak strongly about fuel switching to natural gas 
to replace or at least supplement their remaining nuclear 
fleet.
    The fourth factor is concerns about our dependence on 
foreign oil have led some to propose switching to more use of 
natural gas in the transportation sector in our cars and trucks 
and as a substitute for diesel fuel.
    The fifth factor is that proponents of domestic 
manufacturing have argued that a larger, more stable gas supply 
at competitive prices will lead to a resurgence of investment 
in manufacturing and job creation which is very much desired 
by, I believe, all of us.
    So in the past several years there's been an increase in 
the estimates of natural gas resources available at relatively 
low prices leading many experts to suggest that we may now be 
entering a ``golden age of gas.'' I'll leave the specifics of 
those projections to our witnesses. But in general I think 
there is agreement that there's a greatly expanded, 
unconventional gas resource available domestically with 
potentially 100 years or more in gas available if current rates 
of usage are maintained. This change in the resource base has 
already had significant impacts on investment decisions in the 
power sector, in manufacturing and in transportation and many 
expect that it will continue to have an impact on 
decisionmaking in these and other areas in the future.
    There are many reasons to be optimistic about the natural 
gas resource that has recently been discovered. But recent 
history suggests we should be cautious as well. During the 
1990s, for example, projections of a high supply of natural gas 
at low prices led to tremendous investments of new natural gas 
fired capacity for electricity generation and much of that 
capacity continues to be underutilized today.
    During the early 2000s the optimism over supply was 
replaced by the concern that we would not have enough natural 
gas. As a result significant investments were made in 
infrastructure to import liquefied natural gas from other 
countries. Those import terminals now operate at very low 
capacity as a result of the current low price of domestically 
produced natural gas.
    The promise of expanded domestic gas resources comes with 
the responsibility to address environmental concerns that 
relate to the exploration and production of the gas. Recently 
the public has expressed concerns about the waste water 
management of flow back fluids from natural gas wells, as well 
as the potential for ground water contamination.
    The issue of induced seismicity has also been raised in 
connection with oil and gas extraction related activities in 
Texas and Arkansas. The National Academy of Science is 
undertaking study at Secretary Chu's request and my request.
    I expect that the environmental concerns related to 
developing unconventional gas resources can be managed, but 
only if they are addressed through a transparent, diligent and 
safe approach to well site management through each stage of the 
gas extraction process. The hearing today is intended to shed 
light on many of these high level issues about the current and 
future role of natural gas in meeting our energy needs.
    We have an excellent panel of witnesses. Before I introduce 
them let me call on Senator Murkowski for any opening statement 
she'd like to make.

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

    Senator Murkowski. Thank you, Mr. Chairman. I appreciate 
you scheduling the hearing today. Special thanks to our 
witnesses for joining us today.
    I do appreciate the chance to learn more about MIT's recent 
study and to spend some time thinking about the future of one 
of our Nation's most promising resources. Natural gas is clean 
burning and abundant. It's well understood. It's scalable. It's 
clearly in our best interest to ensure that we maintain a 
stable and affordable supply going forward.
    I think one of the easiest observations to make is that 
we're now in the midst of a very exciting time for the natural 
gas industry. Just in the past several years, we've witnessed 
game changing technological innovations that have unlocked 
tremendous volumes of previously inaccessible natural gas. 
These resources are already benefiting our Nation by further 
diversifying our energy supplies and creating thousands and 
thousands of well paying American jobs.
    This is even more remarkable when you consider that just 3 
or 4 years ago, we were facing a very, very different 
situation. If this was 2005, our opening statements here in 
this committee would probably have expressed at least some 
concern about our ability to ensure that supply kept pace with 
demand. Prices were trending higher and many forecasts 
suggested that we become increasingly dependent on foreign LNG.
    Today, however, new applications of technologies such as 
horizontal drilling and hydraulic fracturing have significantly 
shifted that picture. At moderate cost our vast natural 
resources, our natural gas resources, can meet the most 
aggressive projections of demand and amount to more than 100 
years of supply at today's consumption rates. Of course I think 
that every member of this committee is very well aware of my 
strong interest in helping Alaska bring its huge resources, its 
reserves of natural gas to market. But I think you should also 
know that I made a decision very early on to encourage the 
expanded development and transportation of natural gas all 
throughout our country, even though many felt that the shale 
gas revolution would be bad for Alaska's prospects.
    There are 2 reasons for this.
    The first is that it is still the right thing for Alaska, 
as I believe that we will ultimately have an easier time 
selling our gas to a Nation that has built a larger market and 
infrastructure for gas fired power and gas fired vehicles. 
That's within reach right now.
    The other reason why I'm such a strong supporter of shale 
gas is that it's simply the right decision for our country as a 
whole. Natural gas was once thought of as too precious to burn. 
But that has changed, and I think for the better.
    When I look at the deeply troubling situation in North 
Africa and the Middle East, I don't see a future where we can 
afford to play politics with energy at the national level. The 
rest of the world has already figured that out. I'm hopeful 
that we will begin to see this reality as well.
    I'd like to add that developing all of our resources in a 
responsible way is of paramount importance. Natural gas is no 
exception. We cannot realize the many benefits of our 
tremendous natural gas resources unless we commit to safe, 
environmentally acceptable production and delivery within a 
framework of appropriate regulation and access. Contrary to 
some reports the industry actually has a very exemplary record 
in this regard. I welcome its efforts to proactively seek ways 
to increase transparency and improve the efficiency of the 
extraction process.
    Mr. Chairman, I again thank you for organizing this 
hearing. Many of our members, myself included, are champions of 
natural gas. Greater use of natural gas would move our Nation 
in the right direction in terms of energy security, economic 
growth and environmental protection. Those are 3 critically 
important goals. Every one of them is possible, I believe, 
thanks to our Nation's vast natural gas resources.
    I look forward to the comments that we will hear in the 
presentation from our witnesses this morning.
    The Chairman. Thank you very much.
    Let me introduce our witnesses.
    First is Dr. Howard Gruenspecht, who is the Acting 
Administrator and Deputy Administrator with the U.S. Energy 
Information Administration. He's a frequent witness before our 
committee. Welcome, again today. We appreciate all the work 
you've done on this important issue.
    Dr. Ernest Moniz, who is the Cecil and Ida Green Professor 
of Physics and Engineering Systems at MIT, also the Director of 
the MIT Energy Initiative and the Chief Author of the new 
report that he's going to talk about today related to natural 
gas. We very much appreciate you being here.
    Mr. George J. Biltz is the Vice President for Energy and 
Climate Change with Dow Chemical Company. We very much 
appreciate you being here.
    So why don't each of you--I think we'll have more leeway in 
the timing today take 5 to 10 minutes presenting your 
testimony. Give us the main things you think we need to 
understand about the importance and future of natural gas in 
meeting our energy needs. Then we'll have some questions.
    Dr. Gruenspecht, why don't you start.

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

    Mr. Gruenspecht. Mr. Chairman, Senator Murkowski, members 
of the Committee, I appreciate the opportunity to appear before 
you today. The Energy Information Administration is a 
statistical and analytical agency within the Department of 
Energy. The EIA does not promote or take positions on policy 
issues and is independent 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.
    It's pretty obvious that U.S. natural gas markets have 
recently experienced significant change. After a decade of 
stagnation, domestic dry gas production increased almost 17 
percent between 2006 and 2010, largely driven by the growth in 
shale gas production which increased more than 4 fold over this 
period. In 2010 shale gas accounted for 23 percent of total 
U.S. natural gas production. Natural gas continues to provide 
about 25 percent of total U.S. energy use with current 
consumption spread evenly across buildings, industrial use and 
electric power generation. There's a small amount of use for 
transportation, mostly as fuel for pipelines and I know there's 
a lot of interest in transportation applications more broadly.
    With production growing at a faster rate than consumption, 
U.S. natural gas imports in 2010 were at their lowest level 
since 1994 having declined from roughly 16 percent of U.S. 
natural gas consumption in 2007 to under 11 percent of 
consumption. Wholesale natural gas prices averaged $4.37 per 
million Btu in 2010 close to their level a decade earlier after 
adjustment for inflation.
    Earlier you were discussing the ups and downs of natural 
gas. I remember well I came to EIA in March 2003 when natural 
gas storage at the end of that winter was very low. Chairman 
Greenspan spoke about natural gas and the fact that we'd be 
relying on LNG. So there have been a lot of ups and downs. I 
guess I came in on a down and now we're in a different place.
    On an energy equivalent basis, natural gas is trading at a 
deep discount to oil, with oil prices now more than 3 times 
higher than natural gas prices. With almost all easy 
opportunities to switch from oil to natural gas in industry, 
buildings and electric power generation having already taken 
place, the most active fuel switching area for natural gas 
today involves competition between natural gas and coal as a 
fuel for electric power generation.
    As discussed in my written testimony, reserves data and 
growing resource estimates suggest continued opportunities for 
future production growth.
    Turning to a longer term view, EIA projects that total 
natural gas production will grow by 26 percent between 2009 and 
2035. Shale gas constitutes about 47 percent of total U.S. dry 
gas production in 2035 in our reference case projections.
    Natural gas production costs and prices are projected to 
rise over time as production shifts away from the most 
attractive ``sweet spots'' to less productive areas. Counter 
balancing that will be the presumably continued advance of 
technology. Average annual wholesale natural gas prices remain 
under $5 per million Btu in real 2009 dollars through about 
2020.
    As shown in Figure 4 of my written testimony, the ratio of 
oil- to-natural gas prices in energy equivalent terms remains 
above 3 on an annual average basis in our reference case 
projection as the balance of gas supply and demand within North 
America limits natural gas price increases at a time when the 
world supply/demand balance for oil is expected to push oil 
prices up at a faster rate.
    EIA fully recognizes uncertainties surrounding our 
reference case natural gas projections. Shale gas uncertainties 
are addressed in a prominent special section of our 2011 
Outlook that is discussed in my written testimony. As shown in 
Figure 5 of that testimony, the shale gas cases illustrate how 
the underlying uncertainty regarding the extent of this 
emerging resource and the costs of developing it translates 
into a wide range of production and price projections.
    Shown in Figure 3 and 6 of my written testimony, natural 
gas demand is projected to grow over 16 percent between 2009 
and 2035 with the industrial and electricity generation sectors 
as the main drivers of future demand growth.
    My testimony also discusses a number of significant 
uncertainties affecting the demand side of the natural gas 
market. For example, several factors including regulatory 
changes could increase the use of natural gas in the electric 
power sector. Our 2011 Outlook includes several cases that look 
at the sensitivity of the generation mix and coal retirements 
to different assumptions regarding the price of natural gas, 
the extent and cost of retrofits required for existing coal 
fired facilities and the recovery period for retrofit 
investments. A scenario that combines significant retrofit 
requirements, insistence of the owners on rapid payback of 
retrofit costs and continued low natural gas prices results in 
significant near term retirements of existing coal plants and 
more use of natural gas for generation.
    Another demand uncertainty involves the increased use of 
natural gas as a transportation fuel. In the 2010 edition of 
the Outlook, EIA included sensitivity cases that explored the 
impact of significant incentives to promote the use of natural 
gas as a fuel for heavy duty trucks.
    A third significant uncertainty involves the potential that 
the North American market for natural gas could become more 
fully integrated into the global market for natural gas. 
Ultimately such a possibility will depend on the extent of 
natural gas trade between North America and the rest of the 
world. I think there are several important issues there.
    One relates to the developments in shale gas in the rest of 
the world. That's something that EIA has been looking at 
because of the effect that will have on potential trade.
    The other involves the nature of the pricing of liquefied 
natural gas in the global marketplace, the extent to which you 
have gas on gas competition or whether LNG maintains its 
traditional link to oil prices.
    That concludes my oral statement, Mr. Chairman. I would be 
happy to answer any questions you or the other members might 
have. Thank you very much.
    [The prepared statement of Mr. Gruenspecht follows:]

Prepared Statement of Howard Gruenspecht, Acting Administrator, Energy 
            Information Administration, Department of Energy
    I appreciate the opportunity to appear before you today to address 
current and projected supply and demand conditions for natural gas.
    The 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.
    My testimony today addresses the hearing topic by providing a brief 
overview of recent natural gas developments, EIA's evaluation of U.S. 
natural gas reserves and resources, and a discussion of our natural gas 
projections to 2035 and some of the key uncertainties surrounding them.
Overview of recent U.S. natural gas data
    Production--After a decade of stagnation, U. S. natural gas 
production increased by almost 17 percent between 2006 and 2010, 
reaching 21.6 trillion cubic feet (Tcf) in 2010, the highest level 
since 1973. Production has continued to increase despite a significant 
and sustained decline in natural gas prices since mid-2008.
    The growth in U.S. supplies over the past few years is largely the 
result of increases in production from shale gas formations. Shale gas 
production grew from less than 3 billion cubic feet per day (bcf/d), 
representing 5 percent of overall production in 2006, to 13 bcf/d, 
accounting for 23 percent of overall production in 2010.
    Imports--Increased domestic production has greatly diminished the 
Nation's need for natural gas imports, while lower prices have reduced 
foreign producers' incentive to supply the United States. In 2010, net 
imports to the United States dropped to 2.6 Tcf, representing 10.8 
percent of U.S. consumption, marking the lowest volume of net imports 
since 1994 and the lowest percentage since 1992. As recently as 2007, 
net imports were the highest on record, equaling roughly 16 percent of 
consumption.
    Demand--Natural gas has long played an important role in meeting 
U.S. energy needs. The main uses of natural gas are in buildings, the 
industrial sector, and electric power generation. Natural gas provides 
about 25 percent of the primary energy used in the United States, 
heating about half of U.S. homes, generating almost one-fourth of U.S. 
electricity, and providing an important fuel and feedstock for 
industry. About 31 percent of the natural gas consumed in 2010 was used 
for electric power generation, 33 percent for industrial purposes, and 
34 percent in residential and commercial buildings. Only a small 
portion is used in the transportation sector, predominately at pipeline 
compressor stations, although some is used for vehicles.
    Demand for natural gas in buildings, and to a lesser extent in the 
electric power sector, is highly responsive to weather conditions, for 
space heating and air conditioning. In the industrial sector natural 
gas demand is more responsive to economic conditions, as illustrated by 
that sector's decline in natural gas use in late 2008 and 2009. 
However, the sector has rebounded with consumption in 2010 returning to 
essentially the same level as that in 2008.
    Prices--In 2010 wholesale (Henry Hub) natural gas spot prices 
averaged $4.37 per million Btu, close to the level a decade earlier 
after adjustment for inflation. On an energy-equivalent basis, natural 
gas has traded at a deep discount to oil over the last several years 
with oil prices more than 3 times higher than natural gas prices. 
Almost all easy opportunities to switch away from oil use to natural 
gas in industry, buildings, and electric power generation have already 
taken place or are being actively pursued. For example, in 2010, oil 
provided less than 1 percent of total electric power generation. 
Increasingly, the most important area for fuel switching involving 
natural gas is the competition between natural gas and coal as a fuel 
for electric power generation.
    Drilling activity is also responding to the differential between 
oil and natural gas prices with the number of oil-directed rigs having 
recently exceeded natural gas-directed rigs for the first time since 
1993. However, as noted above, domestic production of natural gas has 
continued to increase despite the renewed focus on drilling for oil. 
This reflects both the high productivity of current gas-directed 
drilling and the fact that oil-directed drilling activity often results 
in production of associated natural gas as well as oil.
    Reserves and Resources--U.S. total natural gas proved reserves grew 
11 percent in 2009 and are now at the highest level since 1971. Shale 
gas proved reserves grew 76 percent after having grown by 48 percent in 
2008, reflecting continued strong drilling activity even as natural gas 
prices declined from their mid-2008 level.
    Estimates of the mean technically recoverable resource of natural 
gas-- that is, resources that are technically producible using 
currently available technologies and industry practices-- have also 
been increasing. EIA's Annual Energy Outlook 2011 uses a total resource 
estimate for U.S. natural gas (onshore and offshore, including Alaska) 
of 2,543 Tcf, including 862 Tcf of shale gas, (35 Tcf of proved 
reserves plus 827 Tcf of technically recoverable unproved resources.) 
(*Figure 1).
---------------------------------------------------------------------------
    * All figures have been retained in committee files.
---------------------------------------------------------------------------
The U.S. natural gas outlook
    EIA projects and analyzes U.S. energy supply, demand, and prices 
through 2035 in our Annual Energy Outlook. EIA sees a continuing rise 
in both natural gas production and consumption as the probable future 
trend.
    Some factors that supported recent production growth, however, are 
expected to play less of a role in the immediate future. These include 
hedging strategies that cushioned the impact of the decline in natural 
gas prices since mid-2008; and lease terms (signed when prices were 
high) that required drilling to begin within a fixed time period in 
order for lease rights to be retained. However, other drivers are 
starting to play a larger role in boosting production activity. For 
example, international joint venture partners, who appear to place a 
value on gaining technical experience and technology associated with 
shale drilling in addition to the value of production, have provided 
major infusions of cash to North American companies. Another driver 
that continues to boost production is the focus on areas where highly 
valued crude oil and natural gas liquids are being produced in 
conjunction with shale gas.
    Production Growth to 2035--In EIA's Reference case projection, 
which assumes no changes in public policy, total natural gas production 
grows by 26 percent, from 21.0 to 26.3 Tcf, between 2009 and 2035, due 
primarily to significant increases in shale gas production, which 
comprises about 47 percent of U.S. dry gas production by 2035. 
Production increases faster than demand resulting in net imports 
declining to below five percent of consumption by 2023 (Figure 2) 
(Figure 3).
    Price Projections to 2035--In EIA's Reference case projections, 
natural gas production costs and prices are expected to rise over time 
as production shifts away from the most attractive ``sweet spots'' to 
less productive areas. Average annual wholesale natural gas prices 
remain under $5 per million Btu (all prices are in real 2009 dollars) 
through about 2020, increasing to higher levels thereafter. As the 
shale gas resource base is developed, production gradually shifts to 
resources that are somewhat less productive and more expensive to 
produce. At the same time, more shale wells are drilled to meet growth 
in natural gas demand and offset declines from other sources, 
increasing demands on the drilling sector and raising costs over time.
    With respect to prices, we have already noted that the energy-
equivalent price premium for oil relative to natural gas has grown 
dramatically in recent years. Oil prices, which were typically 1 to 1.5 
times higher than natural gas prices on an energy equivalent basis 
during the 1995 to 2005 period, are now over 3 times higher than 
natural gas prices. In EIA's AEO 2011 Reference case projection, the 
ratio of oil-to-natural gas prices remains above 3 on an annual average 
basis, as the balance of gas supply and demand within North America 
limits natural gas price increases at a time when the world supply-
demand balance for oil is expected to push oil prices up at a faster 
rate (Figure 4).
    Shale Gas Uncertainties--EIA fully recognizes the uncertainties 
surrounding our Reference case natural gas projections. In fact, we 
actively highlight them. AEO2011 includes a special section that 
examines some of the key uncertainties surrounding shale gas and 
presents the impact of higher and lower shale gas resource and cost 
assumptions for production, consumption, and prices. Several factors 
could lead resources and production to be lower or higher than what EIA 
includes in its Reference case. Some examples include: 1) As most shale 
gas wells are only a few years old their long-term productivity is 
untested, 2) Gas production has been confined largely to ``sweet 
spots'' that may not provide suitable data to infer the productive 
potential of an entire formation, 3) Many shale formations 
(particularly, the Marcellus shale) are so large or new that only a 
portion of the formation has been production tested, 4) Technical 
advances can lead to more productive and less costly well drilling and 
completion.
    The Shale Gas cases in AEO2011 illustrate how a wide variation in 
outlooks can occur due to the underlying uncertainty regarding this 
emerging resource. Two key determinants of the estimated technically 
recoverable shale gas resource base are the estimated ultimate recovery 
(EUR) per well and the recovery factor that is used to estimate how 
much of the acreage of shale gas plays contains recoverable natural 
gas. The largest variations occur in the High- and Low Shale EUR cases, 
where lower and higher costs per unit of shale gas production have the 
effect of increasing and decreasing projected total production from 
U.S. shale gas wells. In the Low Shale EUR case, the Henry Hub natural 
gas price in 2035 is 31 percent higher than the AEO2011 Reference case 
price of $7.07 per million Btu (2009 dollars). Conversely, in the High 
Shale EUR case, the Henry Hub price in 2035 is 24 percent lower than in 
the AEO2011 Reference case. Shale gas production is more than three 
times as high in the High Shale EUR case as in the Low Shale EUR case, 
at 17.1 Tcf and 5.5 Tcf, respectively, as compared with 12.2 Tcf in the 
AEO2011 Reference case (Figure 5).
    Demand outlook to 2035--Demand for natural gas in the Reference 
case grows by over 16 percent between 2009 and 2035 (Figure 6). 
Consumption growth is driven by the industrial and electric generation 
sectors. Natural gas use in the industrial sector grows by 25 percent 
from 2009 to 2035, reflecting the recovery in industrial output and 
relatively low natural gas prices, which spurs a large increase in 
natural gas consumption for combined heat and power (CHP) generation 
more than offsetting the decline in natural gas use for feedstock. 
Electric generation also shows strong growth in natural gas use, where 
65 percent of capacity additions between 2010 and 2035 are expected to 
be natural gas fired. In addition to capital cost considerations, 
uncertainty about future limits on greenhouse gas emissions and other 
possible environmental regulations reduce the competitiveness of coal-
fired plants.
    There are also significant uncertainties affecting the demand side 
of the natural gas market which EIA has examined in various previous 
editions of the Annual Energy Outlook. Some uncertainties relate to the 
impact of possible future policies, others to future developments in 
the North American and global markets for natural gas.
    For example, several factors, including regulatory changes, could 
increase the use of natural gas in the electric power sector. AEO 2011 
includes several cases that look at the sensitivity of the generation 
mix and coal retirements to different assumptions regarding the price 
of natural gas, the extent and cost of environmental control retrofits 
required for existing coal-fired facilities and the recovery period for 
retrofit investments. A scenario that combines significant retrofit 
requirements, a rapid payback of retrofit costs, and continued low 
natural gas prices results in significant near-term retirements of 
existing coal plants and more use of natural gas for generation.
    A second demand uncertainty involves increased use of natural gas 
as a transportation fuel. In the 2010 edition of the Annual Energy 
Outlook, EIA included sensitivity cases that explored the impact of 
significant incentives to promote the use of natural gas as a fuel for 
heavy duty trucks.
    Another significant demand uncertainty involves the potential that 
the North American market for natural gas could become more fully 
integrated into the global market for natural gas. The degree of 
integration will depend on the extent of natural gas trade between 
North America and the rest of the world in the form of liquefied 
natural gas (LNG). The pricing regime in global LNG markets is another 
uncertainty, particularly the extent to which world LNG prices reflect 
``gas on gas'' competition versus retaining the traditional linkage of 
LNG prices to oil prices. Shale gas resources in the rest of the world, 
which EIA has been closely following, and their potential development 
are among the key factors that will shape the development of global 
markets for natural gas (Figure 7).
    This concludes my statement, Mr. Chairman, and I will be happy to 
answer any questions you and the other Members may have.

    The Chairman. Thank you very much.
    Dr. Moniz, go right ahead.

STATEMENT OF ERNEST J. MONIZ, CECIL AND IDA GREEN PROFESSOR OF 
     PHYSICS AND ENGINEERING SYSTEMS DIRECTOR, MIT ENERGY 
 INITIATIVE, MASSACHUSETTS INSTITUTE OF TECHNOLOGY, CAMBRIDGE, 
                               MA

    Mr. Moniz. Thank you, Mr. Chairman, Ranking Member 
Murkowski and distinguished members of the committee. We 
appreciate the opportunity to present results of our recent 
study on natural gas. I'm honored to appear before this 
committee once again.
    I should say the study was carried out by a 
multidisciplinary group of 19 faculty and senior researchers 
over a 3-year period together with 10 graduate students, who do 
most of the work, and some additional contributing authors. For 
context, this is the fourth in our series of studies on various 
pathways to our energy future with a particular emphasis on a 
low carbon future. Nuclear, nuclear fuel cycles, coal, soon the 
grid and solar energy within the next several months.
    When we started this study we had an open mind whether 
natural gas, the least carbon intensive fossil fuel, is part of 
the problem or part of the solution in a carbon context. Our 
top line conclusion is that based on the availability of large 
amounts of moderately priced natural gas that can indeed 
provide a critical bridge to a low carbon future. But assuming 
progressively more stringent carbon constraints down the road 
in some decades, natural gas itself, becomes too carbon 
intensive. We need a very low carbon landing point for this 
bridge to the future, emphasizing the need for continuing 
innovation on zero carbon options, renewables, nuclear, carbon 
capture and sequestration, even as we exploit the robust 
domestic natural gas resource. I would emphasize that in fact a 
critical issue for both coal and natural gas in a long term 
carbon constrained future is reducing the cost of carbon 
capture very, very dramatically.
    I'll briefly summarize some of the key conclusions.
    On the supply side, the world indeed, has a lot of 
inexpensive natural gas, most probably around 9,000 trillion 
cubic feet at costs below $4 a million Btu. A lot of it is 
stranded up to now, but long pipelines and LNG trade are 
changing that.
    Domestically, we largely agree with the EIA estimates, 
although we are somewhat less bullish in our numbers. We 
estimate around 900 trillion cubic feet recoverable gas in the 
modest price range of $4 to $8, more than half of that shale 
gas. But also noting considerable uncertainty and substantial 
intra and inter play variability.
    We should emphasize the economics are complex because of 
large, well to well variability and dependence on liquid 
content. For example, a moderately wet well with today's oil 
price, can easily have a natural gas breakeven price, half of 
that without the liquids. So it's a very complex economic play. 
But the reality is the proof is in the pudding. As Howard said, 
shale gas is growing very dramatically in its contribution to 
our energy supply.
    These supply curves, availability at various costs, are 
then inputs to our modeling. Before I describe those results, a 
few words on the environmental issues, these are clearly very 
important.
    Key issues.
    The need for the highest standards of well completion 
systematically implemented and regulated. We recommend complete 
transparency with respect to frack fluids.
    Management of surface waters, absolutely critical. We 
recommend mandatory integrated, I emphasize, regional water use 
and disposal plans.
    Mitigation of industrial activity. For example, by maximum 
water recycling.
    We also recommend a joint DOE/EPA in depth study on the 
question of methane emissions in the production and delivery of 
all fossil fuels.
    All in all our conclusion is very much along the lines that 
you said in opening the hearing, we consider these 
environmental issues quite challenging. But also manageable in 
the sense that we know how to address them, but we have to 
execute in a proper way. That's in some contrast to what I 
would consider the more difficult challenge of managing 
CO2 emissions in combustion of fossil fuels.
    We find increased gas use under just about any scenario. 
Any relatively more important role over the next decades at 
least in a carbon constrained scenario. One uncertainty is the 
evolution of the global natural gas market.
    Today we have a fragmented regional market with 3 larger 
markets. If an integrated natural gas market develops, 
globally, and that's a big if, I'm not quite sure how we get 
there. But if we do get there, what we find is that it has 
substantial impact on the United States, lower prices, but also 
the potential for substantial imports in 20 to 30 years.
    So this is a complex issue. Nevertheless, for economic and 
geopolitical reasons, we recommend support for the development 
of global market. That would entail for example, erecting no 
barriers to either the export or import of LNG.
    With this supply picture we look at substitution 
possibilities. Natural gas for coal in electricity and 
industry. Natural gas for electricity in buildings. Natural gas 
for oil in transportation.
    Some results.
    First, if we chose tomorrow to substitute underutilized, 
existing natural gas combined cycle capacity for coal plants, 
especially old, inefficient plants. About a third of our fleet 
is over 40 years old, relatively small and without emission 
constraints. We could reduce CO2 emissions in the 
power sector by 20 percent. We will reduce mercury and nox 
emissions by about a third. We would increase gas use by about 
4 trillion cubic feet per year. This would be at a cost of 
about $16, 1, $6, per ton of CO2. So that is 
something that is there in terms of not requiring capital 
investment and having a major shift. As an aside, the mercury 
rule in process at the EPA, as Howard said, will certainly have 
a major impact on this substitution possibility.
    In industry about 85 percent of natural gas use is for 
heat, boilers and process heat. I will defer to Mr. Biltz to 
discuss the feed stock issues. Although I would note that Dow 
was very helpful in our developing the data in that area.
    But on the issue of heat there's, of course, another EPA 
rulemaking in process. That is for industrial boiler emissions. 
Again, heat is a huge use for natural gas industry. We find a 
very attractive net present value for meeting control 
requirements of mercury and other hazardous air pollutants by 
fuel switching to commercially available, super efficient, like 
94 percent, natural gas boilers rather than retrofit of large 
coal boilers. We recommend the EPA include this in their 
revised proposed rule.
    For buildings we support the National Research Council 
recommendation to move to source that is life cycle emission 
standards rather than site standards. This has the potential 
for substantial emissions reductions. However, we also 
emphasize that such standards are not simple to implement. They 
will differ by regional climate conditions. They will differ by 
regional electricity mix. But I think the DOE should really 
move to see how can we incorporate these regional variations 
into good, life cycle emissions standards.
    For transportation. The oil gas price, as we've heard, is 
historically high today. This provides an impetus to look at 
possible substitution for oil in transportation, but direct use 
of natural gas whether CNG or LNG does face a substantial cost 
premium for the vehicles.
    CNG certainly makes sense already for high mileage fleets 
as we see. We find in our modeling significant penetration of 
light duty vehicle CNG vehicles in several decades when there 
is a large CO2 price in addition in our model.
    LNG for heavy trucks we find is very challenged by high 
capital costs, the order of $70,000 per vehicle, fueling 
infrastructure, resale value of class A vehicles on the 
international market and the like. This frankly does not look 
attractive to us for general use. Although, it may find a role 
in high mileage, station to station use.
    Finally in this context, gas to liquids certainly not for 
CO2 reduction but for oil displacement. There are 
many pathways. One large commodity produced today is methanol. 
It has challenges similar to ethanol in terms of vehicle 
modification and infrastructure. But for energy security the 
most important step that we could take is to enable consumer 
arbitrage among fuels derived from different feed stocks, oil, 
biomass, natural gas, possibly coal with carbon capture and 
sequestration.
    So that's gasoline, ethanol, methanol. That leads us to 
consider flex fuel vehicles. There are some challenges but we 
would recommend that that be given a very, very hard look to 
provide this arbitrage from different feed stocks.
    In coming to a conclusion I'll just mention on 
intermittency. We look at the implications of large scale 
intermittent deployed renewables, especially wind. Bottom line 
what we would say is we have to look at the complementarity of 
such intermittent renewables in gas getting in a much more 
systematic way for reliability of our system. Also we need to 
address regulatory issues like a much more robust capacity 
market if we are, in fact, to realize this future.
    Finally R and D. I'll note that public and public/private 
funding of natural gas R and D is way down from its peak. 
Rather ironic given the increasing role of natural gas in our 
energy discussion. So we do recommend a revitalized program 
both at DOE weighted toward basic research and through a 
public/private partnership industry led, weighted toward 
applied research and demonstration.
    Thank you again for the opportunity to testify. I look 
forward to your questions and comments.
    [The prepared statement of Mr. Moniz follows:]

Preoared Statement of Ernest J. Moniz, Cecil and Ida Green Professor of 
   Physics and Engineering Systems Director, MIT Energy Initiative, 
                             Cambridge, MA
    Chairman Bingaman, Senator Murkowski, and Members of the Committee, 
thank you for the opportunity to present some of the key results of the 
recently published MIT multi-disciplinary study, The Future of Natural 
Gas. The study looks at:

   the economics and uncertainty of supply;
   the role of natural gas in the overall energy system, 
        especially in the context of constraints on greenhouse gas 
        emissions;
   the opportunities for capitalizing on an abundant natural 
        gas supply in the electricity, industry, buildings and 
        transportation sectors;
   infrastructure needs;
   global markets and geopolitical implications; and
   the needs for natural gas-related research and development.

    The Future of Natural Gas study is the fourth in a series that 
presents the results of an integrated technically-grounded analysis, 
carried out by a multi-disciplinary group of MIT faculty, senior 
researchers and students, aimed at elucidating the steps needed to 
provide marketplace options for a clean energy future. The first three 
studies addressed nuclear power, coal and the nuclear fuel cycle; 
studies of the grid and of solar energy are in progress. We feel that 
the earlier studies have contributed constructively to the energy 
technology and policy debate in the U.S. and hope that the natural gas 
study will as well. In that context, we are very appreciative of the 
opportunity to present today.
    Prior to carrying out our analysis, we had an open mind as to 
whether natural gas would indeed be a ``bridge'' to a low-carbon 
future. While it is the least carbon-intensive fossil fuel, it does 
emit greenhouse gases in combustion and potentially in production and 
distribution. In broad terms, we find that, given the large amounts of 
natural gas available in the U.S. at moderate cost (enabled to a large 
degree by the shale gas resource), natural gas can indeed play an 
important role over the next couple of decades (together with demand 
management) in economically advancing a clean energy system. However, 
with increasingly stringent carbon dioxide emissions reductions, 
natural gas would eventually become too carbon intensive, which 
highlights the importance of a robust innovation program for zero-
carbon options.
    We all recognize that today there is controversy about natural gas 
and its availability and affordability and about environmental impacts 
from its production and distribution. Our study addresses these issues 
and I hope that our analysis will inform your judgments and policy 
choices about the role natural gas will play in our nation's energy 
future.
Global Gas Resources--Scale and Cost
    Global natural gas resources are abundant. Recent analysis carried 
out as part of the MIT Future of Natural Gas Study\1\ established a 
mean estimate of 16,200 Tcf\2\ for the remaining global resource base, 
with a range between 12,400 Tcf (with a 90% probability of being 
exceeded) and 20,800 Tcf (with a 10% probability of being exceeded). To 
put these estimates into context, 2009 global gas consumption amounted 
to 109 Tcf. These estimates do not include any unconventional resources 
outside of the United States and Canada, because of the large 
uncertainty. However, a recent EIA study has estimated a further 5,300 
Tcf of shale gas internationally, just in regions that do not have 
large conventional resources.
---------------------------------------------------------------------------
    \1\ http://web.mit.edu/mitei/research/studies/natural-gas-
2011.shtml
    \2\ In the US, natural gas volumes are typically measured in 
Standard Cubic Feet (Scf), where the volume is measured at a 
temperature of 60 F and a pressure of one atmosphere (14.7 pounds per 
square inch). 1 trillion cubic feet (Tcf) = 1012 Scf. 
Outside North America, natural gas volumes are typically measured in 
cubic meters. 1 cubic meter &8[35.3 cubic feet.
---------------------------------------------------------------------------
    Although the global gas resource base is large, it is 
geographically concentrated. Excluding the recent estimates of global 
shale resources, around which very high levels of uncertainty still 
exist, about 70% of all gas resources are located in only three 
regions: Russia, the Middle East (primarily Qatar and Iran) and North 
America. By some measures, this makes global gas resources even more 
geographically concentrated than oil. It also means that political 
considerations and individual country depletion policies play at least 
as big a role in global gas resource development as geology and 
economics.
    *Figure 1 depicts global natural gas supply curves calculated 
estimated by the MIT study group. These curves quantify the price 
required at the point of export to enable the economic development of a 
given volume of gas\3\. Studying the figure indicates that much of the 
global gas resource can be developed at relatively low prices at the 
point of export. For example the figure shows that globally, over 4,000 
Tcf of gas can be developed at or below $2.00/MMBtu, with 9,000 Tcf 
available at or below $4.00/MMBtu. These certainly are very large 
volumes of low-cost gas. However, a very large portion of this gas is 
geographically isolated from the major gas consuming markets in Europe, 
East Asia and North America. Unlike oil, the cost of transporting gas 
over long distances is high. Getting the gas to market requires either 
long-haul pipelines or liquefied natural gas (LNG) infrastructure. This 
means that gas, which can be economically developed at the export point 
for $1.00-2.00/MMBtu may well require an added $3.00-5.00/MMBtu of 
transport costs to get the gas to its ultimate destination. These high 
transportation costs are also a significant factor in the evolution of 
the global gas market.
---------------------------------------------------------------------------
    * All figures have been retained in committee files.
    \3\ Supply curves shown here are based on oil field costs in 2007. 
There has been considerable oil field cost inflation, and some recent 
deflation, in the last 10 years. We have estimated cost curves on a 
2004 base (the end of a long period of stable costs) and a 2007 base 
(reasonably comparable to today's costs, 70% higher than the 2004 
level, and continuing to decline).
---------------------------------------------------------------------------
    The substantial growth in production from 1990 to 2009 is leading 
to the expansion of gas markets and the rise in global cross-border gas 
trade. From 1993 to 2008, global cross-border gas trade almost doubled, 
growing from 18 Tcf (25% of global supply), to 35 Tcf (32% of global 
supply). The vast majority of cross-boarder gas movements have 
historically been via pipeline. However, LNG is playing an increasing 
role. In 1993, 17% of cross-boarder gas trade was via LNG. By 2008 the 
proportion had increased to 23%, and the absolute volume had increased 
by 5 Tcf, or 166%. Due to improving technology and growing global gas 
demand, LNG is likely to continue to grow in importance.
United States Natural Gas Supply--A New Paradigm
    Over the past five years the natural gas supply landscape in the 
United States has changed greatly--the driving force behind this change 
has been the rapid growth in production from shale gas plays, as 
illustrated in Figure 4(a). Reviewing EIA, state and commercial data 
reveals that the proportion of total U.S. gas production coming from 
shale resources grew from less than 1% in 2000, to 20% in 2010. By the 
end of 2011, this is expected to reach 25%. Such growth rates would be 
remarkable in any context, but in the U.S., the world's largest gas 
producing nation, it really does represent a paradigm shift.
U.S. Shale Gas Resource--Uncertainty and Relative Economics
    The rapidly increasing estimates of the size of the U.S. shale 
resource have generated significant excitement, both within the gas 
industry and indeed further afield. However, shale gas production is 
still a nascent industry--estimates of the size and relative economics 
of the shale resource are still subject to considerable uncertainty. 
Supply-side analysis carried out as part of the MIT Future of Natural 
Gas Study has explored this uncertainty in great detail, both at the 
resource size and relative economics levels. Some of the key 
conclusions of this analysis include:

          1. Shale gas is now a very substantial component of the 
        overall U.S. gas resource base--MIT's mean estimate of 
        recoverable shale gas volumes is 630 Tcf, or just over 30% of 
        all U.S. gas resources.
          2. Significant uncertainty exists regarding the size of the 
        shale resource--MIT's low estimate (90% probability of being 
        exceeded) is 418 Tcf, and its high estimate (10% probability of 
        being exceeded) is 871 Tcf.
          3. Shale gas is not ``cheap gas,'' rather it is a large 
        resource of ``moderate cost gas,'' with a less steep supply 
        curve than other resource types--Of the 900 Tcf of gas 
        recoverable in the U.S. at or below $8.00/MMBtu, 470 Tcf is 
        shale gas.
          4. There is substantial intra and inter-play variability in 
        the production, and associated economic performance of 
        individual shale wells; however, on a portfolio basis the shale 
        plays are high performance.
          5. The fact that many shale plays also produce natural gas 
        liquids, whose price is linked with the oil price means that 
        the economics of shale can be substantially better than they 
        would appear if only gas production is considered.

    The impact of shale gas on the scale and relative economics of the 
U.S. gas resource base is shown in Figure 5(a) & (b). Figure 5(a), 
illustrates the mean, high and low U.S. natural gas supply curves 
calculated for the MIT Future of Natural Gas Study. Figure 5(b) 
disaggregates the mean supply curve from Figure 5(a) by gas type. 
Reviewing Figure 5(b) reveals that relatively small volumes of gas are 
available at or below $4.00/MMBtu. This reflects the maturity of the 
U.S. resource base, which has seen much of its ``easy'' gas produced 
over the past decades. However, of the gas available in the moderate 
price range; $4.00-8.00/MMBtu, over 60% is shale. For the coming two 
decades MIT analysis predicts U.S. gas prices in the $6.00-8.00/MMBtu 
range. At these price levels Figure 5(b) illustrates that shale gas 
will in most instances be the lowest cost resource. An important point 
to keep in mind when considering gas prices is the fact that 2011 U.S. 
prices have been very low, due in all likelihood to a combination of 
macro-economics factors, and an oversupply of gas from prolific shales, 
where operators continue to drill in the short-term in order to hold 
lease positions. In the recent past U.S. prices have been substantially 
higher than $10.00/MMBtu, and in this context the shale resource 
appears very attractive.
    An illustration of this variability is shown in Figure 6(a), which 
plots the probability distribution of the initial production rates (IP) 
(a key performance metric of shale wells) of the wells drilled in 
Texas' Barnett Shale play during 2009. This distribution is made up of 
over 1,600 individual wells. Reviewing the data reveals there is a 3X 
variation between the IP rate of a good (P20), and bad (P80) well. Such 
a wide range would be uncommon with conventional gas; however, similar 
variability is observed in all the major shale plays currently in 
production. Naturally, this variability impacts on the economics of 
shale wells. Figure 6(b) shows a table that illustrates how the 
performance variation of shale wells drilled during 2009 in the five 
major gas shale plays translated into per-well breakeven gas prices 
(BEPs).
    For the plays shown in Figure 6(b), the BEPs for P50 wells, i.e. 
median performance wells, range between $4.00 and $6.50/MMBtu. However, 
many of the wells in each play had much higher and lower BEPs due to 
the wide production performance variation. This means shale gas 
producers are not currently drilling only low-cost shale resource; 
rather their drilling is sampling along the entire supply curve. 
Clearly this is not ideal, as operators would rather only develop the 
lowest-cost resources; however, as long as their overall portfolio BEP 
is acceptable, the variability in individual well performance is of 
little concern. That is not to suggest that operators are not 
interested in reducing this variability. Significant work is ongoing to 
reduce the per-well performance variability through the use of better 
technology.
    Along with gas production variability, the economics of shale can 
be significantly influenced by the co-production of natural gas liquids 
(NGLs), whose price is linked to the international price for oil. Some 
shale areas are termed ``wet,'' meaning that wells in those areas 
produce NGLs along with gas, and depending on the ratio of liquid to 
gas production, the L/G ratio, the BEPs of shale wells in such areas 
are often dramatically lower than they would be if the wells only 
produced gas. A demonstration of how significant an impact NGLs can 
have on shale well economics is shown in Figure 7. Here, the BEP 
calculated for a theoretical well assuming a 2009 Marcellus P50 gas 
production rate is plotted as the L/G ratio is varied from 0 to 50.
    In this theoretical example, the BEP drops from $4.00/MMBtu, to 
$0.00/MMBtu as the L/G ratio rises from 0 (a ``dry'' well) to 50 (a 
very wet well). With appreciable NGLs production, the gas effectively 
becomes free. Several of the major shale plays currently in development 
contain zones which are ``wet,'' including the southwest portion of the 
Marcellus shale in Pennsylvania and the Eagle Ford shale in southwest 
Texas. In these areas, shale wells which may not appear economic at 
first glance based on the cost of drilling and the price of gas alone, 
are in fact likely to be making money due to the favorable oil-gas 
price spread.
Shale Gas Development--Environmental Concerns and Impacts
    The growth in shale gas production has not been without 
controversy. The use of hydraulic fracturing (or fracking as it is 
referred to in the oil field vernacular), a necessary step in shale gas 
extraction, has been a particular focus of scrutiny by groups concerned 
about the environmental impacts of shale gas production. The MIT Future 
of Natural Gas Study examined the environmental issues around shale gas 
production and identified a set of primary environmental risks, which 
arise from shale development. They are:

   Contamination of groundwater aquifers with drilling fluids 
        or natural gas while drilling and setting casing through the 
        shallow freshwater zones;
   On-site surface spills of drilling fluids, fracture fluids 
        and wastewater from fracture flowbacks;
   Contamination as a result of inappropriate off-site 
        wastewater disposal;
   Excessive water withdrawals for use in high volume 
        fracturing; and
   Excessive road traffic and impact on air quality

    In considering these risks, the MIT analysis concluded that they 
are ``challenging but manageable.'' In all instances the risks can be 
mitigated to acceptable levels through appropriate regulation and 
oversight. In particular, the risk of groundwater contamination via gas 
migration or from drilling fluid can be effectively dealt with if best 
practice case setting and cementing protocols are rigorously enforced. 
Regulation of shale (and other oil and gas) activity is generally 
controlled at the state level, meaning that acceptable practices can 
vary between shale plays. The MIT study recommends that in order to 
minimize environmental impacts, current best practice regulation and 
oversight should be applied uniformly to all shales. It is also the 
case that shale gas production can result in a large industrial 
activity. The local communities clearly have a strong role in 
evaluating the tradeoffs of significant economic activity and 
industrial activity.
    On the specific concerns that surround the chemicals being used in 
fracture fluids, The MIT study recommends requiring complete public 
disclosure of all fracture fluid components. Furthermore the study 
recommends that efforts to eliminate the need for toxic components in 
fracture fluid be continued. The study also recommends required 
integrated regional surface water management plans.
    Another concern has been that of methane emission during natural 
gas production, delivery and use. These factors have been included in 
the modeling described in the next section. Nevertheless, we recommend 
that the DOE and EPA should co-lead a new effort to review, and update 
as appropriate, the methane emission factors associated with fossil 
fuel production, transportation, storage, distribution, and end-use. 
This has public policy implications. The review and analysis should 
rely on data to the extent possible.
The Role of Natural Gas in a Carbon-Constrained World
    To examine and analyze the role of natural gas in a carbon-
constrained world, we utilized MIT's EPPA model, a global model which 
has been used and refined over twenty years to examine the complicated 
interplay of economics, a range of energy technologies, and trade flows 
for 16 regions in the world, including the US. The model accounts for 
all Kyoto gases. The study's supply/cost curves, discussed above, were 
inputs to the economic modeling work and the results, while based on 
global analysis, are focused on the US. I also stress that the results 
are not ``predictions'' but are instead scenarios based on assumptions 
and economically driven behavior.
    We focus today on the CO2 price scenario in the study 
which assumes the following: a 50% reduction from 2005 to 2050 in 
CO2 emissions by developed nations, with no offsets; a 50% 
reduction in CO2 emissions by large emerging economies by 
2070; and no emissions reductions from least developed nations
    There are several key takeaways from this analysis, two of which 
are clearly seen in Figure 8. This graph is a result of EPPA runs and 
depicts the US power sector only under the scenario described above, 
carried out to 2100. In this graph, which reflects a model driven by 
ruthless economics in the face of the stringent CO2 limit, 
we find:

   there must be significant demand reduction from business-as-
        usual to meet the emissions reduction targets;
   natural gas consumption increases dramatically. This occurs 
        because of the lower carbon characteristics of natural gas;
   there is total displacement of coal generation largely with 
        natural gas generation by around 2035;
   carbon capture and sequestration (CCS) is too expensive to 
        make inroads for many decades; and
   by around 2045, natural gas itself becomes too carbon 
        intensive to meet the carbon limits and consumption starts to 
        decline. The slack in this pre-Fukushima model run is taken up 
        largely by nuclear but this could be any scalable no-carbon 
        generation fuel; the point is decarbonization of the power 
        sector after mid-century.

    This figure has become known in our group as the ``bridge fuel'' 
slide. It graphically illustrates the essential role natural gas plays 
between now and 2050 in a carbon constrained world by substituting for 
coal generation in the power sector. It also makes the point that the 
bridge must have a suitable landing point. We must continue to invest 
in research in carbon-free sources--renewables, nuclear, and CCS for 
both coal and natural gas.
    The global market structure is important for the results because of 
trade between different regions. Currently there is no global market in 
gas that approximates the oil market. Instead, we have three distinct 
regional markets where gas prices are established in different ways and 
trade between the three is relatively restricted. We used the model to 
explore a scenario in which the regional barriers to trade are lifted, 
leading to a truly global market in gas (of course with transportation 
costs included). The results are seen in Figures 9a and 9b.
    Interestingly, in spite of the substantial domestic gas supply in 
the US, by 2030 we see an increase in gas imports to the US. This 
occurs because, as I have noted, there are abundant supplies of very 
low-cost gas in the world, and the LNG transportation costs can be 
overcome for some gas.
    This may understandably raise concerns about energy security and 
reliance on imports. This scenario demonstrates however that there are 
major benefits to US gas consumers as prices for gas are substantially 
lower (almost 25%) in the global market scenario. Also, domestic gas 
production does not decline in the US for quite some time despite the 
imports. This is because the lower gas prices in the global market 
scenario increase demand and imports largely make up the increased 
demand.
Fuel Substitution Options
    The U.S. natural gas supply situation has created new opportunities 
for expanding natural gas use, enhancing the substitution possibilities 
for natural gas in the electricity, industry, buildings, and 
transportation sectors. I will specifically discuss the substitution of 
gas for:

   coal in the power generation sector;
   coal in the industrial sector, specifically for industrial 
        boilers;
   electricity in buildings; and
   oil in transportation.

    I will also briefly highlight the impacts on natural gas of large 
scale penetration of intermittent renewables in the power sector.
Natural Gas Substitution for Coal in the Power Sector.
    As noted in the EPPA discussion above, under a carbon-price 
scenario natural gas displaces coal in the power sector by around 2035. 
In the gas study, we drilled down in this area to try to understand how 
this substitution might occur and what some of the impacts might be. 
More specifically, we examined opportunities created by the current 
surplus of natural gas combined cycle generation capacity and what the 
impacts of utilizing this ``surplus'' capacity might be on carbon 
emissions.
    The US has more installed nameplate natural gas generation capacity 
than coal (see Figure 10) but gas supplies only 23% of our generation 
compared to 44% from coal; this demonstrates that there is significant 
unused gas capacity. NGCC generation units in the U.S. averaged only 
42% capacity factors in 2009 (*Table 1) although they are capable of 
operating at capacity factors of around 85%. NGCC units are highly 
efficient, relatively inexpensive to build, and produce significantly 
fewer CO2 and other pollutant emissions than coal plants.
---------------------------------------------------------------------------
    * All tables have been retained in committee files.
---------------------------------------------------------------------------
    Natural gas plants however typically have the highest marginal cost 
(although this is changing) and tends to get dispatched after other 
fuel sources for power generation. This is because the marginal cost is 
dominated by fuel cost. We analyzed what the carbon impacts might be if 
we changed this order and dispatched surplus NGCC generation ahead of 
coal. Older inefficient coal units are good candidates for substitution 
by NGCC.
    After isolating how much of this NGCC generation capacity is 
actually surplus--defined as the amount of NGCC generation that can be 
used over the course of one year to replace coal while respecting 
transmission limits, operation constraints and demand levels at any 
given time--through modeling we were able to conclude the following 
about a policy that requires the dispatch of surplus NGCC over coal 
generation:

   nationwide, CO2 emissions from power generation 
        would be reduced by 20%
   the cost of CO2 emissions avoidance would be 
        around $16 per ton
   mercury emissions would be reduced by 33%
   NOX emissions would be reduce by 32%
   this would require an incremental 4 tcf of natural gas

    It should be noted that these impacts vary widely by region of the 
country, depending on the generation mix, the level of electricity 
imports/exports, etc (Table 2). Also, the mercury rule in development 
at EPA may be a significant driver for utilizing surplus NGCC capacity 
when weighted against the option of retro-fitting coal plants to 
capture mercury. Finally we note that this option may be the only 
practical near-term option for large scale CO2 emissions 
reductions from the power sector. Policy makers could pursue this 
pathway for near term large-scale reductions in CO2 and 
other pollutant emissions from the power sector.
Natural Gas Substitution for Coal in the Industrial Sector.
    Industrial consumers represent about 35% of US gas demand. 
Currently, 85% of industrial demand is in the manufacturing sector and 
36% of manufacturing demand is for industrial boilers. Natural gas 
industrial boilers have a range of efficiencies: pre-1985 gas boilers 
average 65-70%; those designed to meet the 2004 standard of 77-82%; and 
new super boilers with efficiencies in the 94-95% range.
    We focus today on large industrial boilers because of standards 
being developed at EPA for mercury, metals, and other hazardous 
emissions from industrial coal fired boilers. These National Emissions 
Standards for Hazardous Air Pollutants (NESHAP), issued then withdrawn 
by Administrator Jackson for additional comments, are based on Maximum 
Achievable Control Technologies (MACT). Around 68% of large industrial 
boilers are coal-fired. Natural gas boilers, which are much cleaner, 
were not covered by the proposed boiler standards, although there are 
cost-effective options for greater efficiency. Gas boilers were also 
excluded from the MACT as a remedy for covered emissions from coal 
plants.
    The EPA economic analysis supporting the new MACT standards assumed 
that the three sub-categories of coal boilers would retrofit with post-
combustion technologies but concluded that gas fuel was too expensive 
for fuel switching to be considered as an option for meeting MACT 
standards. The price of gas assumed in the EPA analysis was $9.58 per 
MMBtu in 2008; today's price is less than half that.
    Using EPA's methodology but substituting current gas price suggests 
that EPA may wish to reconsider fuelswitching as an option for meeting 
MACT standards. The efficiency of natural gas super boilers combined 
with today's gas prices shows that the net present value cost for these 
super boilers is slightly lower than that for retrofitting existing 
coal boilers (Figure 11). Substitution of large industrial coal boilers 
with natural gas super-boilers would consume slightly less than one Tcf 
of incremental gas per year and reduce CO2 emissions by 
52,000 to 57,000 tons per year per boiler. Interestingly, because the 
savings are so significant, there is a negative per ton CO2 
emission avoidance price of $5.00. The study concluded that replacing 
coal boilers with super-efficient gas boilers could be a cost-effective 
alternative for complying with MACT standards.
Gas Substitution for Electricity in the Buildings Sector.
    As we saw in the EPPA scenarios, reduced energy consumption is a 
critical component of a strategy for achieving a low carbon future. 
Because they represent around 40% of total energy consumed in the US, 
buildings, both residential and commercial, are an essential focus for 
reducing energy demand. This is even more critical for natural gas, 
where buildings represent 55% of all gas consumed, including gas fired 
electricity for buildings.
    The study focused on a comparison of the relative efficiencies of 
the direct use of fuels in building thermal end uses, especially space 
conditioning and hot water heating. It specifically examined site 
efficiency of these appliances (the ratio of useful energy provided 
divided by the amount of retail energy consumed, either electricity or 
fuel) compared to full fuel cycle or ``source `` efficiency (accounting 
for all energy used to extract, refine, convert and transport the fuel 
as well as the efficiency of the end use appliance).
    DOE has historically set standards based only on site efficiency. 
In 2009, the National Research Council recommended that DOE move to 
source efficiency standards. The analysis in the study validates the 
NRC recommendation. Figure 12 shows the amount of energy consumed by 
various furnaces when one looks only at site energy and when one looks 
at both site and source energy. Using this number in a site 
calculation, a gas furnace consumes 10% more energy than an electric 
furnace. When source energy is considered, an electric furnace consumes 
194% more energy than a gas furnace. There are corresponding reductions 
in CO2 emissions.
    These numbers are compelling but such standards are complicated to 
establish because of regional climate and regional electricity supply 
mix. The study recommends incorporating efficiency metrics to provide 
full fuel cycle comparisons in dual fueled appliance standard setting 
but it also finds that there is a need to inform consumers, developers 
and state and local regulators about the cost-effectiveness and 
suitability of various technologies relative to local conditions.
Gas Substitution for Oil based Transportation Fuels.
    The study examines options for both direct use of natural gas for 
transportation as well as conversion of natural gas to liquid fuels.

   Compressed Natural Gas (CNG)--Globally, there are 11 million 
        natural gas vehicles on the road, 99.9% of which are CNG 
        vehicles. CNG is cheaper than gasoline on an energy equivalency 
        basis but there are upfront vehicle costs that have inhibited 
        the growth of the CNG vehicle markets. For a variety of 
        reasons, some of which are not entirely clear, these costs--for 
        both after-market conversion and factory produced issues-- are 
        much higher in the US than elsewhere in the world. The 
        incremental cost for factory produced vehicles in the US for 
        example is $7,000 compared to $3,700 in Europe. The incremental 
        cost of after-market conversions in the US is $10,000, in 
        Singapore it is $2,500.

    The study analyzes the payback period for light duty vehicles 
assuming a $3K and a $10K incremental cost for 12000 miles and 35000 
driven per year per year. At the lower conversion cost, vehicles with 
high miles traveled (typically fleets) have a short payback period, 
making this an attractive option for taxis for example. This is however 
illustrative; as noted incremental costs in the US are much higher than 
$3,000.
    These data suggest that CNG offers a significant opportunity in 
U.S. heavy-duty vehicles used for short-range operation (buses, garbage 
trucks, delivery trucks), where payback times are around three years or 
less and infrastructure issues do not impede development. However, for 
light passenger vehicles, even at 2010 oil-natural gas price 
differentials, high incremental costs of CNG vehicles lead to long 
payback times for the average driver, so significant penetration of CNG 
into the passenger fleet is unlikely in the short term. Payback periods 
could be reduced significantly if the cost of conversion from gasoline 
to CNG could be reduced to the levels experienced in other parts of the 
world such as Europe. The study recommends that the US should consider 
revising its policies on CNG vehicles, including how aftermarket 
conversions are certified to reduce up-front costs and facilitate bi-
fueled CNG-gasoline capability.
    A CO2 emissions charge also favors CNG vehicles relative 
to gasoline-fueled vehicles. In the carbon-constrained scenario 
discussed above, the economic scenario has substantial penetration 
ofCHG vehicles toward mid-century.

   Liquefied Natural Gas (LNG)--LNG has been considered as a 
        transport fuel, particularly in the long-haul trucking sector. 
        However, as a result of operational and infrastructure 
        considerations as well as high incremental costs and an adverse 
        impact on resale value, LNG does not appear to be an attractive 
        option for general use. There may be an opportunity for LNG in 
        the rapidly expanding segment of hub-to-hub trucking 
        operations, where infrastructure and operational challenges can 
        be overcome.
   Conversion of Gas to Liquid Fuels--The chemical conversion 
        of natural gas to liquid fuels could provide an attractive 
        alternative to CNG. Several pathways are possible, with 
        different options yielding different outcomes in terms of total 
        system CO2 emissions and cost. Conversion of natural 
        gas to diesel and gasoline for example--both drop-in fuels that 
        can be used in existing infrastructure, a major plus-- require 
        more processing than other options.

    The study looks more closely at the methanol liquid fuel option, 
largely because there is currently large scale industrial production of 
methanol and it is an alcohol like ethanol, with which we also have a 
good deal of experience. Methanol production and use has GHG emissions 
comparable to those of petroleum derived fuels and at today's oil and 
gas prices is significantly less expensive than gasoline on an energy 
basis. As seen in Table 3, at $4 natural gas, methanol is a dollar 
cheaper than gasoline on a gge basis. This analysis was done when 
gasoline was $2.30 (excluding taxes); the spread would be significantly 
greater at today's gasoline prices.
    Methanol requires modest changes to engines because of its 
corrosive nature and an appropriate distribution infrastructure would 
be required. The issues are very similar to those for ethanol which has 
already penetrated the gasoline market at a material level. Introducing 
methanol, in addition to ethanol, has the energy security benefit of 
providing fuel options derived from petroleum, biomass, and natural gas 
feedstocks. To gain security benefits, arbitrage among the fuels is 
needed at the consumer level, which means flex-fuel vehicles would be 
required. This arbitrage would place downward pressure on prices, 
helping to reduce price spikes and volatility. The study group supports 
implementation of the open fuel standard.
    In addition to its recommendation of support for flex fuel 
vehicles, the study recommends that the federal government conduct a 
serious comparative study of natural gas derived transportation fuels 
compared to petroleum and biofuels.
Natural Gas Power Generation and Intermittent Renewables.
    Natural gas-fired power generation provides the major source of 
backup to intermittent renewable supplies in most U.S. markets. If 
policy support continues to increase the supply of intermittent power, 
then, in the absence of affordable utility-scale storage options, 
additional natural gas capacity will be needed to provide system 
reliability. In most markets, existing regulation does not provide the 
appropriate incentives to build incremental capacity with low load 
factors, and regulatory changes may be required.
    In the short term--defined here to mean a circumstance where a 
rapid increase in renewable generation occurs without any adjustment to 
the rest of the system including generation technologies--increased 
renewable power displaces natural gas combined cycle generation, 
reducing demand for natural gas in the power sector. Modeling of the 
ERCOT system (Texas) provides a more detailed understanding of the 
generation impacts of doubling wind generation in the short term. These 
include:

   Wind generation primarily displaces generation from natural 
        gas combined cycle turbines
   Coal plants are forced to cycle
   Natural gas peaking plants are used more

    In the longer term, where the overall system has time to adjust 
through plant retirements and new construction, increased renewables 
displaces baseload generation. This could mean displacement of coal, 
nuclear or NGCC generation, depending on the region and policy scenario 
under consideration. For example, in the 50% CO2 reduction 
scenario described earlier, increased renewable penetration as a result 
of cost reductions in renewable generation or government policy such as 
a renewable portfolio standard, reduces natural gas generation on a 
nearly one-for-one basis. Another effect: absent breakthroughs in 
storage technologies, gas peaking units will be needed to manage 
intermittency. These units however will not be utilized very often--not 
necessarily an attractive investment option or easily accommodated in 
existing regulatory and rate structures. As such, the study found that 
policy and regulatory measures should be developed to facilitate 
adequate levels of investment in gas generation capacity to ensure 
system reliability and efficiency.
    The study notes a growing interdependency between natural gas and 
electricity infrastructures, not just to accommodate intermittent 
renewable penetration but also in a scenario where gas generation 
displaces coal generation. The degree to which this interdependency 
stresses both the gas and power infrastructures and creates conditions 
where the infrastructures and related contracting, legal and regulatory 
structures may be inadequate is not fully understood. The study 
recommends that a detailed analysis be conducted of these 
interdependencies. The current models are inadequate to fully 
understand the implications of these changing relationships.
Natural Gas Research and Development
    There are numerous RD&D opportunities to address key objectives for 
natural gas supply, deliver, and use:

   improve the long term economics of resource development as 
        an important contributor to the public good;
   reduce the environmental footprint of natural gas 
        production, delivery and end-use;
   expand current use and create alternative applications for 
        societal objectives, such as emissions reduction and diminished 
        oil dependence;
   improve safety and operation of natural gas infrastructure; 
        and
   improve the efficiency of natural gas conversion and end-use 
        so as to use the resource most effectively.

    Given the importance of natural gas in a carbon-constrained world, 
and these opportunities for improved utilization of the resource, an 
increase is in order in the level of public and public-private RD&D 
funding. Historically, public-private RD&D funding played an important 
role in the development of the unconventional natural gas resource. 
Indeed, the technologies needed to produce such resources have been 
pioneered in the United States and now account for about half of 
domestic production.
    Figure 13 shows how the interplay of early stage DOE-supported 
reservoir characterization, the public- Figure 13. CoalbedMethane RD&D 
Spending 19 private Gas Research Institute (GRI) funding for technology 
development and demonstration, and a time-limited tax credit led to 
robust coalbed methane production. A Royalty Trust Fund (RTF) 
established in the 2005 Energy Policy Act, and implemented through a 
public-private partnership, is providing modest resources for 
unconventional gas technology, specifically including minimization of 
environmental impacts. However, the elimination of the GRI rate-payer 
funded program was not compensated by increased DOE appropriations or 
the RTF. The total public and public-private RD&D funding for natural 
gas research is down substantially from its peak and in addition is 
much more limited in scope.
    In agreement with a recommendation made by the President's Council 
of Advisors in Science and Technology with respect to the overall 
Federal energy RD&D effort, we recommend that the Administration and 
Congress support a broad natural gas RD&D program both through a 
renewed DOE effort, weighted towards basic research, and a 
complementary industry-led public-private program, weighted towards 
applied RD&D. The latter should have an assured funding stream tied to 
energy production, delivery and use (such as the RTF).
Conclusion
    Mr. Chairman, Senator Murkowski, members of the committee, let me 
conclude with a summary of some of the major findings of the study (the 
complete list can be found in the study):

   Even with uncertainty, there are abundant supplies of 
        natural gas in the world, and many of these supplies can be 
        developed and produced at relatively low cost. In the U.S., 
        despite their relative maturity, natural gas resources continue 
        to grow, and the development of low-cost and abundant 
        unconventional natural gas resources, particularly shale gas, 
        has a material impact on future availability and price.
   Natural gas plays a major role in most sectors of the modern 
        economy is likely to continue to expand under almost all 
        circumstances
   In a carbon-constrained economy, the relative importance of 
        natural gas is likely to increase even further, as it is one of 
        the most cost-effective means by which to maintain energy 
        supplies while reducing CO2 emissions. This is 
        particularly true in the electric power sector, where, in the 
        U.S., natural gas sets the cost benchmark against which other 
        clean power sources must compete to remove the marginal ton of 
        CO2.
   In the U.S., a combination of demand reduction and 
        displacement of coal-fired power by gas-fired generation is the 
        lowest cost way to reduce CO2 emissions by up to 
        50%. For more stringent CO2 emissions reductions, 
        further de-carbonization of the energy sector will be required; 
        but natural gas provides a cost-effective bridge to such a low-
        carbon future.
   The current supply outlook for natural gas will contribute 
        to greater competitiveness of U.S. manufacturing, while the use 
        of more efficient technologies could offset increases in demand 
        and provide cost-effective compliance with emerging 
        environmental requirements.
   International gas trade continues to grow in scope and 
        scale, but its economic, security and political significance is 
        not yet adequately recognized as an important focus for U.S. 
        energy concerns.

    The Chairman. Thank you very much for your testimony.
    Mr. Biltz, go right ahead.

 STATEMENT OF GEORGE BILTZ, VICE PRESIDENT, ENERGY AND CLIMATE 
         CHANGE, THE DOW CHEMICAL COMPANY, MIDLAND, MI

    Mr. Biltz. Thank you. Chairman Bingaman, Senator Murkowski, 
members of the committee, my name is George Biltz. I'm the Vice 
President of Energy and Climate Change for Dow Chemical. Thank 
you for the opportunity to discuss our views on the future of 
natural gas.
    Natural gas may well be the most critical fuel that our 
economy has when you think about its growing use in homes and 
power plants, its importance as a use in fertilizers and 
therefore for food pricing and how critical it is to 
manufacturing. Dow is one of the largest users of natural gas. 
We use approximately 850,000 barrels of oil per day which is 
about as much energy as the country of Australia uses. We use 
this both as an energy source to fuel our operations as well as 
a raw material from plastics to pharmaceuticals.
    More than 96% of all manufacturing goods are enabled by 
chemistry. Moreover, we turn every dollar of natural gas that 
we use into $8 worth of value for the economy. No other use of 
natural gas even comes close.
    As an example of this, this is our new solar roofing 
shingle which is currently manufactured today in Michigan. The 
polymer in this revolutionary product started with American 
made natural gas. We think the future of natural gas is very 
bright. It will play a vital role in meeting the Nation's 
energy needs over the next decades and it will be critical for 
the growth of U.S. manufacturing.
    As the MIT study concluded and we agree, there is a growing 
abundance of natural gas in the U.S. and elsewhere. The 
environmental challenges are manageable. We need to use the gas 
efficiently.
    Our view is that we must deal with both supply and demand 
at the same time. The manufacturing sector and job creation 
will grow when natural gas prices are competitive. Conversely 
when natural gas prices are high and volatile, manufacturing 
becomes the shock absorber in the system. Exports drop. 
Companies move production elsewhere or they simply shut down.
    As this chart shows which is based on EIA data and allowing 
for the accelerated retirement of coal fired power generation, 
as we just discussed from the MIT report, allowing for natural 
gas vehicles and the Administration's desire to replace 25% of 
oil imports. Demand in this case will far exceed reasonable 
projections of domestic supply. This will force American 
manufacturing to be the shock absorber once again driving 
exports, revenues and jobs offshore.
    Recently, largely due to new Shell gas discoveries, natural 
gas prices have been stable. In a response manufacturing has 
grown. This trend can continue provided that we ensure that gas 
supplies are adequate to meet demand.
    If this viewpoint sounds familiar, it is. As referenced 
earlier back in 2005, DOW's CEO was here, Andrew Liveris. He 
testified before this committee. He indicated that with high 
and volatile natural gas prices our industry would grow but it 
would grow outside the U.S.
    We later announced joint ventures in the Middle East, 
Africa and Asia totaling over $30 billion of investments. 
Today, in contrast, the prospect of abundant natural gas at 
predictable prices has unleashed billions in new chemical 
industry investment back here in the United States. The result 
has been new jobs, more exports and improved trade balance and 
more tax revenue.
    Dow has already invested 500 million in our U.S. Gulf Coast 
assets to increase our raw material flexibility. In April, we 
announced billions more in new investments. Other chemical 
companies are doing likewise. The American Chemical Council 
estimates that a 25% increase in natural gas liquid consumption 
could create 17,000 direct jobs and 400,000 indirect jobs.
    This positive news was simply unthinkable but a few years 
ago. The question is how do we take advantage of the best 
opportunity in decades to fuel a renaissance in American 
manufacturing? We need 3 things.
    First, policy to encourage natural gas production, so that 
supplies are able to meet growing demand. It is imperative that 
we strive for policies that balance supply and demand if we 
want to keep natural gas prices stable. We commend members of 
this committee for trying to bring consensus on the issue of 
OCS development.
    Second, Congress must avoid legislating natural gas demand. 
As we like to say, we've seen this movie before and we don't 
like how it ends. The 1990 Clean Air Act led to fuel switching 
and massive natural gas price spikes. Six million manufacturing 
jobs and $30 billion in chemical exports went away. We simply 
can't afford to make the same mistakes again.
    Third, enact a comprehensive energy policy. Sound national 
energy policy should increase, diversify and optimize domestic 
production of all forms of energy. Rather than pick winners and 
losers Congress and the Administration should encourage 
increased energy efficiency, renewables, clean coal, gas 
production and nuclear power. We need all of them to improve 
our energy security.
    In conclusion, natural gas is a game changer. It can fuel a 
renaissance in American manufacturing. But only if we produce 
enough of it, use it wisely and don't repeat the mistakes of 
the past.
    Thank you for inviting me to speak to you today. I'll 
welcome any of your questions.
    [The prepared statement of Mr. Biltz follows:]

Prepared Statement of George Biltz, Vice President, Energy and Climate 
             Change, The Dow Chemical Company, Midland, MI
Introduction
    The Dow Chemical Company appreciates the opportunity to submit 
these written comments to the Committee on Energy and Natural 
Resources.
    Dow was founded in Michigan in 1897 and is one of the world's 
leading manufacturers of chemicals, plastics and advanced materials. We 
supply more than 3,300 products to customers in approximately 160 
countries, connecting chemistry and innovation with the principles of 
sustainability to help provide everything from fresh water, food, and 
pharmaceuticals to insulation, paints, packaging, and personal care 
products. About 21,000 of Dow's 46,000 employees are in the US, and Dow 
helps provide health benefits to more than 34,000 retirees in the U.S.
    Dow is committed to sustainability. We have improved our 
environmental performance (including on greenhouse gas emissions), and 
we are committed to do even better in the future. Our ambitious 2015 
sustainability goals (http://www.dow.com/sustainability) underscore 
this commitment.
    Dow is an energy-intensive company. We use energy, primarily 
naphtha, natural gas and natural gas liquids (such as ethane), as 
feedstock materials to make a wide array of products essential to our 
economy and quality of life. We also use energy to drive the chemical 
reactions necessary to turn our feedstocks into useful products, many 
of which lead to net energy savings. Dow's global hydrocarbon and 
energy use amounts to the oil equivalent of 850,000 barrels per day, 
approximately the daily energy use of Australia.
    This testimony describes our views on natural gas supply and 
demand, and the value-add created by U.S. manufacturers who use natural 
gas.
    Dow believes that natural gas will play a critical role in US 
energy policy. Because US manufacturing jobs are dependent on the US 
natural gas market, policies that impact natural gas will have a direct 
impact on jobs in the US manufacturing sector. We recommend that any 
natural gas policies carefully consider the need to preserve and 
enhance the competitiveness of U.S. manufacturers.
Natural Gas Fuels US Manufacturing
    Major sectors that use natural gas include the power, 
manufacturing, residential, commercial, and transportation sectors.
    US manufacturers provide the highest value-add of any sector. Using 
natural gas to make petrochemicals results in eight times the value 
over simply combusting it. This productivity stems from the fact that 
the chemical industry uses natural gas not just for fuel and power, but 
also as a raw material or ``feedstock.''
    When natural gas prices are low relative to oil, US chemical 
manufacturers have a competitive advantage. Recent market activity 
underscores the favourable climate for US petrochemical industry. When 
the ratio of oil to gas price is above 7:1, Gulf-Coast-based 
petrochemicals are more competitive versus the world's other major 
chemical-producing regions. The current oilto- gas ratio is very 
favourable for US competitiveness and increases the exports of 
petrochemicals, plastics, and other products.
    Not only do manufacturers provide the greatest value-add, they are 
also the most price sensitive. Those sectors in which demand is most 
sensitive to natural gas prices are termed ``price elastic''. The more 
elastic the demand, the more quickly a sector will change its demand 
for natural gas after a change in price. Inelastic demand occurs when a 
change in price results in little change in demand.
    The industrial sector has the most elastic demand for natural gas. 
From 1997 to 2008, US industrial gas demand fell 22% as average annual 
prices rose 167%. Over the same time, demand for power rose 64% (EIA 
data). The loss in US manufacturing jobs was significant.Indeed, 
government data show that more than six (6) million jobs were lost in 
the US manufacturing sector since 1997, and volatile natural gas prices 
were a significant factor. Change in natural gas price will impact 
industrial sector demand before that in other sectors. For this reason, 
we sometimes say that US manufacturers are the ``shock absorber'' for 
the US natural gas market. The maintenance of a strong presence of 
price-sensitive users will help to minimize price volatility in the 
natural gas market. Government must exercise caution to avoid policies 
that grow inelastic demand to the detriment of price-sensitive users.
    Both price volatility and the ``average'' price over time have an 
impact on the industrial sector. Therefore, policymakers should 
carefully consider the impact of proposed policies on natural gas price 
and the competitiveness of the US manufacturing sector.
    As the figure illustrates, the potential exists for demand to 
outstrip supply, assuming that fuel switching from coal to gas 
continues to accelerate and factoring in the proposals by some to 
displace 25% of our oil imports with natural gas.
Unconventional Natural Gas
    The recent MIT report, The Future of Natural Gas, confirms that the 
US has an abundant supply of natural gas, much of it available at an 
affordable price.
    According to this report, the supply of natural gas is changing, as 
new production of unconventional gas compensate for declining reserves 
of conventional gas (e.g., five shale plays in the US could see a five-
fold growth in production). New supplies are critical as demand for 
natural gas is growing in every sector of the economy, especially power 
generation.
    The report also concludes that the current supply outlook will 
contribute to greater competitiveness of US manufacturing, and 
specifically describes how new sources of natural gas and natural gas 
liquids are changing the economic competitiveness of the chemical 
industry, leading to new investments (and job creation).
    Dow is in general agreement with the report. For example, the 
report portrays an appropriate level of cautious optimism. It says: 
``While the pace of shale technology development has been very rapid 
over the past few years, there are still many scientific and 
technological challenges to overcome before we can be confident that 
this very large resource base is being developed in an optimal 
manner.''
    Dow has concerns, however, with two of the report's 
recommendations. While the study does not openly call for government 
subsidies for natural gas vehicles, it does call for the government to 
revise its policies related to CNG vehicles in order to lower up-front 
costs of such vehicles and the necessary infrastructure. The study also 
does not recognize another fact: Electric vehicles are three times more 
efficient than natural gas vehicles. In addition, the infrastructure 
for an overnight, low-voltage charging infrastructure already exists--
our power grid--and it is cheaper to scale up.
    The second disagreement relates to the development of an efficient 
and integrated global gas market. It states, ``Greater international 
market liquidity would be beneficial to U.S. interests. U.S. prices for 
natural gas would be lower than under current regional markets, leading 
to more gas use in the U.S.'' It is hard to understand how this can be. 
The U.S. has very competitive natural gas prices and exposing it to the 
rest of the world, where prices are linked to oil price, will not lower 
domestic prices. In our view, a global market will raise US prices 
which will be bad for competitiveness of all US energy intensive 
industries including chemicals. If the US were to begin exporting 
natural gas, the world market would equilibrate to one world price 
(with transportation cost differences) which would bring lower prices 
outside the US and higher prices for US consumers.
    The study also offers some acceptable recommendations but in doing 
so calls for unacceptable policy. One recommendation reads, ``In the 
absence of such policy, interim energy policies should attempt to 
replicate as closely as possible the major consequences of a `level 
playing field' approach to carbon-emission reduction. At least for the 
near term, that would entail facilitating energy demand reduction and 
displacement of some coal generation with natural gas.'' We would have 
no problem with the first part of that statement, but do not see the 
need for facilitating displacement of coal with natural gas. It is our 
belief that market and regulatory forces will naturally move it in that 
direction.
    EIA data shows that since 2000, the vast majority of new power 
plants constructed use natural gas. When setting policy, it is 
important to note that homeowners, farmers, and the industrial sector 
are all dependent upon the use of natural gas, and do not have economic 
alternatives. At the same time, the electric power generation and 
transportation markets do have alternative sources of energy. Policy 
that increases demand for natural gas without ensuring that there is 
available supply can increase the price of natural gas and electricity 
for all home-owners, farmers and the industrial sector.
    In the recommendation to ``set a CO2 price for all 
fuels,'' there is no discussion about the negative impact on energy-
intensive trade exposed industries. These increased energy costs would 
not be absorbed by offshore competitors and thus would give them a 
competitive advantage, endangering U.S. jobs.
    Another claim of the report is questionable: ``Displacement of 
coal-fired power by gas-fired power over the next 25 to 30 years is the 
most cost-effective way of reducing CO2 emissions in the 
power sector.'' We would argue that demand reduction via energy 
efficiency is at least as important in cost effectively reducing 
CO2 emissions in the power sector and should preferably be 
pursued prior to any effort to displace coal-fired power by gas. While 
the study considers the impact of natural gas on the government 
objective of environmental protection, it also needs to consider the 
impact that any policies will have on the equally important objectives 
of economic growth and national security. The above recommendation will 
likely increase natural gas prices, which will reduce the 
competitiveness of U.S. industries.
    Finally, the study noticeably lacks any recommendations for a 
streamlined, timely process for exploration and production permitting 
to ensure access to supply despite the report stating ``a robust 
domestic market for natural gas and NGLs will improve competitiveness 
of manufacturing industries dependent on these inputs.'' In our view, 
it is imperative that increased demand not precede increased supply. 
Access to offshore natural gas and crude oil is essential for U.S. 
energy security. Political and regulatory uncertainty threatens to 
significantly reduce the amount of natural gas that can be extracted. 
These issues, including regulations around the use of hydraulic 
fracturing, must be resolved for companies to invest capital in the 
U.S. based on the new natural gas discoveries.
A Potential Renaissance for US Chemical Manufacturers
    What does the promise of increased domestic supply of natural gas 
mean to US manufacturers?
    We believe an increase in the natural gas resource base, especially 
ethane-rich gas such as that in the Marcellus and Eagle Ford regions, 
could be a ``game changer'' for US manufacturers.
    The American Chemistry Council (ACC) recently evaluated the impact 
of a 25 percent increase in the US ethane supply from shale gas. Such 
an increase in ethane supply would generate

   17,000 new jobs in the US chemical industry
   $32 billion increase in US chemical production,
   $16 billion in new capital investment in the chemical 
        industry,
   395,000 new jobs outside the chemical industry, including 
        165,000 jobs in supplier industries, and 230,000 jobs from new 
        capital investment by the chemical industry.

    This would generate an increase in US economic output of $132 
billion per year, and raise $4.5 billion per year in additional annual 
tax revenue for federal, state, and local governments.
    ACC is careful to acknowledge that a reasonable regulatory regime 
will facilitate shale gas development, but the wrong policy initiatives 
(e.g., state moratoria on shale gas development, and other policies 
that artificially increase demand) could derail recovery, economic 
expansion, and job creation.
    The full ACC report is contained in the Appendix to this testimony.
Environmental Issues
    Legitimate concerns have been raised about the use of hydraulic 
fracturing (also known as hydrofracking or fracking) to access 
unconventional gas reserves.
    Dow believes that, if done in a safe and effective manner, 
hydraulic fracturing poses little threat to the environment and is 
essential for the production of natural gas from shale formations.
    As conventional sources of natural gas in the US decline, shale gas 
will play a vital role in the nation's energy demand over the next 
decades.
    Dow produces products used in association with hydraulic 
fracturing, such as biocides for microbial control to ensure gas can 
escape through the fractures. Our biocide products are registered with 
EPA and with each state where the material will be used. The stringent 
regulatory requirements are supported by detailed toxicological and 
environmental fate data which allows selection of proper materials for 
the given application and region.
    In addition to biocides, Dow also produces other products used in 
hydraulic fracturing. Dow has committed to publishing health 
information for all of our products and to make this information 
available on our public website.
    Chemicals in the hydrofracking process make up less than 1 percent 
of the fluids used. Federal law currently requires companies to report 
the hazards of components present in formulations >0.1 percent or >1 
percent depending on the nature of the hazards. The law further 
requires that this hazard information is available to employees via 
Material Safety Data Sheets at all worksites.
    Dow supports transparency with respect to chemical hazards as a 
principal component to ensure worker and environmental safety. We 
promote progressive chemicals management policies and best practices 
worldwide through voluntary standards such as Responsible Carer. We 
believe that disclosure of chemical identity should be pursued to the 
extent possible without compromising true trade secret information, 
while fully characterizing the hazards of the individual components or 
formulated product to alleviate concerns about the risk to human health 
and the environment.
    As this debate further develops, we will share chemicals management 
best practices and provide our feedback on targeted regulations in 
development to preserve the economical production of energy from 
unconventional gas resources. Domestic oil and gas production is a 
necessary part of a balanced energy policy.
U.S. Energy Policy and Natural Gas
    Dow has developed an advanced manufacturing plan to promote a 
competitive manufacturing sector. The plan includes policy 
recommendations in eight areas, ranging from trade and education to 
health care and tax policy. It also calls for a comprehensive energy 
policy, which has four pillars: (1) aggressive pursuit of energy 
efficiency and conservation; (2) increasing, diversifying, and 
optimizing domestic hydrocarbon energy and feedstock supply; (3) 
accelerating development of alternative and renewable energy and 
feedstock sources; and (4) transitioning to a low-carbon economy.
    Natural gas plays a key role in these recommendations. In 
particular, Dow supports policies to increase domestic production of 
natural gas in an environmentally responsible manner, including 
conventional and unconventional natural gas.
    According to the Department of the Interior, there are 93 million 
barrels of oil and 456 trillion cubic feet of natural gas offshore on 
our nation's Outer Continental Shelf (OCS). These are domestic supplies 
that can be produced with state-of-the-art techniques that ensure 
environmentally responsible production, while greatly enhancing our 
nation's energy and feedstock security. Dow has consistently and 
persistently supported expanded access to OCS resources.
    One way to maximize the transformational value of increased oil and 
gas production in the OCS is to share the royalty revenue with coastal 
states and use the federal share to help fund research, development and 
deployment in such areas as energy efficiency and renewable energy. 
Production of oil and gas on federal lands has brought billions of 
dollars of revenue into state and federal treasuries. Expanding access 
could put billions of additional dollars into state and federal 
budgets.
    Dow also believes natural gas can play a role in transitioning to a 
low-carbon economy. In a much-cited study, Princeton scientists Socolow 
and Pacala identified 14 specific solutions, each with the potential to 
reduce one (1) gigaton of carbon dioxide. One of these solutions was 
fuel switching from coal to natural gas in the generation of 
electricity. Such fuel switching has been an ongoing trend in recent 
years, due in part to a downward trend in the price of natural gas. For 
several reasons, this trend is likely to continue, especially as 
pressure builds to retire the oldest coal-fired power plants. However, 
great caution must be taken if the government advances policies to make 
this transition more abrupt.
    Natural gas--including unconventional gas--is a critical component 
of a balanced US energy policy. The key is to ensure alignment between 
supply and demand, and to avoid shocks to the market from unwise 
government policy. The remainder of this section addresses some of 
these important policy issues: inclusion of natural gas through 
imposition of a federal Clean Energy Standard (CES), EPA regulations 
affecting coal-fired power, and tax incentives for natural gas 
vehicles. Each poses a challenge to US manufacturing.
Clean Energy Standard (CES)
    In his last State of the Union address, the President has called 
for ``efficient natural gas'' to be included in the mix of clean energy 
technologies that would receive credit under a clean energy standard 
(CES). We recommend a significant and critical review of such a 
proposal.
    Dow remains concerned about the potential for natural gas 
volatility that is damaging to the manufacturing sector. At a time when 
there continues to be debate about access to domestic natural gas 
supplies, Congress and the Administration must exercise extreme caution 
in pursing policies that encourage fuel switching from coal to natural 
gas in the power sector, which is already happening in the absence of 
government incentives. In this regard, we note that the Bipartisan 
Policy Center, in a landmark study of natural gas volatility, has made 
the same recommendation:

          Government policy at the federal, state and municipal level 
        should encourage and facilitate the development of domestic 
        natural gas resources, subject to appropriate environmental 
        safeguards. Balanced fiscal and regulatory policies will enable 
        an increased supply of natural gas to be brought to market at 
        more stable prices. Conversely, policies that discourage the 
        development of domestic natural gas resources, that discourage 
        demand, or that drive or mandate inelastic demand will disrupt 
        the supplydemand balance, with adverse effects on the stability 
        of natural gas prices and investment decisions by energy-
        intensive manufacturers.

EPA Regulations Affecting Coal-Fired Power
    The government-imposed shocks we worry about most relate to fuel 
switching: (1) from coal to natural gas in the power sector due to EPA 
regulation and (2) from gasoline to natural gas in the transportation 
sector due to government incentives for natural gas vehicles.
    EPA is developing several major regulations (e.g., the recently 
finalized ``transport'' rule and the proposed utility MACT) that will 
increase the cost of operating coal-fired power plants, thus providing 
an added incentive for the retirement of such plants and the 
construction of replacement generation capacity. This replacement 
generation is likely to come from natural gas. Dow believes it would be 
most prudent to ensure a reasonable transition time for the retirement 
of the oldest coal-fired power plants. The more uncertain the 
regulatory environment, the more likely the transition will be abrupt, 
which could alter the demand-supply balance so critical to US 
manufacturers.
Incentives for Natural Gas Vehicles
    Congress is contemplating tax incentives for natural gas vehicles. 
The goal, as noted by proponent T. Boone Pickens, is to replace 25% of 
our oil-based transportation fuel with domestically produced natural 
gas.
    Dow and the chemical industry are opposed to such incentives 
because of the upward pressure they will impose on natural gas demand. 
Data from the Energy Information Agency suggests such a move, in 
combination with expected fuel switching in the power sector, will most 
certainly lead to a situation where demand will outpace supply, with a 
detrimental effect on US manufacturing. History suggests that such 
supply-demand imbalances result in demand destruction for US 
manufacturers.
    This latest push to promote natural gas vehicles raises legitimate 
questions about the incoherent signals that policymakers are sending to 
the transportation sector. Daniel Yergin recently described the 
situation. ``Could natural gas also be a game changer for 
transportation? That is much more of a challenge. Automakers and the 
fuel-supply industry are already dealing with a multitude of 
imperatives-more fuel efficient cars, more bio-fuels, plug-in hybrid 
electric vehicles, pure electric vehicles. Making a push for natural 
gas vehicles would add yet another set of mandates and incentives, 
including the creation of a costly new fueling infrastructure.'' As 
Congress considers the appropriate incentives to advance energy 
security, it should keep in mind that electric vehicles are 3X more 
efficient than natural gas vehicles.
    A recent Ernst & Young analysis concluded that H.R.1380, the 
Natural Gas Act, which would provide tax incentives for natural gas 
vehicles, would be a costly investment. The budget impact is 
approximately $3 billion over five years, $10 billion over ten years, 
and a whopping $135,000 per vehicle, a high figure driven largely by 
the need for substantial infrastructure to support the natural gas 
vehicle market.
    We would also like to note that substantial investment is being 
made to promote natural gas vehicles in the absence of additional 
government incentives. Chesapeake Energy recently announced its 
intention to invest in natural gas vehicles in the absence of 
government incentives.
Conclusions
    We would like the Members of the Committee to remember five major 
points from this testimony.

          1. US manufacturers provide the highest value-add of any 
        natural gas consumer. Every dollar the U.S. chemical industry 
        spends on natural gas as a raw material creates $8 of added 
        value throughout the economy. This creates a ``chain reaction'' 
        for our economy and it means jobs.
          2. Unconventional gas could be a game-changer for US 
        manufacturers, especially as a source of competitively priced 
        feedstock.
          3. Production of unconventional gas, through the technique of 
        hydraulic fracturing can and should be done in an 
        environmentally responsible manner.
          4. Natural gas is a critical component of a balanced US 
        energy policy. The key is to ensure alignment between supply 
        and demand, and to avoid shocks to the market from unwise 
        government policy that restricts supply while artificially 
        increasing demand in the power and transportation sectors.
          5. A comprehensive and sustainable national energy policy is 
        long overdue. Absent such a policy we are in danger of 
        repeating an over-reliance on natural gas and a return to the 
        price volatility that destroyed American manufacturing jobs in 
        the last decade.
   APPENDIX--ACC Study on Shale Gas Shale Gas and New Petrochemicals
   investment: benefits for the economy, jobs, and us manufacturing 
      economics & statistics american chemistry council march 2011
Executive Summary
    Chemistry transforms raw materials into the products and processes 
that make modern life possible. America's chemical industry relies on 
energy derived from natural gas not only to heat and power our 
facilities, but also as a raw material, or ``feedstock,'' to develop 
the thousands of products that make American lives better, healthier, 
and safer.
    Access to vast, new supplies of natural gas from previously 
untapped shale deposits is one of the most exciting domestic energy 
developments of the past 50 years. After years of high, volatile 
natural gas prices, the new economics of shale gas are a ``game 
changer,'' creating a competitive advantage for U.S. petrochemical 
manufacturers, leading to greater U.S. investment and industry growth.
    America's chemical companies use ethane, a natural gas liquid 
derived from shale gas, as a feedstock in numerous applications. Its 
relatively low price gives U.S. manufacturers an advantage over many 
competitors around the world that rely on naphtha, a more expensive, 
oil-based feedstock. Growth in domestic shale gas production is helping 
to reduce U.S. natural gas prices and create a more stable supply of 
natural gas and ethane.
    In its new report, Shale Gas and New Petrochemicals Investment: 
Benefits for the Economy, Jobs and US Manufacturing, the American 
Chemistry Council (ACC) uncovered a tremendous opportunity for shale 
gas to strengthen U.S. manufacturing, boost economic output and create 
jobs.
    ACC analyzed the impact of a hypothetical, but realistic 25 percent 
increase in ethane supply on growth in the petrochemical sector. It 
found that the increase would generate:

   17,000 new knowledge-intensive, high-paying jobs in the U.S. 
        chemical industry
   395,000 additional jobs outside the chemical industry 
        (165,000 jobs in other industries that are related to the 
        increase in U.S. chemical production and 230,000 jobs from new 
        capital investment by the chemical industry)
   $4.4 billion more in federal, state, and local tax revenue, 
        annually ($43.9 billion over 10 years)
   A $32.8 billion increase in U.S. chemical production
   $16.2 billion in capital investment by the chemical industry 
        to build new petrochemical and derivatives capacity
   $132.4 billion in U.S. economic output ($83.4 billion 
        related to increased chemical production (including additional 
        supplier and induced impacts) plus $49.0 billion related to 
        capital investment by the U.S. chemical industry)

    The scenario outlined in ACC's report is corroborated by trends in 
the chemical industry. ACC member companies, including The Dow Chemical 
Company, Shell Chemical, LyondellBasell, Bayer MaterialScience and 
others have announced new investments in U.S. petrochemical capacity to 
benefit from available resources and grow their chemical businesses. 
Some of these investments are being made in areas of the country that 
have been hardest-hit by declines in manufacturing, improving the 
outlook in economically depressed areas of the country. Further 
development of the nation's shale gas and ethane can drive an even 
greater expansion in domestic petrochemical capacity, provided that 
policymakers avoid unreasonable restrictions on supply.
    ACC supports a comprehensive energy policy that promotes energy 
efficiency and conservation, energy diversity, and expanded domestic 
oil and natural gas supply, onshore and offshore. The United States 
must ensure that our regulatory policies allow us to capitalize on 
shale gas as a vital energy source and manufacturing feedstock, while 
protecting our water supplies and environment.
                              Introduction
    This report presents the results of the analysis conducted to 
quantify the economic impact of the additional production of 
petrochemicals and downstream chemical products stimulated by an 
increase in ethane availability. With the development of new shale gas 
resources, the US petrochemical industry is announcing significant 
expansions of petrochemical capacity, reversing a decade-long decline. 
The petrochemical industry is unique in that it consumes energy as a 
raw material in addition to using energy for fuel and power. With vast 
new supplies of natural gas liquids from largely untapped shale gas 
resources, including the Marcellus along the Appalachian mountain 
chain, a new competitive advantage is emerging for US petrochemical 
producers. At a time when the United States is facing persistent high 
unemployment and the loss of high paying manufacturing jobs, these new 
resources provide an opportunity for new jobs in the petrochemical 
sector.
    This report assumes a one-time $16.2 billion private investment 
over several years in new plant and equipment for manufacturing 
petrochemicals\1\. This investment will create jobs and additional 
output in other sectors of the economy and also will lead to a 25 
percent increase in US petrochemicals capacity and $32.9 billion in 
additional chemical industry output. In addition to direct effects, 
indirect and induced effects from these added outputs will lead to an 
additional $50.6 billion gain elsewhere in the economy. It will create 
more than 17,000 jobs directly in the chemical industry. These are 
knowledge-intensive, high-paying jobs, the type of manufacturing jobs 
that policy-makers would welcome in this economy. In addition to 
chemical industry jobs, another 165,000 jobs would be created elsewhere 
in the economy from this chemical industry investment, totaling more 
than 182,000 jobs. The added jobs created and further output in turn 
would lead to a gain in federal, state and local tax collections, about 
$4.4 billion per year, or $43.9 billion over 10 years.
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    \1\ The $16.2 billion capital investment by the chemical industry 
is based on historical capital-output ratios developed from data from 
the Census Bureau.
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    Thus, based on a large private investment initiative driven by 
newly abundant domestic supplies of natural gas, a significant 
strengthening of the vital US petrochemical industry is possible. A 
reasonable regulatory regime will facilitate this development, while 
the wrong policy initiatives could derail this recovery and expansion 
and associated job creation.
    The scenario analyzed in this paper that considers a 25 percent 
increase in ethane is not merely a thought exercise. New investments in 
petrochemical capacity to utilize this resource advantage are already 
being made by chemical companies. The assumptions are reasonable and 
are consistent with public announcements by companies such as Dow 
Chemical, Shell Chemical, LyondellBasell and Bayer MaterialScience 
among others.
    In addition to providing a productive and job-creating outlet for 
increased ethane supplies, the development of additional cracking 
capacity has the indirect effect of supporting natural gas development. 
Because of the recent development of gas from shale formations, the 
additional supply has pushed down the price of natural gas. Natural gas 
is an important fuel for home heating and is a vital input to many US 
manufacturers. Lower natural gas prices, however, also lower the return 
on investment for shale gas producers. Some shale gas formations, 
including the Eagle Ford and parts of the Marcellus are rich in natural 
gas liquids. By providing a market for the co-produced natural gas 
liquids, ethane in particular, shale gas production remains economic.
Energy Use and the Chemical Industry
    The business of chemistry transforms natural raw materials from 
earth, water, and air into valuable products that enable safer and 
healthier lifestyles. Chemistry unlocks nature's potential to improve 
the quality of life for a growing and prospering world population by 
creating materials used in a multitude of consumer, industrial and 
construction applications. The transformation of simple compounds into 
valuable and useful materials requires large amounts of energy.
    The business of chemistry is energy-intensive. This is especially 
the case for basic chemicals, as well as certain specialty chemical 
segments (e.g., industrial gases). The largest user of energy is the 
petrochemical and downstream chemical derivatives business. Inorganic 
chemicals and agricultural chemicals also are energy-intensive.Figure 1 
illustrates the ethylene supply chain from ethane feedstock through 
petrochemical intermediates and final end use products. Figure 1: A 
Simplified Ethylene Flow Chart Bottles, Film Low Density Polyethylene 
(LDPE) and Linear Low Density Polyethylene (LLDPE) Ethylene Ethane 
Miscellaneous Chemicals Linear Alcohols Ethylbenzene Fibers Ethylene 
Oxide Food Packaging, Film, Trash Bags, Diapers, Toys, Housewares High 
Density Polyethylene (HDPE) Housewares, Crates, Drums, Bottles, Food 
Containers Ethylene Dichloride Vinyl Chloride PVC Siding, Window 
Frames, Swimming Pool Liners, Pipes Ethylene Glycol Automotive 
Antifreeze Polyester Resin Miscellaneous Pantyhose, Clothing, Carpets 
Styrene Polystyrene Resins Miscellaneous Models, Cups,
    Insulation Styrene Acrylonitrile Resins
    Unique among manufacturers, the business of chemistry relies upon 
energy inputs, not only as fuel and power for its operations, but also 
as raw materials in the manufacture of many of its products. For 
example, oil and natural gas are raw materials (termed ``feedstocks'') 
for the manufacture of organic chemicals. Petroleum and natural gas 
contain hydrocarbon molecules that are split apart during processing 
and then recombined into useful chemistry products. Feedstock use is 
concentrated in bulk petrochemicals and fertilizers.
    There are several methods of separating or ``cracking'' the large 
hydrocarbon chains found in fossil fuels (natural gas and petroleum). 
Natural gas is processed to produce methane and natural gas liquids 
(NGLs) that are contained in the natural gas. These natural gas liquids 
include ethane, propane, and butane, and are produced mostly via 
natural gas processing. That is, stripping the NGLs out of the natural 
gas (which is mostly methane) that is shipped to consumers via 
pipelines. This largely occurs in the Gulf Coast region and is the 
major reason the US petrochemicals industry developed in that region. 
Ethane is a saturated C2 light hydrocarbon; a colorless and 
odorless gas. It is the primary raw material used as a feedstock in the 
production of ethylene and competes with other steam cracker 
feedstocks. Propane is also used as a feedstock but it is more widely 
used as a fuel. Butane is another NGL feedstock.
    Petroleum is refined to produce a variety of petroleum products, 
including naphtha and gas oil, which are the primary heavy liquid 
feedstocks. Naphtha is a generic term for hydrocarbon mixtures that 
distill at a boiling range between 70 C and 190 C. The major components 
include normal and isoparaffins, naphthenes and other aromatics. Light 
or paraffinic naphtha is the preferred feedstock for steam cracking to 
produce ethylene, while heavier grades are preferred for gasoline 
manufacture. Gas oil is another distillate of petroleum. It is an 
important feedstock for production of middle distillate fuels-kerosene 
jet fuel, diesel fuel and heating oil-usually after desulfurization. 
Some gas oil is used as olefin feedstock.
    Naphtha, gas oil, ethane, propane and butane are processed in large 
vessels or ``crackers'', which are heated and pressurized to crack the 
hydrocarbon chains into smaller ones. These smaller hydrocarbons are 
the gaseous petrochemical feedstocks used to make the products of 
chemistry. In the US petrochemical industry, the organic chemicals with 
the largest production volumes are methanol, ethylene, propylene, 
butadiene, benzene, toluene and xylenes. Ethylene, propylene and 
butadiene are collectively known as olefins, which belong to a class of 
unsaturated aliphatic hydrocarbons. Olefins contain one or more double 
bonds, which make them chemically reactive. Benzene, toluene and 
xylenes are commonly referred to as aromatics, which are unsaturated 
cyclic hydrocarbons containing one or more rings. Another key 
petrochemical feedstock-- methane-- is directly converted from the 
methane in natural gas and does not undergo the cracking process. 
Methane is directly converted into methanol and ammonia. Olefins, 
aromatics and methanol are generally referred to as primary 
petrochemicals, and are the chemical starting point for plastics, 
pharmaceuticals, electronic materials, fertilizers, and thousands of 
other products that improve the lives of a growing population.
    Ethane and propane derived from natural gas liquids are the primary 
feedstocks used in the United States to produce ethylene, a building 
block chemical used in thousands of products, such as adhesives, tires, 
plastics, and more. To illustrate how ethylene is used in the economy, 
a simplified flow chart is presented in *Figure 1. While propane has 
additional non-feedstock uses, the primary use for ethane is to produce 
petrochemicals;, in particular, ethylene. Thus, if the ethane supply in 
the US increases by 25%, it is reasonable to assume that, all things 
being equal, ethylene supply will also increase by 25%.
---------------------------------------------------------------------------
    * All figures have been retained in committee files.
---------------------------------------------------------------------------
    Ethane is difficult to transport, so it is unlikely that the 
majority of excess ethane supply would be exported out of the United 
States. As a result, it is also reasonable to assume that the 
additional ethane supply will be consumed domestically by the 
petrochemical sector to produce ethylene. In turn, the additional 
ethylene and other materials produced from the ethylene are expected to 
be consumed downstream, for example, by plastic resin producers. This 
report presents the results of an analysis that quantified the economic 
impact of the additional production of petrochemicals and downstream 
chemical products.
    The report also examines the economic impact of the investment in 
new plant and equipment needed to enable the petrochemical and 
derivatives sectors to take advantage of the increased ethane supply. 
Because the focus of this analysis is the impact of a 25% increase in 
ethane availability, this analysis does not capture any additional 
activity that could be generated if methanol and ammonia production 
were to return or increase to prior levels due to the increased 
availability of natural gas.
    Increased ethane production is already occurring as gas processors 
build the infrastructure to process and distribute production from 
shale gas formations. According to the Energy Information 
Administration (EIA), ethane supply has already grown by roughly 20%. 
Chemical producers are starting to take advantage of these new ethane 
supplies with crackers running at 95% of capacity, and several large 
chemical companies have announced plans to build additional capacity. 
And because the price of ethane is low relative to oil-based feedstocks 
used in other parts of the world, US-based chemical manufacturers are 
contributing to strong exports of petrochemical derivatives and 
plastics. In 2010, exports in basic chemicals and plastics were up 28% 
from 2009. The trade surplus in basic chemicals and plastic surged to a 
record $16.4 billion.
The Development of Shale Gas
    One of the more interesting developments in the last five years has 
been the dynamic shift in natural gas markets. Between the mid-1960s 
and the mid-2000s, proved natural gas reserves in the United States 
fell by one-third, the result of restrictions on drilling and other 
supply constraints. Starting in the 1990s, government promoted the use 
of natural gas as a clean fuel, and with fixed supply and rising demand 
from electric utilities, a natural gas supply shortage occurred, 
causing prices to rise from an average of $1.92 per thousand cubic feet 
in the 1990s to $7.33 in 2005. Rising prices were exacerbated by the 
effects of hurricanes Katrina and Rita in 2005, which sent prices over 
$12.00 per thousand cubic feet for several months due to damage to gas 
production facilities.
    Shale and other non-conventional gas were always present 
geologically in the United States. Figure 2 illustrates where shale gas 
resources are located in the United States. These geological formations 
have been known for decades to contain significant amounts of natural 
gas, but it was not economically feasible to develop given existing 
technology at the time. It should be noted, however, that uneconomic 
resources often become marketable assets as a result of technological 
innovation, and shale gas is a prime example.
    Over the last five years, several factors have combined to 
stimulate the development of shale gas resources. First was a new way 
of gathering natural gas from tight-rock deposits of organic shale 
through horizontal drilling combined with hydraulic fracturing. 
Horizontal drilling allows producers to drill vertically several 
thousand feet and then turn 90 degrees and drill horizontally, 
expanding the amount of shale exposed for extraction. With the ability 
to drill horizontally, multiple wells from one drilling pad (much likes 
spokes on a wheel) are possible, resulting in a dramatic expansion of 
shale available for extraction, which significantly boosts 
productivity. A typical well might drill 1+ miles beneath the surface 
and then laterally 2,000- 6,000 feet.
    The second innovation entailed improvements to hydraulic fracturing 
(or fracking). This involves fracturing the low-permeability shale rock 
by using water pressure. Although these well stimulation techniques 
have been around for nearly 50 years, the technology has significantly 
improved. A water solution injected under high pressure cracks the 
shale formation. Small particles, usually sand, in the solution hold 
the cracks open, greatly increasing the amount of natural gas that can 
be extracted. Fracturing the rock using water pressure is often aided 
by chemistry (polymers, gelling agents, foaming agents, etc.). A 
typical well requires two to three million gallons of water and 1.5 
million pounds of sand. About 99.5% of the mixture is sand and water. 
Figure 3 illustrates these technologies. Another important technology 
is multi-seismology that allows a more accurate view of potential shale 
gas deposits.
    With these innovations in natural gas drilling and production, the 
productivity and profitability of extracting natural gas from shale 
deposits became possible. Further, unlike traditional associated and 
non-associated gas deposits that are discrete in nature, shale gas 
often occurs in continuous formations. While shale gas production is 
complex and subject to steep production declines, shale gas supply is 
potentially less volatile because of the continuous nature of shale 
formations. Many industry observers suggest that the current state of 
shale gas operations are more closely analogous to manufacturing 
operations than traditional oil and gas exploration, development and 
production.
    The United States is now estimated to possess 2,552 trillion cubic 
feet (TCF) of natural gas reserves, 32% of which is shale gas (827 TCF) 
that no one knew how to extract economically as recently as five years 
ago. This translates into an additional supply of 36 years at current 
rates of consumption of about 23 TCF per year. Total US natural gas 
resources are estimated to be large enough to supply over 100 years of 
demand. In less than two years, the US has sharply reduced gas imports 
from Canada and liquefied natural gas (LNG) receipts. These new 
technical discoveries have vastly expanded reserves and will offset 
declines in conventional associated natural gas production.
    To date, the Barnett, Haynesville, and Woodford basins have 
received the most attention. But not all shale gas formations are 
identical: some have little or no NGLs. Haynesville is reported to be 
mostly dry, while Barnet has dry and rich NGL regions. The Eagle Ford 
shale formation in Texas is close to the existing petrochemical 
industry and infrastructure and portions are reported to be rich in 
ethane and other NGLs. The liquids content adds another layer of 
complexity and economic attractiveness to the shale gas growth story. 
More recently, the Marcellus basin (by some estimates the largest known 
shale deposit in the world) has witnessed significant development. 
Portions of this formation are rich in NGLs but at a distance from the 
Gulf Coast where much of the existing petrochemical industry exists. 
Significant development of infrastructure (pipelines, ethane recovery, 
etc.) would be needed and could also include investment in 
petrochemical and derivatives capacity. Thus, areas in western 
Pennsylvania, New York and/or West Virginia could become the next US 
petrochemical hub. The governor of West Virginia, for example, has 
recently formed the Marcellus to Manufacturing Task Force to harness 
business opportunities surrounding development of the Marcellus basin. 
In addition, the Eagle Ford shale formation in Texas is close in 
location to the US petrochemical industry (and infrastructure) in the 
Gulf Coast and reported to be rich in ethane and other NGLs. Better 
returns from extracting and marketing liquids could provide an added 
incentive for shale investment beyond profits arising from the thermal 
value of natural gas from shale deposits.
    Higher prices for natural gas in the last decade (especially after 
hurricanes Katrina and Rita) and the advances in horizontal drilling 
and hydraulic fracturing (i.e., chemistry in action) changed the 
dynamics for economic shale gas extraction. The latter technologies 
allowed extraction of shale gas at about $7.00 per thousand cubic feet, 
which was well below prices of natural gas during the time just after 
the hurricanes. With new economic viability, natural gas producers 
responded by drilling, setting off a ``shale gas rush'', and as 
learning curve effects took hold, the cost to extract shale gas 
(including return on capital) fell, making even more supply (and 
demand) available at lower cost. Although the path was irregular, 
average daily consumption of natural gas rose from 60.3 billion cubic 
feet (BCF) per day in 2005 to 62.0 BCF per day in 2009. Moreover, since 
the mid-2000s, US-proved natural gas reserves have risen by one-third. 
In economists' terms, the supply curve shifted to the right, resulting 
in lower prices and greater availability. During this same time, 
average natural gas prices fell from $7.33 per thousand cubic feet in 
2005 to $3.65 per thousand cubic feet in 2009. In 2010, a recovery of 
gas-consuming industries and prices occurred. Average daily consumption 
rose to 66.0 BCF and prices strengthened to $4.14 per thousand cubic 
feet. Figure 4 illustrates how this new technology's entrance into the 
market pushed prices lower and expanded supply.
    The results of the shift in North American natural gas markets have 
had the positive effect of lowering prices and expanding supply. Shale 
gas is thus a ``game changer''. In the decades to come, shale gas could 
provide 25% of US natural gas needs, compared to 8 percent in 2008. The 
availability of this low priced natural gas (and ethane) could improve 
US chemical and other industry competitiveness. A number of other 
leading industries, including aluminum, cement, iron and steel, glass, 
and paper, are large consumers of natural gas that also would benefit 
from shale gas developments and could conceivably boost capital 
investments and output.
    With rising population and incomes, as well as increased economic 
activity and regulations, promoting natural gas use in electricity 
generation would tend to shift the demand curve to the right and move 
it up along the supply curve. This could partially offset some of the 
positive gains achieved during the past five years, although further 
technological developments in drilling and fracturing could spur even 
more abundant economic resources.
    The use of hydraulic fracturing in conjunction with horizontal 
drilling has opened up resources in low permeability formations that 
would not be commercially viable without this technology, but there are 
some policy risks. Some public concern, however, has been raised 
regarding hydraulic fracturing due to the large volumes of water and 
potential contamination of underground aquifers used for drinking 
water, although fracking occurs well below drinking water resources. 
Limiting the use of hydraulic fracturing would impact natural gas 
production from low permeability reservoirs. Ill-conceived policies 
that restrict supply or artificially boost demand are also risks. Local 
bans or moratoria could present barriers to private sector investment. 
A final issue is the need for additional gathering, transport and 
processing infrastructure. The Marcellus and some other shale gas 
deposits are located outside the traditional natural gas supply 
infrastructure to access the shale gas.
    The United States must ensure that our regulatory policies allow us 
to capitalize on shale gas as a vital energy source and manufacturing 
feedstock, while protecting our water supplies and environment. We 
support state-level oversight of hydraulic fracturing, as state 
governments have the knowledge and experience to oversee hydraulic 
fracturing in their jurisdictions. We are committed to transparency 
regarding the disclosure of the chemical ingredients of hydraulic 
fracturing solutions, subject to the protection of proprietary 
information.
Shale Gas and Industry Competitiveness
    The developments in shale gas will engender the wider availability 
of low cost, domestic energy. Because US petrochemicals predominantly 
use ethane and other natural gas liquids, the competitiveness of the 
industry is heavily dependent upon the price of these liquids and US 
natural gas, as well as the price of competitive feedstocks.
    As a rough rule of thumb, when the ratio of the price of oil to the 
price of natural gas is more than 7:1, the competitiveness of Gulf 
Coast-based petrochemicals and derivatives vis-a-vis other major 
producing regions is enhanced. In the United States, over 85 percent of 
ethylene, for example, is derived from natural gas liquids while in 
Western Europe over 70 percent is derived from naphtha, gas oil and 
other light distillate oil-based products.
    The price of naphtha, gas oil and other light distillate oil-based 
products are related to the price of oil, a commodity with prices set 
by global supply and demand. The price of naphtha (in Western Europe, 
for example) is highly correlated with the price of oil (Brent) as 
illustrated in Figure 5. As a result, prices for naphtha will parallel 
the price for oil.
    On the other hand, natural gas markets are regional in nature, with 
the United States and Canada being an integrated regional market. The 
price of ethane is correlated with US natural gas prices (Henry Hub). 
This is illustrated in Figure 6. As a result, prices for ethane will 
tend to parallel the price for natural gas. The correlation has 
weakened in recent years and other explanatory variables such as the 
prices of alternative feedstocks (like propane, butane, and naphtha) 
are important. The latter tend to be correlated with the price of oil.
    Thus, the feedstock costs (and relative competitiveness) of 
cracking ethane and naphtha will follow the respective costs of natural 
gas and oil. Historically, other factors (co-product prices, exchange 
rates, capacity utilization, etc.) have played a role as well. This 
shift toward more and lower-cost natural gas (and disconnect of its 
relationship with oil prices) has benefitted the US chemical industry, 
resulting in greater competitiveness and heightened export demand. This 
helped offset downward pressures during the recession.
    Figure 7 shows the long-term trend in the oil-to-gas ratio, from 
1970 through 2015. The early- 2000s represent a period in which US 
petrochemicals were facing competitive challenges. This was in contrast 
to the 1970s and the period through early-1990s, when US natural gas 
prices were low and oil prices were high, the latter the result of the 
Gulf War. In the 1990s, US energy policy favored use of natural gas in 
electricity generation but did little to address supply. In late- 2000, 
the first of several large price spikes occurred, resulting in higher 
US natural gas prices as US supply was constrained. This continued 
during the next five or so years, with subsequent natural gas price 
spikes pushing the oil-to-gas ratio down to levels associated with 
noncompetitiveness. At that time there were numerous concerns about the 
long-term viability of the US petrochemical industry. Moreover, a 
number of plant closures occurred during this period and investment 
flowed to the Middle East and other ``remote gas'' locations.
    As noted, with several shale gas technological developments, 
learning curve effects, and the hurricanes of 2005 (and subsequent 
spikes in natural gas prices) the oil-to-gas relationship began to 
change. With the development of low cost shale gas resources in the 
United States, the oil-to-gas ratio has improved, from a non-
competitive ratio of 5.5:1 in 2003 and 6.3:1 in 2005 to 15.9:1 in 2009 
and 17.9:1 in 2010. The current ratio is very favorable for US 
competitiveness and exports of petrochemicals, plastics and other 
derivatives. Abundant availability and economic viability of shale gas 
at prices suggests a continued crude oil-natural gas price disconnect. 
Moreover, forecasters at the EIA and energy consultants expect high 
oilto- gas ratios to continue.
    Figure 8 illustrates the changing dynamics of natural gas relative 
to oil from a more long-term perspective. The chart measures the real 
price of oil (in constant 2009 dollars) relative to this oil-to-gas 
ratio for the years 1974 through 2010. Five-year moving averages are 
employed to better illustrate these trends. When the oil-to-gas ratio 
is high, US Gulf Coast petrochemicals are generally advantaged, as they 
largely were from 1974 through the late-1990s. But with the promotion 
of natural gas demand and supply constraints, the situation worsened 
last decade. Moreover, the real price of oil rose during the past 10 
years, which led to advantages among remote locations with abundant 
natural gas, most notably in the Middle East. With the advent of shale 
gas, the US petrochemical competitive position is once again evolving, 
returning closer to the situation which prevailed during the 1980s, 
when oil prices were relatively high compared to natural gas prices.
    Figure 9 illustrates a global petrochemical cost curve for 2010. 
Using data for 26 major nations and sub-regions, the curve reflects the 
differences in plant capacity and feedstock slates and shows how the US 
has moved to a globally competitive position\2\. The scale is not 
included in Figure 9 as the figure is only intended to illustrate the 
short-run supply curve. The cost curve is built on the cumulative 
petrochemical capacity from the lowest cost producers (in the Middle 
East) to the highest cost producers (in Northeast Asia). While the 
Middle Eastern facilities are substantially advantaged relative to the 
marginal producers their competitiveness is almost comparable to US 
ethane-based producers. In the 2010, the Northeast Asian and Western 
European producers appear to be the least competitive. The latter are 
not only highcost producers but also have smaller facilities with an 
average age of around 35 years resulting in substantially higher 
maintenance spending relative to their global competitors. As recently 
as 2005, the United States ranked behind Western Europe. With the 
revolution in shale gas, US producers have moved down the cost curve 
and now, rank behind Canada and the Middle East.
---------------------------------------------------------------------------
    \2\ Petrochemical costs vary depending on historical feedstock 
costs, by-product credits, cost of fuels and other utilities, hourly 
wages and staffing levels, other variable operating costs, and fixed 
costs as well as differences in operating rates. The vertical axis 
reflects the cash (or variable) costs on a per pound basis while the 
horizontal axis reflects the corresponding capacity for the country or 
region.
---------------------------------------------------------------------------
    Figure 10 illustrates the competitive dynamics of petrochemicals 
and derivatives by examining the strong correlation between 
thermoplastic exports (as measured in millions of pounds) and the oil-
to-gas ratio. As a result of shale gas (and weak industrial demand for 
gas), the US oil-to- gas ratio has been above 7:1 for several years. 
The ratio of oil prices to natural gas prices has been over 22:1 
recently. This position is very favorable for US competitiveness and 
exports of petrochemicals, plastics and other derivatives. In 2010, the 
US Gulf Coast cost position improved so much that the region now is 
second only to the Middle East in terms of competitiveness. As a 
result, for example, US plastic exports are up nearly 10% due to this 
improved position. Furthermore, ethane supplies are tightening in the 
Middle East and are constrained. The era of low-cost feedstocks is over 
for some producing nations in that region. This will also aid US 
competitiveness and may induce capital investment in the United 
States.With the further development of shale gas, the oil-to-gas ratio 
is expected to remain high, and the future for the US petrochemical 
industry appears positive. This analysis seeks to quantify the economic 
impact of the additional production of petrochemicals and downstream 
chemical products.
Methodology and Assumptions
    The objective of the research was to quantify the effects of 
private investment in US petrochemicals and downstream chemical 
products on additional output of the industry, as well as indirect and 
induced effects on other sectors of the economy. The economic impact of 
new investment is generally manifested through four channels:

   Direct impacts--such as the employment, output and fiscal 
        contributions generated by the sector itself
   Indirect impacts--employment and output supported by the 
        sector via purchases from its supply chain
   Induced impacts--employment and output supported by the 
        spending of those employed directly or indirectly by the sector
   Spillover (or catalytic) impacts--the extent to which the 
        activities of the relevant sector contribute to improved 
        productivity and performance in other sectors of the economy

    The analysis focused on the first three channels. Spillover (or 
catalytic) effects would occur from new investment in petrochemicals, 
but these positive externalities are difficult to quantify and thus 
were not examined in the analysis. These positive effects could include 
heightened export demand and the impacts on the chemical industry from 
renewed activity among domestic end-use customer industries. Due to 
model limitations, the impact on exports cannot be separately 
identified, but clearly, increased production of petrochemicals would 
likely lead to higher exports because of enhanced competitiveness.
    In addition to added output, the effects on employment and tax 
revenues also were assessed. To accomplish the goals of the analysis, a 
robust model of the direct, indirect and other economic effects is 
needed, as well as reasonable assumptions and parameters of the 
analysis. To estimate the economic impacts from increasing investment 
in US petrochemicals production, the IMPLAN model was used. The IMPLAN 
model is an input-output model based on a social accounting matrix that 
incorporates all flows within an economy. The IMPLAN model includes 
detailed flow information for 440 industries. As a result, it is 
possible to estimate the economic impact of a change in final demand 
for an industry at a relatively fine level of granularity. For a single 
change in final demand (i.e., change in industry spending), IMPLAN can 
generate estimates of the direct, indirect and induced economic 
impacts. Direct impacts refer to the response of the economy to the 
change in the final demand of a given industry to those directly 
involved in the activity. Indirect impacts (or supplier impacts) refer 
to the response of the economy to the change in the final demand of the 
industries that are dependent on the direct spending industries for 
their input. Induced impacts refer to the response of the economy to 
changes in household expenditure as a result of labor income generated 
by the direct and indirect effects.
    The analysis was broken into two parts: the one-time change in 
final demand that occurs during the initial capital investment phase 
when new plant and equipment are purchased and the ongoing change in 
final demand that occurs with a 25% increase in ethane production in 
the United States. It was assumed that production of ethylene and 
downstream plastics resins would experience a similar increase. Since 
99% of all US ethane supply goes into ethylene production, and over 82% 
of ethylene goes into plastic resins, this linear relationship is a 
reasonable assumption. Other ethylene derivatives (synthetic rubber, 
polyolefins, etc.) production is expected to expand as well, but not by 
as much. Table 1 details the additional chemical industry output 
generated by a 25% increase in ethane production. The assumption that 
production of ethylene will increase is reasonable and consistent with 
public announcements by companies such as Dow Chemical, Shell Chemical, 
Lyondell Basell and Bayer Material Science, among others.

   In December 2010, Dow Chemical announced it will increase 
        ethane cracking capability on the US Gulf Coast by 20 percent 
        to 30 percent over the next two to three years, and is 
        reviewing options for building a natural gas liquids (NGL) 
        fractionator to secure ethane supplies. The latter provides a 
        new source of NGL supplies, helping to position U.S. 
        petrochemical companies as one of the lowest cost producers of 
        ethylene globally. Both actions are intended to capitalize on 
        the favorable supply dynamics in North America.

   In the Autumn/Winter 2010 issue of Shell Chemicals Magazine, 
        the company discussed how its base chemicals operations in the 
        Gulf Coast region have taken advantage of changing hydrocarbon 
        market dynamics to strengthen its feedstock processing 
        capability. The turnaround in competitive positioning achieved 
        was deemed vital to the success of Shell's chemicals business 
        in the United States and for future security of supply to 
        customers in North American heartland markets.
   Bayer MaterialScience has expressed interest in siting an 
        ethane cracker in West Virginia at one of its two manufacturing 
        complexes in the state, according to press reports. There are 
        no ethane crackers in the Marcellus region. A West Virginia 
        ethane cracker would be the first to serve the hub of chemical 
        manufacturing in the western Pennsylvania/West Virginia area.

    The IMPLAN model used to analyze this boost of production was 
adjusted to avoid double counting the impact of increased petrochemical 
and intermediate organic chemical demand. In addition, spending for oil 
and gas production and related services was excluded. Thus, the model 
was tailored to incorporate an annual increase in spending of $32.8 
billion from an expansion of petrochemicals and associated downstream 
chemical manufacturing activity.

 Table 1: Additional Chemical Industry Output Generated by a 25 percent
                      Increase in Ethane Production
------------------------------------------------------------------------
                                                                    $
                                                                 Billion
------------------------------------------------------------------------
Bulk Petrochemicals and Organic Intermediates                     $18.3
Carbon Black                                                        0.2
Plastics Resins                                                    13.1
Synthetic Rubber                                                    1.0
Man-Made Fibers                                                     0.3
------------------------------------------------------------------------
      Total                                                       $32.8
------------------------------------------------------------------------

    Lower natural gas costs also could engender new carbon black 
capacity (in line with new synthetic rubber capacity and higher 
activity in rubber products). Higher activity in downstream plastic 
products manufacturing (or processing) would lead to higher sales of 
plastic additives and plastics compounding. Similarly, higher activity 
in downstream tire and other rubber products manufacturing (or 
processing) would lead to higher sales of rubber processing chemicals. 
These effects are not captured in the analysis. Another effect that is 
not captured in the analysis is the improved competitive position which 
would result in higher chemical exports.
    Because the model does not include the effects of the investment 
needed to produce the added $32.8 billion output of petrochemicals that 
would be generated by the 25 percent increase in ethane supply, the 
value of the capital investment was separately estimated. Based on the 
economics and chemical engineering literature, typical capital-output 
ratios were estimated to range from 0.27:1 to 0.73:1. That is, $1.0 
billion in added petrochemical and derivative output could require new 
capital investment ranging from $270 million to $730 million. Data 
sources for calculating these capital-output ratios include the 
Quarterly Financial Report prepared by the US Census Bureau, fixed 
asset and industry data from the Bureau of Economic Analysis (BEA), and 
the Corporation Sourcebook prepared by the Statistics of Income 
Division of the Internal Revenue Service. The capital-output ratio of 
0.49:1 that was used was based on an average of ratios calculated. That 
is, $1.0 billion in added petrochemical and derivative output would 
require new capital investment on the order of $490 million. The scope 
of the analysis was limited to the chemical sector and did not include 
the investment or business activity generated by the extraction, 
recovery or infrastructure related to delivery of the ethane to 
chemical plants. It also did not include the effects from investment in 
development and production of shale gas nor pipeline and other 
infrastructure development.
    The results of the analysis indicate that the added $32.8 billion 
output of petrochemicals and derivatives would necessitate new capital 
investment of $16.2 billion. These investments could be a combination 
of debottlenecking, brownfield and greenfield projects. The composition 
by asset type for this capital investment was derived using the average 
historical mix for the chemical industry's expenditures for fixed 
assets. The fixed asset data from the BEA was used. These assumed 
spending by asset type were assigned to the appropriate NAICS industry 
and the IMPLAN model was re-run to incorporate the effects of the new 
investment. Effects on added output, jobs, and tax revenues from the 
new investment spending were assumed to be a one-time impact and were 
modeled as such. Although the spending would likely occur over the 
period of three years, distinct phases in the project are likely, with 
engineering and design occurring early, followed by equipment 
procurement, and then construction and installation. Some overlap of 
construction activity is possible but assumed to be modest in scope.
Added Output and Job Creation
    The output and employment generated by additional ethane 
utilization in the petrochemical and derivative industries is 
significant. The additional $32.8 billion in chemical industry activity 
would generate over 17,000 high-paying, desirable jobs in the chemical 
industry. Innovative, creative and pacesetting, the business of 
chemistry is one of the most knowledge-intensive industries in the 
manufacturing sector. ``Knowledge worker'' is a term that was 
originally coined by management guru, Peter Drucker, several decades 
ago. It refers to employees with university degrees/training whose 
principal tasks involve the development or application of specialized 
knowledge in the workplace. A study by Industry Canada showed that 38% 
of all employees in the US business of chemistry have at a minimum, a 
university degree. This is nearly double the average in US 
manufacturing.

 Table 2: Economic Impact from Expanded Production of Petrochemical and
          Derivatives from a 25% Increase in Ethane Production
------------------------------------------------------------------------
                                                       Payroll   Output
               Impact Type                Employment     ($        ($
                                                      Billion)  Billion)
------------------------------------------------------------------------
Direct Effect                               17,017       $2.4     $32.8
Indirect Effect                             79,870        6.6      36.9
Induced Effect                              85,563        4.1      13.7
------------------------------------------------------------------------
    Total Effect                           182,450      $13.1     $83.4
------------------------------------------------------------------------

    In addition, the increased use of ethane by the chemical industry 
would generate purchases of raw materials, services, and other supplies 
throughout the supply chain. Thus, nearly another 80,000 indirect jobs 
would be supported by the boost in ethane production. Finally, the 
wages earned by new workers in the chemical industry and workers 
throughout the supply chain are spent on household purchases and taxes 
generating more than 85,000 jobs induced by the response of the economy 
to changes in household expenditure as a result of labor income 
generated by the direct and indirect effects. All told, the additional 
$32.8 billion in chemical industry output from a 25% increase in ethane 
production would generate $83.4 billion in output to the economy and 
more than 182,000 new jobs in the United States generating a payroll of 
$13.1 billion. This comes at a time when 15 million Americans are out 
of work. Moreover, the new jobs would primarily be in the private 
sector. A detailed table on jobs created by industry is presented in 
Appendix Table 1.

   Table 3: Economic Impact from New Investment in Plant and Equipment
------------------------------------------------------------------------
                                                       Payroll   Output
               Impact Type                Employment     ($        ($
                                                      Billion)  Billion)
------------------------------------------------------------------------
Direct Effect                               54,094      $ 4.3     $16.2
Indirect Effect                             74,479        5.1      16.8
Induced Effect                             100,549        4.8      16.1
------------------------------------------------------------------------
    Total Effect                           229,122      $14.2     $49.0
------------------------------------------------------------------------

    Following a decade of contraction in the petrochemical sector, new 
plant and equipment would be required to use the additional feedstock 
supplies. A one-time $16.2 billion investment would generate more than 
54,000 jobs, mostly in the construction and capital equipmentproducing 
industries. Indirectly, another $16.8 billion in output and more than 
74,000 jobs would be generated throughout the supply chain. Finally, a 
further $16.1 billion in output and more than 100,000 jobs would be 
created through the household spending of the workers building, making, 
and installing the new plant and equipment and those throughout the 
supply chain. All told, a $16.2 billion investment in the chemical 
industry would support nearly 230,000 jobs and $14.2 billion in 
payrolls. These impacts would likely be spread over several years. A 
detailed table on jobs created by industry is presented in Appendix 
Table 2.
Tax Revenues
    The IMPLAN model allows a comprehensive estimation of additional 
tax revenues that would be generated across all sectors as the result 
of increased economic activity. Table 4 details the type and amount of 
tax revenues that would be generated from a boost in ethane production 
by 25% and its subsequent consumption by the chemical industry. The 
additional jobs created and added output in turn would lead to a gain 
in taxes receipts. Federal taxes on payrolls, households, and 
corporations would yield about $2.5 billion per year, and assuming 
historical tax buoyancy, would generate $24.9 billion over 10 years. On 
a state and local level, an additional $1.9 billion per year would be 
generated, or $19.0 billion over 10 years.

   Table 4: Tax Impact from Expanded Production of Petrochemical and Derivatives from a 25% Increase in Ethane
                                             Production ($ Billion)
----------------------------------------------------------------------------------------------------------------
                                                                       Corporations
                                                          Households   and Indirect
                                              Payroll         and        Business        Total     Over 10 Years
                                                          Proprietors      Taxes
----------------------------------------------------------------------------------------------------------------
 Federal                                       $1.0          $0.9          $0.6          $2.5          $24.9
State and Local                                $0.02         $0.30         $1.57         $1.9          $19.0
----------------------------------------------------------------------------------------------------------------

    There are also considerable tax revenues generated from the $16.2 
billion investment in new plant and equipment. Federal tax receipts 
would be $3.1 billion, while state and local receipts would be $1.8 
billion. While the impact from the new plant and equipment investment 
would be short-lived, it would nonetheless be welcomed during these 
times of fiscal imbalances.
    Combining the additional federal tax revenues from the added output 
with tax revenues associated with this private-sector boost in 
investment, the 10-year revenue addition to the US Treasury would be at 
least $25.0 billion. Similar large gains in revenues would accrue to 
the states and various localities.

                   Table 5: Tax Impact from New Investment in Plant and Equipment ($ Billion)
----------------------------------------------------------------------------------------------------------------
                                                                                  Corporations
                                                  Payroll       Households and    and Indirect        Total
                                                                 Proprietors     Business Taxes
----------------------------------------------------------------------------------------------------------------
Federal                                              $1.4             $1.2             $0.5             $3.1
State and Local                                      $0.04            $0.4             $1.3             $1.8
----------------------------------------------------------------------------------------------------------------

Future Research
    The economic impact of the additional production of petrochemicals 
and downstream chemical products was quantified in this report. Added 
output, jobs and tax revenues were all evaluated based on the 
additional output in chemicals only. A number of other manufacturing 
industries, including aluminum, cement, iron and steel, glass, and 
paper also are large consumers of natural gas that would benefit from 
shale gas developments and could conceivably boost capital investments 
and output. In addition, the rubber and plastics products industries 
could similarly expand. Further analysis could be conducted to 
incorporate these effects. In addition, the economic effects arising 
from the development of shale gas for other non-industrial markets and 
for possible exports could be examined. Finally, the renewed 
competitiveness arising from shale gas has enhanced US chemical 
industry exports, production and jobs. These positive trends will 
persist and will need to be quantified. Combined, these positive 
effects could be comparable in scope to the primary findings of this 
analysis.
Conclusions
    The economic effects of new petrochemicals investment in the United 
States are overwhelmingly positive. Recent breakthroughs in technology 
have made it productive and profitable to tap into the vast amount of 
shale gas resources that are here, in the United States. Barring ill-
conceived policies that restrict access to this supply, further 
development of our nation's shale gas resources will lead to a 
significant expansion in domestic petrochemical capacity. Indeed, a new 
competitive advantage has already emerged for US petrochemical 
producers. And this comes at no better time: The United States is 
facing persistent high unemployment and the loss of high paying 
manufacturing jobs. Access to these new resources, building new 
petrochemical and derivative capacity, and the additional production of 
petrochemicals and downstream chemical products will provide an 
opportunity for more than 400,000 jobs--good jobs. A large private 
investment initiative would enable a renaissance of the US 
petrochemical industry and in this environment, a reasonable regulatory 
regime will be key to making this possible.







    The Chairman. Thank you very much. Thank you all for your 
excellent testimony and all of the work that went into 
developing it, particularly all the 3-years of work there at 
MIT in this future of natural gas study.
    Let me start with a question that I think both Dr. 
Gruenspecht and Dr. Moniz alluded to. That is this whole issue 
of whether or not we wind up seeing our natural gas integrated 
into a world market. Whether there's an evolution of an 
integrated, global natural gas market, I think is the way it 
was referred to.
    Frankly I have some concerns when I hear about that 
potential because I see what's happened to us in oil. I mean, 
we produce substantial amounts of oil. In my State I noticed 
that regardless of the fact that it costs not a dime more to 
produce oil from 1 day to the next, the price is the same. The 
price that we pay at the pump, that consumers pay at the pump 
goes up dramatically because of something that happens in Saudi 
Arabia or Libya or wherever.
    It concerns me if we're going to see the same kind of 
global market for natural gas which would be subject to the 
same kinds of volatility and price shocks that we've seen in 
the world market for oil. Is that an unjustified concern, Dr. 
Gruenspecht?
    Mr. Gruenspecht. I would say all else equal increased 
demand for North America natural gas whether domestically or 
from the rest of the world would tend to raise its price just 
as increased demand for other commodities like agricultural 
commodities tend to raise their prices. We have not looked 
particularly at U.S. exports of gas, but we have looked at gas 
cases with increased demand and we do see higher prices.
    Of course it's also true that higher global demand for 
domestically produced energy or non energy commodities also 
tends to boost the economy and employment. So I guess the 
question is how you weigh those things. As suggested by my 
testimony I think an analysis of the potential impacts of LNG 
exports would depend on both the domestic side of the picture, 
involving domestic natural gas resource and production 
developments, and on the future evolution of the global natural 
gas market.
    Again, this issue is whether that market has gas on gas 
competition. Then the issue becomes--how competitive the U.S. 
would be as a source of feedstock for creating liquefied 
natural gas versus other stranded gas throughout the world. 
Convergely, retaining the traditional linkage of LNG to oil 
prices which would maybe give more room for U.S. sourced gas to 
be a feedstock in a world market.
    I guess the other aspect of this issue is this potential of 
shale gas as an alternative to LNG in the other parts of the 
world. That could also play a role. So I agree with you. It's 
just a very complex issue.
    The Chairman. Dr. Moniz.
    Mr. Moniz. First of all I believe there is the 
justification for concern and to addressing this issue. 
However, I would offer a few reasons why we, in the end, come 
down on advantages, net advantages, for the country to support 
development of a global market. Recognizing it will be very 
difficult and take a long time for that to happen, especially 
given the structure of the markets in Asia.
    But I think the, in this case, compared to oil first of all 
there would appear to be less leverage for cartel like 
behavior. At its core, natural gas has a lot of substitution 
possibilities in the other way as well. That is, it can be 
substituted out in the power sector. It can be substituted out 
in the industry sector.
    For example, natural gas liquids verses NAFLA for ethylene 
production. Right now we have a competitive advantage with 
that. But that could be substituted out.
    It's the analog of what I mentioned for the--in the gas and 
transportation. What is critical is to have substitution 
possibilities. With oil in the transportation sector we 
fundamentally don't have it to any serious degree today, 
whereas gas, as I say, has these substitution possibilities.
    So in that context we see lower prices for the United 
States. We see, at least for some time in our models and they 
should be taken with a grain of salt or a cup of salt, the--
what we see is the main impact as lower prices and higher 
demand, not actually materially impacting domestic production. 
We see that that market would help our allies, like a Germany 
etcetera, which in turn helps us in our geopolitical 
flexibility.
    So net, we come down there. But there's no question there 
is the concern on import dependence.
    The Chairman. Mr. Biltz, did you want to make a comment?
    Mr. Biltz. Yes, thank you, Mr. Chairman.
    From an industrial perspective this is one of the very few 
points we disagree with MIT in the study. Our perspective is 
that there is a global market in gas today. It's very closely 
tied to the oil pricing. The U.S. market today is disconnected 
from that, our natural gas abundance and the shale with which 
it's produced in provides a distinct competitive advantage, as 
was just mentioned.
    Should that become truly tied to the global market that 
competitive advantage that manufacturers enjoy would disappear. 
The addax advantage that I talked about earlier would 
disappear. So our view from a manufacturing standpoint is we 
think the U.S. would be better served to use that gas to 
produce products, export those products with an addax impact to 
the GDP of the country as opposed to a one time export of the 
natural gas.
    The Chairman. So you think we should take action. We should 
not be encouraging the import and export of natural gas. We 
should try to keep our domestic natural gas market somewhat 
insulated from the global market?
    Mr. Biltz. We would agree that it's a very complex area. As 
a company we strongly support free trade. But there is a 
competitive advantage enjoyed today that does allow us to 
export. To the extent that supply and demand wind up out of 
balance that puts that at a very critical juncture.
    So it's not simply a matter of LNG import export. It's the 
whole aspect of supply and demand and how those balance out.
    The Chairman. Thank you very much.
    Dr. Moniz, did you want to make one more comment? I've run 
over my time, but go ahead.
    Mr. Moniz. I just have a brief comment that first of all, 
as Mr. Biltz said, we do disagree on this. I certainly could 
not characterize there as being a global market. There are 3 
large regional markets with very, very different pricing 
structures.
    I would just end by pointing out the irony that the MIT 
professor is supporting the free market.
    [Laughter.]
    The Chairman. Alright.
    Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman.
    Mr. Biltz, I appreciate your testimony and the reminder to 
us all that in order to be effective in creating jobs and 
ensuring that our U.S. businesses are competitive we really do 
have to have an energy policy that is comprehensive. I also 
appreciate your written testimony which endorses revenue 
sharing. That's not an issue that's before us today, but it is 
something that will come before this committee next week. I 
appreciate you weighing in on that.
    Dr. Gruenspecht, let me ask you about the recent article 
that came out of the New York Times regarding the future of 
natural gas. It was a pretty negative series of articles. I 
think the Times own public editor took strong exception with 
the bias that was displayed in these articles.
    But it's my understanding that the articles were based in 
part on emails that were leaked by senior officials within EIA. 
I think it goes without saying that the Energy Committee relies 
on EIA for independent and impartial energy information. We 
then use this information to hopefully make good strong policy.
    So in light of the testimony that you've given us today, in 
light of the published reports by EIA, I am assuming that EIA 
considers our shale gas resources in this country to 
besignificant and that you stand by that. I'd also like to know 
how this stuff got out there. Can you give me a little more 
background on it?
    You have to admit that when those came out it sure raised a 
lot of eyebrows. I think it deserves some kind of an 
explanation as to where we are at this point.
    I think you need to push that button there.
    Mr. Gruenspecht. I want to be heard I guess.
    [Laughter.]
    Senator Murkowski. Of course we want you to be heard.
    Mr. Gruenspecht. First let me say that we've carefully 
looked at the New York Times article. We found nothing in it 
that causes us concern regarding the methodology, data and 
analysis that underlie the shale gas projections that we've 
published and that we've shared with you.
    I guess I would say a key principle for EIA is to look at 
the data. The data clearly show that shale gas has rapidly 
become a significant source of domestic natural gas supply as 
I've reviewed in my testimony. It's grown to 23% of production 
for 2010. Production and production share growth has continued 
into 2011.
    Again, we recognize there are uncertainties. But that's not 
what the New York Times article was about. The New York Times 
article was suggesting, I believe, some bias of some sort. We 
do not see that.
    In fact, I know EIA staff explicitly pointed the Times 
reporter to the extensive section of the 2011 Outlook on shale 
gas uncertainties. But it was not mentioned in the article. I'm 
not a media critic. You know, I guess there's a famous saying, 
don't get into arguments with people who buy ink by the barrel, 
or something.
    But I really do believe that EIA is doing a solid job in 
effectively tracking the emergence of shale gas in the U.S. 
energy system and thoughtfully reflecting it in our 
projections. It's something that a government agency, frankly, 
could not be on top on. It's moving very, very quickly. To stay 
in touch we need to access the best available information and 
incorporate it into our outlook. I think that's really what 
we've done.
    Now, going back to your question about the emails. I don't 
think the characterization is exactly right there. Most of the 
emails are largely to and from a person who was hired by EIA in 
2009 as an intern and later developed into an entry level 
position.
    I would say that the emails as posted on the Times' website 
were heavily redacted and redacted in ways that I think provide 
misleading information on their context. The folks up on the 
other side of the Capitol, were very interested in this subject 
and had asked us for the unredacted versions of the emails and 
information as to how we develop our shale gas work. I can't 
tell you that EIA is 100% right with its projections, but 
again, we've emphasized the uncertainty. We do pride ourselves 
on being transparent; and we have been transparent. We provided 
them with the unredacted emails. We'd be happy to provide you 
with similar information.
    We want to be really open about this as we do stand behind 
our shale gas work.
    Senator Murkowski. I think it is important that you do make 
that statement, do make that commitment because I think in our 
work here in the committee, again, we look to you for 
scientifically rigorous and impartial data. If that now has 
been caused to be in question because of this I think that's a 
real loss to us as policymakers. We need to know that we can 
rely on that.
    So if you have additional information and background that 
you can give the committee, I think that that would be 
appreciated. I know that you've had an opportunity to be over 
on the House side as well. But----
    Mr. Gruenspecht. It's a big stack. You can have it.
    [Laughter.]
    Senator Murkowski. Alright. This is why we have all these 
fine people that sit behind us and pour over this. But this is 
an important issue for us to understand what the resource is. 
When stories like this come out that cause doubt as to the 
reliability of the data, I think it is important to try to air 
that. So I'd appreciate anything that you can do to help us 
with that.
    Thank you, Mr. Chairman.
    The Chairman. Thank you.
    Senator Manchin.
    Senator Manchin. Thank you, Mr. Chairman. Thank all of you 
3 for being here. We appreciate it very much.
    As West Virginians you know we've been blessed with a lot 
of natural resources, coal being predominantly. Natural gas, we 
just found the Marcellus shale on the 3 States of New York, 
Pennsylvania and West Virginia. We have a really emerging 
biofuels with our chemical industry. We have a tremendous 
renewables in our wind farms on the largest wind farms east of 
the Mississippi is in West Virginia.
    So with all that we've been very, very pleased and very 
blessed. As you know, coal has been on the tack and the EPA 
moving is rapidly as they are without having anything in place. 
I'll ask this--I have 2 parts. But Mr. Biltz first of all from 
the coming from the manufacturing part.
    Are you concerned about the spike in prices as far as the 
cost of energy and especially your presence in our State that 
could really disrupt your global presence in America and 
without having an alternative as coming on in the same like 
price range?
    Mr. Biltz. It absolutely is a large concern to us. What we 
continue to look at as policy or other actions that move the 
demand well out ahead of the supply.
    Senator Manchin. Right.
    Mr. Biltz. So for us trying to keep that balance between 
supply and demand is absolutely critical. We believe market 
forces work that affect. We can help those, for example, in 
West Virginia. We're working very hard on some carbon capture 
technology, running a pilot plant, a successful pilot plant 
right now.
    Senator Manchin. Yes, you are. Alstom.
    Mr. Biltz. We look to find ways--yes, with Alstom. We look 
to find ways to do more of that to keep the balance across all 
opportunities in energy space.
    Senator Manchin. Mr.--Dr. Moniz, I would ask on with, you 
know, our concern environmentally with shale right now is we 
don't know. As you know New York is about shut down and has 
very little exploration going on. Pennsylvania is throttling 
pedal to the metal. We're kind of in between. With that being 
said in shale and we have a chance at the cracker coming back 
and if we have 1 or 2 cracker, we're back in the ball game 
again manufacturing as you mentioned with all the wet products 
coming off of it.
    What do you see that we should be concerned about? We're 
concerned about the injection we're having with one major 
supplier of the chemicals that go into the injection that won't 
reveal the contents because they're afraid to trade breach, if 
you will. What should we be, as the State of West Virginia, be 
very much concerned environmentally and how do we bridge that 
or get past that with the Marcellus development?
    Then you've got Utica coming on in Ohio, I understand.
    Mr. Moniz. Certainly in terms of the fracking fluids 
issues. As I said, we strongly recommend a required disclosure 
of all the contents. We have been completely unconvinced by 
these arguments of proprietary advantage.
    Senator Manchin. Agree.
    Mr. Moniz. Whatever the case I think the public interest 
overrides it.
    Having said that, we found--we have not found any evidence 
of the fracking itself harming the shallow, the water 
resources. But it's a very large scale activity. There clearly 
have been problems. We have, in the report, a 5-year summary of 
all of the major environmental incidents that we could find. 
Half of them were from faulty well completion. It's the cement, 
the cement, the cement.
    Right now, we have variable State regulations. We think 
that all the State regulations should be brought up to the 
highest standards and of course, enforced. That's very 
critical.
    The second issue is, I said, these regional, this 
integrated water management plan. Absolutely critical. In 
Pennsylvania they have the challenge of not having the kind of 
EPA regulated disposal infrastructure, disposal well 
infrastructure that one finds in some of the more mature 
producing regions.
    So things like recycling of fluids, absolutely critical.
    Not having surface spills. Surface spills are the second 
largest major environmental impact.
    Senator Manchin. Right.
    Mr. Moniz. So we view, we think we need tough regulation. 
When we have gone around and spoken about this our advice, 
whether asked or not to the companies, is you should be seeking 
strong regulation, especially as the larger companies move into 
this. It seems to me it's to their benefit to get out ahead of 
this and work with the States.
    Senator Manchin. I have one final question, if I may.
    First of all, right now natural gas has been used as a 
combined cycle as far as impeaking. It has not been base load. 
Now with the production of gas and what we found, I and hear in 
your testimonies, looking more at it from a base load.
    As we convert some of our older plants and the coal plants 
some of them have 40 years or older. As we have been upgrading 
some of our plants as far as with carbon capture as you know we 
have the mountaineer plant in commercial development.
    Mr. Moniz. Yes.
    Senator Manchin. It looks very promising. But with that 
being said, the scrubbers and the CPRs and all the things 
that's been done to point. We're getting pushed by the EPA 
basically to move further with air quality. But also we have a 
lot of plants that could be converted with the scrubbers and 
CPRs and then move with the filtration on the back end.
    With all that happening and the plants that basically are, 
should be cycled out, the old coal fired plants. Working with 
the utilities I think they would come up and convert some of 
those to a combined cycle natural gas that would be base 
loaded. Do you believe it's feasible to base load off of 
natural gas the way we base loaded off of coal and nukes?
    Mr. Moniz. Yes. So the first, Senator Manchin, I wouldn't 
say that NGCCs have really been used in a peaking mode. It's 
more a mid load variation as opposed to turbines.
    Senator Manchin. Right. Right.
    Mr. Moniz. Which are used for the real peaking. AThose were 
not part of our--we didn't have, we had no substitution, if you 
like, on those. So those are needed for reliability of----
    Senator Manchin. So you got to have a main balance of that?
    Mr. Moniz. Right. So but on the NGCC plants in our 
modeling, we did include a transmission constraints and the 
need to maintain variable load capability. So that was already 
part of our consideration. With the large supply we could do 
substitution as well. Indeed, the issue was again for these old 
inefficient coal plants that--those 45 year old----
    Senator Manchin. Right. Sure.
    Mr. Moniz. 30% efficient plants without any scrubbers. I 
think we all understand that the economics of a retrofit----
    Senator Manchin. Sure.
    Mr. Moniz. They don't make any sense. In fact, you could 
probably build a brand new NGCC plant for the same cost as 
putting a scrubber on that plant. So I think we will see a lot 
of that no matter what the regulations are. But certainly a 
push toward, especially mercury control, would accelerate that.
    Senator Manchin. Thank you all so much.
    Sorry.
    The Chairman. No problem.
    Senator Landrieu.
    Senator Landrieu. Thank you. Let me begin, Mr. Biltz, 
thanking you for your endorsement of revenue sharing for the 
Gulf Coast States. Dow has a tremendous presence in our Nation, 
but particularly along the Gulf Coast. We're very grateful for 
your support.
    You say one way to maximize the transformational value of 
increased oil and gas production in the OCS is to share the 
royalty revenues with coastal States. You also go on to say, 
and use a portion of the Federal share to help fund research. I 
couldn't agree with you more. We'll be working on that exact 
policy later on this week with this committee. So I thank you.
    I want to ask the question about the conclusion that it 
seems like you all have reached that natural gas is a game 
changer. Dr. Moniz, you stated that and also the EIA. Did you 
all--I don't want to ask both of you. Did you all arrive at 
this conclusion independently, the EIA and your study that 
natural gas could be a game changer for U.S. independence for 
environmental improvements and economic transformation? Yes or 
no? Or did you all use the same studies to come to that 
agreement or that conclusion?
    Mr. Gruenspecht. EIA arrived at its, Outlook based on work 
we've been doing for a long time. Again, that means by 
following the data and looking at the resources----
    Senator Landrieu. You trust the data that you followed and 
you're confident of your conclusions?
    Mr. Gruenspecht. The data--look there's a--if EIA was a 
library there's a data part and those are facts. Frankly, there 
are projections. Projections are just that. They involve 
modeling. They involve assumptions. But the data we followed. 
We are----
    Senator Landrieu. But based on the facts in the library 
what is your conclusion about the future?
    Mr. Gruenspecht. The facts in the library are that with 23% 
of U.S. natural gas production having come from shale gas last 
year and a larger percentage coming this year, its impact is 
already happening. On the issue of the resources we are working 
hard to keep up. Again, the U.S. Geological Survey is expected 
to come out with a new evaluation of the Marcellus Shale which 
will be very important.
    Senator Landrieu. The reason I ask you that----
    Is because following up what Senator Murkowski said. We 
depend on you to give us the information so that this committee 
and Congress----
    Can make the wisest decisions possible relative an issue 
that is extremely important to our constituents and that is the 
energy sufficient, self sufficiency of the United States moving 
to more independence. Right now on their minds is jobs. 
According to what Mr. Biltz said, if we do this right we could 
potentially create hundreds of thousands of jobs and tremendous 
wealth for a Nation that desperately needs it.
    Now this New York Times article which I have, which the 
good Senator from Alaska was referring really challenges you 
and your agency. So do you accept this challenge or what do you 
have to say to the New York Times and to others that your data 
can be trusted?
    Mr. Gruenspecht. Again, I think we're very comfortable with 
where we are and we've seen nothing of the New York Times 
report that would cause us to change our view.
    Senator Landrieu. Dr. Moniz, let me ask you.
    Mr. Moniz. Yes.
    Senator Landrieu. You're one of the 4 most universities in 
the world. You've been studying this for 3 years. So, state 
again for the record. Do you think natural gas has a future in 
America? Is it a game changer?
    Mr. Moniz. Yes. In fact, we've called it a paradigm shift 
game changer, yes. In fact going back to your original 
question, let me just emphasize that in our supply analysis 
which is very extensive, very transparent, statistical methods 
are all laid out.
    Our data did not come from EIA. They came from the 
potential gas committee, very highly respected group out of 
Colorado mines, out of the USGS, out of ICF. We had a team of 5 
working on this for 3 years, a lot of well by well analysis and 
that's where we get our whole distribution of resources.
    I'll be honest on the New York Times article, if I may say, 
this is frankly very disappointed that, you know, I and the 
supply team were not consulted----
    Senator Landrieu. Let me ask you this because I've got one 
more question because I'm disappointed in it as well. You know, 
it's sort of like staring a gift horse in the mouth. I mean, 
here is a supply that's domestic. It's 40% cleaner than some of 
our traditional sources that we're using. It's available 
spread, you know, not equally, but shared widely among States 
in the United States.
    There seems to be this sort of behind the scenes push back. 
It's too good to be true. It can't possibly be true. I think we 
need to break through on this.
    My last question because my time is out. On the MIT report 
you said that environmental impacts of shale are challenging. 
Anything is challenging. Coal, oil, nuclear, there's nothing 
that is not challenging.
    But what I focused my eyes on is the word manageable. But 
you said it's challenging but manageable. So could you give us 
30 seconds of what are sort of the manageable components that 
we've got to underlie so that we can tap into this really 
phenomenal resource that we seem to be discovering?
    Mr. Moniz. Those words were very carefully chosen. The 
manageable part means, as said earlier, it means really having 
excellent requirements on well completion. It really means 
having good sensible, strong regulation on surface water 
management.
    You know, there was some issues, clearly, in terms of using 
some surface water treatment plants that would not, you know, 
we just have to have a very good, sound, water management plan. 
That's the key.
    Senator Landrieu. That can be done at the regional level?
    Mr. Moniz. Also, yes.
    Senator Landrieu. It can be done regionally.
    Mr. Moniz. Regional level. Also the other thing I would say 
is that issue such as introducing the technologies of water 
recycling, for example, are very important, not only for 
managing the water, but for their indirect effects of reducing, 
for example, potentially hundreds of heavy truck movements that 
would otherwise be required.
    So that's what I mean by----
    Senator Landrieu. By manageable. Thank you.
    The Chairman. Senator Udall.
    Senator Udall. Thank you, Mr. Chairman. Good morning, 
gentlemen. It's been very helpful. This is an exciting set of 
developments. Also important questions have been raised.
    Mr. Moniz, if I could start with you. In your testimony you 
touched on the fact that the vast majority of known gas 
resources, I think, are located in 3 regions, North America, 
Russia and the Middle East. That these resources are even, and 
I'm going to quote you, ``Even more geographically concentrated 
than oil.''
    I sit on the Intelligence Committee and the Armed Services 
Committee and that drives me and others to be really keenly 
attuned to geopolitics, particularly how oil affects our 
national security. Could you talk a little bit about the 
potential geopolitical implications of natural gas, 
particularly in a post Fukushima world where more countries may 
be looking to import gas to replace nuclear power? You've heard 
the announcement from the Japanese leadership recently, and Of 
course the Germans have now changed course yet again on their 
supporter of nuclear power.
    So, just the----
    Mr. Moniz. Sorry.
    Senator Udall, so the geopolitics, as we did say, are 
complex. They are roughly 70% of the recoverable resources are 
in those 3 regions that you say. However, I do want to add that 
that did not include unconventional resources outside the 
United States because our feeling was it was too uncertain. 
Although now the EIA has just this recent report which they 
also say it's uncertain. But it's a very, very substantial 
amount of shale gas.
    So if, for example, China really can develop an appreciable 
part of their estimated 1,200 trillion cubic feet of shale gas, 
that has a major implication on the Asian market, where, of 
course, Japan is now playing. Maybe it will lead to different 
market structures.
    In Europe, huge issues. Germany, we all know the problems 
they've had with their Russian supply. They're desperate to 
diversify. There are substantial resources, shale resources in 
Poland, in France. The latter has said they don't want to 
develop them at the moment. Poland will.
    But that plus the great game around the Caspian which you 
are, no doubt, involved in, is huge. Will the Caspian gas move 
to Europe through Turkey? Will it go through Russia? Will it 
have--will it go east to China?
    So these are big issues that will affect the market 
structure. All we can do is, in our view, play in the game. In 
fact, one of our observations is our view that natural gas has 
not been given the attention, geopolitically frankly, in our 
Department of State as we form our foreign policy.
    Senator Udall. I could use the rest of my time interacting 
with you on this topic. But I look forward to more 
conversation. Potentially this is the subject of a hearing not 
only in the Foreign Relations Committee, but perhaps even in 
the Armed Services Committee.
    Mr. Moniz. I might say that my group and I are available to 
any member, any time to come and explain our work.
    Senator Udall. You--and I just want to ask a question for 
the record and then I want to move to my final question before 
my time expires.
    You touched on this in your, both in your report, but then 
in your comments about the risks of shale gas drilling. But you 
have suggestions for addressing that risk including following 
best practices for casing and cementing. Do you think current 
best practices for cementing and casing are sufficient to 
protect ground water from the materials in the well bore or is 
more R and D needed to improve industry methods in this area?
    Again, I want to just--I'm going to move on. But I'm going 
to let you know that I'm asking you that question for the 
record.
    Senator Udall. So let me move to my third question. The MIT 
report discusses that the upfront costs of natural gas vehicles 
are significantly higher in our country compared to other 
countries. For example, your testimony states that factory 
produced vehicles in the U.S. are more than $3,300 more 
expensive than in Europe.
    Why are the upfront costs for CNG systems for vehicles so 
much more expensive in the U.S. than they are in the rest of 
the world?
    Mr. Moniz. I wish I understood. But we certainly think this 
needs to be addressed.
    First of all, also for aftermarket conversion the costs in 
the United States driven, I think, through regulatory 
requirements, are just off scale compared to what they are in 
other places.
    Second, in terms of the new car market in Europe you can 
get a bi-fuel vehicle for a lower incremental cost than here 
for a simple CNG vehicle. This does not seem to make sense. I 
think, frankly, it was tied up in a perhaps, unintended 
consequences of certain kinds of credits for alternative fuel 
vehicles. So this is something that really deserves more study 
and may be amenable to legislative action.
    Senator Udall. The vehicle you just described, so it would 
run on natural gas, on liquid fuels in Europe.
    Mr. Moniz. In Europe. But you can buy a VW bi-fuel vehicle 
at a smaller incremental cost then the Honda available in the 
United States as a pure natural gas vehicle.
    Senator Udall. So we may have something to learn from how 
the Europeans who are embracing this challenge.
    Mr. Moniz. Yes, and maybe how we are putting in alternative 
fuel incentives in our legislation.
    Senator Udall. Thank you, Doctor.
    Thank you, Mr. Chairman.
    The Chairman. Let me ask a few other questions here. One of 
the issues, I think, that was alluded to in your MIT report, 
Dr. Moniz, is the possibility of boosting the usage of natural 
gas in the power sector by having a dispatching order of 
generation linked to some environmental metric so that I gather 
you would have, you would build in a sort of bias toward more 
use of natural gas in the dispatching that occurs. I think you 
also make reference to the fact that there is a lot of natural 
gas fired generation capacity that is not utilized to a very 
great extent, right?
    Could you maybe elaborate a little more on how that might 
work and this concept of environmental dispatch, if that's the 
right phrase to use?
    Mr. Moniz. Of course today on the basis of economic 
dispatch than gas tends to be last in line for the simple 
reason that the marginal cost is almost entirely the fuel cost. 
Whereas in other, in coal or nuclear, it's--well nuclear 
especially, it's the opposite. The cost is all in the fixed 
cost and essentially nothing in the fuel cost. So the marginal 
cost is quite low.
    So basically, anything which would change that dispatch 
order. For example, a carbon--a decision that for carbon 
reasons we are going to dispatch first, lower carbon. That 
would have this impact.
    Clearly the simplest policy approach would be essentially a 
20 dollar per ton price on CO2 emissions. That is 
probably, you know better than I, but that is probably not in 
the cards at the moment.
    The Chairman. I think you also made reference to work 
needing to be done with regard to the full life cycle emissions 
of greenhouse gases from natural gas. I think there have been 
some studies recently that have suggested that the emissions of 
natural gas are substantially higher than others fuel 
feedstocks, than previously estimated if you do look at the 
full life cycle. What could you tell us about that?
    Mr. Moniz. We do think there's a lot of uncertainty at the 
moment. I should add that all of the economic modeling that we 
did already includes these emission factors that were the EPA 
standard for many years. So we have included that already.
    However, there are some suggestions that there may be much 
higher emissions in the shale production. I can't say that we 
can confirm or categorically deny that. What we do recommend is 
a joint DOE/EPA study based upon data that looks at the so 
called fugitive emissions for production of all fossil fuels, 
coal, gas, oil. Let's get it on equal footing and find out.
    Our own estimates suggest that there still remains the 
order of a factor of 2 improvement in net CO2 
emissions for a natural gas combined cycle plant verses a coal 
plant.
    The Chairman. One other issue that I wanted to explore a 
little bit is the implications of all this new natural gas 
that's been discovered for the whole idea of carbon capture and 
storage, CCS. It strikes me that if we're going to have an 
adequate and ample supply of natural gas at low prices for a 
long time for the future, the viability of a lot of this CCS 
work is brought into question, just whether or not it's 
economically feasible to try to deal with the issue of 
greenhouse gas emissions that way. I'd be interested in any of 
you commenting on that.
    Mr. Biltz, you said you folks are engaged or participating 
in a project in West Virginia related to CCS. So maybe you have 
some expertise on this?
    Mr. Biltz. From our perspective the carbon capture has a 
great benefit in terms of reducing carbon and helping 
transition toward a low carbon economy with regards to coal 
plants. There's certainly other ways to achieve the goal. We, 
for example, would put energy efficiency right up as our very 
first choice. Anything moving toward energy efficiency we would 
support as a company before we get down the path of picking CCS 
or other alternatives.
    But our pilot plant in West Virginia has been successful. 
We're looking at larger operations for that either as retrofits 
in conventional coal facilities or as part of new higher 
efficient facilities.
    The Chairman. So there's nothing in the changed outlook on 
natural gas that causes you to change your enthusiasm for CCS?
    Mr. Biltz. No, in principle. We've not reached a point of 
looking at natural gas as the silver bullet. We believe that 
any energy solution from America is going to involve all energy 
fuel sources, carbon through coal or nuclear included. Finding 
solutions across all the fuel sources are important.
    The Chairman. Anybody else want to make a comment?
    Mr. Gruenspecht. Yes, I'll make a comment. Without some 
kind of policy related to carbon dioxide, I think we al know 
that CCS in the electric power sector is pretty challenging. I 
would say that carbon capture in other sectors where there's 
more of a pure stream of carbon dioxide could be attractive in 
the context of enhanced oil recovery for example.
    We're talking about natural gas today, but we often talk 
about oil. Certainly CO2 assisted EOR, you know, is 
an important technology. There's been a lot of natural sourced 
CO2 coming some out of your State, for example, that 
goes into oil recovery.
    The potential's there at least to develop some of the 
technology. But actually getting it into the electric power 
sector without some kind of greenhouse gas policy, I think, is 
quite challenging. There have been some recent developments in 
West Virginia in that regard.
    The Chairman. Dr. Moniz, did you want to make a comment?
    Mr. Moniz. Yes, if I may? Certainly your initial statement 
fully described you. That is that with current costs of gas, of 
CCS, getting the marginal kind of CO2 out of the 
system is far less expensive just by using gas.
    However, on CCS my view remains and I think this is very 
much in line with what Mr. Biltz said earlier, that well, my 
premise is I do believe that we are, at some point, going to 
have a carbon dioxide emission mitigation strategy. I 
personally have a lot of confidence that Mother Nature will be 
giving us more and more stern lessons about this. So I believe 
that it is a public good to prepare the options that we will 
need for meeting carbon restrictions among those is CCS.
    However, as Howard says, you know, today carbon capture and 
sequestration for a coal power plant is extraordinary expensive 
mainly because of the carbon capture. So I believe that our 
plan should be much more to in this decade firmly establish 
sequestration, the regulatory requirements, the way we manage 
the infrastructure. What we need to do that is, in my view, get 
the cheapest source of megatons of CO2 that we can 
to have an organized program on sequestration.
    That source of CO2 is a lot less expensive when 
you get it from somebody like Dow, for example. Because if it's 
a coal to chemicals plant or an ethanol plant the cost of the 
CO2 is dramatically lower than it is from a large 
power plant. Then at the same time we should be funding what I 
believe is a lot of innovative technology ideas that can 
dramatically cut the carbon capture cost, not incrementally. A 
20% reduction is not going to change the game for CCS from a 
large coal plant, but a factor of 2 reduction could do that.
    So we need new concepts.
    The Chairman. Thank you very much.
    Senator Murkowski.
    Senator Murkowski. Just one last question, Mr. Chairman. I 
want to ask about developments in NGTL's gas to liquids. I 
think it was you, Dr. Moniz, that said it may be the best 
pathway to significant market penetration. I think we recognize 
that we've got this widening price spread between natural gas 
and oil. As I understand it, it's expected to continue.
    Are we doing enough to encourage the necessary development 
for gas to liquids within what we've got going on right now?
    Mr. Moniz. I'm sure Mr. Biltz would want to add to this. 
But I would say that right now the market is simply moving that 
way in terms of where the rigs are, where the action is because 
the winter production strong NGL content has a much more 
favorable economics. The Southwestern part of the Marcellus 
shale is an example where there is some--a lot of opportunity.
    There is, in our view, a need however--so suppose one has a 
lot of GTL development in the Marcellus region. We don't 
believe we have the infrastructure yet, you know, all the 
processing infrastructure etcetera. On the other hand we feel 
that the market will take care of it.
    Senator Murkowski. Mr. Biltz.
    Mr. Biltz. Yes. We would agree with that view. We believe 
the market is treading in that direction. The issues that 
concern us are around artificial demand, particularly inelastic 
demand increases.
    So for example in the House right now there's a bill, the 
NAT Gas bill, looking at putting natural gas into vehicles, as 
was discussed earlier. In principle based on supply on demand 
may or may not be an issue. But the fundamental concern is 
there's no counter balance discussion on supply.
    So we might choose to legislate demand without increasing 
the supply to support that. In which case we are back into the 
position we were in 2005. So our perspective is there's better 
alternatives. In that particular case the Argon National lab 
would tell you that you have a 3 times impact from electric 
vehicles verses a compressed natural gas vehicle.
    So look at using the gas into electricity into vehicles 
makes a lot more sense from an energy policy as a Nation. What 
we get mostly concerned about the supply, artificial supply. 
That particular bill, 180 members, roughly in Congress support 
it, 80 of those members have never voted for a supply option.
    So we get concerned about people very focused on increasing 
inelastic demand without looking to supply the whole balance 
set off.
    Senator Murkowski. I think we worry around here about 
picking the winners and losers, rather than thinking about the 
comprehensive enery policy that you talk about. Sometimes we 
get it right and sometimes we don't get it right.
    I know up in Alaska we're looking at how we might be able 
to utilize gas to liquids. You know, we've got an oil pipeline 
that's less than half full now. We're trying to figure out how 
we keep that moving.
    So when we talk about the technologies and what is it that 
we're doing to help advance them, gas to liquids should be part 
of the discussion, part of that policy debate.
    I appreciate the testimony that all 3 of you have given us, 
and the extensive level of analysis that has gone into the MIT 
report.
    Dr. Gruenspecht, for all that you and the fine folks at EIA 
do to provide us with the data and the information that we 
need, we appreciate it.
    Thank you, Mr. Biltz as well.
    The Chairman. Let me ask 1 or 2 other questions here.
    You know, when we look at our dependence on oil and our 
lack of adequate progress in reducing that dependence. You 
know, it's sort of--it's come about because we've had an 
abundant, relatively cheap source of oil for a very long time. 
We're now talking about an abundant, relatively cheap source of 
natural gas for a very long time ahead of us.
    I fear that we could see similar consequences in that any 
serious effort at further development or deployment of 
renewable energy would be put on the back burner that further 
efforts at increased energy efficiency would be put on the back 
burner. Because everybody says, look, we've got plenty of 
natural gas. It's not very expensive. So let's concentrate on 
that and back away on these other areas.
    Is this a valid concern in your views? Are there policies 
we need to put in place to guard against this concern?
    Any of you? Mr. Biltz, did you have a view on this?
    Mr. Biltz. Yes, we do. You know, I've worked for Dow for 
well over 30 years now. This is at least the third time I've 
been told that we have an abundance of natural gas that will 
solve our problems. It hasn't played out that way in the past 
couple experiences.
    So we would be very concerned about assuming natural gas as 
a silver bullet. We would want to see policies that help, 
again, take the broad look across the supply and demand of 
energy, the energy policy that would help America focus on 
energy efficiency as well as on developing our other energy 
supply sources and ultimately moving toward a low transition or 
transition to a lower carbon economy.
    The Chairman. Dr. Moniz.
    Mr. Moniz. Yes. I certainly think it would be a huge 
mistake to lose our focus.
    First of all on efficiency in our scenarios certainly to 
meet carbon goals over a multi-decade period, gas is a critical 
bridge, as we said earlier. But it only works if we have very, 
very strong demand management. That's actually where it starts. 
Then comes the gas. So being much more aggressive on the demand 
side is absolutely critical.
    Second, on renewables and I would add nuclear, in 
particular CCS. The--we also believe that in this carbon 
context we cannot stop, take a pause, to prepare economic 
options with essentially zero carbon. We still have many 
challenges.
    Nuclear has obvious challenges, not to mention the recent 
ones generated with Fukushima. But that's where, in my view, I 
really believe we should get on with the option of having a 
look see whether these small, modular reactors do or do not 
represent a game changer.
    On renewables, we need to look also at the whole issue of 
how do we integrate large scale wind, let's say, with storage, 
with gas peaking. How do we get a system that allows us to 
scale up that wind deployment?
    To longer term, by the way, I will admit to being very, 
very bullish on solar energy. I would like to advertise our 
future of solar energy report that I hope to have in about 6 
months.
    [Laughter.]
    The Chairman. We will try to have a hearing on that when 
that comes out.
    Dr. Gruenspecht, did you want to make a final statement?
    Mr. Gruenspecht. All I would say is that all else equal, 
with lower prices there is a demand response. So to the extent 
that there are goals related to renewables, related to other 
technologies, related to the overall level of consumption, more 
abundant natural gas and lower natural gas prices would tend to 
make it more necessary, if one wanted to reach those goals, to 
use other policy instruments.
    The Chairman. So you're saying large quantities of cheap 
natural gas make it more important that we have policies that 
drive us to continue with development of some of these 
alternative----
    Mr. Gruenspecht. I wouldn't presume to set the goals, but 
if indeed you have goals in these other areas I think it's fair 
to say that abundant, low priced, fossil fuels including 
natural gas make it less likely that you will reach those goals 
without the type of policies you're talking about.
    The Chairman. I think it's been very useful.
    Senator Murkowski, do you have any additional questions?
    Senator Murkowski. Very appreciative of the testimony.
    The Chairman. Thank you very much. Thanks for the excellent 
work that went into the report, Dr. Moniz.
    That will conclude our hearing.
    [Whereupon, at 12:03 p.m. the hearing was adjourned.]
                               APPENDIXES

                              ----------                              


                               Appendix I

                   Responses to Additional Questions

                              ----------                              

     Responses of George Biltz to Questions From Senator Murkowski
[Natural Gas Vehicles: conditional support or none at all]
    Question 1. In your written testimony, you point out that while the 
study doesn't openly advocate subsidies for natural gas vehicles, it 
does call for the government to revise its policies related to CNG 
vehicles in order to lower up-front costs of such vehicles and the 
necessary infrastructure. From your written remarks I understand that 
Dow is opposed to such government-provided incentives. I also note that 
you highlight Chesapeake Energy's recent announcement regarding their 
intention to invest in natural gas vehicles, as an illustration that 
government intervention is unnecessary. Is it safe to say that you 
support CNG vehicles as long as private industry funds them, but not 
when the government intervenes? How do you feel about gas-to-liquids 
technology then?
    Answer. Dow advocates for policies that advance the competitiveness 
of US manufacturing. We advocate against policies that would make the 
US manufacturing sector less competitive. This is why we feel a sense 
of obligation to raise concerns with government policies or proposed 
policies that would significantly increase demand for natural gas in 
sectors that are relatively inelastic (such as the power sector and the 
transportation sector).
    We do not have a bright-line position on government subsidies in 
general. We are sympathetic to the issue of energy security and of the 
need for the country to reduce its reliance on foreign oil. We note 
that there are many different technologies to reduce this dependence on 
the demand side. CNG vehicles are a part of the equation, as are 
hybrids, plug-in hybrids, electric vehicles, biofuel-powered vehicles, 
more efficient gasoline vehicles, etc. Our point in the testimony was 
that the market is already driving adoption of CNG vehicles, so 
incentives are unnecessary. In addition to Chesapeake Energy, AT&T, 
FedEx, UPS and Waste Management are among corporations converting their 
fleets to CNG because it saves them money.
    On the supply side, renewed efforts in exploration and production 
in areas like the Outer Continental Shelf will also help reduce 
dependence on foreign energy sources.
    Increased focus on energy efficiency should also be a priority for 
the nation. As we said in the Dow Energy Plan for America, ``As a first 
step in this comprehensive and more sustainable energy policy, we need 
an accelerated energy efficiency program over the next 10 years.''
    On gas-to-liquids technology, Dow believes it is proven technology 
that does not need government incentives to develop further. It is 
currently being deployed in many regions of the world. If market 
conditions become favorable, it will also be deployed in the United 
States.
[Impact of rising natural gas prices on competitiveness]
    Question 2. I absolutely agree that natural gas policies should 
carefully consider the need to preserve and enhance the competitiveness 
of U.S. manufacturers. With natural gas prices so much lower relative 
to oil, American chemical manufacturers clearly enjoy a competitive 
advantage to their foreign counterparts. I wonder how you see this 
trend playing out in the near to medium term, as demand for natural gas 
grows in every sector of the economy, especially power generation. How 
this will impact your competitiveness?
    Answer. Assuming moderate demand growth unperturbed by policies 
that spike demand ahead of supply, we see this favorable trend 
continuing. We must be mindful of regulatory policies (emissions 
regulations, for example) that accelerate retirement of coal-based 
power generation and artificial incentives for CNG vehicles to displace 
oil as well as regulatory policies that significantly delay or reduce 
new supplies of natural gas.
    We believe the US needs a balanced energy policy that assures a 
diverse energy mix including coal, nuclear, natural gas and renewables. 
Natural gas should not be positioned as the nation's only growth fuel.
    Provided government policies do not accelerate demand ahead of 
supply, we see the favorable trend with respect to natural gas 
continuing in the medium term. Given our outlook, we are beginning to 
invest for new growth in the United States.
[Fracking chemicals]
    Question 3. As a producer of some of the chemicals that are used in 
the fracking process, generally speaking, what can you tell us about 
the safety of these chemicals and why are there such concerns about 
their usage?
    Answer. Legitimate concerns have been raised about hydraulic 
fracturing (also known as hydrofracking) to access unconventional gas 
reserves and the chemicals used in the process. There's no doubt the 
vast majority of concern is because fracking is new to the public and 
there is a lack of information about it. This is why Dow supports 
disclosure of chemical identity. We believe it should be pursued to the 
extent possible without compromising true trade secret information and 
expect it will alleviate concerns about the risk to human health and 
the environment.
    It is not well understood that chemicals in the hydrofracking 
process make up less than 1 percent of the fluids used. Federal law 
currently requires companies to report the hazards of components 
present in formulations >0.1 percent or >1 percent depending on the 
nature of the hazards. The law further requires that this hazard 
information is available to employees via Material Safety Data Sheets 
(MSDS) at all worksites.
    Dow believes that, if done in a safe and effective manner, 
hydrofracking poses little threat to the environment and is essential 
for the production of natural gas from shale formations.
    Dow produces products used in association with hydrofracking, such 
as biocides for microbial control, which keep water used in the process 
clean. This enables recycling and prevents the souring of wells, which 
can cause them to become flammable and explosive. Our biocide products 
are regulated under the Federal Insecticide, Fungicide and Rodenticide 
Act (FIFRA) and registered with EPA and with each state where the 
material will be used. The stringent regulatory requirements are 
supported by detailed toxicological and environmental fate data which 
allows selection of proper materials for the given application and 
region.
    In addition to biocides, Dow also produces other products used in 
hydrofracking. Dow has committed to publishing product safety 
assessments for all of our products by 2015 and to make this 
information available on our public website. This information is 
available at www.dowproductsafety.com
    As this debate further develops, we will share chemicals management 
best practices and provide our feedback on targeted regulations in 
development to preserve the economical production of energy from 
unconventional gas resources. Domestic oil and gas production is a 
necessary part of a balanced energy policy.
       Response of George Biltz to Question From Senator Cantwell
    Question 1. Dow Chemical derives a portion of its consumer base 
from companies involved in Marcellus Shale natural gas extraction. 
However, your statements in response to the recent Pickens proposal for 
subsidizing natural gas cars suggest that your company was concerned 
about the safety and environmental impact of extraction. What are your 
specific concerns about the safety and environmental impacts of 
extraction? What would be the appropriate steps to mitigate these 
safety and environmental concerns?
    Answer. Our concern with the Pickens Plan is that it will drive up 
natural gas demand without assurances on supply. Much has been made of 
the ``Shale Gale,'' but in fact it has only added 8 Bcf/d in the last 
five years. The power sector can absorb this growth on its own with 
retirements of just one third of coal plants 50 years or older.
    On extraction, research to date indicates that, if done in a safe, 
responsible and effective manner, hydrofracking poses little threat to 
the environment. The process is essential for production of natural gas 
from shale formations.
    Product stewardship of chemicals used in hydrofracking solutions 
should follow the same product stewardship principles as for other 
chemical uses. Chemicals should be evaluated according to their risk 
potential and managed appropriately. The US chemical industry has 
developed principles on disclosure and the protection of confidential 
business information (CBI) in evaluating chemicals, and these 
principles apply equally to chemicals used in hydrofracking.
    Dow is committed to transparency regarding the disclosure of the 
chemical ingredients of hydrofracking solutions, subject to the 
protection of proprietary information. Dow supports disclosure of 
constituents of hydrofracking solutions where chemical identity is not 
proprietary, but not to the proportions used of each component in the 
solution (except in the case of medical emergencies, where Dow supports 
disclosure of the chemical identity of proprietary formulas to medical 
personnel performing professional duties, subject to a signed 
confidentiality agreement after disclosure). Dow also supports 
disclosure of chemical identity to workers and employees in appropriate 
circumstances with a signed confidentiality agreement, and the sharing 
of CBI with states and tribes, contingent on the recipient's adoption 
of enforceable CBI standards and procedures that are at least as 
protective of CBI as those that EPA has adopted and implemented, and 
subject to a written agreement.States should control reporting 
requirements and format of reporting and public disclosure. Because 
local geological, hydrological, geographical and other differences can 
require the use of different chemicals in hydrofracking solutions, 
oversight should be handled by states. State governments have the 
knowledge and experience to oversee hydrofracking in their 
jurisdictions, and have done so safely for many years.
                                 ______
                                 
  Responses of Howard Gruenspecht to Questions From Senator Murkowski
    Question 1. The MIT report asserts that CO2 emissions 
price for all fuels without subsidies will maximize the value to 
society of the large domestic resource base. Do you agree?
    Answer. Recent EIA analyses suggest that placing an explicit or 
implicit price on CO2 emissions would send a clear signal to 
all producers and consumers of fossil fuel-based energy to takes steps 
to reduce their overall energy consumption, switch from carbon 
intensive fuels to less carbon intensive fuels or carbon-free fuels, or 
invest in equipment that captures and sequesters the CO2 
emitted from fossil fuel plants. Placing a price on CO2 
would likely lead to increased use of natural gas and reduced use of 
coal in the near-term, because natural gas is less carbon intensive 
than coal.
    Question 2. What implications does the recent Fukushima tragedy 
have on the global energy outlook? What fuels will face the most direct 
impact from fuel switching from nuclear energy in light of the concerns 
stemming from that tragedy?
    Answer. In addition to being a human tragedy, the earthquake and 
tsunami in Japan also had a significant impact on the country's energy 
infrastructure. A large number of energy facilities were knocked off 
line and many remain out of service today. Taking account of both 
damaged and undamaged nuclear plants that are not currently in use, 
less than 18 gigawatts (GW) of a total commercial nuclear capacity of 
49 GW is currently in operation. In response, Japan has both increased 
its reliance on other fuels including coal, oil and natural gas, and 
called upon its people and businesses to conserve electricity.
    The longer term impacts of the tragedy will depend on how countries 
with existing nuclear fleets or planned nuclear additions respond. 
While a few countries have announced plans to reduce their reliance on 
nuclear, most with existing or planned nuclear units are carefully 
reviewing the Fukushima incident to determine if they need to make 
changes in their nuclear plant construction, operation or regulatory 
practices. It appears likely that there will be some impact on the 
projected expansion of global nuclear power generation, but that impact 
is difficult to quantify at this time. The alternative options to 
nuclear will vary by country.
                                 ______
                                 
    Responses of Ernest J. Moniz to Questions From Senator Murkowski
[Technology & resource estimates]
    Question 1. In this industry, technology changes so rapidly, that 
what was considered ``cutting edge'' two or three years ago is now 
standard industry practice. With regards to the resource estimates you 
provide in your report, and particularly the ``mean estimate case,'' 
are you taking into consideration the most advanced technology 
available today? Given the work that is being done by the National 
Petroleum Council, the Potential Gas Committee and others to compile 
new resource estimates based on today's advanced technologies, why did 
you chose to base your conclusions off of less recent figures?
    Answer. Technological development is an important uncertainty when 
considering the potential size of the recoverable shale resource. The 
resource estimates, and associated supply curves (low, medium and 
high,) used for analysis in the MIT Future of Natural Gas Study were 
based upon the best geologic data available to the study group during 
its work, and assuming the use of 2010 drilling and completion 
technologies. Analysis was also carried out regarding an ``advanced 
technology'' scenario, the details of which can be found in Appendix 2C 
of the report. As to be expected, this advanced technology analysis 
suggested appreciably larger resources. However, the level of 
uncertainty surrounding the advanced technology assumptions and the 
associated resource estimates meant it was not considered suitable for 
use as the study's ``base case.'' Of course, our economic modeling 
built upon the shale resource ``base case'' already showed a major 
impact in multiple sectors; this would be amplified with a larger 
modest-price resource.
    The current work being undertaken by the National Petroleum Council 
and the Potential Gas Committee is using data in their contemporary 
analysis that was not available when the MIT study group was carrying 
out its work. These data will likely lead to a further increase in 
estimates of the shale resource size. However, it is important to 
appreciate that these new estimates still remain subject to significant 
uncertainty. Furthermore, our work emphasized the importance of 
treating natural gas resources through supply cost curves; for the 
short to intermediate term, the issue will be the extent to which new 
technology extends the resource base at low and modest breakeven 
prices.
[Global gas market & energy security]
    Question 2. In your report you recommend that the U.S. pursue the 
development of an integrated global gas market, as this would be 
beneficial to U.S. interests and security, but then say that if this 
integrated market evolves, the U.S. could become a ``substantial net 
importer of LNG in future decades.'' It's hard for me to reconcile 
this--that somehow importing a resource that we can produce at a 
significant scale here at home makes a lot of sense. Can you explain?
    Answer. Indeed, the MIT report recommends the development of an 
integrated global gas market as it will advance security interests 
through diversity of supply and resilience to disruption both in the 
U.S. and its allies. In addition, there is a potential for small 
natural gas exports from the U.S. in the next decade. We also show that 
by 2030-2040 relatively cheaper shale resources in the U.S. will be 
already produced and lower cost suppliers will be competitive again on 
the U.S. natural gas market (of course, these dates could be shifted 
later with improvements in shale gas science and technology that expand 
the modestly priced resource base). The figure below (*Figure 2.10 from 
the MIT study) provides costs and volumes of natural gas in different 
regions of the world; while the U.S. has substantial resources at 
modest breakeven prices, there are other regions with lower cost 
supplies, regardless of natural gas market structure--but often with 
great distances to large markets.
---------------------------------------------------------------------------
    * All figures have been retained in committee files.
---------------------------------------------------------------------------
    By 2030-2040 the U.S. could become a substantial net importer of 
LNG, but access to relatively cheaper natural gas imports in a truly 
integrated global gas market would lower natural gas prices for the 
U.S. consumers, which is beneficial for the U.S. economy. The U.S. will 
still produce a resource at a significant scale here at home; indeed we 
find that the lower domestic prices increase domestic demand 
substantially, so imports do not displace domestic gas on a one-for-one 
basis. In our scenarios the need for substantial imports will not 
happen until 2030 or later. We also stress that the path to a global 
integrated market is far from clear.
    The situation for natural gas is quite different from that for oil, 
where there is already a global market but also non-market cartel 
forces at work. Recent oil prices have been very high: about three 
times that for U.S. natural gas on an energy equivalence basis, largely 
because we have a functioning gas market with gas-on-gas pricing. Given 
our extreme dependence on oil imports, this has resulted in a roughly 
$1B/day contribution to the U.S. trade imbalance. However, the oil 
market is relatively inelastic in that our transportation is almost 
entirely dependent on oil. In contrast, there is a high degree of 
substitution possible for gas, especially in the large electricity 
market, so it is much less likely that an effective cartel could 
develop to ``control'' prices.
    The U.S. also has unique security responsibilities. The segmented 
global natural gas markets leave some U.S. allies vulnerable to supply 
disruptions, such as experienced in Germany not long ago when Russian 
supplies were interrupted, and this can constrain U.S. foreign policy 
options for collective action if allies are limited by energy security 
vulnerabilities. This consideration balances security concerns about 
imports given our large resource base and the substitution options for 
natural gas.
[``Whether'' vs. ``How'' resources will be developed]
    Question 3. In the introduction to your report, you explain that 
the report sets out to review the extent and cost of shale gas 
resources, and I couldn't help but notice that you use the word 
``whether'' these supplies can be developed and produced in an 
environmentally sound manner. I would have thought that we are at the 
stage of discussing ``how'' these supplies can be developed in an 
environmentally sound manner, rather than ``whether'' they will. Do you 
question that this is possible? It seemed a bit of a contradiction from 
your statement that ``the environmental impacts of shale gas are 
challenging but manageable.''
    Answer. When work commenced in 2008 on the MIT Future of Natural 
Gas Study a broad set of questions remained open regarding the U.S. 
shale resource. One of the key questions at that time related to the 
environmental impacts of shale development, and whether shale gas could 
be developed in an environmentally sound manner. Over the course of the 
study, extensive work was carried out on this issue and it was 
concluded that shale related environmental issues are ``challenging but 
manageable.'' In other words, it is the Study Group's position that the 
shale resource can be developed in an environmentally sound manner, 
assuming rigorous enforcement of best practice regulations and adoption 
of integrated water plans. Our ``challenging but manageable'' 
conclusion was the result of our studies, not an assumption at the 
outset. Given this, we feel that no contradiction exists.
[Methane hydrates]
    Question 4. Your report mentions the possibility of the production 
of methane hydrates in the out years of the report and recommends that 
we continue to fund flow testing of well-to-tap hydrates. Coming from 
Alaska, where we are estimated to have between 560 and 600 trillion 
cubic feet of methane hydrate onshore and about 32,000 trillion cubic 
feet offshore--15 percent of the nation's theoretical 200,000 trillion 
cubic feet of the gas--should we be doing even more to prove the 
technology to get that energy supply to market in an environmentally 
sensitive manner?
    Answer. Although not currently considered commercially recoverable, 
methane hydrates do offer the potential of a very large future natural 
gas resource. However, in order for this potential to be realized a 
very substantial amount of research and development work needs to occur 
over the coming years. The MIT study recommends that methane hydrate 
research currently ongoing should be continued. Areas of focus should 
include methods for detecting highly concentrated deposits, better 
resource assessment and longer-term production testing. In terms of 
support for this work, we believe that additional funding is merited as 
part of a balanced portfolio that addresses intermediate term 
unconventional gas opportunities as well (such as the basic science of 
shale formations and production). As pointed out in the report, there 
are numerous RD&D opportunities to address key objectives for natural 
gas supply, delivery, and use, and a renewed DOE program is appropriate 
for much of this agenda.
    Responses of Ernest J. Moniz to Questions From Senator Cantwell
    Question 1. The newly-released MIT natural gas study found that 
methanol produced from domestic natural gas resources was cost-
competitive as a transportation fuel even under the assumption of a 
relatively low $2.30 per gallon gasoline price and natural gas prices 
as high as $8 per MMBtu. What would you estimate to be the economic 
advantages (vs. petroleum-derived gasoline, corn-based ethanol, and 
ethanol imports) of methanol at today's gasoline prices, which are 
close to $4.00 per gallon?
    Answer. The cost of producing methanol (natural gas cost and 
conversion) in $ per gasoline gallon equivalent (gge) in the MIT report 
should be compared to the cost of producing gasoline (oil cost and 
refining). For gasoline at a retail price of $4.00 per gallon, we take 
an illustrative production cost around $3.10/gallon. For $6/MMBtu 
natural gas, the illustrative production cost in the report was $1.60/
gge. In this case the economic advantage of methanol would be around 
$1.50/gge on a production cost basis. Since the cost of transportation 
of methanol is around $ 0.10/gge higher than gasoline, the economic 
advantage relative to gasoline would be around $1.40/gge.
    The present cost of corn based ethanol is around $2.75 per gallon 
of ethanol, corresponding to around $ 3.90/gge (the ethanol futures 
price has risen dramatically in the last year). In this case the 
economic advantage of $1.60 /gge methanol (from $6/MMBTu gas) is around 
$2.30/gge. Even with an ethanol price of about $1.85, which is more 
typical of the price a year ago, there would still be about a $1/gge 
advantage to methanol from $6/MMBtu gas (and today's price is close to 
$4/MMBtu). The methanol price advantage is quite robust at this time.
    It is difficult to make a comparison to ethanol imports.
    Question 2. The MIT natural gas study advocates the adoption of a 
federal open fuel standard requiring auto makers to produce light-duty 
vehicles with tri-flex-fuel (gasoline, ethanol, and methanol) 
capability, noting that the production cost associated with expansion 
to tri-flex-fuel capability would be around $100 per vehicle. How was 
the incremental cost of making a vehicle tri-flex-fuel capable derived 
or sourced and is the incremental cost higher or lower than the 
traditional bi-fuel (E85) capable flex fuel vehicle? Would this 
incremental cost allow the U.S. light-duty fleet to operate on high-
concentration blends of methanol (e.g., M70) and ethanol (E85), without 
degradation of engine components or lower vehicle performance? Do you 
believe there any technological challenges that might impede the use of 
high-concentration methanol blends in U.S. light-duty vehicles? Has MIT 
reviewed other considerations of consumer acceptance that might impede 
the adoption of tri-flex vehicles?
    Answer. The incremental cost of $100-200 for a tri-flex fuel 
vehicle that was given in the MIT report is relative to the present 
ethanol -gasoline flex fuel vehicle. The main component in this extra 
cost was an alcohol sensor that is required for control of the air/fuel 
ratio in a tri-flex fuel vehicle.
    Yes this would allow high concentrations of methanol and ethanol. 
In fact, vehicle performance and/or efficiency can be higher if 
advantage is taken of the higher octane of methanol relative to 
gasoline. However, for a given size fuel tank vehicle range is reduced 
when using M70 to around two thirds of the range when using gasoline. 
The consumer has choices, such as using less alcohol when driving long 
distances, assuming that the fueling infrastructure is sufficiently 
flexible.
    A 2010 MIT report by Bromberg and Cheng (PSFC/RR-10-12) concluded 
that the technical challenges could be addressed at an incremental 
vehicle cost of the scale noted above. Continuing engineering 
developments will be needed at the auto companies and research 
laboratories, depending especially on how future emissions requirements 
(e.g. for hydrocarbons) are set; very stringent emissions requirements 
could well raise the incremental cost to enable a wide range of fuel 
mixtures. Of course, environmental precautions are also needed in the 
transportation of the methanol (e.g. preventing dispersion in surface 
waters), as is the case for all liquid fuels.
    We have not reviewed consumer acceptance considerations.
    Question 3. The MIT Future of Natural Gas study affirms that 
methanol infrastructure is needed for penetration of the fuel into 
commercial transportation. What are the estimated installation costs 
for new methanol tank and pump apparatus, and what are the estimated 
costs to upgrade existing gasoline tank and pump apparatus? How do 
these costs compare with ethanol and gasoline tank and pump apparatus? 
What policy incentives do you foresee as necessary to spur the 
development of a national refueling infrastructure to support a tri-
flex-fuel U.S. passenger fleet?
    Answer. We estimate the installation costs for providing new tank 
and pump apparatus for methanol fueling to be in the $ 60,000-$70,000 
range. The cost is similar to ethanol tank and pump costs and modestly 
higher than gasoline tank and pump costs.
    The most important policy incentive would be clarity in moving 
towards tri-flex-fuel capability in a large part of the light duty 
vehicle fleet (for reasons discussed below). Clearly other incentives 
could include subsidies for methanol fueling infrastructure, similar to 
that for ethanol.
    Question 4. What role would the adoption of a tri-flex-fuel open 
fuel standard play in breaking the petroleum monopoly in the U.S. 
transportation sector?
    Answer. A tri-flex fuel vehicle standard addresses two long-term 
and related US energy concerns: global oil prices ``controlled'' by a 
cartel; and the lack of fuel alternatives in the US transportation 
sector.
    OPEC effectively controls oil prices by increasing or decreasing 
supplies and controlling the amount of surplus oil productive capacity. 
Also, oil based products meet 97% of US transportation needs. 
Artificial constraints on supply plus the lack of transportation fuel 
alternatives and the associated price inelasticity, places American 
consumers and our transportation system at risk, where even minor 
market perturbations result in price volatility and higher prices.
    An open fuel standard, by requiring engines that could run on three 
liquid fuels--gasoline, ethanol and methanol--would promote competition 
and a type of arbitrage between fuels, putting downward pressures on 
prices and reducing opportunities for cartel behaviors. Importantly, 
these fuels would be derived from three major feedstocks: petroleum, 
biomass, natural gas. We have recently seen oil prices and corn ethanol 
futures rise considerably, while natural gas prices have dropped 
significantly. In the future, this pattern could be different, so 
consumer flexibility is critical. Furthermore, cellulosic ethanol and 
biomass-derived methanol provide pathways to carbon dioxide emissions 
reductions as well.
    An open fuel standard would not dictate fuel or technology choice; 
this would still reside with the consumer. Indeed it would enable fuel 
choice options that currently do not widely exist.
    The cost of creating this option is modest, in the $100-$200 range 
per vehicle. There are also additional infrastructure needs; we do 
however have a growing experience base with ethanol distribution that 
could inform the methanol option. It is worth noting that we have 
changed our retail fuelling infrastructures successfully in the recent 
past to respond to policies and mandates, most notably by adding 
specialized pumps for unleaded fuels and E85.
    Question 5. Given current U.S. natural gas resources, what share of 
the nation's transportation fuel demand could be satisfied with 
domestically-produced high-concentration methanol blends such as M70? 
What would be the implications of this level of penetration for U.S. 
greenhouse gas emissions?
    Answer. The ultimate limitation could be how much natural gas 
production can be increased for this new market. Around 3 tcf/yr of 
natural gas must be converted into methanol in order to replace 1 
million barrels/day of oil. Thus, about 14% of today's U.S. natural gas 
consumption would displace about 9% of vehicular transportation fuel 
(gasoline plus diesel). In addition to replacement of gasoline in light 
duty vehicles, natural gas derived methanol could also be used as in 
high efficiency spark ignition engines in heavy duty vehicles as a 
replacement for diesel fuel. This substitution of a natural gas derived 
liquid fuel for diesel fuel is an alternative to the use of LNG for 
heavy duty vehicles.
    US greenhouse gas emissions would essentially be unchanged unless 
carbon dioxide was captured during the natural gas to methanol 
conversion process and then sequestered, reducing greenhouse gas 
emissions by 20-30%.
    Question 6. The MIT natural gas study states that when conversion 
energy losses are taken into account, greenhouse gas emissions from 
natural gas-derived methanol are slightly lower than those from 
gasoline use. Yet, the study then notes that methanol's ``GHG emissions 
could be somewhat higher if methane emissions are included.'' (p. 133) 
Would you please explain in greater detail the actual or potential 
sources of the methane emissions to which the study refers? Would these 
emissions be greater or smaller depending on the method of natural gas 
production (e.g. conventional production versus fracturing)? How 
significantly could production-related methane emissions alter the GHG 
profile of methanol relative to gasoline?
    Answer. When comparing GHG emissions for different energy sources, 
attention should be paid to the entire system. In particular, the 
potential for leakage of methane in the production, treatment, and 
distribution of fossil fuels has an effect on the total GHG impact of 
each fuel type. The EPA is revisiting methane emissions factors. A 
recent focus has been on fugitive emissions from the production of 
natural gas at the well. The MIT report includes methane leakage in its 
system-wide modeling studies but does not attempt a detailed accounting 
for the analysis of specific end uses. The statement quoted above was a 
reference to potential impact. However, the report urges the EPA and 
DOE to co-lead a new effort to review, and update as appropriate, the 
methane emissions factors associated with fossil fuel production, 
conversion, transportation, and use, seeking broad-based consensus on 
the appropriate methodology. The analysis should rely on data and 
should reflect the potential for cost-effective actions to prevent 
fugitive emissions and venting of methane.
    We do not expect a significant increase in the GHG profile of 
natural gas derived methanol relative to gasoline. The recommended 
study would provide a quantitative measure. However, there are also 
opportunities to reduce system emissions further by improving the 
natural gas to methanol conversion efficiency and by capturing the 
higher engine efficiency attainable with methanol.
    Question 7. Recent reports from Cornell University, Duke 
University, and the U.S. Forest Service have been published regarding 
the general environmental impacts of hydraulic fracturing. The Cornell 
study stated that natural gas extraction contributed to greater 
greenhouse gas emissions than previously thought. The Duke study found 
that there was a correlation between methane levels and distance to 
natural gas drilling sites. The Forest Service found immediate 
vegetation die-off possibly as a result of hydraulic fracturing 
wastewater disposal. How would these current reports alter your 
conclusions in the frequency and type of environmental impacts of 
hydraulic fracturing? In particular, regarding the possible greater 
greenhouse gas footprint of natural gas extracted from shale.
    Answer. While they appeared recently, the Cornell and Duke 
University studies were available to us prior to the completion of the 
report and so our conclusions reflect our consideration of these 
studies. We are not aware of the specifics of the U.S. Forest Service 
study.
    Our gas study team reviewed the environmental issues that have been 
associated with hydraulic fracturing. *Figure 1 is taken from the study 
(Table 2E.1) and it shows that on-site spills and inappropriate offsite 
water disposal account for 33 and 9 percent, respectively of the 
widely-reported environmental incidents over a five year period. While 
the study identifies the types of additives used as fracturing fluids 
and showed that many are chemicals commonly used in households, even 
some of these regularly used chemicals can be toxic to plants at high 
levels, so an incident of vegetation die-off is possible from improper 
disposal of hydraulic fracturing wastewater. These potential 
environmental risks were considered as we developed recommendations, 
leading to one of four highlighted recommendations on gas supply:
---------------------------------------------------------------------------
    * All figures have been retained in committee files.

          A concerted coordinated effort by industry and government, 
        both state and Federal, should be organized so as to minimize 
        the environmental impacts of shale gas development through both 
        research and regulation. Transparency is key, both for 
        fracturing operations and for water management. Better 
        communication of oil- and gas-field best practices should be 
        facilitated. Integrated regional water usage and disposal plans 
        and disclosure of hydraulic fracture fluid components should be 
---------------------------------------------------------------------------
        required.

    In particular, the study recommended that the constituents of 
fracturing fluids should be publicly available, allowing research to 
investigate potential hazards and for regulation to limit use of 
chemicals that were found to be hazardous.
    Figure 1 also shows that half of the widely-reported environmental 
incidents were related to the contamination of groundwater with natural 
gas, as the result of drilling operations. Most frequently, this 
appears to be related to inadequate cementing of casing into wellbores. 
The Duke University study was carefully done and its findings reiterate 
concerns about the care with which gas drilling has been conducted in 
some cases. Because the study was not able to sample water in wells 
before and after the drilling operation, the finding leaves open the 
possibility that the gas was present in these wells prior to the 
drilling operation. However, the strong statistical relationship 
between high levels of gas in water wells close to the drilling 
operation as compared with those some distance away strongly suggests 
that the drilling operation was responsible. The Duke study concluded 
that because the fracturing occurs thousands of feet below near-surface 
aquifers it seems highly unlikely that fracturing itself leads to 
methane contamination of groundwater. It also concluded, as do we, that 
the likely source of methane is poor construction of the well casings. 
The MIT study included a diagram and steps for proper well 
construction, repeated here as Figure 2 (Fig. 2.18 of the report) and 
concludes that proper regulation, inspection, and management of the 
drilling operation could likely minimize this risk. That is, properly 
implemented cementing should prevent methane leaks to groundwater. Poor 
construction of casings would also lead to methane contamination of 
water from conventional gas production and so this does not raise new 
issues that just apply to shale gas or to hydraulic fracturing.
    These specific issues associated with methane contamination were 
also behind the major recommendation already repeated above. Given the 
one limitation of the Duke University study, the inability to sample 
prior to drilling, in the future any wells or shallow aquifers near a 
drilling site should be sampled both prior to when the drilling 
operation commences and then after to determine more conclusively the 
cause and effect relationship. Such sampling and testing might be 
carried out by an independent party.
    We also had the benefit of having access to the Cornell University 
study prior to the completion of our report. That study's lifecycle 
greenhouse gas emissions associated with the production and use of 
natural gas appear to us to be substantially too high. This is an 
important issue. However, cited material in the Cornell study did not 
contain details at the depth needed to reproduce the calculations or 
directly evaluate them.
    A major conclusion of our study is that natural gas can be a very 
effective near to mid-term solution for reducing greenhouse gas 
emissions, principally by substituting for coal in electricity 
generation. It is generally recognized that combustion of natural gas 
for power generation is only + or less GHG-intensive than producing 
power from coal using conventional methods that do not capture 
CO2. The Cornell University study produced calculations that 
suggested the exact opposite, that power generation from natural gas 
might be twice as GHG-intensive as coal generation. Consequently, a 
group of MIT faculty (John Reilly, Henry Jacoby, Ron Prinn, Dick 
Schmalensee), some part of the Natural Gas study and some not, 
collaborated on a review of the Cornell study. Combined with the 
assumption of very high fugitive emissions in shale gas production, the 
MIT faculty group trace the extreme conclusion of the Cornell study on 
the climate impacts of natural gas versus coal to: (1) the use of 20-
year Global Warming Potential (GWP) indices when authoritative 
scientific and regulatory bodies have settled on 100-year GWPs, the 
result being to dramatically elevate the climate effects of methane 
leakage versus carbon dioxide from fossil fuel combustion; and (2) 
using a very low natural gas-to-electricity conversion efficiency, that 
associated with gas peaking plants, when any replacement of base load 
coal power generation would almost certainly use high efficiency 
combined cycle plants to replace very inefficient old coal plants (as 
is happening already with no carbon policy!). Neither assumption is in 
our view appropriate. Replacing them with accepted ones restored the 
conclusion that gas is about + as GHG-intensive as coal, even with high 
estimates of gas leakage.
    Nevertheless, the issue of quantifying fugitive methane emissions 
for fossil fuel production, conversion, transportation, and end use 
should be revisited. This led us to include, in our study, the 
following major recommendation:

          The EPA and the U.S. Department of Energy (DOE) should co-
        lead a new effort to review, and update as appropriate, the 
        methane emission factors associated with natural gas 
        production, transmission, storage and distribution. The review 
        should have broad-based stakeholder involvement and should seek 
        to reach a consensus on the appropriate methodology for 
        estimating methane emissions rates. The analysis should, to the 
        extent possible: (a) reflect actual emissions measurements; (b) 
        address fugitive emissions for coal and oil as well as natural 
        gas; and (c) reflect the potential for cost-effective actions 
        to prevent fugitive emissions and venting of methane.

    Another important factor is that methane emissions at the wellhead 
can be captured for economic benefit. Indeed, a GHG cap and trade 
policy would provide further economic incentive. This is in contrast to 
post-combustion carbon dioxide capture and sequestration, which is a 
very expensive proposition than can be justified only with a high 
carbon dioxide emissions price (or equivalent regulation). Our report 
shows that, together with demand management, substitution of natural 
gas for coal is the most cost effective near-term approach to reducing 
carbon dioxide emissions.
       Response of Ernest J. Moniz to Question From Senator Udall
    Question 1. Your report has several suggestions for addressing the 
risks of shale gas drilling, including following best practices for 
casing and cementing. Do you think current best practices for cementing 
and casing are sufficient to protect groundwater from the materials in 
the well bore, or is more R&D needed to improve industry methods in 
this area?
    Answer. We believe that the application of current best practice to 
casing and cementing is the minimum level of regulation necessary to 
address the environmental issues associated with shale development. 
Additional research and development would be appropriate given the 
importance of the technology, and much of this will go on in industry. 
However, public funding of more basic research, such as developing 
novel materials and advanced sensors to further enhance the safety and 
reliability of drilling operations, would also be appropriate.
     Responses of Ernest J. Moniz to Questions From Senator Shaheen
    Question 1. The recent MIT report discusses the importance of 
energy efficiency and makes recommendations on how efficiency should be 
deployed to balance energy demand in the future. Energy efficiency is 
the cheapest, fastest way to address our energy needs, and it must play 
a central role in moving us to a clean energy future. Could you discuss 
the interplay between the development of a domestic natural gas supply 
and the increased use of combined heat and power (CHP) in industry and 
in the power sector?
    Answer. We see a strong interplay between the current outlook for 
natural gas supplies and the potential for increased use of CHP in 
large scale applications. CHP systems have very high overall energy 
efficiency levels (in the range of 60% up to 90% in some cases). 
Natural gas combustion turbines, coupled with waste heat recovery 
systems, are the leading technology for larger scale CHP systems, and 
thus represent an opportunity for increased demand for natural gas for 
this application. The combination of current supply and price for 
natural gas and relatively low capital and operating costs for natural 
gas based CHP systems make natural gas based CHP an attractive 
alternative for many industrial facilities. Industrial CHP systems can 
be sized to meet heat loads within the plant. Electrical supply and 
demand levels within the industrial facility can be balanced with the 
grid. For example, many local electricity distributors offer programs 
for the purchase of excess electricity generation from industrial CHP 
facilities. The report notes the recent Energy Information 
Administration Annual Energy Outlook 2011 projection of an increase of 
181 percent in electricity generated from end-user CHP systems by 2035. 
This would imply an increase in natural gas use of 1.7 Tcf per year by 
2035.
    Question 2. A recent report by Black and Veatch (a global 
engineering, construction and consulting firm) estimated that 54,000 MW 
(or 16% of the existing coal-fired power generation fleet) will likely 
be retired in the near future. There are a variety of factors for these 
retirements, including age and the economics of the plants as well as 
pending EPA regulations to reduce smog and hazardous air pollutants. 
Coming from a downwind state, these are important regulations to 
protect the health of children and at-risk populations. But in all 
likelihood we are looking at a time of tremendous transition in our 
power sector. What role do you see for natural gas and greater use of 
CHP in this transition of our power sector?
    Answer. We see a significant role for natural gas in electricity 
generation in just about any scenario, not only to reduce emissions of 
conventional pollutants but also as a measure to achieve significant 
reductions in greenhouse gas (GHG) emissions in the power generation 
sector. Our study analyzed this issue from several different 
perspectives. In Chapter 4 of the report, we present an analysis of 
near term opportunities achieving emissions reductions through 
increased utilization of existing natural gas combined cycle generation 
capacity to displace existing coal generation capacity. Our analysis 
showed that there is sufficient surplus NGCC capacity to displace 
roughly one-third of U.S. coal generation, an amount approximately 
twice as large as the level of retirements projected by Black and 
Veatch. The analysis indicated that, on a national basis, the full 
utilization of existing NGCC would reduce NOx and mercury emissions by 
about one-third and CO2 emissions by about 20 percent, while 
increasing demand for natural gas by about 4 Tcf per year. We concluded 
that this represents a low cost solution to achieving significant 
emissions reductions, without the need for significant capital 
investment in new electricity generation capacity. However, we point 
out that these are national results, and that analysis in greater 
geographical detail is needed in order to validate the actual 
displacement by region and also to identify with higher resolution 
constraints due to the existing transmission infrastructure and to the 
needs of balancing supply and demand.
    We also performed longer-term modeling of the electricity sector 
using the MIT Emissions Prediction and Policy Analysis (EPPA) model. We 
used this model to better understand the implications of policies for 
achieving significant reductions in GHG emissions in the U.S. economy. 
Our base GHG emission reduction scenario was a price case where a 50 
percent economy-wide GHG emissions reduction is achieved by 2050 
through the application of a price on carbon. In this case, coal 
generation completely phased out by 2035, while the level of natural 
gas generation tripled. Subsequently however, natural gas also began to 
decline due to increasing carbon prices, transitioning to a carbon-free 
electricity sector. Coal and eventually natural gas need more economic 
CCS in order to compete with nuclear and renewables when the emissions 
price is very high.
    Question 3. Your report finds that CHP isn't currently viable at 
residential scales. What steps can we take to expand CHP in this 
sector? Do we need more research and development?
    Answer. Our analysis of residential CHP use indicated that the 
economics of CHP use was strongly dependent upon the matching of heat 
and power loads with the heat and power output levels (or heat to power 
ratios) from various CHP technologies. We modeled a residential case 
study of the New England region that entails large seasonal variation 
in heat and power loads, with a large power load in summer (for air 
conditioning) and a large heat load in the winter season. Deployment of 
existing engine-based CHP technologies, which have relatively high 
heat-to-power ratios, was not economic, even in cases where the CHP 
system was sized to meet the winter peak heat load. We concluded that 
efforts to reduce the capital cost of residential CHP technologies, as 
well as develop technologies with lower heat to power ratios, were 
needed in order to make residential CHP systems more competitive.
    Our analysis clearly identifies the need for additional R&D on 
smaller scale CHP technologies. A quote from Chapter 8 (p. 165) sums 
this best:

           . . . micro-CHP (kilowatt scale) will need a substantial 
        breakthrough to become economic. Micro-CHP technologies with 
        low heat-to-power ratios will yield greater benefits for many 
        regions, and this suggests sustained research into kW-scale 
        high-temperature, natural gas fuel cells.''
                              Appendix II

              Additional Material Submitted for the Record

                              ----------                              

                                      Department of Energy,
                                     Washington, DC, July 19, 2011.
Hon. Jeff Bingaman,
Chairman, Committee on Energy and Natural Resources, U. S. Senate, 
        Washington, DC.
    Dear Mr. Chairman:
    As promised in response to the questions this morning concerning 
the recent New York Times article relating to EIA's shale gas 
assessment, I am enclosing the complete response EIA provided to a 
letter from Representative Edward J. Markey, Ranking Member of the 
House Committee on Natural Resources.
    Please do not hesitate to contact me should you have any questions. 
Your staff may also contact John Conti, Assistant Administrator for 
Energy Analysis at 202-586-2222.
                                                 Sincerely,
               Howard K. Gruenspecht, Acting Administrator,
                                 Energy Information Administration.

Enclosure.
                                       Department of Energy
                                      Washington, DC, July 8, 2011.
Hon. Edward J. Markey,
Ranking Member, Committee on Natural Resources, U.S. House of 
        Representatives, Washington, DC.
    Dear Representative Markey:
    This is in response to your letter of June 27, 2011 concerning the 
data and methodology used by the U.S. Energy Information Administration 
(EIA) to compile estimates of shale gas reserves and resources. Your 
letter cites a New York Times (NYT) article that EIA believes unfairly 
characterizes the integrity of our shale gas estimates. We are glad to 
have the chance to address your concerns and have sought to provide you 
with responsive information promptly.
    The enclosure provides responses to the questions raised in your 
letter and additional materials that bear on your inquiry, including 
EIA's response to a pre-publication inquiry from the author of the NYT 
article cited in your letter and more complete copies of selectively 
redacted e-mails that were posted on the NYT website.
    As noted in your letter, the estimate of shale gas resources 
(excluding proved reserves) in EIA's Annual Energy Outlook 2011 
(AE02011) is 827 trillion cubic feet. An additional 35 trillion cubic 
feet of proved reserves brings the total estimate of technically 
recoverable shale gas resources in AE02011 to 862 trillion cubic feet.
    EIA staff and management have carefully reviewed the NYT article 
and have found nothing that causes us any concern regarding the 
methodology, data, and analysis that underlies the estimates of shale 
gas in AE02011. In fact, the AE02011 Issues in Focus section includes a 
dEIAiled discussion that addresses both the upside and downside 
uncertainties surrounding shale gas.
    Hopefully, the enclosed information will provide you with useful 
insight into the data and methodology that underlie EIA's shale gas 
estimates. We would also welcome the opportunity to brief you and your 
staff on our shale gas estimates and any issues raised by the NYT 
article.
    Please do not hesitate to contact me if we can be of further 
assistance. Your staff may also contact John Conti, Assistant 
Administrator for Energy Analysis, at 202-586-2222.
                                                 Sincerely,
              Howard K.. Gruenspecht, Acting Administrator,
                            U.S. Energy Information Administration.
    Responses to questions raised in a June 27, 2011 letter from 
Representative Edward J. Markey, Ranking Member, House committee on 
Natural Resources to Richard G. Newell, Administrator, energy 
Information Administration
                           table of contents
    Responses
    Appendices Containing Materials Referenced in the Responses*
---------------------------------------------------------------------------
    * Materials to the appendices have been retained in committee 
files.
---------------------------------------------------------------------------
    Appendix A--Assumptions to the Annual Energy Outlook 2011, Oil and 
Gas Supply Module.
    Appendix B--U.S. Geological Survey, Assessment of Undiscovered Oil 
and Gas Resources of the Williston Basin Province of North Dakota, 
Montana, and South Dakota, 2008, Fact Sheet 2008-3092, November 2008.
    Appendix C--U.S. Geological Survey, Assessment of Undiscovered Oil 
and Gas Resources of the Appalachian Basin Province, 2002, USGS Fact 
Sheet FS-009-03, February 2003, Table 1, page 2.
    Appendix E--U.S. Geological Survey: Improved USGS Methodology for 
Assessing Continuous Petroleum Resources, Data Series 587, Version 1, 
2010. Appendix E: U.S. Geological Survey, Analytic Resource Assessment 
Method for Continuous-Type Petroleum Accumulations--The ACCESS 
Assessment Method, Chapter 6 of Total Petroleum System and Assessment 
of Coalbed Gas in the Powder River Basin Province, Wyoming and Montana, 
USGS Powder River Basin Province Assessment Team, U.S. Geological 
Survey Digital Data Series DDS-69-C, 2004, page 1.
    Appendix F--AE02010 Documentation of the Oil and Gas Supply Module 
(OGSM), DOE/EIA-M063(2010).
    Appendix G--Review of Emerging Resources, U.S. Shale Gas and Shale 
Oil Plays. Includes INTEK, inc. Report Prepared for the Office of 
Energy Analysis, EIA, December 2010, including a brief EIA summary 
paper that provides context for its findings.
    Appendix H--Howard Gruenspecht, EIA Deputy Administrator, 
presentation: ``Shale Gas in the United States: Recent Developments and 
Outlook'' December 2, 2010.
    Appendix I--EIA Oil and Gas Lease Equipment and Operating Costs 
1994 through 2009.
    Appendix J--AE02011, Issues in Focus article ``Prospects for Shale 
Gas''.
    Appendix K--EIA's response to a prepublication inquiry from the 
author of the NYT article referenced in the letter.
    Appendix L--Copies of individual emails posted on the NYT website 
followed by more complete copies of selectively redacted emails. The 
redactions in the more complete versions are limited to a personal 
email address and the name of an EIA employee whose views were being 
characterized by someone else.

    Question 1. Please provide the methodology and all supporting 
materials behind EIA's estimate of U.S. natural gas resources or 
reserves used in the AE02011. Has the methodology used to estimate U.S. 
natural gas resources or reserves changed from previous estimates? If 
so, how and why was the methodology changed?
    Answer. EIA continues to use the methodology instituted over a 
decade ago tc estimate oil and natural gas resources, including shale 
gas resources, for the Annual Energy Outlook (AEO) energy projections. 
EIA's oil and gas resource estimates are updated annually as new 
information becomes available. In recent years, the AEO natural gas 
resource estimates have increased substantially as extensive shale gas 
drilling and production indicated the widespread economic viability of 
shale gas production in a growing number of shale formations, 
particularly in the Marcellus and Haynesville shale formations.\1\
---------------------------------------------------------------------------
    \1\ The Annual Energy Outlook 2011 oil and natural gas resource 
estimates and model assumptions are available on the EU website at 
http:/Avww.eia.govi/forecasts/aeo/assumntions/oi__gas,pdf. (See 
attached Appendix A.)
---------------------------------------------------------------------------
    EIA's domestic oil and natural gas technically recoverable 
resources\2\ consist of proved reserves,\3\ inferred reserves,\4\ and 
undiscovered technically recoverable resourees.\5\ EIA resource 
assumptions used in the AEO are based on estimates of technically 
recoverable resources from the United States Geological Survey (USGS) 
and the Bureau of Ocean Energy Management Regulation and Enforcement 
(BOEMRE). EIA then makes adjustments to add frontier plays that have 
not been quantitatively assessed and for those plays currently under 
development where the latest available USGS assessment was clearly out-
of-date.
---------------------------------------------------------------------------
    \2\ Technically recoverable resources are resources in 
accumulations producible using current recovery technology but without 
reference to economic profitability.
    \3\ Proved reserves are the estimated quantities that analysis of 
geologic and engineering data demonstrates with reasonable certainty to 
be recoverable in future years from known reservoirs under existing 
economic and operating conditions.
    \4\ Inferred reserves are that part of expected ultimate recovery 
from known fields in excess of cumulative production and current 
reserves.
    \5\ Undiscovered resources are located outside oil and gas fields 
in which the presence of resources has been confirmed by exploratory 
drilling; they include resources from undiscovered pools within 
confirmed fields when they occur as unrelated accumulations controlled 
by distinctly separate structural features or stratigraphic conditions.
---------------------------------------------------------------------------
    Over the past decade, several important EIA adjustments have 
involved continuous-type resources of oil or natural gas that are 
trapped within the source rock where they were created.\6\ For example, 
for AE02007, EIA adopted in 2006 an estimate of 3.60 billion barrels of 
oil resources for the Bakken formation, significantly higher than the 
latest USGS resource estimate at that time, which had been based on an 
assessment made in 1995. Subsequently, in 2008, USGS issued an updated 
assessment that estimated Bakken mean technically recoverable oil 
resources at 3.65 billion barrels.\7\
---------------------------------------------------------------------------
    \6\ Conventional oil and gas resources, which accounted for 
virtually all production prior to 1990, are hydrocarbons that have 
migrated from their source rock and accumulated in a reservoir where 
they are trapped by impermeable cap or seal.
    \7\ U.S. Geological Survey, Assessment of Undiscovered oil and Gas 
Resources of the Williston Basin Province of North Dakota. Montanoa and 
South Dakota, 2008, Fact Sheet 2008-3092, November 2008. (See attached 
Appendix B.)
---------------------------------------------------------------------------
    Turning to shale gas, the rapid increase in development activity 
and production over the past several years has created situations where 
the latest available USGS assessment was clearly out of date. For 
example, the last USGS assessment of the Marcellus shale was published 
in February 2003 for 2002, with the mean value of technically 
recoverable resources estimated at 1.9 trillion cubic feet.\8\ 
Subsequent to the USGS assessment of the Marcellus, it became apparent 
that the application of horizontal drilling and hydraulic fracturing 
technologies would result in much higher resource recovery rates. The 
EIA estimates that Marcellus shale gas production in 2010 was about 400 
billion cubic feet, which would have been impossible if the Marcellus 
resource were constrained to the volume estimated by the USGS in 2002.
---------------------------------------------------------------------------
    \8\ U.S. Geological Survey, Assessment of Undiscovered Oil and Gas 
Resources of the Appalachian Basin Province, 2002, USGS Fact Sheet FS-
009-03, February 2003, Table 1, page 2. (See attached Appendix C.)
---------------------------------------------------------------------------
    The EIA estimates of shale gas resources within a specific shale 
formation use an assessment methodology for continuous-type resources 
originally developed by the USGS\9\. A shale formation's gas resources 
are calculated fora particular subregion and sub-play using the 
following equation:
---------------------------------------------------------------------------
    \9\ The earliest USGS publications on this methodology were 
published before 2000. The latest version of the USGS methodology is 
provided in the following USGS publication entitled: Improved USGS 
Methodology for Assessing Continuous Petroleum Resources, Data Series 
587, Version 1, 2010. (See attached Appendix D.)


 
 
 
 
 
Resources =                                                              (Play/sub-play area in square miles) x
 
                                                                      (Estimated ultimate gas recovery per well
                                                                                                            EEUR], in billion cubic feet [Bcfl per well) x
 
                                                                            (Number of wells per square mile) x
 
                                                                                           (Play probability) x
                                                                                                  (USGS factor)
 


    As discussed in more detail below, EIA's shale gas resource 
assessment methodology is intended to be relatively conservative, 
taking into consideration the variation in shale gas well productivity 
within core and non-core subregions of a play and by assigning a ``play 
probability'' and a ``USGS factor'' that significantly reduces the 
shale gas resource estimates.
    The estimate of Marcellus shale gas resources used in AE02011 
illustrates the application of the assessment approach outlined above. 
Because the Marcellus shale is large in extent, covering about 95,000 
square miles,\10\ the Marcellus shale gas play is divided into seven 
subregions,\11\ with each subregion having three distinct subregions' 
shale gas well recovery characteristics to capture the variability in 
production and resource circumstances within a subregion.
---------------------------------------------------------------------------
    \10\ The square mileage figure used in EIA's Marcellus shale gas 
resource estimation is 94,893 square miles.
    \11\ The Marcellus subregions are as follows: 1) active (aka. core 
region) region in PA & WV, 2 undeveloped region in MD, 3) undeveloped 
in NY, 4) undeveloped in OH, 5) undeveloped in PA, 6) undeveloped in 
VA, and 7) undeveloped in WV.
---------------------------------------------------------------------------
    The Marcellus sub-plays have the following shale gas well recovery 
characteristics over the life of the well for the core and undeveloped 
(non-core) subregions:

          1. The core subregion encompasses 10,622 square miles of 
        Pennsylvania and West Virginia and is subdivided into 3 
        productivity and resources levels:

   With 30% of the core region having an estimated ultimate 
        recovery (EUR) of 4.66 Bcf/well,
   With 30% of the core region having an EUR of 3.50 Bcf/well,
   With 40% of the core region having an EUR of 2.63 Bcf/well.

          2. The 6 undeveloped (non-core) subregions encompass 84,271 
        square miles in Maryland, New York, Ohio, Pennsylvania, 
        Virginia, and West Virginia, with this region further 
        subdivided into 3 productivity and resources levels:

   With 30% of the non-core region having an EUR of 1.53 Bcf/
        well,
   With 30% of the non-core region having an EUR of 1.15 Bcf/
        well,
   With 40% of the non-core region having an EUR of 0.86 Bcf/
        well.

    The EIA uses a variety of public data sources to estimate Marcellus 
shale gas production decline curves and EURs, including HPDI, LLC well-
specific production data.
    In each Marcellus subregion, shale gas well spacing is assumed to 
be 8 wells per square mile, which is 80 acres per well and typical for 
most shale gas plays.
    Given that large portions of the non-core Marcellus have not been 
production tested, the EIA assessment methodology applies a ``play 
probability'' that represents the possibility that some portion of the 
Marcellus could be noneconomic to develop. The play probability for the 
Marcellus play is set at 70 percent, which means that 30 percent of the 
play area is assumed to be uneconomic based on well productivity and 
EUR considerations. A low well EUR could be due to some or all of the 
following attributes: the formation is too thin or too close to the 
surface, low porosity, low pore pressure, high clay content, low carbon 
content, low absorbed gas volume, and/or low thermal maturation.
    The EIA shale gas resource assessment also applies an additional 
multiplicative factor to reduce resources based on the USGS assessment 
methodology for ``basin continuous'' gas formations, which classifies 
technically recoverable resources as those that can be expected to be 
potentially added to reserves over a 30-year period.\12\ The ``USGS 
factor'' used to make this adjustment recognizes that over a 30-year 
period only some fraction of the technically recoverable resources are 
likely to be developed due to a number of constraints, including 
domestic gas consumption requirements, drilling rig availability, 
sufficiently high gas prices, the availability of producer cash flow 
and capital funding, and the development of gas processing and pipeline 
infrastructure. The core Marcellus region is assumed to have a 60 
percent USGS factor, and the non-core region is assumed to be a 30 
percent USGS factor.
---------------------------------------------------------------------------
    \12\ U.S. Geological Survey, Analytic Resource Assessment Method 
for Continuous-Type Petroleum Accumulations--The ACCESS Assessment 
Method, Chapter 6 of Total Petroleum System and Assessment of Coalbed 
Gas in the Powder River Basin Province Wyoming and Montana, USGS Powder 
River Basin Province Assessment Team, U.S. Geological Survey Digital 
Data Series DDS-69-C, 2004, page 1. (See attached Appendix E.)
---------------------------------------------------------------------------
    The EIA shale gas resource assessment methodology also takes into 
consideration natural gas that has been produced or booked as proven 
:reserves. Consequently, with all else remaining the same over the long 
term, the Marcellus shale gas resource volumes would decline as these 
resources are booked as proven reserves and subsequently produced.
    Moving beyond EIA's assessment methodology and its application to 
the development of updated shale gas resource estimates for AE02011, it 
should be noted that EIA's oil and natural gas resource estimates 
undergo continuous modification and improvement based on new 
information regarding drilling and production technologies, and the 
ability to produce oil and natural gas resources using those 
technologies. However, the ultimate cumulative productive capability of 
any particular shale gas well or set of wells cannot be fully 
ascertained until those wells are plugged and abandoned.
    Finally, it should be noted that EIA oil and natural gas resource 
assessments are not performed in a vacuum. EIA is constantly comparing 
its estimates with those of other groups, such as the USGS, the BOEMRE, 
IHS-CERA, the National Petroleum Council (NPC), and the Potential Gas 
Committee, when updates and revisions are made available by these 
groups. Furthermore, the EIA conducts open and public workshops in 
which representatives of the USGS, the BOEMRE, and other experts are 
invited to critique both the EIA resource assessment methodology and 
resource estimates. The last such workshop was held on April 27, 2011 
after the conclusion of the EIA Energy Conference.
    Question 2. Please list any outside contractors used in formulating 
EIA's estimate of natural gas reserves used in the AE02011; the 
criteria used for selecting those specific outside contractors; all 
correspondence (including reports, emails, memos, phone or meeting 
minutes or other materials) between EIA staff and any outside 
contractors, natural gas industry representatives or members of 
academic institutions regarding estimates of U.S. natural gas reserves; 
all internal EIA staff correspondence (including reports, emails, 
memos, phone or meeting minutes or other materials) relating to 
uncertainties in estimates of U.S. natural gas reserves.
    Answer. EIA utilizes a multiple award, Indefinite Delivery 
Indefinite Quantity procurement vehicle (EOP 3) to obtain the vast 
majority of its contractor support services, including those related to 
producing the estimates of natural gas reserves in the AE02011. Task 
Order Contracts are then issued on a competitive baths, amongst the EOP 
3 Multiple Award Coneract winning vendor teams. Science Applications 
International Corporation (SAIC) was awarded two task orders under EOP 
3 to support EIA's modeling and forecasting activities that, among 
other requirementsaincluded expertise pertaining to natural gas 
resources. As part of its effort, SAIC utilized a team of 
subcontractors to address the broad spectrum of modeling and 
forecasting requirements that feeds into the AEO production process. 
The subcontractor that specifically contributed to the natural gas 
resource estimates was INTEK, Inc.
    SAIC was awarded a contract under EDP 3 by demonstrating its 
capability to meet a broad array of technical support requirements with 
respect to the following selection criteria:

   Business Management Approach
   Technical Approach
   Past Performance
   Corporate Experience

    By virtue of its EOP 3 contract award, SAIC was eligible to bid on 
individual task orders, including the two technical support tasks 
referenced above. Task order award criteria, standardized across EIA 
tasks, are as follows:

   Criterion 1: Technical Proposal

    --la: Business Management Approach

      --Task Management Plan
      --Staffing Plan
      --Quality Assurance Plan
      --Risk Management Plan
      --Transition Plan

    --lb:Technical Approach

    --Criterion 2: Experience
    --Criterion 3: Evaluation of Cost

    SA1C was selected because it represented the best value to the 
government based on the totality of its task proposals rather than 
being based solely on the presence of a particular subcontractor(s), as 
the natural gas resource estimates represented only a portion of the 
overall support needs addressed by these task orders.
    Question 3. Please provide the methodology and all supporting 
materials behind EIA's estimate of future U.S. natural gas production, 
in particular production of shale gas. Has the methodology used to 
project future U.S. natural gas production changed from previous 
estimates? If so, how and why has that methodology changed?
    Answer. The basic methodology used in the Oil and Gas Supply Module 
(OGSM) of the National Energy Modeling System underlying the 2010 and 
2011 Annual Energy Outlooks is unchanged. The majority of the changes 
between the AE02010 and AE02011 reflects updates/revisions to input 
data and not structural methodological revisions. The major changes 
include:

   Texas Railroad Commission District 5 is included in the 
        Southwest region instead of the Gulf Coast region.
   Re-estimation of Lower 48 States onshore exploration and 
        development costs.
   Updates to crude oil and natural gas resource estimates for 
        emerging shale plays.
   Addition of play-level resource assumptions for tight gas, 
        shale gas, and coalbed methane
   Updates to the assumptions used for the announced/
        nonproducing offshore discoveries.
   Revision of the North Slope new field wildcat exploration 
        wells (NFW) drilling rate function. The NFW drilling rate is a 
        function of the low-sulfur light projected crude oil prices and 
        was statistically estimated based on Alaska Oil and Gas 
        Conservation Commission well counts and success rates.
   Recalibration of the Alaska oil and gas well drilling and 
        completion costs based on the 2007 American Petroleum Institute 
        Joint Association Survey on Drilling Costs.
   Updates to oil shale plant configuration, cost of capital 
        calculation, and market penetration algorithm.

    The description of the lower-48 oil and gas supply module from OGSM 
documentation for AE02010 is provided as a part of this response and is 
also included in the complete OGSM documentation that is available on 
the EIA website.\13\ The OGSM documentation for AE02011, which will 
reflect the changes summarized above, is currently being prepared, and 
is scheduled to be released by the end of July 2011.
---------------------------------------------------------------------------
    \13\ http://www.eia.gov/FTPROOT/modeldoc/m063(2010).pdf(See 
attached Appendix F)
---------------------------------------------------------------------------
    The key assumptions underlying the AE02011 are published in the 
AE02011 Assumptions Document (Oil and Gas Supply Module).\14\ A 
comparison of the play-level resources assumptions between AE02011 and 
AE02010 is provided in the following table (Table 1).
---------------------------------------------------------------------------
    \14\ http://www.eia.gov/forecasts/aeo/assumptions/pdf/oil__gas.pdf 
(See attached Appendix A.)



    Question 4. Please list any outside contractors used in formulating 
EIA's projection of future U.S. natural gas production used in the 
AE02011 and all other agency reports or publications centering on shale 
gas; the criteria used for selecting those specific outside 
contractors; all correspondence (including reports, emails, memos, 
phone or meeting minutes or other materials) between EIA staff and any 
outside contractors regarding projections of future U.S. natural gas 
production; all internal EIA staff correspondence (including reports, 
emails, memos, phone or meeting minutes or other materials) relating to 
uncertainties in projections of future U.S. natural gas production.
    Answer. The AE02011 oil and natural gas production projections are 
developed within the Office of Petroleum, Natural Gas, and Biofuels 
Analysis which is within the ERA's Office of Energy Analysis. Analysts 
and managers meet weekly to review and discuss the latest runs and the 
assumptions driving these results. Contractors contribute to the 
development of oil and natural gas input data and estimation parameters 
but are not part of the run review process. In addition, EIA holds 
working group meetings to solicit comments/suggestions pertaining to 
key assumptions and preliminary results. Participants in these working 
group meetings have been from other offices within the U.S. Department 
of Energy (DOE), the U.S. Environmental Protection Agency, USGS, NPC, 
industry, academia, consulting firms, oil and gas associations, 
National laboratories, and other government agencies.
    The contractor used to assist in the development of AE02011 natural 
gas assumptions and data was SAIC. They chose to subcontract the shale 
gas resource assessment to INTEK under the EOP 3 task order previously 
discussed in the response to Question 2. INTEK's report to EIA, along 
with a brief EIA paper that summarizes and provides context for its 
findings, is available on EIA's website and is included in this 
response.\15\
---------------------------------------------------------------------------
    \15\ http://www.eia.gov/analysis/studies/usshalegas/ (See attached 
Appendix G.)
---------------------------------------------------------------------------
    The timing and level of production of natural gas resources, 
including shale gas, is determined within the National Energy Modeling 
System, primarily driven by the economics of drilling, rig 
availability, and demand. Although INTEK was instrumental instrumental 
in estimating the shale gas resource base, the conversion of these 
resources into production is modeled by EIA analysts. INTEK was not 
independently consulted but did participate in various working group 
meetings and workshops with attendees from other groups outside of EIA 
as previously indicated.
    Question 5. According to The New York Times article, some of the 
outside contractors used by EIA to formulate estimates of natural gas 
reserves or projected levels of production have a financial or other 
interest in oil and/or gas companies or business relationships with 
such companies. Please provide details about each such contractor, the 
specific company and the nature of the interest or other relationship 
How does EIA ensure that all outside contractors conducting work for 
the agency do not have financial or other interests or relationships 
that could bias the results of any report? How does EIA ensure proper 
disclosure of any such interests?
    Answer. EIA's contractual policies with regard to real and/or 
potential conflicts of interest are those prescribed by the Federal 
Acquisition Regulation (FAR). That is, the agency requires that 
contractors submit Organizational Conflict of Interest (OCI) 
documentation prior to any contract award to include:

   A statement of any past (within the past twelve months), 
        present, or currently planned financial, contractual, 
        organizational, or other interests relating to the performance 
        of the statement of work.
   A statement that no actual or potential conflict of interest 
        or unfair competitive advantage exists with respect to the 
        advisory and assistance services to be provided.

    This documentation is reviewed at the Departmental level by the 
relevant Contracting Officer, and the contract award itself is reviewed 
by DOE's Office of General Counsel to ensure that all pertinent rules 
are followed in the selection process.
    Further, the prime contractor is required to obtain similar OCI 
documentation from all potential subcontractors and consultants and 
determine in writing whether the interests disclosed present an actual 
or potential conflict prior to issuance of a subcontract.
    At the task order level, including the two task orders under which 
support was provided for the estimated natural gas resources, OCI 
documentation was again required in advance of an award being made.
    Question 6. According to The New York Times article, some EIA 
staffers have reservations about the quality of the data provided by 
those contractors, specifically citing the use of press releases and 
media reports as a source of data. To what extent are EIA's projections 
based on press releases or media reports? What steps does the EIA 
follow to independently fact-check those press releases or media 
reports?
    Answer. EIA's projections are not based directly on press releases 
or media reports. These sources are used to help inform where the 
industry focus is and where interest/development is heading. For 
example, an announcement of the major oil or gas discovery in the 
offshore Gulf of Mexico will direct analysts to check with the BOEMRE 
for confirmation and additional data needed to incorporate this new 
discovery into the model.
    Data provided from contractors is reviewed and evaluated against 
other sources where available. Specifically, the shale gas resource 
base provided by INTEK for AE02011 was compared to recent estimates 
from other sources, some of which are summarized in slide 13 of a 
December 2010 presentation by Deputy Administrator Gruenspecht to the 
U.S.-Canada Energy Consultative Mechanism.\16\ Drilling and completion 
costs are based on data provided by the American Petroleum Institute in 
their Joint Association Survey on Drilling Costs. Lease equipment and 
operating costs are based on EIA's lease equipment and operating cost 
estimates provided by the Office of Oil, Gas, and Coal Supply 
Statistics.\17\
---------------------------------------------------------------------------
    \16\ http://www.eia.gov/neic/speeches/gruenspecht12022010.pdf (See 
attached Appendix H.)
    \17\ http://www.eia.gov/pub/oil__gas/natural__gas/
data__pub1ications/cost__indices__equipment__production/current/ 
coststudy.html (See attached Appendix I.)
---------------------------------------------------------------------------
    To the extent possible, EIA uses resource assessments from USGS and 
the BOEMRE. The EIA uses contractors to provide assistance with 
updating resource estimates where development activities undertaken 
since the last available resource assessments by government agencies 
have added significant new knowledge. When the USGS and BOEMRE release 
updated resource assessments, these estimated resources replace the 
resource estimates developed by the EIA.
    Recognizing that publicly announced production rates tend to be 
skewed toward high-production and high-profit wells, the EIA and its 
contractors use State reported well production where available to 
compare to publically available data and to calibrate engineering-based 
production curves. To project production from emerging or undeveloped 
areas with little to no drilling, EIA and its contractors use 
experience from other plays of similar nature as analogs. Thus, there 
is a great deal of uncertainty underlying the production projections. 
The EIA highlights the shale gas resource uncertainty in an AEO2011 
Issues in focus article titled ``Prospects for shale gas'' and presents 
the impact of higher and lower shale gas resource assumptions on 
production, consumption, and prices.\18\
---------------------------------------------------------------------------
    \18\  http://www.eia,gov/forecasts/aeo/pdf/0383(2011).pdf, pages 
37-40. (See attached Appendix J.)
---------------------------------------------------------------------------
    Question 7. Among the documents published by The New York Times are 
emails in which EIA officials express concern about the financial 
stability of shale gas companies and the economic viability of shale 
gas production. For example, one EIA official says ``It is quite likely 
that a lot of these companies will go bankrupt'' Another describes 
``irrational exuberance'' around shale gas production. Can you please 
elaborate on those concerns? If shale gas is more expensive to produce 
than previously understood, how will the EIA's projections about 
natural gas supply and consumption be affected?
    Answer. As noted in EIA's response to a pre-publication inquiry 
from the author of the June 27th NYT article\19\, the continuing 
discussion regarding shale gas among EIA staff at all levels is a part 
of a healthy analytical process that considers both the shorter term 
dynamic of the industry and the longer term implications. Also, as your 
question references emails published on the NYT website that were 
selectively redacted, you may find the more complete versions that are 
provided with this response of some interest.\20\ Those emails are 
largely to and from an individual who came to EIA as an intern in 2009 
helping develop materials for a shale gas website and was subsequently 
hired as an entry-level employee in a position that did not involve 
responsibility for the development of EIA's energy projections. Some of 
redactions in the emails published on the NYT website obscure this 
context.
---------------------------------------------------------------------------
    \19\ http://www.eia.gov/pressroom/releases/pdf/shale__gas.pdf. (See 
attached Appendix K.)
    \20\ See attached Appendix L.
---------------------------------------------------------------------------
    Ultimately, the profitability of shale gas development is a 
function of the costs required to drill and produce the gas and the 
price of natural gas. Over the last five years, wellhead natural gas 
prices have demonstrated considerable variability, rising well above 
$10 per thousand cubic feet in July 2008 and falling below $3 per 
thousand cubic feet in September 2009. Future natural gas prices and 
producer profitability have an impact on how much shale gas is produced 
and consumed in the different cases that are included in AEO2011.
    As also noted in EIA's response to a pre-publication inquiry from 
the author of the June 27th NYT article, the uncertainty surrounding 
shale gas resources and the cost of developing them is explored in a 
section of the AE02011 entitled: ``Prospect for shale gas,'' that is 
referenced in EIA's response to Question 6 and included in this 
enclosure as Appendix J. That analysis notes That ``There is a high 
degree of uncertainty around the [AEO2011 Reference case] projection, 
starting with the estimated size of the technically recoverable shale 
gas resource. Estimates of technically recoverable shale gas are 
certain to change over time as new information is gained through 
drilling and production, and through development of shale gas recovery 
technology.'' The article then delineates 5 specific uncertainties 
associated with shale gas resources and costs. The analysis goes on to 
discuss 4 alternate case projections, which double and halve the 
resource base and the shale gas production cost per well. The variation 
in alternatecase assumptions is consistent with the degree of resource 
variability shown in USGS shale gas resource assessments. Across the 4 
alternate shale gas cases, considerable variation is projected in 
domestic shale gas and total natural gas production, natural gas 
imports, natural gas prices, and natural gas consumption.
    As noted in the response to Question 1, as additional information 
becomes available, EIA will change its assessment of domestic oil and 
gas resources and the cost of producing those resources.

                                    

      
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