[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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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
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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
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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).
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* All figures have been retained in committee files.
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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.
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\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.
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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%.
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* All figures have been retained in committee files.
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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\
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\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.
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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\
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\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.
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\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.
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\13\ http://www.eia.gov/FTPROOT/modeldoc/m063(2010).pdf(See
attached Appendix F)
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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).
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\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\
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\15\ http://www.eia.gov/analysis/studies/usshalegas/ (See attached
Appendix G.)
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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\
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\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.)
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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\
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\18\ http://www.eia,gov/forecasts/aeo/pdf/0383(2011).pdf, pages
37-40. (See attached Appendix J.)
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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.
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\19\ http://www.eia.gov/pressroom/releases/pdf/shale__gas.pdf. (See
attached Appendix K.)
\20\ See attached Appendix L.
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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.