Legislature(2009 - 2010)HOUSE FINANCE 519
04/08/2009 03:30 PM House ECON. DEV., TRADE & TOURISM
| Audio | Topic |
|---|---|
| Start | |
| Presentation(s): Porter Bennett, Bentek Energy, "technologies for Shale Gas Development in the U.s."; Presentation by Dr. Mark Myers, Agia, Alaska's Natural Gas, Needed or Not? | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
JOINT MEETING
HOUSE SPECIAL COMMITTEE ON ECONOMIC DEVELOPMENT,
INTERNATIONAL
TRADE AND TOURISM
HOUSE RESOURCES STANDING COMMITTEE
SENATE RESOURCES STANDING COMMITTEE
April 8, 2009
3:34 p.m.
MEMBERS PRESENT
HOUSE SPECIAL COMMITTEE ON ECONOMIC DEVELOPMENT, INTERNATIONAL
TRADE AND TOURISM
Representative Jay Ramras, Chair
Representative Mike Chenault
Representative Mark Neuman
Representative Mike Doogan
Representative Chris Tuck
HOUSE RESOURCES STANDING COMMITTEE
Co-Chair Mark Neuman
Co-Chair Craig Johnson
Representative Scott Kawasaki
Representative Chris Tuck
Representative Peggy Wilson
Representative Paul Seaton
Representative Bryce Edgmon
Representative David Guttenberg
SENATE RESOURCES STANDING COMMITTEE
Co-Chair Bill Wielechowski
Co-Chair Lesil McGuire
Senator Hollis French
Senator Bert Stedman
Senator Gary Stevens
Senator Charlie Huggins
Senator Thomas Wagoner
MEMBERS ABSENT
HOUSE SPECIAL COMMITTEE ON ECONOMIC DEVELOPMENT, INTERNATIONAL
TRADE AND TOURISM
Representative Nancy Dahlstrom
Representative Kyle Johansen
Representative Reggie Joule
Representative Lindsey Holmes
HOUSE RESOURCES STANDING COMMITTEE
Representative Kurt Olson
SENATE RESOURCES STANDING COMMITTEE
All members present
OTHER LEGISLATORS PRESENT
Senator Gene Therriault
COMMITTEE CALENDAR
Presentation(s): Porter Bennett, BENTEK Energy, "Technologies
For Shale Gas Development in the U.S."; Dr. Mark Myers, AGIA,
"Alaska's Natural Gas - Needed or Not?"
PREVIOUS COMMITTEE ACTION
No previous action to report
WITNESS REGISTER
MARK MYERS, Ph.D., AGIA Coordinator
Office of the Commissioner
Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Delivered a presentation on "Alaska's
Natural Gas - Needed or Not?"
PORTER BENNETT, President and CEO
BENTEK Energy
Evergreen, CO
POSITION STATEMENT: Delivered a presentation on "How Horizontal
Drilling $ Fracturing Technologies are Changing Natural Gas
Markets."
ACTION NARRATIVE
3:34:03 PM
CO-CHAIR MCGUIRE called the joint meeting of the House Special
Committee on Economic Development, International Trade and
Tourism, the House Resources Standing Committee, and the Senate
Resources Standing Committee to order at 3:34 p.m. Present at
the call to order from the House Special Committee on Economic
Development, International Trade and Tourism were
Representatives Neuman, Doogan, and Tuck. Representatives
Chenault and Ramras arrived as the meeting was in progress.
Present at the call to order from the House Resources Standing
Committee were Representatives Tuck, Wilson, Seaton, Edgmon,
Guttenberg, Neuman, and Johnson. Representative Kawasaki arrived
as the meeting was in progress. Present at the call to order
from the Senate Resources Standing Committee were Senators
French, Stedman, Stevens, Huggins, Wagoner, and McGuire. Senator
Wielechowski arrived as the meeting was in progress. Also in
attendance was Senator Therriault.
3:34:38 PM
^PRESENTATION(S): PORTER BENNETT, BENTEK ENERGY, "TECHNOLOGIES
FOR SHALE GAS DEVELOPMENT IN THE U.S."; PRESENTATION BY DR. MARK
MYERS, AGIA, ALASKA'S NATURAL GAS, NEEDED OR NOT?
3:34:39 PM
CO-CHAIR MCGUIRE announced that the first order of business is a
presentation by Dr. Mark Myers.
MARK MYERS, Ph.D., AGIA Coordinator, Office of the Commissioner,
Department of Natural Resources, delivered a PowerPoint
presentation titled "Alaska's Natural Gas - Needed or Not? What
about Shale Gas and Carbon Regulation?"
Slide 1 stresses the importance of the changing world demand for
energy due to urbanization, industrialization, and growing
population. The world energy picture is one of growth and
traditional sources are becoming supply limited. The maximum
delivery time for Alaska gas is 20-30 years and over that long
term the demand drive is intensive and growth is massive. Slide
2 illustrates the growth in energy demand for the different
supplies - coal, oil, gas, nuclear, hydro, and other renewables.
Historically increased demand has been accommodated by
increasing oil production. He noted that there's also been a
dramatic increase in the production of coal, a subtle increase
in nuclear and a worldwide increase in the use of natural gas. A
concern for the Alaska project is that energy demand might
switch to other sources including renewables and alternative
sources of gas. Slide 3 illustrated that now and in the future
the dominant energy source will be fossil fuels. Renewable
sources simply cannot grow fast enough to offset the demand
growth.
Slide 4 illustrates the shift from oil to the use of coal and
nuclear for electrical generation in the 30 year period from
1974 to 2004. The use of natural gas for electrical generation
increased just slightly because of limited supplies, but looking
forward it's clear that massive supplies of new, low CO energy
2
will be needed. This pushes the U.S. toward a gas economy and
argues for competition for an overseas LNG market. He
highlighted that much of the demand growth that could
theoretically be met will be limited by the environmental
consequences of all types of energy, renewable or not.
Slide 5 shows that all new sources of energy have unique
environmental challenges, particularly those that use an
abundance of fresh water. For example, the irrigation of
agricultural corn to produce ethanol is drawing down aquifers at
an alarming rate and is non-sustainable. Oil shale and the
growth of hydro have challenging water issues and in some ways
shale gas will be limited by water issues. To sustain the life
of a well it may be fraced up to 10 times and use up to 4
million gallons of water per frac. Because of resource
limitations and environmental constraints past growth can't be
assumed in the future.
3:44:10 PM
MR. MYERS displayed slide 6 highlighting the changes since the
AGIA license was approved.
· The massive global recession has led to a decrease in the
use of energy. Natural gas use in the U.S. has been reduced by
about 1.3 percent and prices out of Henry Hub have dropped
dramatically.
· There's been a rapid expansion of shale gas supplies in the
U.S.
· The new administration's policy shift will potentially
limit OCS and other access for oil and gas exploration and
development.
· The first international Arctic oil and gas assessment shows
Arctic Alaska leading with respect to gas and oil.
· There's increased likelihood of carbon regulation.
SENATOR WAGONER asked if the same gas-rich geologic structure in
the Arctic extends to the Outer Continental Shelf.
3:46:55 PM
MR. MYERS replied the underlying geologic source rocks that
generate oil and gas onshore continue out into the Beauford and
Chukchi seas. Alaska is probably the most prolific generator of
hydrocarbons in North America in terms of the number of source
rocks, the richness of those source rocks and the great geologic
structures both on and offshore. Alaska also has a promising
continental margin that has a huge sedimentary cover and great
structures. For example, the Berger structure had 14 Tcf of gas
in the Chukchi Sea. The offshore potential is large. The
production of associated gas prolongs the life of an oilfield
and if production costs are shared between gas and oil it makes
the gas cheaper to produce. The existing infrastructure in
Prudhoe Bay and the potential of Point Thomson help make
Alaska's gas very competitive at low prices. The ultimate cost
of gas production comes from the transportation and operating
costs additional to the field costs that are relatively minor.
MR. MYER displayed slide 7 showing that the number of gas rigs
in use dropped 45 percent in the last year. Unless some of those
are picked up in the near future, there will be a decline in
production in the next two or three years.
MR. MYER said slide 8 outlines Jim Mulva's, viewpoint that a
long-term view is needed as the driver for a pipeline. Look at
long term demand and the long term price of getting the gas to
market - the competitiveness of the project given alternative
sources.
The line graphs on slide 9 reflect the EIA's most recent 2009
forecast and illustrate that both Lower 48 unconventional and
Alaska North Slope gas will be needed in the future. He said
it's important to realize that new gas supplies often replace
existing conventional supplies that are in rapid decline so
there's a balancing effect. The forecast for Alaska gas is that
it will be a significant player. The second line graph showed
historical and projected natural gas production for 1990-2030 in
five cases - slow technology, low price, reference, rapid
technology, and high price. The models show a dramatic increase
in demand for gas in 2018, which is very good timing for Alaska
gas.
3:51:44 PM
CO-CHAIR WIELECHOWSKI recognized that Representative Ramras had
joined the committee and Commissioner Galvin was in the
audience.
3:52:13 PM
MR. MYERS displayed slide 10 looking at the 2009 EIA forecasts
of prices and said that none of the published forecasts he's
seen indicate that the flood of new gas into the market will
lower prices in the long term. In the short term prices
absolutely will be affected. Lower 48 wellhead and Henry Hub
Spot market prices out to 2030 are all well above the needed
return to make an Alaska gas pipeline profitable. Slide 11
clarified that this is well within the range of expected
outcomes that were modeled in the AGIA findings.
The chart on slide 12 illustrates that shale gas provides about
five percent of domestic production. In 2007 about 47 percent of
domestic production came from nonconventional gas. He explained
that conventional resources in the Lower 48 - except for deep
water offshore, Alaska and potentially Atlantic and West Coast
margins - have been heavily explored and are in rapid decline.
This has caused a shift to the unconventional resources -
coalbed methane, tight gas sands, deep basin centered sands, and
now shale gas. They are typically more expensive to produce.
Slide 13 depicts Wyoming gas reserves and the production history
from 1977 to 2006. Conventional gas resources became more
difficult to produce, accumulations were smaller and
nonconventional gas increased. The same thing will happen in
Alaska but conventional resources will come first, which is why
Alaska gas has such great economics.
Slide 14 shows shale gas plays in the Lower 48. Some shale gas
has to be de-watered and sometimes water has to be added for
fracturing. There's a wide variety of heterogeneity to the
reservoirs and they have a wide variety of economic costs and
development strategies depending on the geochemistry, quality of
the shale, the source rock, whether it's naturally fractured,
ductile or brittle, the depth and ease of extraction due to
surface conditions, access, water availability, land use
policies, royalty rates and environmental policies of the local
district. Overall there is wide variation on the cost structure;
the equation is not simple.
3:55:49 PM
MR. MYERS displayed slide 15 showing the estimated break-even
costs for Lower 48 shale gas and Alaska North Slope onshore gas.
USGS modeled new field development and estimated breakeven costs
at about $3 at the AECO Hub. For the Foothills, USGS generally
used breakeven numbers of about $4.25. Bank of America NYMEX
numbers showed Alaska gas either under or at the low end of the
best Lower 48 shale gas. Low grade was $4.20, medium was $6.64
and the highest was $11.50. Lower drilling and steel costs today
coupled with technology improvements enhance the economics of
both. The balance is that development costs go up for everyone
when fuel prices are high and go down for everyone when prices
are low. It would be a good deal if steel could be purchased
cheaply in the next few years because the base gas in Prudhoe
Bay is currently being cycled.
3:57:26 PM
CO-CHAIR WIELECHOWSKI welcomed Speaker Chenault to the meeting.
He then asked if the $3 figure for onshore North Slope gas
reflects $2.76 for the tariff and $0.20 for capital and
operating costs.
MR. MYERS agreed that operating and capital costs are small.
$2.67 includes treatment plant costs and $4.25 is the cost of
developing a new field, feeder pipelines, and associated
operational costs in the Foothills onshore. Offshore numbers
would be a bit higher.
CO-CHAIR WIELECHOWSKI asked if $4.25 is for a totally new field
outside of Prudhoe/Kuparuk.
MR. MYERS said yes, on state lands onshore. He offered to
provide the numbers that USGS used.
3:58:38 PM
MR. MYERS said Arctic Alaska is one of the two areas of highest
potential for gas according to the most recent assessment. In
fact, Alaska's gas resources represent about 36 percent of the
national total for undiscovered, conventional estimates.
Compared relative to continuous or nonconventional gas, the
December 2008 USGS numbers indicate about 364 Tcf of technically
recoverable gas - including coalbed methane. The price of gas
would need to be between $11 and $12 coupled with lack of
environmental restrictions on access to the resource. Slide 19
showed the mean continuous gas resources excluding coalbed
methane to be about 275 Tcf.
The chart on slide 21 depicts USGS/MMS assessments of
undiscovered, conventional natural gas in Arctic Alaska that are
roughly at parity to Lower 48 gas resources. The graph on slide
22 showed 33 Tcf of undiscovered technically recoverable
nonassociated gas in the central North Slope. Various price
scenarios show that much of the gas is recoverable in the $4-$6
range. It takes about $4 gas to start recovering new field
development away from infrastructure on the central North Slope.
This is consistent with the $4.25 figure. Fields cost different
amounts depending on location, the quality of gas, number of
wells drilled, whether they are horizontal or vertical, and
what's in the gas. This is a relatively good comparison between
the two resources. The EIA price forecast similarly indicates
that much of Alaska's gas is commercial.
MR. MYERS reviewed slide 24 and described the Arctic Alaska
province as immature; just a handful of gas wells have been
drilled for exploration. In comparison, the density of wells in
Wyoming is 80 times that of Alaska. The assumption is that much
more gas will be found as more wells are drilled. Slide 25
indicated about 100 Tcf of technically recoverable coalbed
methane and natural gas hydrates. In neither Alaska nor the
Lower 48 has the over-pressured basin-centered gas - the tight
gas sands - been assessed. It is, however, potentially huge.
Slide 26 reflects Alaska North Slope natural gas hydrate
assessment results for nonconventional gas.
MR. MYERS displayed slide 27 to highlight what happens in a
carbon constrained environment. The IPCC (International Panel
and Climate Change) and the national CCSP (U.S. Climate Change
Science Program) assessments say that if carbon isn't mitigated
now there will be an increase in global temperatures. It is the
consensus of the scientific community that if greenhouse gases
increase there is a natural increase in temperature. To limit
that, manmade CO has to be mitigated. If Congress and the
2
administration choose to do that, it will change fuel strategy
dramatically toward natural gas. Slide 28 reflected a 14 Bcf/day
increase in demand in a carbon managed growth case. More recent
analysis show up to 20 Bcf/day, but the EIA forecast has yet to
take that into account.
4:02:45 PM
CO-CHAIR WIELECHOWSKI asked what he assumes would be taxed under
cap-and-trade.
MR. MYERS replied this model reflects a tax of about $35/ton of
carbon for all sources.
CO-CHAIR WIELECHOWSKI asked how natural gas emissions compare to
other sources.
MR. MYERS replied natural gas emits about one-third what a coal-
fired power plant produces and capital costs are about one-third
as well. To get to the growth that's modeled in all the
scenarios lots more gas is necessary and the price has to be
higher. EIS estimates that the price to consumers will drop
about $0.63/Mcf off the Henry Hub Spot in 2018-2019 when Alaska
gas comes to market. Over time the market will recalibrate and
the price will increase, which will be good for Alaska's gas
prospects.
The latest EIA model indicates that natural gas from LNG will
increase until about 2018 after which it will decrease. Canadian
production will continue to decline because of overall basin
depletion, but the predicted increase in LNG hasn't
materialized. One reason for that is that other areas of the
world value LNG more; the U.S. has alternative gas sources.
MR. MYERS displayed slide 32 showing that the most recent EIA
forecast is higher than the 2004 and 2006 forecasts used for
AGIA. The price estimations are more bullish even with the
increase in supply. He recapped the reasons include worldwide
demand, population demand, national demand, decrease of
conventional supplies and development of more expensive
alternatives. This puts Alaska in a good position.
Slide 33 depicts Atigun Gorge along the gasline route including
the Lisbon formation. This is a high potential target in
limestones and is similar to what is seen in much of the
Canadian Overthrust Belt.
4:07:21 PM
CO-CHAIR WIELECHOWSKI referenced slide 32 and noted that
TransCanada yesterday said the new forecast adds about $125
billion in value to governments and producers. He asked Mr.
Myers if that's his understanding
MR. MYERS said yes; once the infrastructure is constructed the
tariff will remain fairly constant over the life of the pipeline
so the cost will come from the variation in the cost to develop
those resources. For example, if gas is coming out of Prudhoe
Bay, the operating and capital costs stay the same and the
pipeline tariff is pretty much the same. Conversely, when the
price goes down you lose significantly. That is why it's
important to understand the "break-even" formula - what the net
present value of 10-15 percent gives you. The AGIA numbers said
net present value of 10 percent, not break-even. The TransCanada
numbers were probably also net present value of 10 percent.
CO-CHAIR WIELECHOWSKI thanked Mr. Myers for the presentation.
CO-CHAIR JOHNSON introduced Mr. Bennett and clarified that he is
not being paid by the state. He highlighted that the gas
presentation he delivered in Washington D.C. was simple and easy
to understand for the lay person.
4:09:45 PM
PORTER BENNETT, President and CEO, BENTEK Energy LLC, said he
would cover five key points.
· The energy world has changed radically over that last two
years. Technology has changed the way natural gas is developed
and produced, which is profoundly impacting the market.
· Natural gas should no longer be viewed as unavailable,
unreliable or too expensive.
· Due to unconventional gas production, the U.S. has become
supply-long. Prices are falling and consumers will benefit.
· The burgeoning supplies are overwhelming the nation's
pipeline capacity. The impact of constraints is to drive prices
lower by stimulating gas-on-gas competition.
· The production growth creates a unique opportunity to use
gas and reduce carbon emissions.
MR. BENNETT displayed slide 5 showing that the production of gas
began to increase rapidly beginning in the summer of 2007. In
2005 and 2006 it grew about 1.5 percent to 2 percent a year and
in 2008 it grew nearly 7 percent. At the same time demand
increased between 1 percent and 2 percent depending on the
source. Slide 6 demonstrated that in 2008 Lower 48 production
was at near historic levels. Had the recession not hit, levels
would likely have been higher.
4:14:07 PM
MR. BENNETT displayed slide 7 showing that gas production
increased everywhere but in the Gulf of Mexico and Gulf Coast
basins and the Paradox and San Juan basins. He noted that the
Gulf decreased about 600 Mcf/day. If it weren't for the impact
of the hurricanes, he estimated that the decline would have been
closer to 100 Mcf/day. Production in the Rockies grew by about 1
Bcf/day largely due to tight sands and coalbed methane. The
South East Supply area, comprised of the Arkoma, Arcola, East
Texas and Fort Worth basins, grew more than 3 bcf/day last year,
primarily from shale. Production in the Appalachian Basin grew
by 200 Mcf/day last year and the year before. That's where
Marcellus is located and future grow is expected. Production in
the Anadarko and Permian basins, which are primarily
conventional, also grew some last year.
MR. BENNETT highlighted that the market share has changed quite
radically over the last 20 years. In the 1980s the Rockies
produced about 3 percent of the gas consumed in the U.S. and now
it's about 20 percent. The South East supply area only produced
about 9 percent of the gas produced in the country in 2000 and
now it produces 25 percent. Appalachia production was less than
1 percent in 1980 and is now about 4 percent.
MR. BENNETT displayed slide 8 demonstrating that the type of
drilling reflects the shift to unconventional gas production. He
noted that the horizontal drilling is primarily shale gas and
although it's been used since 1990, it's only in the last 2-3
years that it's started to take over. Directional drilling is a
tight sands approach that allows multiple wells on a single pad.
This new technology uses fracing, which produces gas from a
considerably larger area. The fracs are a mix of sand, water and
ceramic beads that are forced in under high pressure to break
the dense shale and allow the gas to flow to the well stem.
Today some wells are fraced 10 or 12 before they're brought on
thereby bringing a tremendous amount of gas into the system.
This has made a tremendous difference in the production of oil.
In 2007 an average well generated about 900 Mcf/day after about
60 days of production. This year the same area was producing
more than twice that amount just because of fracing.
4:20:43 PM
REPRESENTATIVE NEUMAN asked if that is why fewer wells will need
to be drilled for shale gas.
MR. BENNETT replied no; this in itself won't be a problem unless
there is some environmental regulation on fracing. Such
regulation is being proposed and is a significant issue for the
industry. Currently, the states regulate fracing but there is
talk about bringing it under EPA supervision, which would not be
good for either oil or gas production in the U.S.
MR. BENNETT displayed slide 10, a chart of exploration
investment by producers totaling $1 trillion since 2003. That
investment has been possible due to price levels over the past
six or seven years and as a result, gas prices are on the way
down. Slide 11 shows that the Henry Hub price per MMBtu in March
2009 was in the $3.40 to $3.50 range.
4:23:17 PM
MR. BENNETT explained how the geography of production has
changed. Slide 12 illustrates where production was in 1980; the
size of each circle is a function of the total production out of
the field. Over half of U.S. gas production in 1980 was in the
Gulf area and most of the pipeline structure was designed to
move gas out of that area and the Anadarko/Permian to Northeast
and Midwest markets. By 1990 production in the Rockies was
increasing, but the production of Barnett Shale in the Fort
Worth Basin was in decline. By 2000 there was a lot more
production in the Rockies and still some growth in the Gulf, but
the area along the coast of Louisiana had started to decline and
Fort Worth was even smaller.
By the end of last year the situation was very different. Most
of the gas is now coming from east Texas, Northern Louisiana,
the Rockies and the emerging Marcellus production in
Pennsylvania. However the pipeline structure has not changed
very much and therein lie the capacity issues.
Slide 13 maps 2008 gas prices minus the Henry Hub settlement
price by location, to reveal how pipeline constraints create
price anomalies. In Boston or New York for example, the price
averaged $1.23 more than the price at Henry Hub. In the
producing areas of the west, prices were less than Henry hub. In
other words, the areas noted in red had too much gas relative to
demand, or were "supply long" while the areas in blue were
"supply short". The market tries to balance those out by
building pipelines.
Slide 14 illustrates new pipeline projects including the Rockies
Express (REX) which is coming on line soon to bring low-cost gas
out of the Rockies to the higher-priced market. There are 75
pipeline projects going in the Gulf, more than 45 in the east
and another 10 being considered in the Rockies.
4:27:54 PM
MR. BENNETT continued, slide 15 shows the movement of gas out of
the Rockies; blue indicates daily flow on the pipelines and red
indicates capacity. There are three major routes. On the Pacific
Northwest route, capacity utilization rates have been in the
area of 90 percent since 2005. The Southwest (Arizona, Nevada
and California) is also full both directions. The flows going
east out of Cheyenne were constrained but began to open up a
little in 2007 when REX came on line. It dipped a little in 2008
and 2009 due to a maintenance event that caused part of the
pipeline to be closed for a time. He noted that when they get
cold weather in Colorado, that pipeline tends to open up.
SENATOR WAGONER asked about the breakdown of gas coming out of
the Rockies.
4:29:45 PM
MR. BENNETT said it is driven by the Green River which is mostly
tight sands. He guessed that it is approximately 75 percent
unconventional; a lot of it is coal bed methane. He added that
the Powder River and San Juan are also coal bed methane; Jonah
and Pinedale are tight gas and Uinta and Piceance are tight gas
with some conventional. DJ [Denver-Julesburg Basin] is an oily
area; this is conventional but has a lot of horizontal drilling.
It is a good example of how unconventional technologies have
been applied successfully to a conventional reservoir to extend
and expand its productive life.
Slide 17 shows capacity and flows in the Rockies on an aggregate
basis. The blue area represents the amount of total supply that
can be exported and the gold area the amount that is consumed or
stored in the region. The red line is total capacity out of the
Rockies and the green line is price measured at Opal, the
primary pricing point in the Green River.
MR. BENNETT pointed out that the green line fluctuates
dramatically. That fluctuation is due to maintenance which
causes a loss in productive capacity causing the price to go
down. During 2007 the average utilization rate was 103 percent,
a period known as the "Rockies Experience." On more than one day
that summer, producers in the Rockies received only $.05 for
their gas and on many others the price was less than $.75. When
that happens, when there are more producer/sellers than there
are consumers, they bid the price down. There are few long-term
contracts there, so a constraint like this drives the price way
down.
When REX came on, it alleviated the situation so that last year
the utilization rate was 97 percent until the maintenance
problems caused closures.
4:33:43 PM
SENATOR WAGONER questioned what the green line will look like in
six months and 12 months from that time.
MR. BENNETT responded that the current price at Henry Hub is
$3.50 and the price at Opal yesterday was $3.25; so it should be
about where it is now.
MR. BENNETT said he expects the price to be below $1.00 on many
days this summer because there is just too much gas.
Slide 20 displays first year production from an average well in
the Piceance. The red bar represents first year production at
about 500,000 per day, but it declines very quickly. Drilling
the same well the next year results in an incremental increase
of 244 Mcf/day because the balance goes to offset declines from
the first year's well. So to answer Senator Wagoner's question,
that line will eventually flatten out if they don't keep
drilling more than one well.
The blue on this graph represents a projection that is based on
drilling rate as of the end of January according to the
announced plans of producers at that time. Since the end of
January 2009 they have lost more rigs in the Rockies however,
and when that happens it doesn't take long for production to
decline. Based on the rigs projected for this year, they don't
expect to produce enough gas to need the new pipeline that is
being built. That does not mean those projects won't get built;
producers will drill again when the price goes up, leading to
new capacity issues next year. This capacity issue is what
constrains the price of natural gas in the Lower 48.
Slide 21 indicates new pipelines that are unneeded at this
point. Slide 22 shows about 1.6 Bcf/day coming into Lebanon and
325 million a day of unused space going east from Lebanon with
about 250 MMcf/day of local demand. REX pipeline will bring in
another 1.6 Bcf/day and, because 1.6 B won't fit into 325
MMcf/day of space, the price will drop again.
At the end of the year when REX gets over to Eastern Ohio, there
will be plenty of room to get gas into the pipelines but
Marcellus production is growing. It all goes into storage fields
and on a peak day in the winter there is only half a B of open
capacity east of those storage fields. That gas is going to
continue to sit in the storage field until the pipelines are
expanded. Unfortunately, there are only about 100 million per
day in expansions planned for development by 2011. That means a
whole lot of surplus gas in the area, which means prices in Ohio
will drop dramatically.
MR. BENNETT went on to discuss production in the Gulf as shown
on slides 23 and 24. There are 15 projects bringing 7.3 Bcf/day
of gas in and there is 6.4 Bcf/day of incremental capacity (it
starts full). Some gas will be pushed back, leaving about 5
Bcf/day of gas without a home. It gets worse, because the
impact of REX means that some of the gas flowing to that area
will get pushed back and will have to be discounted 70 to 90
percent to make that equalize.
4:41:52 PM
SENATOR WAGONER asked why a producer would want to drill and
produce gas at a loss.
MR. BENNETT explained that is why they are not drilling right
now.
SENATOR WAGONER said, going back to the chart on the
continuation of drilling production, he would expect to see the
decline occur very quickly.
MR. BENNETT stressed that it is important to recognize that
these are long-haul pipelines that have to be built, with an
average cost of $6 to $7 billion and no one is talking about a
solution. The only alternative is to increase demand in the
area. This is different from the Rockies problem where there are
new pipelines already planned. He predicted that with the new
technologies available, producers in the Gulf will be able to
choke off their wells so they can cut back production when
prices are down.
Slide 26 shows drilling activity across the country. He pointed
out that the Permian and Anadarko have lost about 80 percent of
their rigs since October 2008. Haynesville has actually
increased but 14 others have lost rigs.
On slide 27 the basins are color-coded to indicate whether they
are predominantly conventional or unconventional. The circles
are sized based on average daily production over the first two
years of the well and the figures denote number of rigs inactive
since October 17, 2008. Mr. Bennett said the Haynesville has
gained eight rigs because, while their wells cost about $10
million each, they can produce so much more out of those wells
it makes sense to do so even with the price environment that
exists. Another reason is that all of that is "fee land" on
which most of the private three-year leases will soon be
expiring.
He clarified that those rigs aren't just going down they are
being moved around as the technology changes. The new technology
is evolving quickly and creating rigs that are increasingly more
productive; producers are putting their most efficient rigs on
their most productive properties and learning how to use them
effectively. He believes the magic of production technology is
going to mean a lot of gas will be available at relatively low
prices in the near future.
4:50:54 PM
MR. BENNETT said that drilling declines are going to curb
production which will drive prices up a little bit, but they're
not going to go up very far before the increased production they
stimulate hits the constraints and starts to drive prices back
down again. Technology and production will make it possible to
recover from these cyclic changes more rapidly, so the price
response will not be nearly as volatile as it has been
historically. But new pipelines are critical in order to expand
the industry, to expand production and demand; if something is
not done to fix the pipelines and increase demand, it will
become a real problem.
SENATOR WAGONER asked about projections on the replacement of
aging coal plants and compressed gas for vehicles.
4:54:04 PM
MR. MYERS responded that about 50 percent of the energy
generated in this country is from coal and the demand for energy
keeps growing. Looking at a five or ten year period and
disregarding the cyclic bumps, demand for energy is increasing
at a fairly predictable and steady rate as the population
grows. Switching to compressed natural gas or to fuel cells
driven by natural gas will create a dramatic increase in demand;
that is more and more likely as the price of gas is de-coupled
from oil. If people move to electric cars, the country still
has to power the electrical grid; so such possible scenarios as
carbon constraint, fuel-load switching and gas to liquids, can
be realized if the ratio between gas and oil stays high and gas
is abundant.
The key is maintaining an available source of supply that is
relatively abundant and moderately priced. He agrees that a
price in the $7 to $9 range, depending on what oil does, is a
valuable sweet spot. Based on the economics of Alaska gas, it is
also extremely profitable at those numbers. He believes there
will be a dramatic increase in need if the country makes those
policy decisions and if oil availability and oil demand overseas
is difficult. The country is decreasing domestic production of
oil generally. What they do in the Beaufort and Chukchi seas
matters, but we can't drill ourselves out of the lack of energy.
As the demand for oil increases, competition will force prices
up and as oil prices go high, he expects to see fuel-switching
out of oil as there was for electrical generation and
transportation fuel. The upside potential is that if gas is
available and prices stay in that moderate range, it will become
practical to build new gas power plants.
4:57:16 PM
MR. BENNETT said that, in looking at gas consumption for power
generation, it is important to break it down by type. Gas is
used by "peakers," the things that go up and down a lot, and in
combined cycles, which are typically shoulder to base-load
facilities running at 30 to 70 percent. Right now three quarters
of the gas-fired combined cycles, the shoulder technology, is
unused primarily because of the price over the past few years
relative to coal. Now that gas prices are down, coal is having
a little more difficulty competing. Unfortunately, long-term
contracts underpin the coal market so it isn't as easy to switch
away from it as it is gas, which is a spot-market fuel. Longer
term, the obvious way to reduce carbon emissions is to reduce
the use of coal immediately in favor of gas, but it all depends
on where the plants are located. If the plants are in New York,
there is not sufficient capacity on winter days
CO-CHAIR WIELECHOWSKI asked Mr. Meyers if Mr. Bennett's
presentation had changed his opinion at all regarding the
viability of the Alaska gas pipeline.
SENATOR THERRIAULT joined the meeting.
4:59:39 PM
MR. MYERS answered that he did not see a potential conflict but
would like to make a few points. Long-term demand growth has
occurred despite recession and alternative fuel sources. If the
fuel is available and if we are environmentally constrained,
there will be even more growth. There is an excess of supply in
the current recessionary environment. Certainly the pipeline
infrastructure is racing to keep up with localized deltas in the
Lower 48; however Alaska gas has some fundamental differences.
The first gas produced is coming out of gas that is being cycled
at 8.4 Bcf per day. It is not a matter of drilling new wells to
keep up; it is how wide they turn the valve open to produce the
gas. So Alaska is looking at conventional wells that can be
easily choked back or increased beyond the design capacity of
the pipeline. The management techniques and approach are going
to be different in conventional fields where there isn't the
rapid decline and continual need to frac.
Much of the technology being used in the Lower 48 was developed
in Alaska. For example, when he was the discovery geologist at
the Meltwater field, they got zero flow on the first discovery
wells prior to fracing; they got 4,000 barrels per day
afterward. Much of the advanced fracture technology, horizontals
and multi-lateral horizontals, are the way heavy oil is being
developed on the North Slope. These are technologies that have
evolved through a transfer of knowledge from Alaska to the gas
fields of the Lower 48. He believes the technology is not
revolutionary but evolutionary and has limits based on physics,
geology, geochemistry, depth and water-use issues. So he
disagreed a bit with Mr. Bennett on the rate at which technology
enhancement lowers cost. Conventional gas, cost and structure
will beat it every time, he asserted, if that conventional gas
is available and if the pipeline tariffs are reasonable.
5:03:40 PM
MR. BENNETT said he absolutely disagrees with Mr. Meyer's last
statement. He stated that the empirical evidence, the Securities
Exchange filings and the producers that are actually doing this,
show the cost of drilling in shales is dropping dramatically.
Producers he met with yesterday said their costs had gone from
between $6 and $8 last summer to less than $3. A lot of them are
looking at prices in the range of $1.10 to $1.20 in finding and
development costs; lifting will add about $1. In many cases,
their conventional properties are more expensive now than the
unconventional. That is why drilling is off so badly at the
Permian and Anadarko; that is a very expensive place to operate.
He does not think it is correct to characterize unconventional
gas as being more expensive any more.
He also said that the impact on the market is the big issue and,
to him, it isn't certain at all. When they start building these
projects, they need to watch how the market is evolving to see
what that means. For example, people have speculated that LNG
is going to be the big thing; right now two ships are scheduled
to come into Cove Point within the next week or so that will
knock about 20 percent off the price of gas. The only reason
they are coming is that there is no demand anywhere else and we
have the only available storage fields. The problem is that the
producers who can't make any money now at a $3 price are going
to Europe or Africa or China to figure out how to exploit shales
in other parts of the world. It is entirely likely that ten
years from now gas will be produced in places around the world
that we don't even know have gas. It is the same on oil side;
the new technology has already encouraged new development in the
U.S.
5:07:36 PM
MR. MYERS said he would agree compared to coalbed methane, tight
gas sands or shale gas. The Alaska reservoirs haven't been
tapped and according to the test data the rates out of Prudhoe
Bay and Pt. Thomson will far exceed the best shale gas areas.
The only exceptions might be the deep subsalt exploration in the
Gulf of Mexico and places where it is very expensive to set
platforms.
REPRESENTATIVE SEATON asked if gas-to-liquids conversion makes
sense here in Alaska.
5:09:48 PM
MR. MYERS replied it is important to start with an understanding
that the Alaska project connects with an increasingly
underutilized 14 Bcf/day natural gas distribution system in
Alberta. Most scenarios show underuse of the capacity in that
system because the basin is well past its peak. He made the
point that AGIA is expandable and said he believes that the
producers designed their system to go into the liquid hub with
lots of overbuilt capacity. Their highest net back is to get the
gas to the first liquid market. Another point is that Alaska gas
- at least out of Prudhoe Bay - is extremely rich in gas liquids
and that has a lot of value in the petrochemical industry.
5:13:34 PM
MR. BENNETT said anything that can be done to consume the gas
here in Alaska seems very logical.
REPRESENTATIVE RAMRAS expressed skepticism about the commercial
viability of Alaska gas and spending $500 million when the
markets ultimately prevail. He then asked Mr. Bennett to address
the tax policies that are driving exploration and development in
the different regions.
MR. BENNETT replied he isn't aware of any specific incentives,
but the proposed budget eliminates intangible drilling costs and
reduces the depletion allowance. If implemented that would be
very detrimental to drilling activity in the Lower 48.
5:16:21 PM
CO-CHAIR JOHNSON asked Mr. Bennett if he agrees with Mr. Myers'
statement that there's a race to build pipelines in the Lower
48.
MR. BENNETT replied there are lots of projects being proposed
but they aren't being built right now. Smaller projects will
help relieve the bottleneck by 2012-2013 but building a long-
haul pipeline will take a fundamental change in demand.
5:18:41 PM
CO-CHAIR JOHNSON asked about the 5 Bcf of Alaska gas that
potentially will go into the Midwestern U.S.
MR. BENNETT replied for that project to make sense demand has to
increase by perhaps 6-8 Bcf/day. Perhaps in 30 years, but in the
next 10 years it's dubious that an additional 5 Bcf would fit
into the existing Lower 48 demand structure.
MR. MYERS added that the driver is the decline in western
Canadian production and the push to increase use of natural gas
for oil shales. Alaska gas will help supplement the traditional
demand that's been met from Canada. Once the gas gets to the
underutilized liquid hub in Alberta it will flow to the best
available market.
CO-CHAIR WIELECHOWSKI thanked Mr. Myers and Mr. Bennett for
their testimony and turned the gavel to Co-Chair Johnson.
5:21:48 PM
CO-CHAIR JOHNSON observed that during the pipeline hearings in
Anchorage the administration said the gas would go to Chicago
and not to Alberta. He questioned whether there might now be
opposition from environmentalists if the gas went to the oil
sands.
MR. MYERS emphasized that gas molecules aren't branded and
tracked. The gas will flow to the first liquid hub in Alberta
after which it will either go to Chicago or offset gas that went
to the oil sands. North Slope producers aren't forced to deliver
their gas to a particular market.
5:23:24 PM
MR. BENNETT stated agreement.
SENATOR WAGONER commented that there is a lot of liquid in the
gas and once it's removed there will be a large reduction in the
cubic feet of methane put through to Chicago. Responding to a
question, he said it's not established where the liquids will be
removed, but preferably it would be in Alaska. He conceded that,
that may be hard to do.
REPRESENTATIVE DOOGAN asked Mr. Bennett to elaborate on the
checklist item, "state, local and federal government policies
critical to realizing this fragile opportunity."
5:25:43 PM
MR. BENNETT said the federal energy policy that's currently
being formulated doesn't just ignore natural gas it works
against the production of incremental gas because of what appear
to be growing restrictions in access to lands and how to deal
with fracing.
Colorado provides an example at the state level. It is a
proponent of wind energy, but it's an expensive way to produce
peaking power. Using the combined cycle produces less carbon to
begin with as opposed to a single cycle turbine, which you need
for wind power. As a consequence, part of Colorado's energy
policy is reducing the demand for gas.
CO-CHAIR JOHNSON thanked Mr. Myers and Mr. Bennett for their
presentations.
5:27:35 PM
ADJOURNMENT
There being no further business before the committees, the joint
meeting of the House Special Committee on Economic Development,
International Trade and Tourism, the House Resources Standing
Committee, and the Senate Resources Standing Committee meeting
was adjourned at 5:27 p.m.
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